EPA Mandatory Greenhouse Gas Reporting Rules

Energy & Mineral Law Foundation and the West Virginia University College of Law

Climate Change Short Course Morgantown, WV

Wednesday, August 4, 2010

10:45-11:30: Greenhouse Gas Reporting

Final Mandatory Reporting of Greenhouse Gases Rule

Prepared by: Marshall Miller & Associates, Inc.

August 2010

scarpenter

Typewritten Text

Steven M. Carpenter, Director

scarpenter

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TABLE OF CONTENTS

TITLE PAGE ............................................................................................................... I TABLE OF CONTENTS ................................................................................................ II

GLOSSARY OF TERMS AND ACRONYMS .................................................................. III 1.0 INTRODUCTION ................................................................................................. 1 2.0 RULE APPLICABILITY ....................................................................................... 2

2.1 “All-In” Source Categories .........................................................................................2 2.2 Threshold Source Categories ......................................................................................3 2.3 Stationary Combustion Source Categories .................................................................3 2.4 Supplier Source Categories .........................................................................................4

3.0 GENERAL RECORDKEEPING MONITORING AND REPORTING ......................... 5 3.1 Monitoring Plan ..........................................................................................................5 3.2 Recordkeeping .............................................................................................................5 3.3 Calibration Accuracy Requirements ...........................................................................6 3.4 Authorization and Responsibilities of the Designated Representative ........................7

3.4.1 Notice of Delegation .................................................................................................... 8 3.5 Report Submissions .....................................................................................................9

3.5.1 Schedule ....................................................................................................................... 9 3.5.2 2011 Required Reporting ........................................................................................... 10 3.5.3 2011 Non-Reportable Emissions ................................................................................ 11 3.5.4 Ability to Cease Reporting ......................................................................................... 11 3.5.5 Error Reporting .......................................................................................................... 12 3.5.6 Special Provisions for Reporting Year 2010 .............................................................. 12

3.5.6.1 Best available monitoring methods ............................................................... 12 3.5.6.1.1 Requests for extension of the use of best available monitoring methods 13 3.5.6.1.2 Approval Criteria ......................................................................... 13

4.0 STATIONARY COMBUSTION SOURCE EMISSIONS .......................................... 14 4.1 Measurement and Monitoring Methodologies ..........................................................14

4.1.1 Tier 1 Calculation Methodology ................................................................................ 14 4.1.1.1 Emissions Calculations ................................................................................. 15



TABLE OF CONTENTS (CONTINUED)

4.1.4 Tier 4 Calculation Methodology ................................................................................ 20 4.2 Data Reporting and Recordkeeping Requirements ...................................................21

5.0 UNDERGROUND COAL MINES ........................................................................ 21 5.1 Source Definition .......................................................................................................22 5.2 Reportable GHGs ......................................................................................................22 5.3 Calculation Methods .................................................................................................23 5.4 Reporting Requirements ............................................................................................23

APPENDICES

APPENDIX A Exhibits A-1 ................................................................................................ Global Warming Potentials C-1.............................................................. Default CO2 Emissions Factors and Heat Values C-2............................................................................. Default CH4 and N2O Emission Factors

GLOSSARY OF TERMS AND ACRONYMS

Abbreviation Definition ASTM American Society for Testing and Materials

Btu British Thermal Unit CEMS Continuous Emissions Monitoring System

cf cubic feet CH4 Methane

CMM Coal Mine Methane CO2 Carbon Dioxide CO2e Carbon Dioxide Equivalent COD Chemical Oxygen Demand DOC Degradable Organic Carbon GCV Gross Caloric Value

F Fraction of CH4 HHV High Heat Value GWP Global Warming Potential GHG Greenhouse Gas HFC Hydrofluorocarbons

k Decay Rate Mg Metric Tons

MM&A Marshall Miller & Associates, Inc. MSHA Mine Safety and Health Administration MSW Municipal Solid Waste

MMBtu Million British thermal units MRR Mandatory Reporting of Greenhouse Gases Rule N2O Nitrous Oxide PFC Perfluorocarbons SF6 Sulfur Hexafluoride TSD Technical Support Documents

USEPA United States Environmental Protection Agency

1.0 INTRODUCTION

In response to the Fiscal Year 2008 Consolidated Appropriations Act (H.R. 2764; Public Law

110–161), the United States Environmental Protection Agency (USEPA) issued 40 CFR 98,

the Mandatory Reporting of Greenhouse Gases Rule (MRR). The rule, signed by the USEPA

Administrator, Ms. Lisa Jackson, on September 22, 2009, requires reporting of greenhouse gas

(GHG) emissions from large sources and suppliers in the United States, and is intended to collect

accurate and timely emissions data to inform future policy decisions.

The MRR was effective on January 1, 2010, and a report of the total emissions for calendar year

2010 is required to be submitted to the USEPA by March 31, 2011. Under the MRR, suppliers

of fossil fuels or industrial GHGs, manufacturers of vehicles and engines, and certain facilities

that emit 25,000 metric tons or more per year of GHG emissions are required to submit annual

reports to the USEPA. The GHGs covered by the rule are carbon dioxide (CO2), methane (CH4),

nitrous oxide (N2O), hydrofluorocarbons (HFC), perfluorocarbons (PFC), sulfur hexafluoride

(SF6), and other fluorinated gases as outlined in Table A-1 of Subpart A of the MRR, which is

also provided in Appendix A of this document.

On June 28, 2010, Administrator Jackson amended the MRR to include two actions related to

reporting requirements including:

• An addition of four source categories: Magnesium Production (Subpart T), Underground

Coal Mines (Subpart FF), Industrial Wastewater Treatment (Subpart TT), and Industrial

Waste Landfills (Subpart II).

• A final decision not to include ethanol production and food processing as distinct

Subparts in the MRR, as well as a final decision not to include suppliers of coal at this

time.

With these two actions, the USEPA has covered all outstanding source categories and Subparts

from the April 2009 proposal for the MRR.

Final Mandatory Reporting of Greenhouse Gases Rule Review August 2010 • Page 2

2.0 RULE APPLICABILITY

The USEPA has identified four primary source categories that are required to report GHG

emissions. These source categories are listed below.

2.1 “All-In” Source Categories A facility that operates one or more of the following source categories must report its GHG

emissions, regardless of the total quantity of annual emissions:

• Electricity generation (if CO2 emissions are reported year-round through 40CFR Part 75);

• Adipic acid production.

• Aluminum production.

• Ammonia manufacturing.

• Cement production.

• HCFC-22 production.

• HFC-23 destruction processes that are not collocated with a HCFC-22 production facility and that destroy more than 2.14 metric tons of HFC-23 per year.

• Industrial Waste Landfills that accepted waste on or after January 1, 1980, and is located at a facility with a total landfill design capacity greater than or equal to 300,000 metric tons.

• Lime manufacturing.

• Magnesium Production.

• Manure management systems with combined CH4 and N2O emissions in amounts equivalent to 25,000 metric tons CO2e or more per year.

• Municipal solid waste landfills that generate CH4 equivalent to 25,000 metric tons carbon dioxide equivalent (CO2e) or more per year.

• Nitric acid production.

• Petrochemical production.

• Petroleum refineries.

• Phosphoric acid production.

• Silicon carbide production.

• Soda ash production.

• Titanium dioxide production.


• Underground Coal Mines that are subject to quarterly or more frequent sampling of mine

ventilation systems by the Mine Safety and Health Administration (MSHA).

An “All-In” facility must report all emissions sources for which calculation methods are

provided in Subparts C through JJ of the MRR.

2.2 Threshold Source Categories A facility that is not subject to the “All-In” source category AND emits a total ≥25,000 metric

tons CO2e per year from combined emissions from stationary fuel combustion units,

miscellaneous uses of carbonate, and all source categories that are listed below:

• Ferroalloy production.

• Glass production.

• Industrial Wastewater Treatment.

• Hydrogen production.

• Iron and steel production.

• Lead production.

• Pulp and paper manufacturing.

• Zinc production.

These facilities are required to report emissions from all sources for which calculation methods

are provided in Subparts C through JJ of the MRR.

2.3 Stationary Combustion Source Categories A facility that operates one or more stationary fuel combustion sources and does not meet the

requirements of “All-In” or Threshold source categories AND the facility’s stationary

combustion sources emit ≥25,000 metric tons CO2e per year AND have an aggregate maximum

rated heat input of 30 MMBtu/hr or greater must report stationary combustion sources under

Subpart C of the MRR. Stationary combustion sources include but are not limited to the

following:

• Boilers.

• Thermal dryers.


• Stationary internal combustion engines.

• Process heaters.

• Combustion turbines.

• Incinerators.

• Other stationary fuel combustion equipment.

However, emissions from emergency generators, portable equipment, flares, hazardous waste

combustion, and biomass-derived fuels are exempt.

2.4 Supplier Source Categories Suppliers of ANY of the following categories must report:

• Coal-based liquid fuels suppliers

• All producers of coal-based liquid fuels.

• Importers and exporters of coal-based liquid fuels (annual quantities ≥25,000 metric tons CO2e).

• Petroleum products suppliers

• All producers of petroleum products.

• Importers and exporters of petroleum products (annual quantities ≥25,000 metric tons CO2e).

• All producers of natural gas and natural gas liquids;

• Natural gas fractionators.

• Natural gas distribution companies.

• Industrial GHG suppliers; and

• All producers of industrial GHGs.

• Importers and exporters of industrial greenhouse gases with annual bulk imports of N2O, fluorinated GHG, and CO2 that in combination are equivalent to 25,000 metric tons CO2e or more.

• CO2 suppliers.

• All producers of CO2.

• Importers and exporters of industrial greenhouse gases with annual bulk imports of N2O, fluorinated GHG, and CO2 that in combination are equivalent to 25,000 metric tons CO2e or more.


These suppliers must report total emissions as well as the calculations methodologies utilized as

established in Subparts KK through PP of the MRR.

However, research and development activities are not considered to be part of any source

category defined in the supplier source category.

3.0 GENERAL RECORDKEEPING MONITORING AND REPORTING

3.1 Monitoring Plan An owner or operator of a facility required to report GHG emissions must prepare a written GHG

Monitoring Plan. At a minimum, the GHG Monitoring Plan should include the following:

• Identifies responsibilities (i.e., job titles) for data collection.

• Explains processes and methods used for data collection.

• Describes quality assurance procedures, maintenance, and repair of all continuous emissions monitoring systems (CEMS).

• May rely on references to existing corporate documents (e.g., standard operating procedures).

The owner or operator should revise the GHG Monitoring Plan as needed to reflect changes in

production processes, monitoring instrumentation, and quality assurance procedures or to

improve procedures for the maintenance and repair of monitoring systems to reduce the

frequency of monitoring equipment downtime.

Upon request by the USEPA Administrator, the owner or operator should make all information

that is collected consistent with the GHG Monitoring Plan available for review during an audit.

Electronic storage of the information in the plan is permissible, provided that the information can

be made available in hard copy upon request during an audit.

3.2 Recordkeeping An owner or operator of a facility required to report GHG emissions must retain the following

records:


• A list of all units, operations, processes, and activities for which GHG emissions were

calculated.

• The data used to calculate the GHG emissions for each unit, operation, process, and activity, categorized by fuel or material type. These data include but are not limited to the following information:

• The GHG emissions calculations and methods used.

• Analytical results for the development of site-specific emissions factors.

• The results of all required analyses for high heat value (HHV), carbon content, and other required fuel or feedstock parameters.

• Any facility operating data or process information used for the GHG emission calculations.

• The annual GHG reports.

• For each missing data event, also retain a record of the duration of the event, actions taken to restore malfunctioning monitoring equipment, the cause of the event, and the actions taken to prevent or minimize occurrence in the future.

• The results of all required certification and quality assurance tests of CEMS, fuel flow meters, and other instrumentation used to provide data for reported GHGs.

• Maintenance records for all CEMS, flow meters, and other instrumentation used to provide data for reported GHGs.

These records must be retained for at least 3 years. The records should be kept in an electronic

or hard-copy format (as appropriate) and recorded in a format that is suitable for expeditious

inspection and review. Upon request by the USEPA Administrator, the records must be made

available to the USEPA. Records may be retained off site if the records are readily available.

For records that are electronically generated or maintained, the equipment or software necessary

to read the records should be made available, or, if requested by the USEPA, electronic records

should be converted to paper documents.

3.3 Calibration Accuracy Requirements The owner or operator of a facility or supplier that is subject to the MRR must meet certain

calibration accuracy requirements. Devices (e.g., belt scales, flow meters) that measure data

used to calculate GHG emissions should have been calibrated prior to April 1, 2010, for source

categories required to report on March 31, 2011, using the manufacturer’s recommended

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


reporting rule. All measurement devices should be calibrated to an accuracy of 5 percent. For

facilities and suppliers that become subject to calibration accuracy requirements after April 1,

2010, the initial calibration should be conducted on the date that data collection is required to

begin. Subsequent calibrations should be performed at the frequency specified in each

applicable Subpart.

For source categories required to report on March 31, 2011, a flow meter or other measurement

device that has been previously calibrated in accordance with the MRR, an initial calibration is

not required by the date specified (April 1, 2010). The previous calibration performed would

comply with the MRR.

For units and processes that operate continuously with infrequent outages, it may not have been

possible to meet the April 1, 2010, deadline for the initial calibration of a flow meter or other

measurement device without removing the device from service and shipping it to a remote

location, thereby disrupting normal process operation. In such cases, the owner or operator may

have postponed the initial calibration until the next scheduled maintenance outage, and may have

similarly postponed the subsequent recalibrations. Such postponements must be well

documented in the required GHG Monitoring Plan.

3.4 Authorization and Responsibilities of the Designated Representative Each owner or operator who is subject to the recordkeeping requirements should assign a

designated representative (as well as alternate designated representative, if desired) who would

be responsible for certifying, signing, and submitting GHG emissions reports and any other

submissions for each applicable source at each applicable facility to the USEPA.

A Certificate of Representation must be completed and include the following:

• Identification of the facility or supplier for which the Certificate of Representation is submitted.

• The name, address, e-mail address (if any), telephone number, and facsimile transmission number (if any) of the designated representative and any alternate designated representative.

• A list of the owners and operators of the facility or supplier provided that, if the list includes the operators of the facility or supplier and the owners with control of the facility


or supplier. The failure to include any other owners will not make the Certificate of Representation incomplete.

• The following certification statements by the designated representative and any alternate designated representative:

• “I certify that I was selected as the designated representative or alternate designated representative, as applicable, by an agreement binding on the owners and operators of the facility or supplier, as applicable.”

• “I certify that I have all the necessary authority to carry out my duties and responsibilities under 40 CFR Part 98 on behalf of the owners and operators of the facility or supplier, as applicable, and that each such owner and operator should be fully bound by my representations, actions, inactions, or submissions.”

• “I certify that the owners and operators of the facility or supplier, as applicable, should be bound by any order issued to me by the USEPA Administrator or a court regarding the facility or supplier.”

• “If there are multiple owners and operators of the facility or supplier, as applicable, I certify that I have given a written notice of my selection as the ‘designated representative’ or ‘alternate designated representative’, as applicable, and of the agreement by which I was selected to each owner and operator of the facility or supplier."

• The signature of the designated representative and any alternate designated representative and the dates signed.

Unless otherwise required by the USEPA Administrator, documents of the agreement referred to

in the Certificate of Representation should not be submitted to the USEPA Administrator. The

USEPA Administrator will not be under any obligation to review or evaluate the sufficiency of

such documents, if submitted.

3.4.1 Notice of Delegation

A designated representative or an alternate designated representative may delegate his or her

own authority, to one or more individuals, to submit an electronic submission to the USEPA

Administrator. In order to delegate his or her own authority, to one or more individuals, to

submit an electronic submission to the USEPA Administrator, the designated representative or

alternate designated representative must submit a Notice of Delegation electronically to the

USEPA Administrator, in a format prescribed by the USEPA Administrator, which includes the

following elements:

• The name, address, e-mail address (if any), telephone number, and facsimile transmission number (if any) of the designated representative or alternate designated representative.


• The name, address, e-mail address, telephone number, and facsimile transmission number

(if any) of each delegated individual (referred to as an “agent”).

• For each agent, a list of the type or types of electronic submissions for which authority is delegated to him or her.

• For each type of electronic submission listed above, a list of the facilities for which the electronic submission may be made.

• The following certification statements by the designated representative or alternate designated representative:

• “I agree that any electronic submission to the Administrator that is by an agent identified in this notice of delegation and of a type listed, and for a facility or supplier designated, for such agent in this notice of delegation and that is made when I am a designated representative or alternate designated representative, as applicable, and before this notice of delegation is superseded by another notice of delegation under §98.4(m)(3) should be deemed to be an electronic submission certified, signed, and submitted by me.”

• “Until this notice of delegation is superseded by a later signed notice of delegation under §98.4(m)(3), I agree to maintain an e-mail account and to notify the Administrator immediately of any change in my e-mail address unless all delegation of authority by me under §98.4(m) is terminated.”

• The signature of such designated representative or alternate designated representative and the date signed.

• Any electronic submission must be certified, signed, and submitted by the designated representative or alternate designated representative who is submitting the Notice of Delegation.

3.5 Report Submissions Each GHG report and Certificate of Representation for a facility or supplier must be submitted in

accordance with the requirements of the MRR and in an electronic format.

3.5.1 Schedule

The following table on the next page outlines the schedule for monitoring and reporting under

the MRR.


Schedule for Monitoring and Reporting

1/1/2010 Start collecting data using best available monitoring methods

for source categories listed in the September 22, 2009 promulgated MRR.

30 days after effective date of rule (estimated 1/31/2010)

Deadline for submitting application to extend use of best available monitoring methods

3/31/2010 Monitors installed and calibrated. Begin using required monitoring methods (if extension request not obtained)

12/31/2010 Complete 2010 data collection

1/30/2011 Submit Certificate of Representation

3/31/2011 Submit GHG report for 2010 for source categories listed in the September 22, 2009 promulgated MRR.

1/1/2011 Start collecting for Magnesium Production, Underground

Coal Mines, Industrial Wastewater Treatment, and Industrial Waste Landfills added June 28, 2010.

3/31/2012 Submit GHG report for 2011 for Magnesium Production,

Underground Coal Mines, Industrial Wastewater Treatment, and Industrial Waste Landfills added June 28, 2010.

Ongoing Submit corrected report 45 days after each discovery

Ongoing Submit annual reports on 3/31 each year

The owner or operator of a facility required to report GHG emissions on March 31, 2010 should

have begun collecting data on January 1, 2010. The first annual GHG monitoring report is due

on March 31, 2011. Subsequent reports are to be submitted annually.

3.5.2 2011 Required Reporting

The 2011 reporting of GHG emissions will be required to include the following:

• Identifying information.

• Annual GHG emissions excluding biomass CO2, metric tons CO2e.

• Annual CO2 emissions from biomass combustion, metric tons.

• Annual emissions of each GHG for each source category, tons each gas.

• Other emissions data required by an applicable Subpart (e.g., by unit or process).

• Verification data required by each Subpart (e.g., data used to calculate emissions).

• Description of best available methods used.


• Data elements for which a missing data procedure was used.

• Certification by the “designated representative.”

3.5.3 2011 Non-Reportable Emissions

As finalized for 2011, the MRR does not require emissions reporting for the following sources:

• Indirect emissions (e.g., electricity use).

• Mobile source emissions (e.g., fleet emissions, off- road equipment).

• Waste water treatment.

• Emissions from coal mining sources.

• Refrigerant emissions.

• Emissions from the use of explosives.

• Emission offsets.

• Carbon sequestration.

3.5.4 Ability to Cease Reporting

Facilities can cease reporting if annual emissions are less than either of the following:

• 25,000 metric tons CO2e for 5 years

• 15,000 metric tons CO2e for 3 years.

To cease reporting, the owner or operator of the facility must notify the USEPA of the intent to

cease reporting and explain the reasons for the reduction in emissions. This provision applies to

all facilities and suppliers subject to the rule, regardless of their applicability category (i.e.,

whether rule applicability was initially triggered by an “All-In” source category or a source

category with a 25,000 metric tons CO2e threshold). The owner or operator must keep records

for all five consecutive years in which emissions were less than 25,000 metric tons per year, or

all three consecutive years in which emissions were less than 15,000 metric tons per year, as

appropriate. If GHG emissions (or quantities in products supplied) subsequently increase to

25,000 metric tons CO2e in any calendar year, the owner or operator must again begin annual

reporting. The MRR also contains a provision to allow facilities and suppliers to notify the

USEPA and stop reporting if they close all GHG-emitting processes and operations covered by

the MRR.


3.5.5 Error Reporting

If the owner or operator discovers an error or is notified by the USEPA of errors in an annual

GHG monitoring report, a revised GHG report must be submitted within 45 days.

3.5.6 Special Provisions for Reporting Year 2010

To try to alleviate industry burden, the USEPA has made special provisions to the reporting year

2010. They are as follows.

3.5.6.1 Best available monitoring methods Beginning on January 1, 2010, and continuing through March 31, 2010, owners or operators of

facilities and/or sources that are mandated by the MRR to report GHG emissions were allowed to

use best available monitoring methods for any parameter (e.g., fuel use, carbon content, etc.) that

cannot reasonably be measured according to the monitoring and QA/QC requirements of a

relevant subpart.

Best available monitoring methods are defined under the MRR as any of the following methods:

• Monitoring methods which are currently in use at the facility but do not meet the specifications for monitoring under the relevant subpart.

• Supplier data.

• Engineering calculations.

• Other company records.

The reporter was still required to use the calculation methodologies and equations in the

“Calculating GHG Emissions” sections of each relevant subpart, but may use the best available

monitoring method for any parameter for which it is not reasonably feasible to acquire, install,

and operate a piece of monitoring equipment required under the MRR by January 1, 2010.

However, after April 1, 2010, the reporter was required to discontinue using best available

monitoring methods and begin following all applicable monitoring and QA/QC requirements.

There are two exceptions, which are outlined in Sections 3.5.6.1.1 and 3.5.6.1.2 below.


3.5.6.1.1 Requests for extension of the use of best available monitoring methods The reporter may have submitted a request to the Administrator to use one or more best available

monitoring methods beyond March 31, 2010.

• Timing of request: The extension request must have been submitted to the USEPA no later than 30 days after the effective date of the GHG reporting rule, January 1, 2010.

• Content of request: Requests must have contained the following information:

o A list of the specific monitoring instrumentation for which the request is being made and the location(s) where each piece of monitoring instrumentation will be installed.

o Identification of the specific rule requirements (by rule subpart, section, and paragraph numbers) for which the instrumentation is needed.

o A description of the reasons why the necessary equipment could not be obtained and installed before April 1, 2010.

o If the reason for the extension is that the equipment cannot be purchased and delivered by April 1, 2010, the request must include supporting documentation such as the date the monitoring equipment was ordered, investigation of alternative suppliers and the dates by which alternative vendors promised delivery, backorder notices or unexpected delays, descriptions of actions taken to expedite delivery, and the current expected date of delivery.

o If the reason for the extension is that the equipment cannot be installed without shutting down the process unit, the request must include supporting documentation demonstrating that it is not practicable to isolate the equipment and install the monitoring instrument without a full process unit shutdown. Include the date of the most recent process unit shutdown, the frequency of shutdowns for this process unit, and the date of the next planned shutdown during which the monitoring equipment can be installed. If there has been a shutdown or if there is a planned process unit shutdown between January 1 and April 1, 2010, include a justification of why the equipment could not be obtained and installed during that shutdown.

o A description of the specific actions the facility will take to obtain and install the equipment as soon as reasonably feasible and the expected date by which the equipment will be installed and operating.

3.5.6.1.2 Approval Criteria To obtain approval, the reporter must have demonstrated to the Administrator’s satisfaction that

it was not reasonably feasible to acquire, install, and operate a required piece of monitoring

equipment by the April 1, 2010 deadline.


The USEPA will not approve the use of best available methods beyond December 31, 2010.

4.0 STATIONARY COMBUSTION SOURCE EMISSIONS

As many of MM&A’s clients will be required to report GHG emissions from stationary

combustion sources, a detailed summary of the requirements as well as calculation methods are

detailed below.

4.1 Measurement and Monitoring Methodologies Four different methods (tiers) for calculating GHG emissions from stationary combustion

sources can be employed. The different tiers used are based on unit size, fuel type, and other

factors.

4.1.1 Tier 1 Calculation Methodology

In the Tier 1 calculation, annual fuel consumption (from company records) is used together with

fuel-specific HHV and default CO2, CH4, and N2O emission factors to calculate the stationary

combustion emissions.

The total annual fuel consumption should be directly measured by gravimetric or volumetric

means such as:

• Tank drop measurements.

• Engineering calculations (e.g., using generation or unit operating hours).

• Fuel billing records.

Facilities can use the Tier 1 calculation methodology for any type of fuel combusted if all

THREE of the following conditions are met:

• The combustion units have a maximum rated heat input capacity of ≤250 MMBtu/hr.

• There is an applicable default CO2 emission factor and applicable default HHV for the fuel utilized as provided in Table C-1 (Appendix A).


• The owner or operator of the facility DOES NOT routinely perform fuel sampling and

analysis of the fuel’s HHV or routinely receive the results of HHV sampling and analysis from the fuel’s supplier.

The Tier 1 methodology may be used for municipal solid waste (MSW) in a unit of any size that

does not produce steam, if the use of the Tier 4 methodology (as outlined in Section 4.1.4 of this

document) is not required. Tier 1 may be used for solid, gaseous, or liquid biomass fuels in a

unit of any size provided that the fuel is listed in Table C-1 (Appendix A).

4.1.1.1 Emissions Calculations The CO2, CH4, and N2O emissions from stationary combustion sources are calculated by

multiplying the total annual fuel consumption by the default HHV and default emission factors

for the fuel as defined in Equation C-1 below:

E = Fuel use x HHV x EF x 0.001 (Eq. C-1)

Where: E = Annual emissions in the units of Mg (metric tons). HHV = Default High heat value in the units of MMBtu. EF = Emission factor in the units of kg GHG/ MMBtu from Table C-1 and Table C-2 (Appendix A). 0.001= conversion from kg to Mg.

The CO2 default HHV and default emissions factors by fuel type are outlined in the Table C-1 of

the MRR. The default HHV and default emission factors by fuel type for CH4 and N2O are

outlined in Table C-2 of the MRR. Both tables have been provided in Appendix A of this

document.


In the Tier 2 calculation, annual fuel consumption (from company records) is used together with

measured fuel-specific HHV and default CO2 emission factors.

Facilities MUST use the Tier 2 calculation methodology for any type of fuel combusted if all

THREE of the following conditions are met:


• A units rated maximum rated heat input capacity of 250 MMBtu/hr or less (units that

combust only pipeline natural gas and/or distillate oil may be greater than 250 MMBtu/hr).

• There is an applicable default CO2 emission factor and applicable default HHV for the fuel listed in Table C-1 (Appendix A).

• The owner or operator routinely perform fuel sampling and analysis for the fuel HHV or routinely receives the results of HHV sampling and analysis from the fuel supplier.

For use in the Tier 2 calculation, the HHV of the fuel must be measured at the following

minimum sampling frequency:

• Natural gas: Semiannual.

• Coal and fuel oil: Each shipment or delivery.

• Other liquid fuels and biogas: Quarterly.

• Other solid fuels and MSW: Weekly sample and monthly analysis.

• Other gaseous fuels: Daily (if equipment in place) or weekly.

The Tier 2 methodology may not be used for MSW.

4.1.2.1 Emissions Calculations Annual emissions can be calculated under the Tier 2 methodology for each type of fuel by using

Equation C-2a, C-2b or C-2c.

Equation C-2a calculates CO2, CH4 and N2O emissions by multiplying the annual fuel

consumption by the measured HHV and default emission factors for the fuel listed in Table C-1

(Appendix A) as defined below:

E = Annual Fuel Use x (HHV)annual x EF x 0.001 (Eq. C-2a)

Where: E = Annual emissions in units of Mg (metric tons). (HHV)annual = Weighted annual average high heat value of the fuel (MMBtu per mass or volume) as calculated in Equation C-2b below. EF = Emission factor in the units of kg GHG/ MMBtu from Table C-1 and Table C-2 of Appendix A. 0.001= conversion from kg to Mg.


Equation C-2b is used to calculate the weighted annual average of the measured monthly HHV:

( )

( )∑

∑

=

=

×= n

ii

iii

1

n

1annual

Fuel

Fuel (HHV) (HHV) (Eq. C-2b)

Where: (HHV)annual = Weighted annual average high heat value of the fuel (MMBtu per mass or volume). (HHV)i = High heat value of the fuel, for month “i” (MMBtu per mass or volume). (Fuel)i = Mass or volume of the fuel combusted during month “i” (express mass in short tons for solid fuel, volume in standard cubic feet for gaseous fuel, and volume in gallons for liquid fuel). n = Number of months in the year that fuel is burned in the unit.

If the results of fuel sampling are received less frequently than monthly, then the annual average

HHV should be computed as the arithmetic average HHV for all values for the year. In

calculating the arithmetic average HHV, any valid sample results that are found to be missing

can be substituted with the arithmetic average of the quality-assured HHV values immediately

preceding and immediately following the missing data incident. If the "after" value has not been

obtained by the time that the GHG emissions report is due, the "before" value may be used for

missing data substitution or the best available estimate of the parameter, based on all available

process data. If, for a particular parameter, no quality-assured data are available prior to the

missing data incident, the substitute data value must be the first quality-assured value obtained

after the missing data period.

For units that combust MSW and that produce steam, the following equation can be used to

calculate CO2 emissions:

CO2= Steam x B x EF x 0.001 (Eq. C-2c)

Where: CO2 = Annual CO2 emissions from MSW combustion in units of Mg. Steam = Total mass of steam generated by MSW or solid fuel combustion during the reporting year (lb steam). B = Ratio of the boiler’s maximum rated heat input capacity to its design rated steam output capacity (MMBtu/lb steam). EF = Default emission factor, from Table C-1 (kg CO2/MMBtu).


0.001 = Conversion factor from kilograms to metric tons.

Equation C-2c can also be used for any other solid fuel listed in Table C-1 (Appendix A)

provided that steam is generated by the unit.


In the Tier 3 calculation methodology, annual fuel consumption—either from company records

(for solid fuels) or directly measured with fuel flow meters (for liquid and gaseous fuels), billing

meter, or tank drop measurements—is used together with periodic measurements of fuel carbon

content.

The Tier 3 methodology MUST be used in the following situations:

• The unit has a maximum rated heat input capacity of ≥250 MMBtu/hr for any fuel listed in Table C-1 (Appendix A), except:

• Pipeline natural gas and distillate oil.

• MSW.

• If Tier 4 calculation methodology is required.

• The unit has a maximum rated heat input capacity of ≥250 MMBtu/hr and the emission factors for the fuel source is NOT provided in Table C-1 of Appendix A, only if:

• The fuel provides 10% or more of the annual heat input to the unit.

For use in the Tier 3 calculation, the carbon content of fuel must be measured at the following

minimum sampling frequency:

• Natural gas: Semiannual.

• Coal and fuel oil: Each shipment or delivery.

• Other liquid fuels and biogas: Quarterly.

• Other solid fuels and MSW: Weekly sample and monthly analysis.

• Other gaseous fuels: Daily (if equipment in place) or weekly.

4.1.3.1 Emissions Calculations The annual CO2 mass emissions for each fuel are calculated using Equation C-3, C-4, or C-5.


For a solid fuel, use Equation C-3:

0.91 CC Fuel 1244 CO2 ×××= (Eq. C-3)

Where: CO2 = Annual CO2 mass emissions from the combustion of the specific solid fuel (metric tons). Fuel = Annual mass of the solid fuel combusted, from company records. CC = Annual average carbon content of the solid fuel (percent by weight, expressed as a decimal fraction, e.g., 95% = 0.95). The annual average carbon content must be determined using the same procedures as specified for HHV in paragraph (a)(2)(ii) of Subpart C of the MRR. 44/12 = Ratio of molecular weights, CO2 to carbon. 0.91 = Conversion factor from short tons to metric tons.

For a liquid fuel, use Equation C-4:

0.001 CC Fuel 1244 CO2 ×××= (Eq. C-4)

Where: CO2 = Annual CO2 mass emissions from the combustion of the specific liquid fuel (metric tons). Fuel = Annual volume of the liquid fuel combusted (gallons). The volume of fuel combusted must be measured directly, using fuel flow meters calibrated according to §98.3(i). Fuel billing meters may be used for this purpose. Tank drop measurements may also be used. CC = Annual average carbon content of the liquid fuel (kg C per gallon of fuel). The annual average carbon content should be determined using the same procedures as specified for HHV in paragraph (a)(2)(ii) of Subpart C of the MRR. 44/12 = Ratio of molecular weights, CO2 to carbon. 0.001 = Conversion factor from kg to metric tons.

For a gaseous fuel, use Equation C-5:

0.001 MVCMW CC Fuel

1244 CO2 ××××= (Eq. C-5)

Where: CO2 = Annual CO2 mass emissions from combustion of the specific gaseous fuel (metric tons). Fuel = Annual volume of the gaseous fuel combusted (scf). The volume of fuel combusted must be measured directly, using fuel flow meters calibrated according to §98.3(i). Fuel billing meters may be used for this purpose.


CC = Annual average carbon content of the liquid fuel (kg C per gallon of fuel). The annual average carbon content shall be determined using the same procedures as specified for HHV in paragraph (a)(2)(ii) of Subpart C of the MRR. MW = Annual average molecular weight of the gaseous fuel (kg/kg-mole). The annual average carbon content shall be determined using the same procedures as specified for HHV in paragraph(a)(2)(ii) of Subpart C of the MRR. MVC = Molar volume conversion factor (849.5 scf per kg-mole at standard conditions, as defined in§98.6). 44/12 = Ratio of molecular weights, CO2 to carbon. 0.001 = Conversion factor from kg to metric tons.


The Tier 4 calculation methodology is used only for combustion units that have existing CEMS

in place. Tier 4 MUST be used in the following situations:

• A stationary combustion unit of any size, combusting any type of fuel, which is currently being monitored by a CEMS.

• Units that have a maximum rated heat input capacity ≥250 MMBtu/hr and meet all FIVE of the following conditions:

• The unit combusts solid fossil fuel, either as a primary or secondary fuel.

• The unit has operated for more than 1,000 hours in any calendar year since 2005.

• The unit has installed CEMS that are required either by an applicable Federal or State regulation or the unit’s operating permit.

• The installed CEMS include a gas monitor of any kind or a stack gas volumetric flow rate monitor, or both, and the monitors have been certified, either in accordance with the requirements of 40 CFR Part 75, Part 60 of Subpart 60 of the MRR, or an applicable State continuous monitoring program.

• The installed gas or stack gas volumetric flow rate monitors are required, either by an applicable Federal or State regulation or by the unit’s operating permit, to undergo periodic quality assurance testing in accordance with either Appendix B to 40 CFR Part 75, Appendix F to 40 CFR Part 60, or an applicable State continuous monitoring program.

• Units that have a maximum rated heat input capacity of ≤250 MMBtu/hr and meet all THREE of the following conditions:

• The unit has both a stack gas volumetric flow rate monitor and a CO2 concentration monitor.


• The unit combusts solid fossil fuel or MSW, either as a primary or secondary fuel. The

unit operated >1,000 hours in a calendar year since 2005, and the unit has installed a CEMS as required by federal or state regulation.

• The CO2 and stack gas volumetric flow rate monitors meet the conditions specified in conditions 4 and 5 listed above.

The Tier 4 Calculation Methodology should be used beginning on:

• January 1, 2010 for a unit that is required to report CO2 mass emissions beginning on that date, assuming that all of the monitors needed to measure CO2 mass emissions have been installed and certified by that date.

• January 1, 2011 for a unit that is required to report CO2 mass emissions beginning on January 1, 2010, if all of the monitors needed to measure CO2 mass emissions have not been installed and certified by January 1, 2010. In this case, the owner or operator may use the Tier 2 or Tier 3 Calculation Methodology to report GHG emissions for 2010.

4.2 Data Reporting and Recordkeeping Requirements Regardless of which calculation methodology is employed to determine the GHG emissions for

stationary combustion units, the emissions report must include the following data:

• The unit’s ID number.

• A code representing the type of unit.

• The maximum rated heat input of the unit.

• Each type of fuel combusted in the unit during the reporting year.

• The tier calculation methodology used to calculate emissions for each type of fuel combusted.

• The CO2, CH4, and N2O emissions for each type of fuel combusted, expressed in metric tons of each gas and in metric tons of CO2e.

• The customer meter number for units that combust natural gas.

5.0 UNDERGROUND COAL MINES

As many of MM&A’s clients will be required to report GHG emissions from underground coal

mines, a detailed summary of the requirements as well as calculation methods are detailed below.

Owners or operators of facilities that are subject to quarterly or more frequent sampling of mine

ventilation systems by MSHA must report emissions from underground coal mines and all other


source categories located at the mine for which methods are defined in the rule. Owners or

operators are required to collect emission data; calculate GHG emissions; and follow the

specified procedures for quality assurance, missing data, recordkeeping, and reporting.

5.1 Source Definition This source category consists of both underground mines under development and underground

mines categorized by MSHA as active (where coal is currently being produced or has been

produced within the previous 90 days). It includes all underground coal mines that have

operational pre-mining degasification systems. Abandoned (closed) mines, surface coal mines,

and post-coal mining activities are not included in this source category.

This source category consists of the following emission points:

• Each ventilation well or shaft.

• Each degasification system well or shaft, including degasification systems deployed

before, during, or after mining operations.

CH4 liberation (including both emitted and combusted) from each ventilation shaft and each

degasification well must be included; however, monitoring for each system type may take place

at one or more centralized monitoring points that covers all emissions points within that system.

5.2 Reportable GHGs Underground coal mine owners and operators must report:

• Quarterly CH4 liberation from each ventilation well or shaft, and/or each centralized monitoring point.

• Weekly CH4 liberated from each degasification system, and/or each centralized monitoring point.

• Weekly CH4 destruction from each destruction device or point of offsite transport.

• Quarterly CO2 emissions from coal mine gas CH4 destruction where the gas is not a fuel input for energy generation or use.

• Annual CO2, and N2O emissions from stationary fuel combustion devices using the calculation methods specified in 40 CFR part 98, subpart C (General Stationary Combustion Sources).


In addition, each facility must report GHG emissions for any other source categories for which

calculation methods are provided in other subparts of the rule, as applicable.

5.3 Calculation Methods Total annual CH4 emissions are the sum of quarterly CH4 that is liberated from ventilation wells and

shafts and degasification systems, less the quantity of CH4 that is collected and destroyed.

• For ventilation wells and shafts, liberated CH4 is determined by quarterly or more frequent

sampling, or continuous monitoring of flow rate and CH4 concentration.

• For degasification systems, liberated CH4 is determined by weekly or more frequent

sampling, or continuous monitoring of flow rate and CH4 concentration.

• CH4 destroyed is determined by continuous monitoring of flow rate and CH4

concentration of gas collected for destruction and by applying a destruction efficiency.

CO2 emissions from CH4 destruction are estimated by applying a factor to the estimate of CH4

destroyed.

5.4 Reporting Requirements Underground coal mines subject to Subpart FF must begin monitoring GHG emissions on January 1,

2011 in accordance with the methods specified in the Subpart. The first reports are due to the USEPA

on March 31, 2012 and annually thereafter.

In addition to the information required by the General Provisions at 40 CFR 98.3(c), each

underground coal mine must report the following information:

• Volumetric flow rate, CH4 concentration, and any CH4 destruction for each ventilation

system (minimum quarterly measurements required) and degasification system (minimum

weekly measurements required).

• For each degasification system, dates in the reporting period where active ventilation of

mining operations is taking place or when continuous monitoring equipment is not

properly functioning.

• Quarterly CH4 liberated and CH4 emitted (net) from each ventilation well or shaft, and

from each degasification system.


• Quarterly CO2 emissions from onsite destruction of coal mine CH4, where the gas is not a

fuel input for energy generation or use.

• Temperatures (°R), moisture content (%), and pressure (atm) values at the time, location,

and conditions for which measurements are made for each ventilation system (minimum

quarterly measurements required) and degasification system (minimum weekly

measurements required).

• Where CH4 is destroyed or transported for destruction, continuous monitoring is required

for volumetric flow rate, CH4 concentration, temperatures (°R) and, moisture content, and

pressure (atm) values of the gas.

APPENDIX A Tables

A-1...................................................................................... MMR Global Warming Potentials C-1.............................................................. Default CO2 Emissions Factors and Heat Values C-2.............................................................................Default CH4 and N2O Emission Factors

Mandatory Greenhouse Gas Reporting Rule

Global Warming Potential

Name CAS # Chemical FormulaGlobal Warming Potential

(100 yr.)

Carbon dioxide 124-38-9 CO2 1Methane 74-82-8 CH4 21

Nitrous oxide 10024-97-2 N2O 310HFC-23 75-46-7 CHF3 11,700HFC-32 75-10-5 CH2F2 650HFC-41 593-53-3 CH3F 150HFC-125 354-33-6 C2HF5 2,800HFC-134 359-35-3 C2H2F4 1,000HFC-134a 811-97-2 CH2FCF3 1,300HFC-143 430-66-0 C2H3F3 300HFC-143a 420-46-2 C2H3F3 3,800HFC-152 624-72-6 CH2FCH2F 53HFC-152a 75-37-6 CH3CHF2 140HFC-161 353-36-6 CH3CH2F 12

HFC-227ea 431-89-0 C3HF7 2,900HFC-236cb 677-56-5 CH2FCF2CF3 1,340HFC-236ea 431-63-0 CHF2CHFCF3 1,370HFC-236fa 690-39-1 C3H2F6 6,300HFC-245ca 679-86-7 C3H3F5 560HFC-245fa 460-73-1 CHF2CH2CF3 1,030

HFC-365mfc 406-58-6 CH3CF2CH2CF3 794HFC-43-10mee 138495-42-8 CF3CFHCFHCF2CF3 1,300Trifluoromethyl

sulphurpentafluoride373-80-8 SF5CF3 17,700

Nitrogen trifluoride 7783-54-2 NF3 17,200PFC-14 (Perfluoromethane) 75-73-0 CF4 6,500PFC-116 (Perfluoroethane) 76-16-4 C2F6 9,200PFC-218 (Perfluoropropane) 76-19-7 C3F8 7,000

Perfluorocyclopropane 931-91-9 c-C3F6 17,340PFC-3-1-10 (Perfluorobutane) 355-25-9 C4F10 7,000

Perfluorocyclobutane 115-25-3 c-C4F8 8,700PFC-4-1-12 (Perfluoropentane) 678-26-2 C5F12 7,500PFC-5-1-14 (Perfluorohexane) 355-42-0 C6F14 7400

PFC-9-1-18 306-94-5 C10F18 7500HCFE-235da2 (Isoflurane) 26675-46-7 CHF2OCHClCF3 350

HFE-43-10pccc (H-Galden1040x) E1730133 CHF2OCF2OC2F4OCHF2 1,870HFE-125 3822-68-2 CHF2OCF3 14,900HFE-134 1691-17-4 CHF2OCHF2 6,320

Table A-1

Mandatory Greenhouse Gas Reporting Rule Table A-1 Page 1 of 2

Mandatory Greenhouse Gas Reporting Rule

Global Warming Potential

Name CAS # Chemical FormulaGlobal Warming Potential

(100 yr.)

Table A-1

HFE-143a 421-14-7 CH3OCF3 756HFE-227ea 2356-62-9 CF3CHFOCF3 1,540

HFE-236ca12 (HG-10) 78522-47-1 CHF2OCF2OCHF2 2,800HFE-236ea2 (Desflurane) 57041-67-5 CHF2OCHFCF3 989

HFE-236fa 20193-67-3 CF3CH2OCF3 487HFE-245cb2 22410-44-2 CH3OCF2CF3 708HFE-245fa1 84011-15-4 CHF2CH2OCF3 286HFE-245fa2 1885-48-9 CHF2OCH2CF3 659HFE-254cb2 425-88-7 CH3OCF2CHF2 359HFE-263fb2 460-43-5 CF3CH2OCH3 11

HFE-329mcc2 67490-36-2 CF3CF2OCF2CHF2 919HFE-338mcf2 156053-88-2 CF3CF2OCH2CF3 552

HFE-338pcc13 (HG-01) 188690-78-0 CHF2OCF2CF2OCHF2 1,500HFE-347mcc3 28523-86-6 CH3OCF2CF2CF3 575HFE-347mcf2 E1730135 CF3CF2OCH2CHF2 374HFE-347pcf2 406-78-0 CHF2CF2OCH2CF3 580HFE-356mec3 382-34-3 CH3OCF2CHFCF3 101HFE-356pcc3 160620-20-2 CH3OCF2CF2CHF2 110HFE-356pcf2 E1730137 CHF2CH2OCF2CHF2 265HFE-356pcf3 35042-99-0 CHF2OCH2CF2CHF2 502HFE-365mcf3 378-16-5 CF3CF2CH2OCH3 11HFE-374pc2 512-51-6 CH3CH2OCF2CHF2 557

HFE-449sl (HFE-7100)Chemical blend

HFE-569sf2 (HFE-7200)Chemical blend

163702-05-4 163702-06-5

C4F9OC2H5 (CF3)2CFCF2OC2H5 59

Sevoflurane 28523-86-6 CH2FOCH(CF3)2 345HFE-356mm1 13171-18-1 (CF3)2CHOCH3 27HFE-338mmz1 26103-08-2 CHF2OCH(CF3)2 380

(Octafluorotetramethylene)hydroxymethyl group

NA X-(CF2)4CH(OH)-X 73

HFE-347mmy1 22052-84-2 CH3OCF(CF3)2 343Bis(trifluoromethyl)methanol 920-66-1 (CF3)2CHOH 1952,2,3,3,3pentafluoropropanol 422-05-9 CF3CF2CH2OH 42

PFPMIE NA CF3OCF(CF3)CF2OCF2OCF3 10,300

163702-07-6 163702-08-7

C4F9OCH3 (CF3)2CFCF2OCH3 297

Mandatory Greenhouse Gas Reporting Rule Table A-1 Page 2 of 2

Mandatory Greenhouse Gas Reporting RuleDefault CO2 Emission Factors and High Heat Values for Various Types of Fuel

Fuel Type Default High Heat Value Default CO2 Emission Factor

Coal and Coke MMBtu/short ton kg CO2/MMBtu Anthracite 25.09 103.54Bituminous 24.93 93.4

Subbituminous 17.25 97.02Lignite 14.21 96.36Coke 24.8 102.04

Mixed (Commercial sector) 21.39 95.26Mixed (Industrial coking) 26.28 93.65Mixed (Industrial sector) 22.35 93.91

Mixed (Electric Power sector) 19.73 94.38

Natural Gas MMBtu/scf kg CO2/MMBtu Pipeline (Weighted U.S. Average) 1.028 x 10-3 53.02

Petroleum Products MMBtu/gallon kg CO2/MMBtu Distillate Fuel Oil No. 1 0.139 73.25Distillate Fuel Oil No. 2 0.138 73.96Distillate Fuel Oil No. 4 0.146 75.04Residual Fuel Oil No. 5 0.14 72.93Residual Fuel Oil No. 6 0.15 75.1

Still Gas 0.143 66.72Kerosene 0.135 75.2

Liquefied petroleum gases (LPG) 0.092 62.98Propane 0.091 61.46

Propylene 0.091 65.95Ethane 0.096 62.64

Ethylene 0.1 67.43Isobutane 0.097 64.91

Isobutylene 0.103 67.74Butane 0.101 65.15

Butylene 0.103 67.73Naphtha (<401 deg F) 0.125 68.02

Natural Gasoline 0.11 66.83Other Oil (>401 deg F) 0.139 76.22

Pentanes Plus 0.11 70.02Petrochemical Feedstocks 0.129 70.97

Petroleum Coke 0.143 102.41Special Naphtha 0.125 72.34Unfinished Oils 0.139 74.49Heavy Gas Oils 0.148 74.92

Lubricants 0.144 74.27

Table C-1

Mandatory Greenhouse Gas Reporting Rule Table C-1 Page 1 of 2

Mandatory Greenhouse Gas Reporting RuleDefault CO2 Emission Factors and High Heat Values for Various Types of Fuel

Fuel Type Default High Heat Value Default CO2 Emission Factor

Table C-1

Petroleum Products MMBtu/gallon kg CO2/MMBtu Motor Gasoline 0.125 70.22

Aviation Gasoline 0.12 69.25Kerosene-Type Jet Fuel 0.135 72.22

Asphalt and Road Oil 0.158 75.36Crude Oil 0.138 74.49

Fossil Fuel-derived Fuels (Solid) MMBtu/shortton kg CO2/MMBtu Municipal Solid Waste1 9.95 90.7

Tires 26.87 85.97

Fossil Fuel-derived Fuels (Gaseous) MMBtu/scf kg CO2/MMBtu Blast Furnace Gas 0.092 x 10-3 274.32

Coke Oven Gas 0.599 x 10-3 46.85

Biomass Fuels - Solid MMBtu/shortTon kg CO2/MMBtu Wood and Wood Residuals 15.38 93.8Agricultural Byproducts 8.25 118.17

Peat 8 111.84Solid Byproducts 25.83 105.51

Biomass Fuels - Gaseous MMBtu/scf kg CO2/MMBtu Biogas (Captured methane) 0.841 x 10-3 52.07

Biomass Fuels - Liquid MMBtu/gallon kg CO2/MMBtu Ethanol (100%) 0.084 68.44

Biodiesel (100%) 0.128 73.84Rendered Animal Fat 0.125 71.06

Vegetable Oil 0.12 81.55


Mandatory Greenhouse Gas Reporting RuleDefault CH4 and N2O Emission Factors for Various Types of Fuel

Fuel Type Default CH4 Emission Factor

(kg CH4 /MMBtu) Default N2O Emission Factor

(kg N2O/MMBtu)

Coal and Coke (All fuel types in Table C-1)

0.011 0.0016

Natural Gas 0.0010 0.00010

Petroleum (All fuel types in Table C-1)

0.0030 0.00060

Municipal Solid Waste 0.032 0.0042

Tires 0.032 0.0042

Blast Furnace Gas 0.000022 0.00010

Coke Oven Gas 0.00048 0.00010

Biomass Fuels - Solid (All fuel types in Table C-1)

0.032 0.0042

Biogas 0.0032 0.00063

Biomass Fuels – Liquid (All fuel types in Table C-1)

0.0011 0.00011

Table C-2


GHG BASELINE AUDIT CHECKLIST

Site/Location: Calendar Year: 20__

COMPLETED N/A

Subsidiaries

Joint Venture Agreements

Contactor Agreements

Production Sharing AgreementsEmissions Sharing agreements

COMPLETED N/A

Maps Property

Building(s), Structures

P&ID

Tanks, Pipelines

Other

Permits Air Permits

Toxic Release Inventories

Part B

Other

I. ORGANIZATIONAL ACTIVITIES

Company Structure & Operations

II. OPERATIONAL ACTIVITIES

* Please state the type of control in comments

(i.e. equity share, financial or operational)

COMMENTS

COMMENTS

Page 1 of 4


COMPLETED N/AMonthly production and sample composition data

Process, Waste Streams

Raw materials consumption.Waste composition, volume

COMPLETED N/A

Electricity Purchased

Invoices

Meter Readings

Steam Purchased

Hot Water Purchased

Chilled Water Purchased

III. RAW DATA

IV. ENERGY CONSUMPTION COMMENTS

COMMENTS

Page 2 of 4


COMPLETED N/A

Stationary Source Combustion

Fuel used for water heating or cooling, and for space heatingFuel used for electric power generationFuel for process heat or process steamFuel for equipment i.e. compressors or pumps

Methane flaring

Spent oil burned in heaters

Incineration

Other

Mobile Source Emissions

Heavy Equipment

* Based on fuel use or distance traveled. Company Vehicles

Haulers, Vac Trucks

Other

Non-fuel use of fossil fuels

V. FOSSIL FUEL USAGE COMMENTS

Page 3 of 4


COMPLETED N/AHFC Leakage from air conditioning/refrigeration equipment

Fugitive Emissions Equipment leakage from seals, gaskets etc.

Gas processing facility Emissions

Gasification Emissions

Other Emissions

COMPLETED N/AFuel Storage Data

Waste water treatment data

Gas Recovery Data

Misc. Emission Sources not mentioned

VII. OTHER DATA

VI. INDUSTRIAL PROCESS COMMENTS

COMMENTS

Page 4 of 4

Data

Gathering

Decision

(Organizational vs Operational)

(Corporate vs. facility)

GHG Inventory

1605b vs. GHG Inventory

Yearly updates

Sell “Credits”

(or “Bank” for

Internal Use)

Pay “Tax”

(or Buy Credits)

Re-Evaluate and

Re-Process

ANNUALLY

Data Collection

Determined by location,

accuracy, format and

amount of data

(Oracle vs. SAP)

“All in”

Sources

§98.2(a) (1)

Report data

Electronically

to EPA

Yes No

“Threshold”

Sources

§98.2(a) (2)

>25k tons/year

Produce heat,

steam or power

from Stationary

Source

§98.2(a) (3)

Suppliers

Sources

§98.2(a) (4)

No

No

<25k tons/year

Yes

>30MM Btu/hr AND >25k tons/year

Emission

Reduction

Target

AboveBelow

FOOTPRINT

BLUEPRINT®

16 DEC 09 NONE

31 DEC 09 MB02

DATE ORIGINAL

LATEST REVISION

SCALE

JOB NO.

REVISIONS

NO. DATE DESCRIPTION

SMC SMCDRAWNCHECKED

TITLE

Protocols

Strategic Decision

Financial Decision

Due Diligence

Use of Footprint

Report Format

GHG Baseline Checklist

MM&A Report

1605b Report

Protocol Report

Monitoring,

Data

Collection &

Emission

Calculations

BAMM

Deferment

QA/QC

Monitoring

Plan

Tier 1:

Company Records

Yes

No

Tier 2:

HHV * Fuel

No

No

Yes

Tier 3:

Carbon Content

of Fuel

Tier 4:

CEMS

Yes

Re-Evaluate and

Re-Process

ANNUALLY

Carbon Capture & Storage

CCX

IRP or IMP

Public Disclosure

Due Diligence

CCX

Aggregator

Due Diligence

Public Disclosure

MRR Changes

New Sources

New RulesDeferments

Monitoring Plan

Data Collection

Designated Representative

CEMS

Tier Calculation

EPA Reporting

Begin

Here

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