2/4/2016 GHG Emissions Verification

http://www.arb.ca.gov/cc/reporting/ghg­ver/ghg­ver.htm 1/2

Verification of GHG Emissions Data Reports

This page last modified July 23, 2015

The Regulation for the Mandatory Reporting of Greenhouse Gas Emissions (reporting regulation

or MRR) requires the independent verification of greenhouse gas (GHG) emissions data reports.

Verification questions may be sent to ghgverify@arb.ca.gov. Information about the Offset Verification

Program is provided at: http://www.arb.ca.gov/cc/capandtrade/offsets/offsets.htm.

MRR Regulation

Cap­and­Trade Regulation

Background

The reporting regulation was developed under the California Global Warming Solutions Act of 2006

(Statutes of 2006; Chapter 488; Health and Safety Code sections 38500 et seq.) and approved by the

California Air Resources Board (ARB or Board) in December 2007, with subsequent amendments in

2010, 2012, 2013, and 2014. The 2014 MRR revisions became effective on January 1, 2015. The

requirements for independent verification of emissions data reports and ARB oversight of

accreditation were included in the original regulation and are consistent with international best

practices. The MRR is codified in Subchapter 10, Article 2, sections 95100 to 95158, title 17,

California Code of Regulations.

Information for Verifiers

Questions regarding ARB accreditation and verification should be sent to ghgverify@arb.ca.gov.

Application for Verifier Reaccreditation (an application must be submitted for existing accredited

verifiers)

Verification Body Application

Conflict of Interest (COI/NOVS) Form (for 2014 emissions data reported in 2015)

Verification Statement Form (for use with all reporting entities except petroleum refineries)

Petroleum Refinery Verification Statement Form (for use with petroleum refineries only)

Information for Reporting Entities

Reporting entities are required to have their GHG emissions data reports verified each year by an ARB­accredited verification body, beginning in 2010 for 2009

emissions. The third­party verification requirements and deadline are specified in section 95103(f) of the reporting regulation. Compliance dates are summarized at:

http://www.arb.ca.gov/cc/reporting/ghg­rep/ghg­rep­dates.htm.
2/4/2016 GHG Emissions Verification

http://www.arb.ca.gov/cc/reporting/ghg­ver/ghg­ver.htm 2/2

Only ARB­accredited verification bodies and verifiers may provide verification services to reporting entities. The following web link provides a list of ARBaccredited verification bodies and additional information: http://www.arb.ca.gov/cc/reporting/ghg­ver/ghg­ver­accreditation.htm.

On April 24, 2013, a webinar titled "Tips for a Successful Verification" was given to emissions data reporters. A link to the presentation is here.
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board February 2015 

LEGAL DISCLAIMER & USER’S NOTICE 

Unofficial electronic version of the 

Regulation for the Mandatory Reporting of 

Greenhouse Gas Emissions 

Unofficial Electronic Version 

This unofficial electronic version of the Regulation for the Mandatory Reporting of 

Greenhouse Gas Emissions following this Disclaimer was produced by California Air 

Resources Board (ARB) staff for the reader’s convenience. ARB staff has removed the 

underline-strikeout formatting which exists in the Final Regulation Order approved by 

the Office of Administrative Law (OAL) on December 31, 2014 and included the full 

regulatory text for the regulation; however, the following version is not an official legal 

edition of title 17, California Code of Regulations (CCR), sections 95100-95158. While 

reasonable steps have been taken to make this unofficial version accurate, the officially 

published CCR takes precedence if there are any discrepancies. 

Official Legal Edition 

The official legal edition of title 17, CCR, sections 95100-95158 is available at the OAL 

website: http://www.oal.ca.gov/CCR.htm. To access relevant provisions online, click on 

the following path items from the OAL site: 

 “Online” link (http://ccr.oal.ca.gov/linkedslice/default.asp?SP=CCR1000&Action=Welcome) 

 “List of CCR Titles” 

“Title 17. Public Health” 

 “Division 3. Air Resources” 

 “Chapter 1. Air Resources Board” 

 “Subchapter 10. Climate Change” 

 “Article 2. Mandatory Greenhouse Gas 

Emissions Reporting” 

 then choose the relevant subarticle(s) 

and section(s). 

For ease of reviewing, once you have selected a section, scroll to the bottom left-hand 

corner of the page and click on “Docs in Sequence.” This will enable easy switching 

from one section to the next. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board February 2015 

Page Intentionally Blank 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board i February 2015 

Subchapter 10. Climate Change 

REGULATION FOR THE MANDATORY REPORTING OF 

GREENHOUSE GAS EMISSIONS 

This table of contents is not part of the official published regulation, 

and is provided for convenience only. 

TABLE OF CONTENTS 

Subarticle 1. General Requirements for Greenhouse Gas Reporting ...................1 

95100 Purpose and Scope .........................................................................1 

95101 Applicability ......................................................................................2 

95102 Definitions ........................................................................................9 

 91502(a) – General Definitions ........................................................9 

 95102(b) – Product Data Definitions .............................................. 60 

 95102(c) – Refining and Related Process Definitions .................... 69 

95103 Greenhouse Gas Reporting Requirements .................................... 76 

95104 Emissions Data Report Contents and Mechanism ......................... 88 

95105 Record Keeping Requirements ...................................................... 90 

95106 Confidentiality ................................................................................ 93 

95107 Enforcement .................................................................................. 93 

95108 Severability .................................................................................... 94 

95109 Standardized Methods ................................................................... 94 

Subarticle 2. Requirements for the Mandatory Reporting of 

Greenhouse Gas Emissions from Specific Types of 

Facilities, Suppliers, and Entities ................................................... 95 

95110 Cement Production ........................................................................ 95 

95111 Data Requirements and Calculation Methods for 

Electric Power Entities .................................................................. 97 

95112 Electricity Generation and Cogeneration Units ............................ 112 

95113 Petroleum Refineries ................................................................. 120 

95114 Hydrogen Production .................................................................. 129 

95115 Stationary Fuel Combustion Sources ......................................... 132 

95116 Glass Production ......................................................................... 139 

95117 Lime Manufacturing ..................................................................... 140 

95118 Nitric Acid Production .................................................................. 142 

95119 Pulp and Paper Manufacturing .................................................. 143 

95120 Iron and Steel Production ............................................................ 144 

95121 Suppliers of Transportation Fuels ................................................ 146 

95122 Suppliers of Natural Gas, Natural Gas Liquids, and 

Liquefied Petroleum Gas ............................................................. 151 

95123 Suppliers of Carbon Dioxide ........................................................ 157 

95124 Lead Production ........................................................................... 158 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board ii February 2015 

Subarticle 3. Additional Requirements for Reported Data ................................ 160 

95129 Substitution for Missing Data Used to Calculate Emissions 

from Stationary Combustion and CEMS Sources ........................ 160 

Subarticle 4. Requirements for Verification of Greenhouse Gas Emissions Data 

Reports; Requirements Applicable to Emissions Data Verifiers; 

Requirements for Accreditation of Emissions Data and 

Offset Project Data Report Verifiers ............................................. 171 

95130 Requirements for Verification of Emissions Data Reports ........... 171 

95131 Requirements for Verification Services ....................................... 172 

95132 Accreditation Requirements for Verification Bodies, 

Lead Verifiers, and Verifiers of Emissions Data Reports 

and Offset Project Data Reports .................................................. 189 

95133 Conflict of Interest Requirements for Verification Bodies ............ 194 

Subarticle 5. Reporting Requirements and Calculation Methods for 

Petroleum and Natural Gas Systems ........................................... 202 

95150 Definition of the Source Category ............................................... 202 

95151 Reporting Threshold .................................................................... 204 

95152 Greenhouse Gases to Report ...................................................... 204 

95153 Calculating GHG Emissions ......................................................... 208 

95154 Monitoring and QA/QC Requirements ......................................... 240 

95155 Procedures for Estimating Missing Data ...................................... 243 

95156 Additional Data Reporting Requirements ..................................... 244 

95157 Activity Data Reporting Requirements ......................................... 247 

95158 Records that Must be Retained ................................................... 257 

Appendix A Emission Factors and Calculation Data for Petroleum 

and Natural Gas Systems Reporting ........................................... A-1 

Appendix B TEST PROCEDURE: Flash Emissions of Greenhouse Gases 

and Other Compounds from Crude Oil and Natural Gas 

Separator and Tank Systems ...................................................... B-1 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 1 February 2015 

Amend Division 3, Chapter 1, Subchapter 10, Article 2, sections 95101, 95102, 95103, 

95104, 95111, 95112, 95113, 95114, 95115, 95119, 95121, 95122, 95124, 95130, 

95131, 95132, 95133, 95152, 95153, 95156, 95157, and Appendix A, title 17 California 

Code of Regulations to read as follows:

Article 2: Mandatory Greenhouse Gas Emissions Reporting 

Subarticle 1. General Requirements for Greenhouse Gas Reporting 

§ 95100. Purpose and Scope. 

(a) The purpose of this article is to establish mandatory greenhouse gas (GHG) 

reporting, verification, and other requirements for operators of certain facilities that 

directly emit GHGs, suppliers of certain fuels and carbon dioxide, electric power 

entities, verifiers of GHG emissions data reports and offset project data reports 

submitted pursuant to the cap-and-trade regulation, and verification bodies. This 

article is designed to meet the requirements of section 38530 of the Health and 

Safety Code, and to support GHG emissions inventory and regulatory programs of 

the California Air Resources Board. 

(b) Organization of this Article. Subarticle 1 specifies general requirements for the 

reporting of GHG emissions that apply to all reporting entities listed in section 

95101. Subarticle 2 specifies reporting requirements and calculation methods for 

specific types of facilities and entities. Subarticle 3 specifies additional 

requirements for reported data, including procedures for the substitution for missing 

data. Subarticle 4 specifies verification requirements for GHG emissions data 

reports, requirements for those who provide verification services for GHG reporting 

entities, and accreditation requirements for verifiers of emissions data reports and 

offset project data reports. Subarticle 5 specifies reporting requirements and 

calculation methods for petroleum and natural gas production, processing, and 

storage facilities. 

(c) U.S. EPA GHG Reporting Rule. This article incorporates various provisions of title 

40, Code of Federal Regulations (CFR), Part 98. These provisions are a portion of 

the U.S. Environmental Protection Agency (U.S. EPA) Final Rule on Mandatory 

Reporting of Greenhouse Gases. Unless otherwise specified, references in this 

article to 40 CFR Part 98 are to those requirements promulgated by U.S. EPA and 

published in the Federal Register on October 30, 2009, July 12, 2010, September 

22, 2010, October 28, 2010, November 30, 2010, December 17, 2010, and April 25, 

2011. 

(d) Except as otherwise specifically provided: 

(1) Wherever the term “Administrator” is used in the federal rules referred to in 

this article, the term “Executive Officer of the California Air Resources Board” 

or “Executive Officer” shall be substituted. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 2 February 2015 

(2) Wherever the term “EPA” is used in the federal rules referred to in this article, 

the term “California Air Resources Board” or “ARB” shall be substituted. 

(3) In cases where the owner and operator of a facility or a supplier are not the 

same party, the operator is responsible for compliance with this article. 

(4) For purposes of reporting GHG emissions in California, reporting entities must 

follow the requirements of this article where any incorporated provisions of 40 

CFR Part 98 or Part 75 appear in conflict with it. 

NOTE: Authority cited: Sections 38510, 38530, 39600, 39601 and 41511, Health and 

Safety Code. Reference: Sections 38530, 39600 and 41511, Health and Safety Code. 

§ 95101. Applicability. 

(a) General Applicability.

(1) This article applies to the following entities:

(A) Operators of facilities located in California with source categories listed 

below are subject to this article regardless of emissions level: 

1. Electricity generation units that report CO2 mass emissions year 

round through 40 CFR Part 75; 

2. Cement production; 

3. Lime manufacturing; 

4. Nitric acid production; 

5. Petroleum refineries; 

6. Geologic sequestration of carbon dioxide; 

7. Injection of carbon dioxide. 

(B) Operators of facilities located in California with source categories listed 

below, are subject to this article when stationary combustion and process 

emissions of CO2, CH4, and N2O equal or exceed 10,000 metric tons 

CO2e for a calendar year: 

1. Stationary fuel combustion, which includes electricity generating units 

not subject to 40 CFR Part 75; 

2. Glass production; 

3. Hydrogen production; 

4. Iron and steel production; 

5. Pulp and paper manufacturing; 

6. Petroleum and natural gas systems; 

7. Geothermal electricity generation; 

8. Lead production; 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 3 February 2015 

(C) Suppliers of fuels provided for consumption within California that are 

specified below in paragraph (c); 

(D) Carbon dioxide suppliers as specified below in paragraph (c), including 

CO2 producers regardless of quantity produced, and CO2 importers and 

exporters when bulk imports or exports equal or exceed 10,000 metric 

tons for 2011 or a later calendar year; 

(E) Electric power entities as specified below in paragraph (d); and, 

(F) Operators of petroleum and natural gas systems as specified below in 

paragraph (e). 

(G) Any California reporting entity subject to subparts E, F, G, I, K, L, O, R, T, 

U, X, Z, BB, CC, EE, FF, GG, II, LL, OO, QQ, SS, or TT of 40 CFR 

Part 98 that emits over 10,000 metric tons of CO2e resulting from CO2, 

N2O, or CH4 emissions. If a reporting entity utilizes the above industrial 

processes and emits over 10,000 metric tons of CO2e resulting from CO2, 

N2O, or CH4 emissions, they must notify the Executive Officer within 90 

days of the effective date of this regulation or within 90 days of 

commencing the industrial process. This notification requirement also 

applies to facility operators subject to section 95103(a), for abbreviated 

reporting. 

(2) Any reporting entity in one or more of the categories in subsection (a)(1) 

above must submit an annual emissions data report, except as provided in the 

cessation provisions of subsections (h) and (i) of this section. The emissions 

data report must cover all source categories and GHGs for which calculation 

methods are provided or referenced in this article for the reporting entity. 

Except as otherwise specified in this article, the report must be compiled using 

the methods specified by source category in 40 CFR Part 98. 

(3) If a facility operator determines their reporting applicability and responsibility 

on the basis of common ownership, the basis of reporting applicability and 

responsibility can only be changed to common control at the beginning of a 

compliance period. If a facility operator determines their reporting applicability 

and responsibility on the basis of common control, the basis of reporting 

applicability and responsibility can only be changed to common ownership at 

the beginning of a compliance period. These provisions do not apply if there is 

a legal change in facility ownership. If there is a change in facility ownership, 

the provisions of section 95103(n) apply. 

(4) Verifiers and Verification Bodies. In addition to the reporting entities specified 

in subsection (a)(1) above, this article contains requirements for entities acting 

as verification bodies and individuals acting as third party verifiers of 

emissions data reports and offset project data reports. These requirements 

are specified in sections 95130 through 95133 of this article. 

(b) Calculating GHG Emissions Relative to Thresholds. For facilities for which an 

emissions-based applicability threshold is specified in section 95101(a)(1), the 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 4 February 2015 

operator must calculate emissions for comparison to applicable thresholds as 

specified below: 

(1) For the purpose of computing emissions relative to the 25,000 metric ton CO2e 

threshold specified in section 95812 of the cap-and-trade regulation, operators 

must include all covered emissions of CO2, CH4, and N2O. 

(2) For the purpose of computing emissions relative to the 10,000 metric ton CO2e 

threshold for reporting applicability specified in section 95101(a), operators 

must include emissions of CO2, CH4 and N2O from stationary combustion 

sources and process emissions, but may exclude any vented and fugitive 

emissions from the estimate. However, if all the CO2, CH4, and N2O emissions 

captured within the reporting entity’s facility boundary, including vented and 

fugitive emissions, exceed the 25,000 metric ton CO2e threshold specified in 

sections 95103(a) and 95103(f), the reporting entity is not eligible for the 

abbreviated reporting option provided in section 95103(a) and must submit an 

emissions data report pursuant to the full requirements of this Article, including 

obtaining verification services pursuant to section 95103(f). 

(3) Facilities with only stationary combustion emissions are subject to reporting 

according to the requirements of 40 CFR §98.2(a)(3), except that the 

thresholds for reporting in California are 10,000 metric tons of CO2e and an 

aggregate maximum heat input capacity of 12 MMBtu/hr or greater. 

(4) Notwithstanding 40 CFR §98.2(b)(2), operators of facilities and suppliers must 

include emissions of CO2 from the combustion of biomass and other biofuels 

when determining applicability relative to thresholds for emissions reporting 

and cessation of reporting. 

(5) Operators of geothermal generating units must report when total facility 

emissions of CO2 and CH4 equal or exceed 10,000 metric tons of CO2e. 

(6) Operators of a hydrogen fuel cell unit must include emissions from the 

hydrogen fuel cell unit in calculating emissions for comparison to applicability 

thresholds. 

(c) Fuel and Carbon Dioxide Suppliers. The suppliers listed below, as defined in 

section 95102(a), are required to report under this article when they produce, import 

and/or deliver an annual quantity of fuel that, if completely combusted, oxidized, or 

used in other processes, would result in the release of greater than or equal to 

10,000 metric tons of CO2e in California, unless otherwise specified in this article:

(1) Position holders at terminals and refiners delivering petroleum fuels and/or 

biomass-derived fuels, as described in section 95121; 

(2) Enterers that import transportation fuels outside the bulk transfer/terminal 

system, as described in section 95121, and biofuel production facilities that 

produce and deliver transportation fuels outside the bulk/terminal system, as 

described in section 95121; 

(3) All refiners that produce liquefied petroleum gas, without regard to quantities, 

as described in section 95121; 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 5 February 2015 

(4) Operators of interstate pipelines delivering natural gas, as described in section 

95122; 

(5) California consignees of imported liquefied petroleum gas, compressed natural 

gas, or liquefied natural gas, as described in section 95122; 

(6) Local distribution companies who are public utility gas corporations or publiclyowned natural gas utilities delivering natural gas, as described in section 

95122; 

(7) Operators of intrastate pipelines delivering natural gas as described in section 

95122; 

(8) All natural gas liquid fractionators, without regard to quantities produced, as 

described in section 95122; 

(9) All producers of carbon dioxide without regard to quantity produced, and 

importers and exporters of carbon dioxide with annual bulk imports into or 

exports from California of 10,000 metric tons or more, as described in section 

95123. 

(10) Operators of liquefied natural gas production facilities that produce liquefied 

natural gas products from natural gas received from interstate pipelines, as 

described in section 95122; 

(d) Electric Power Entities. The entities listed below are required to report under this 

article:

(1) Electricity importers and exporters, as defined in section 95102(a); 

(2) Retail providers, including multi-jurisdictional retail providers, as defined in 

section 95102(a); 

(3) California Department of Water Resources (DWR);

(4) Western Area Power Administration (WAPA); 

(5) Bonneville Power Administration (BPA). 

(e) Petroleum and Natural Gas Systems. The facility types listed below, as further 

specified in section 95150, are required to report under this article when their 

stationary combustion and process emissions equal or exceed 10,000 metric tons 

of CO2e, or their stationary combustion, process, fugitive, and vented emissions 

equal or exceed 25,000 metric tons of CO2e. 

(1) Offshore petroleum and natural gas production facilities; 

(2) Onshore petroleum and natural gas production facilities; 

(3) Onshore natural gas processing plants; 

(4) Onshore natural gas transmission compression facilities; 

(5) Underground natural gas storage facilities; 

(6) Liquefied natural gas storage facilities; 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 6 February 2015 

(7) Liquefied natural gas import and export facilities; 

(8) Natural gas distribution facilities. 

(f) Exclusions. This article does not apply to, and greenhouse gas emissions reporting 

is not required for:

(1) Electricity generating facilities that are solely powered by nuclear, 

hydroelectric, wind, or solar energy, unless on-site stationary combustion 

emissions equal or exceed 10,000 metric tons of CO2e; 

(2) Generating units designated as backup or emergency generators in a permit 

issued by an air pollution control district or air quality management district; 

(3) Fire suppression systems and equipment; 

(4) Portable equipment, except where specifically required to report under 40 CFR 

Part 98 or this article; 

(5) Primary and secondary schools with a NAICS code of 611110; 

(6) Fugitive methane emissions from municipal solid waste landfills described in 

40 CFR Part 98, Subpart HH; 

(7) Fugitive methane and fugitive nitrous oxide emissions from livestock manure 

management systems described in 40 CFR Part 98, Subpart JJ, regardless of 

the magnitude of emissions produced; 

(8) Agricultural irrigation pumps. 

(g) Demonstration of Nonapplicability. The Executive Officer may request a 

demonstration from any operator, supplier, or entity that the operator, supplier, or 

entity does not meet one or more of the applicability criteria specified in this article. 

Such demonstration must be provided to the Executive Officer within 20 days of 

receipt of a written request.

(h) Cessation of Reporting. A facility operator or supplier who is not subject to the capand-trade regulation, whose emissions fall below the applicable emissions reporting 

thresholds of this article and who wishes to cease annual reporting must comply 

with the requirements specified in section 95101(h). A reporting entity that is 

subject to the cap-and-trade regulation must follow the requirements in section 

95812 and continue to comply with all reporting requirements until there is no longer 

a compliance obligation. If the compliance obligation ceases, the reporting entity 

must still follow the requirements in section 95101(h) before ceasing to comply with 

the reporting requirements of this article. The operator or supplier must provide the 

letter notifications specified below to the address indicated in section 95103 of this 

article. 

(1) For facilities with source categories in section 95101(a)(1)(A) that are subject 

to the requirements of this article regardless of emissions level, cessation of 

reporting provisions in section 95101(h)(1) apply, but the 2011 data year is the 

earliest year that criteria for cessation can be applied. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 7 February 2015 

 If reported emissions are less than 10,000 metric tons of CO2e per year for 

three consecutive years, then the owner, operator, or supplier may discontinue 

complying with this article provided that the owner, operator, or supplier 

submits a notification to ARB that announces the cessation of reporting and 

explains the reasons for the reduction in emissions. The notification must be 

submitted no later than March 31 of the year immediately following the third 

consecutive year in which emissions are less than 10,000 metric tons of CO2e 

per year. The owner, operator, or supplier must maintain the corresponding 

records required under section 95103 for each of the three consecutive years 

and retain such records for five years following the year that reporting was 

discontinued. The owner, operator, or supplier must resume reporting if 

annual emissions in any future calendar year increase to 10,000 metric tons of 

CO2e per year or more. 

(2) If the operations of a facility or supplier are changed such that all applicable 

GHG-emitting processes and operations listed in paragraph (a)(1) of this 

section cease to operate or are permanently shut down, the owner, operator, 

or supplier must submit an emissions data report for the year in which a facility 

or supplier’s GHG-emitting processes and operations ceased to operate, and 

for the first full year of non-operation that follows. The owner, operator, or 

supplier must submit a notification to ARB that announces the cessation of 

reporting and certifies to the closure of all GHG-emitting processes and 

operations no later than March 31 of the year following such changes. 

Paragraph 95101(h)(2) does not apply to seasonal or other temporary 

cessation of operations. The owner, operator, or supplier must resume 

reporting for any future calendar year during which any of the GHG-emitting 

processes or operations resume operation and are subject to reporting 

pursuant to section 95101(a)(1). 

(3) Electric power entities must comply with the following requirements for 

cessation of reporting: 

(A) Electric power entities that import or export electricity in 2011 or 2012 

must continue to submit and certify an emissions data report through the 

2014 data year. If an electric power entity has zero imports or exports, it 

must indicate as such in its emissions data report. 

(B) Electric power entities that import or export electricity in any year of a 

subsequent compliance period must continue to submit and certify an 

emissions data report through the end of the same compliance period. If 

an electric power entity has zero imports or exports, it must indicate as 

such in its emissions data report. 

(C) Electric power entities no longer importing or exporting electricity at the 

beginning of a subsequent compliance period are not required to submit, 

and certify an emissions data report demonstrating that they have no 

imports or exports pursuant to this article, but must notify the Executive 

Officer in writing of the reason(s) for cessation of reporting. The 

notification must be submitted no later than March 31 of the year 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 8 February 2015 

following the last year that the electric power entity is required to submit 

an emissions data report. 

(D) Electric power entities who meet the definition of “retail provider” must 

always report retail sales for each calendar year. WAPA and DWR must 

always report pump loads for each calendar year. 

(i) Cessation of Verification. A facility operator, supplier, or electric power entity who 

wishes to cease annual verification must comply with the requirements specified in 

section 95101(i) and notify ARB by the applicable reporting deadline if the reporting 

entity has met the cessation criteria and intends to no longer obtain verification 

services. A reporting entity that is subject to the cap-and-trade regulation must 

follow the requirements in section 95812 and continue to comply with all verification 

requirements until there is no longer a compliance obligation. If the compliance 

obligation ceases, the reporting entity must still follow the requirements in section 

95101(i) before ceasing to comply with the verification requirements of this Article. 

(1) If the operations of a facility or supplier are changed such that all applicable 

GHG-emitting processes and operations listed in paragraph 95101(a)(1) of this 

section cease to operate or are permanently shut down, the owner, operator, or 

supplier must continue to obtain the services of an accredited verification body 

for purposes of verifying the emissions data report for the year in which the 

facility or supplier’s GHG-emitting processes and operations ceased to operate. 

Verification is not required for the emissions data report of the first full year of 

non-operation that follows. 

(2) If the operations of an electric power entity are changed such that the entity 

ceases to import and export electricity, the electric power entity must continue to 

obtain the services of an accredited verification body for purposes of verifying 

the emissions data report for the year in which the imports and exports ceased. 

Verification is not required for the emissions data report of the first full year of 

non-operation that follows. 

(3) A facility operator or supplier whose emissions decrease to less than 25,000 

metric tons of CO2e, including CO2 from biomass-derived fuels and geothermal 

sources, must continue to obtain the services of an accredited verification body 

for purposes of verifying the emissions data report for the first year in which the 

facility or supplier’s emissions are less than 25,000 metric tons of CO2e. 

NOTE: Authority cited: Sections 38510, 38530, 39600, 39601, 39607, 39607.4 and 

41511, Health and Safety Code. Reference: Sections 38530, 39600 and 41511, Health 

and Safety Code. 

 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 9 February 2015 

§ 95102. Definitions. 

(a) For the purposes of this article, the definitions in subsections (a), (b), and (c) shall 

apply. Subsection (b) is specific to product data definitions. Subsection (c) is 

specific to definitions regarding refining and related processes. 

(1) “Absorbent circulation pump” means a pump commonly powered by natural 

gas pressure that circulates the absorbent liquid between the absorbent 

regenerator and natural gas contactor. 

(2) “Accuracy” means the closeness of the agreement between the result of the 

measurement and the true value of the particular quantity (or a reference 

value determined empirically using internationally accepted and traceable 

calibration materials and standard methods), taking into account both random 

and systematic factors. 

(3) “Acid gas” means hydrogen sulfide (H2S) and/or carbon dioxide (CO2) 

contaminants that are separated from sour natural gas by an acid gas 

removal. 

(4) “Acid gas removal unit (AGR)” means a process unit that separates hydrogen 

sulfide and/or carbon dioxide from sour natural gas using liquid or solid 

absorbents or membrane separators. 

(5) “Acid gas removal vent stack emissions” mean the acid gas separated from 

the acid gas absorbing medium (e.g., an amine solution) and released with 

methane and other light hydrocarbons to the atmosphere or a flare. 

(6) “Adverse emissions data verification statement” means a verification 

statement rendered by a verification body attesting that the verification body 

cannot say with reasonable assurance that the submitted emissions data 

report is free of material misstatement, or that the emissions data submitted in 

the emissions data report contains correctable errors as defined pursuant to 

this section and thus is not in conformance with the requirement to fix such 

errors pursuant to section 95131(b)(9), or both. 

(7) “Adverse product data verification statement” means a verification statement 

rendered by a verification body attesting that the verification body cannot say 

with reasonable assurance that the submitted emissions data report is free of 

material misstatement, or that the covered product data submitted in the 

emissions data report contains correctable errors as defined pursuant to this 

section and thus is not in conformance with the requirements to fix such 

errors pursuant to section 95131(b)(9), or both. 

(8) “Adverse verification statement” means a verification statement rendered by a 

verification body attesting that the verification body cannot say with 

reasonable assurance that the submitted emissions data report is free of 

material misstatement, or that the emissions or covered product data 

submitted in the emissions data report contains correctable errors as defined 

pursuant to this section and thus is not in conformance with the requirements 

to fix such errors pursuant to section 95131(b)(9), or both. This definition 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 10 February 2015 

applies to the adverse emissions data verification statement and the adverse 

product data verification statement. 

(9) “Agricultural waste” means waste produced on land used for horticulture, fruit 

growing, seed growing, dairy farming, livestock breeding and keeping, or 

grazing land, meadow land, osier land (growing willow ), market gardens and 

nursery grounds as a result of agricultural activity. 

(10) “Air injected flare” means a flare in which air is blown into the base of a flare 

stack to induce complete combustion of gas. 

(11) “Annual” means with a frequency of once a year; unless otherwise noted, 

annual events such as reporting requirements will be based on the calendar 

year. 

(12) “API” means the American Petroleum Institute. 

(13) "API Gravity" means a scale used to reflect the specific gravity (SG) of a fluid 

such as crude oil, water, or natural gas. The API gravity is calculated as 

[(141.5/SG) - 131.5], where SG is the specific gravity of the fluid at 60°F, and 

where API refers to the American Petroleum Institute. 

(14) “AQMD/APCD” or “air district” or “air quality management district” or “air 

pollution control district” means any district created or continued in existence 

pursuant to the provisions of Part 3 (commencing with Section 40000) of 

Division 26 of the Health and Safety Code. 

(15) “ARB” means the California Air Resources Board. 

(16) “ARB ID” means, for the purposes of this article, the unique identification 

number assigned to each facility, supplier, and electric power entity that 

reports GHG emissions to the ARB. 

(17) “ARB offset credit” is as defined in the cap-and-trade regulation. 

(18) “Artificial island” is a plot of land or other structure constructed on a body of 

water to support onshore petroleum or natural gas production. 

(19) “Asphalt” means a dark brown-to-black cement-like material obtained by 

petroleum processing and containing bitumens as the predominant 

component. It includes crude asphalt as well as the following finished 

products: cements, fluxes, the asphalt content of emulsions (exclusive of 

water), and petroleum distillates blended with asphalt to make cutback 

asphalts. 

(20) “Asset-controlling supplier” means any entity that owns or operates interconnected electricity generating facilities or serves as an exclusive marketer 

for these facilities even though it does not own them, and is assigned a 

supplier-specific identification number and system emission factor by ARB for 

the wholesale electricity procured from its system and imported into 

California. Asset controlling suppliers are considered specified sources. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 11 February 2015 

(21) "Assigned emissions level” means an amount of emissions, in CO2e, 

assigned to the reporting entity by the Executive Officer under the 

requirements of section 95103(g). 

(22) “Associated gas” or “produced gas” means a natural gas that is produced in 

association with the production of crude oil. 

(23) “ASTM” means the American Society of Testing and Materials. 

(24) “Authorized project designee” means an entity authorized by an Offset Project 

Operator to act on behalf of the Offset Project Operator. 

(25) “Aviation gasoline” means a complex mixture of volatile hydrocarbons, with or 

without additives, suitably blended to be used in aviation reciprocating 

engines. Specifications can be found in ASTM Specification D910–07a, 

“Standard Specification for Aviation Gasolines” (2007). 

(26) “Balancing authority” means the responsible entity that integrates resource 

plans ahead of time, maintains load-interchange-generation balance within a 

balancing authority area, and supports interconnection frequency in real time. 

(27) “Balancing authority area” means the collection of generation, transmission, 

and loads within the metered boundaries of a balancing authority. A 

balancing authority maintains load-resource balance within this area. 

(28) “Barrel” means a volume equal to 42 U.S. gallons. 

(29) “Basin” means geological provinces as defined by the American Association 

of Petroleum Geologists (AAPG) Geologic Note: AAPG-CSD Geological 

Provinces Code Map: AAPG Bulletin, Prepared by Richard F. Meyer, Laurie 

G. Wallace, and Fred J. Wagner, Jr., Volume 75, Number 10 (October 1991), 

which is hereby incorporated by reference. 

(30) "Best available data and methods" means ARB methods for emissions 

calculations set forth in this article where reasonably feasible, or facility fuel 

use and other facility process data used in conjunction with ARB-provided 

emission factors and other data, or other industry standard methods for 

calculating greenhouse gas emissions. 

(31) “Bias” means systematic error, resulting in measurements that will be either 

consistently low or high relative to the reference value. 

(32) “Bigeneration unit” means a unit that simultaneously generates electricity and 

useful thermal energy from the same fuel source but without waste heat 

recovery. An example of bigeneration includes a boiler generating steam that 

is split into two streams, and one stream powers a steam turbine to generate 

electricity, while the other stream is used for other industrial, commercial, 

heating and cooling purposes that are not in support of or a part of the 

electricity generation system. 

(33) “Biodiesel” means a diesel fuel substitute produced from nonpetroleum 

renewable resources that meet the registration requirements for fuels and fuel 

additives established by the U.S. Environmental Protection Agency under 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 12 February 2015 

section 211 of the Clean Air Act. It includes biodiesel that is all of the 

following: 

(A) Registered as a motor vehicle fuel or fuel additive under 

40 CFR Part 79; 

(B) A mono-alkyl ester; 

(C) Meets American Society for Testing and Material designation ASTM D 

6751-08 “Standard Specification for Biodiesel Fuel Blendstock (B100) 

for Middle Distillate Fuels” (2008), which is hereby incorporated by 

reference; 

(D) Intended for use in engines that are designated to run on conventional 

diesel fuel; and 

(E) Derived from nonpetroleum renewable resources. 

 (34) “Biofuel production facility” means a production facility that produces one or 

more of the following biomass-derived transportation fuels: ethanol, biodiesel, 

renewable diesel, rendered animal fat, or vegetable oil. 

(35) “Biogas” means gas that is produced from the breakdown of organic material 

in the absence of oxygen. Biogas is produced in processes including 

anaerobic digestion, anaerobic decomposition, and thermochemical 

decomposition. These processes are applied to biodegradable biomass 

materials, such as manure, sewage, municipal solid waste, green waste, and 

waste from energy crops, to produce landfill gas, digester gas, and other 

forms of biogas. 

(36) “Biogenic portions of CO2 emissions” means carbon dioxide emissions 

generated as the result of biomass combustion from combustion units. 

(37) “Biomass” means non-fossilized and biodegradable organic material 

originating from plants, animals and micro-organisms, including products, 

byproducts, residues and waste from agriculture, forestry and related 

industries as well as the non-fossilized and biodegradable organic fractions of 

industrial and municipal wastes, including gases and liquids recovered from 

the decomposition of non-fossilized and biodegradable organic material. For 

the purpose of this article, biomass includes both California Renewable 

Portfolio Standard (RPS) eligible and non-eligible biomass as defined by the 

California Energy Commission. 

(38) “Biomass-derived fuels” or “biomass fuels” or “biofuels” or “biomass-based 

fuels” means fuels derived from biomass. 

(39) “Biomethane” means biogas that meets pipeline quality natural gas 

standards. 

(40) “Blendstocks” are petroleum products used for blending or compounding into 

finished motor gasoline. These include RBOB (reformulated blendstock for 

oxygenate blending) and CBOB (conventional blendstock for oxygenate 

blending), but exclude oxygenates, butane, and pentanes plus. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 13 February 2015 

(41) “Blowdown” means the act of emptying or depressurizing a vessel. This may 

also refer to the discarded material such as blowdown water from a boiler or 

cooling tower. 

(42) “Blowdown vent stack emissions” mean natural gas and/or CO2 released due 

to maintenance and/or blowdown operations including compressor blowdown 

and emergency shut-down (ESD) system testing. 

(43) “Boiler” means a closed vessel or arrangement of vessels and tubes, together 

with a furnace or other heat source, in which water is heated to produce hot 

water or steam. 

(44) “Bone dry short ton” means an amount of material that weighs 2,000 pounds 

at zero percent moisture content. 

(45) “Bottom ash” means ash that collects at the bottom of a combustion chamber. 

(46) “Bottoming cycle” means a type of cogeneration system in which the energy 

input to the system is first applied to a useful thermal energy application or 

process, and at least some of the reject heat emerging from the application or 

process is then used for electricity production. 

(47) “British thermal unit” or “Btu” means the quantity of heat required to raise the 

temperature of one pound of water by one degree Fahrenheit at about 39.2 

degrees Fahrenheit. 

(48) “BTEX” means gaseous compounds of benzene, toluene, ethyl benzene, and 

xylenes. 

(49) “Bulk transfer/terminal system” means a fuel distribution system consisting of 

refineries, pipelines, vessels, and terminals. Fuel storage and blending 

facilities that are not fed by pipeline or vessel are considered outside the bulk 

transfer system. 

(50) “Busbar” means a power conduit of a facility with electricity generating units 

that serves as the starting point for the electricity transmission system. 

(51) “Business-as-usual scenario” means the set of conditions reasonably 

expected to occur within the offset project boundary in the absence of the 

financial incentives provided by offset credits, taking into account all current 

laws and regulations, as well as current economic and technological trends. 

(52) “Butane” or “n-Butane” is a paraffinic straight-chain hydrocarbon with 

molecular formula C4H10. 

(53) “Butylene” or “n-Butylene” means an olefinic straight-chain hydrocarbon with 

molecular formula C4H8. 

(54) “Bypass dust” means discarded dust from the bypass system dedusting unit 

of suspension preheater, precalciner and grate preheater kilns, consisting of 

fully calcined kiln feed material. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 14 February 2015 

(55) “Calcination” means the thermal decomposition of carbonate minerals, such 

as calcium carbonate (the principal mineral in limestone) to form calcium 

oxide in a cement kiln. 

(56) “Calcine” means to heat a substance so that it oxidizes or reduces. 

(57) “Calendar year” means the time period from January 1 through December 31. 

(58) “Calibrated bag” means a flexible, non-elastic, anti-static bag of a calibrated 

volume that can be affixed to an emitting source such that the emissions 

inflate the bag to its calibrated volume. 

(59) “California balancing authority” means a balancing authority with control over 

a balancing authority area primarily located in the State of California. A 

California balancing authority is responsible for the operation of the 

transmission grid within its metered boundaries which may extend beyond the 

geographical boundaries of the State of California.

(60) “California Climate Action Registry” or “CCAR” means the entity established 

pursuant to former Health and Safety Code Section 42800 et seq. 

(61) “California consignee” means the person or entity in California to whom the 

shipment is to be delivered. 

(62) “California Energy Commission” or “CEC” means the California Energy 

Resources Conservation and Development Commission. 

(63) “California Reformulated Gasoline Blendstock for Oxygenate Blending” or 

“CARBOB” has the same meaning as defined in title 13 of the California Code 

of Regulations, section 2260(a). 

(64) “Cap-and-trade regulation” or “cap-and-trade program” means ARB’s 

regulation establishing the California Cap on Greenhouse Gas Emissions and 

Market-Based Compliance Mechanisms set forth in title 17, California Code of 

Regulations, Chapter 1, Subchapter 10, article 5 (commencing with section 

95800). 

(65) “Carbon dioxide” or “CO2” means the most common of the six primary 

greenhouse gases, consisting on a molecular level of a single carbon atom 

and two oxygen atoms. 

(66) “Carbon dioxide equivalent” or “CO2 equivalent” or “CO2e” means the number 

of metric tons of CO2 emissions with the same global warming potential as 

one metric ton of another greenhouse gas. For the purposes of this article, 

global warming potential values listed in Table A-1 of 40 CFR Part 98 are 

used to determine the CO2 equivalent of emissions. 

(67) “Carbon dioxide supplier” means: (a) facilities with production process units 

located in the State of California that capture a CO2 stream for purposes of 

supplying CO2 for commercial applications or that capture the CO2 stream in 

order to utilize it for geologic sequestration where capture refers to the initial 

separation and removal of CO2 from a manufacturing process or any other 

process, (b) facilities with CO2 production wells located in the State of 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 15 February 2015 

California that extract or produce a CO2 stream for purposes of supplying CO2

for commercial applications or that extract a CO2 stream in order to utilize it 

for geologic sequestration, (c) exporters (out of the State of California) of bulk 

CO2 that export CO2 for the purpose of geologic sequestration, (d) exporters 

(out of the State of California) of bulk CO2 that export for purposes other than 

geologic sequestration, and (e) importers (into the State of California) of bulk 

CO2. This source category is focused on upstream supply and is not 

intended to place duplicative compliance obligations on CO2 already covered 

upstream. The source category does not include transportation or distribution 

of CO2, purification, compression or processing of CO2, or on-site use of CO2

captured on-site. 

(68) “Carbonate” means compounds containing the radical CO3

−2. Upon 

calcination, the carbonate radical decomposes to evolve carbon dioxide 

(CO2). Common carbonates consumed in the mineral industry include 

calcium carbonate (CaCO3) or calcite; magnesium carbonate (MgCO3) or 

magnesite; and calcium-magnesium carbonate (CaMg(CO3)2) or dolomite. 

(69) “Carbonate-based raw material” means any of the following materials used in 

the manufacture of glass: Limestone, dolomite, soda ash, barium carbonate, 

potassium carbonate, lithium carbonate, and strontium carbonate. 

(70) “Catalyst” means a substance added to a chemical reaction, which facilitates 

or causes the reaction, and is not consumed by the reaction. 

(71) “CBOB-summer” or “conventional blendstock for oxygenate blendingsummer” means a petroleum product which, when blended with a specified 

type and percentage of oxygenate, meets the definition of conventionalsummer. 

(72) “CBOB-winter” or “conventional blendstock for oxygenate blending-winter” 

means a petroleum product which, when blended with a specified type and 

percentage of oxygenate, meets the definition of conventional-winter. 

(73) “Cement” means a building material that is produced by heating mixtures of 

limestone and other minerals or additives at high temperatures in a rotary kiln 

to form clinker, followed by cooling and grinding with blended additives. 

Finished cement is a powder used with water, sand and gravel to make 

concrete and mortar. 

(74) “Cement kiln dust” or “CKD” means the fine-grained, solid, highly alkaline 

waste removed from cement kiln exhaust gas by air pollution control devices. 

CKD consists of partly calcined kiln feed material and includes all dust from 

cement kilns and bypass systems including bottom ash and bypass dust. 

(75) “Centrifugal compressor” means any equipment that increases the pressure 

of a process natural gas or CO2 by centrifugal action, employing rotating 

movement of the driven shaft. 

(76) “Centrifugal compressor dry seals” mean a series of rings around the 

compressor shaft where it exits the compressor case that operate 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 16 February 2015 

mechanically under the opposing forces to prevent natural gas or CO2 from 

escaping to the atmosphere. 

(77) “Centrifugal compressor wet seal degassing vent emissions” means 

emissions that occur when the high-pressure oil barriers for centrifugal 

compressors are depressurized to release absorbed natural gas or CO2. 

High-pressure oil is used as a barrier against escaping gas in centrifugal 

compressor seals. 

(78) “Certification” or “certify” refers to the procedure in 40 CFR §98.4(e), as 

required for reports submitted to ARB under this article. 

(79) “Chain of title” means the sequence of historical transfers of title to a fuel from 

the producer to the reporting entity. 

(80) “City gate” means a location at which natural gas ownership or control passes 

from one party to another, neither of which is the ultimate consumer. In this 

article, in keeping with common practice, the term refers to a point or 

measuring station at which a local gas distribution utility receives gas from a 

natural gas pipeline company or transmission system. Meters at the city gate 

station measure the flow of natural gas into the local distribution company 

system and typically are used to measure local distribution company system 

sendout to customers. 

(81) “Coal” means all solid fuels classified as anthracite, bituminous, subbituminous, or lignite by the American Society for Testing and Materials 

Designation ASTM D388–05 “Standard Classification of Coals by Rank” 

(2005), which is hereby incorporated by reference. 

(82) “Coal coke” means a solid residue high in carbon content produced by the 

destructive distillation of coal at high temperatures in either a by-product coke 

oven battery or a non-recovery coke oven battery. 

(83) “Cogeneration” means an integrated system that produces electric energy 

and useful thermal energy for industrial, commercial, or heating and cooling 

purposes, through the sequential or simultaneous use of the original fuel 

energy. Cogeneration must involve generation of electricity and useful 

thermal energy and some form of waste heat recovery. Some examples of 

cogeneration include: (a) a gas turbine or reciprocating engine generating 

electricity by combusting fuel, which then uses a heat recovery unit to capture 

useful heat from the exhaust stream of the turbine or engine; (b) Steam 

turbines generating electricity as a byproduct of steam generation through a 

fired boiler; (c) Cogeneration systems in which the fuel input is first applied to 

a thermal process such as a furnace and at least some of the heat rejected 

from the process is then used for power production. For the purposes of this 

article, a combined-cycle power generation unit, where none of the generated 

thermal energy is used for industrial, commercial, or heating and cooling 

purposes (these purposes exclude any thermal energy utilization that is either 

in support of or a part of the electricity generation system), is not considered a 

cogeneration unit. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 17 February 2015 

(84) “Cogeneration system” means individual cogeneration components including 

the prime mover (heat engine), generator, heat recovery, and electrical 

interconnection, configured into an integrated system that provides sequential 

or simultaneous generation of multiple forms of useful energy (usually 

mechanical and thermal), at least one form of which the facility consumes onsite or makes available to other users for an end-use other than electricity 

generation. 

(85) “Cogeneration unit” means a unit that produces electric energy and useful 

thermal energy for industrial, commercial, or heating and cooling purposes, 

through the sequential or simultaneous use of the original fuel energy and 

waste heat recovery. 

(86) “Coke (petroleum)” means a solid residue consisting mainly of carbon which 

results from the cracking of petroleum hydrocarbons in processes such as 

coking and fluid coking. This includes catalyst coke deposited on a catalyst 

during the refining process which must be burned off in order to regenerate 

the catalyst. 

(87) “Combustion emissions” means greenhouse gas emissions occurring during 

the exothermic reaction of a fuel with oxygen. 

(88) “Combustion source” means a source of emissions resulting from 

combustion. 

(89) “Commercial propane” means liquefied petroleum gas that has a wide mixture 

of gases that can sustain combustion as defined by ASTM D1835-05 

“Standard Specification for Liquefied Petroleum (LP) Gases” (2005), which is 

hereby incorporated by reference. 

(90) “Common control” means having common “operational control” as defined 

herein. 

(91) “Compliance instrument” is as defined in the cap-and-trade regulation. 

(92) “Compliance obligation” means the quantity of verified reported emissions or 

assigned emissions for which an entity must submit compliance instruments 

to ARB. 

(93) “Compliance offset protocol” means an offset protocol adopted by the Board. 

(94) “Compliance period” means the period for which the compliance obligation is 

calculated for covered entities pursuant to the cap-and-trade regulation. 

(95) “Component” for the purposes of sections 95150 to 95157 of this article 

means each metal to metal joint or seal of non-welded connection separated 

by a compression gasket, screwed thread (with or without thread sealing 

compound), metal to metal compression, or fluid barrier through which natural 

gas or liquid can escape to the atmosphere. 

(96) “Compressed natural gas” or “CNG” means natural gas in high-pressure 

containers that is highly compressed (though not to the point of liquefaction), 

typically to pressures ranging from 2900 to 3600 psi. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 18 February 2015 

(97) “Compressor” means any machine for raising the pressure of a natural gas or 

CO2 by drawing in low pressure natural gas and discharging significantly 

higher pressure natural gas or CO2. 

(98) “Condensate” means hydrocarbon and other liquid, including both water and 

hydrocarbon liquids, separated from natural gas that condenses due to 

changes in the temperature, pressure, or both, and remains liquid at storage 

conditions. 

(99) “Conflict of interest” means a situation in which, because of financial or other 

activities or relationships with other persons or organizations, a person or 

body is unable or potentially unable to render an impartial verification 

statement of a potential client’s greenhouse gas emissions data report, or the 

person or body’s objectivity in performing verification services is or might be 

otherwise compromised. 

(100) “Consignee” means the same as “California consignee.” 

(101) “Continuous bleed” means a continuous flow of pneumatic supply natural gas 

to the process control device (e.g. level control, temperature control, pressure 

control) where the supply gas pressure is modulated by the process 

condition, and then flows to the valve controller where the signal is compared 

with the process set-point to adjust gas pressure in the valve actuator. 

(102) “Continuous emissions monitoring system” or “CEMS” means the total 

equipment required to obtain a continuous measurement of a gas 

concentration or emission rate from combustion or industrial processes. 

(103) “Continuous physical transmission path” means the full transmission path 

shown in the physical path table of a single NERC e-tag from the first point of 

receipt closest to the generation source to the final point of delivery closest to 

the final sink. This is one criterion to establish direct delivery. 

(103) “Conventional-summer” means 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, but which meet 

summer RVP standards required under 40 CFR §80.27 or as specified by the 

state. Note: This category excludes conventional gasoline for oxygenate 

blending (CBOB) as well as other blendstock. 

(105) “Conventional wells” mean crude oil or gas wells in producing fields that do 

not employ hydraulic fracturing to produce commercially viable quantities of 

crude oil or natural gas. 

(106) “Conventional-winter” means 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 or the summer 

RVP standards required under 40 CFR §80.27 or as specified by the state. 

Note: This category excludes conventional blendstock for oxygenate blending 

(CBOB) as well as other blendstock. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 19 February 2015 

(107) “Correctable errors” means errors identified by the verification team that affect 

covered emissions data, non-covered emissions data, or covered product 

data in the submitted emissions data report that result from a nonconformance with this article. Differences that, in the professional judgment 

of the verification team, are the result of differing but reasonable methods of 

truncation or rounding or averaging, where a specific procedure is not 

prescribed by this article, are not considered errors and therefore do not 

require correction. 

(108) “Covered emissions” mean all emissions included in a compliance obligation 

under sections 95852 through 95852.2 of the cap-and-trade regulation, 

regardless of whether the cap-and-trade regulation imposes a compliance 

obligation for the data year. 

(109) “Covered product data” means all product data included in the allocation of 

allowances under sections 95870, 95890, and 95891 of the cap-and-trade 

regulation, regardless of whether the cap-and-trade regulation imposes a 

compliance obligation for the data year. 

(110) “Cracking” means the process of breaking down larger molecules into smaller 

molecules, utilizing catalysts and/or elevated temperatures and pressures. 

(111) "Crude oil" means a mixture of hydrocarbons that exists in the liquid phase in 

natural underground reservoirs and remains liquid at atmospheric pressure 

after passing through surface separating facilities. Depending upon the 

characteristics of the crude stream, it may also include any of the following: 

(A) Small amounts of hydrocarbons that exist in gaseous phase in natural 

underground reservoirs but are liquid at atmospheric conditions 

(temperature and pressure) after being recovered from oil well (casinghead) gas in lease separators and are subsequently commingled with 

the crude stream without being separately measured. Lease 

condensate recovered as a liquid from natural gas wells in lease or field 

separation facilities and later mixed into the crude stream is also 

included. 

(B) Small amounts of non-hydrocarbons, such as sulfur and various metals. 

(C) Drip gases, and liquid hydrocarbons produced from tar sands, oil 

sands, gilsonite, and oil shale. 

(D) Petroleum products that are received or produced at a refinery and 

subsequently injected into a crude supply or reservoir by the same 

refinery owner or operator. 

Liquids produced at natural gas processing plants and natural gas 

fractionating facilities are excluded, unless the produced natural gas 

liquids are extracted from produced gas, associated gas, and waste gas 

at a facility and re-injected into barrels of crude oil produced by the 

same facility. Crude oil is refined to produce a wide array of petroleum 

products, including heating oils; gasoline, diesel and jet fuels; 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 20 February 2015 

lubricants; asphalt; ethane, propane, and butane; and many other 

products used for their energy or chemical content.

(112) “Customer” means a purchaser of electricity not for the purposes of 

retransmission or resale. 

(113) “Customer meter” means natural gas meter, riser, and fittings at residential, 

commercial, or industrial premise(s). 

(114) “Data year” means the calendar year in which emissions occurred. 

(115) “De minimis” means those emissions reported for a source or sources that 

are calculated using alternative methods selected by the operator, subject to 

the limits specified in section 95103(i). 

(116) “Dehydrator” means a device in which a liquid absorbent (including desiccant, 

ethylene glycol, diethylene glycol, or triethylene glycol) directly contacts a 

natural gas stream to absorb water vapor. 

(117) “Dehydrator vent emissions” means natural gas and CO2 release from a 

natural gas dehydrator system absorbent (typically glycol) reboiler or 

regenerator to the atmosphere or a flare, including stripping natural gas and 

motive natural gas used in absorbent circulation pumps. 

(118) “Delayed coking” means a process by which heavier crude oil fractions are 

thermally decomposed under conditions of elevated temperature and 

pressure to produce a mixture of lighter oils and petroleum coke. 

(119) “Delivered electricity” means electricity that was distributed from a PSE and 

received by a PSE or electricity that was generated, transmitted, and 

consumed. 

(120) “Demethanizer” means the natural gas processing unit that separates 

methane rich residue gas from the heavier hydrocarbons (e.g., ethane, 

propane, butane, pentane-plus) in the feed natural gas stream. 

(121) “Desiccant” means a material used in solid-bed dehydrators to remove water 

from raw natural gas by adsorption or absorption. Desiccants include 

activated alumina, palletized calcium chloride, lithium chloride and granular 

silica gel material. Wet natural gas is passed through a bed of the granular or 

pelletized solid adsorbent or absorbent in these dehydrators. As the wet gas 

contacts the surface of the particles of desiccant material, water is adsorbed 

on the surface or absorbed and dissolves the surface of these desiccant 

particles. Passing through the entire desiccant bed, almost all of the water is 

adsorbed onto or absorbed into the desiccant material, leaving the dry gas to 

exit the contactor. 

(122) “Designated representative” means the person responsible for certifying, 

signing, and submitting the GHG emissions data report. 

(123) “Diesel fuel” means Distillate Fuel No. 1 and Distillate Fuel No. 2, including 

dyed and nontaxed fuels. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 21 February 2015 

(124) “Direct delivery of electricity” or “directly delivered” means electricity that 

meets any of the following criteria: 

(A) The facility has a first point of interconnection with a California 

balancing authority; 

(B) The facility has a first point of interconnection with distribution facilities 

used to serve end users within a California balancing authority area; 

(C) The electricity is scheduled for delivery from the specified source into a 

California balancing authority via a continuous physical transmission 

path from interconnection of the facility in the balancing authority in 

which the facility is located to a sink located in the state of California; or 

(D) There is an agreement to dynamically transfer electricity from the facility 

to a California balancing authority. 

(125) “Distillate fuel oil” means a classification for one of the petroleum fractions 

produced in conventional distillation operations and from crackers and 

hydrotreating process units. The generic term distillate fuel oil includes 

kerosene (EIA product code 311), kerosene-type jet fuel (EIA product codes 

213, 217, and 218), diesel fuels (Diesel Fuels No. 1, No. 2, and No. 4; EIA 

product codes 465, 466, and 467), and fuel oils (Fuel Oils No. 1, No. 2, and 

No. 4; EIA product codes 508, 509, and 510). 

(126) “Distillate Fuel No. 1” has a maximum distillation temperature of 550°F at the 

90 percent recovery point and a minimum flash point of 100°F and includes 

fuels commonly known as Diesel Fuel No. 1 and Fuel Oil No. 1, but excludes 

kerosene. This fuel is further subdivided into categories of sulfur content: 

High Sulfur (greater than 500 ppm), Low Sulfur (less than or equal to 500 

ppm and greater than 15 ppm), and Ultra Low Sulfur (less than or equal to 15 

ppm). 

(127) “Distillate Fuel No. 2” has a minimum and maximum distillation temperature of 

540°F and 640°F at the 90 percent recovery point, r espectively, and includes 

fuels commonly known as Diesel Fuel No. 2 and Fuel Oil No. 2. This fuel is 

further subdivided into categories of sulfur content: High Sulfur (greater than 

500 ppm), Low Sulfur (less than or equal to 500 ppm and greater than 15 

ppm), and Ultra Low Sulfur (less than or equal to 15 ppm). 

(128) “Distillate Fuel No. 4” is a distillate fuel oil made by blending distillate fuel oil 

and residual fuel oil, with a minimum flash point of 131°F. 

(129) “Distribution pipeline” means a pipeline that is designated as such by the 

Pipeline and Hazardous Material Safety Administration (PHMSA) in 49 CFR 

§192.3. 

(130) “District Heating Facility” means a facility that, at a central plant, produces hot 

water, steam and/or chilled water that is distributed through underground 

pipes to buildings and facilities connected to the system that are not part of 

the same facility. District Heating Facility does not include a facility that 

produces electricity. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 22 February 2015 

(131) “Double-Valve Cylinder,” for purposes of Appendix B, means a cylinder used 

for gathering crude oil or condensate samples. The cylinder is provided by a 

laboratory filled with laboratory grade water which prevents flashing within the 

cylinder. 

(132) “Dry gas” means a natural gas that is produced from gas wells not associated 

with the production of crude oil. 

(133) “E&P Tank” means E&P Tank Version 2.0 for Windows software, copyright 

1996-1999 by the American Petroleum Institute and the Gas Research 

Institute (published 2000). 

(134) “EIA” means the Energy Information Administration. The Energy Information 

Administration (EIA) is a statistical agency of the United States Department of 

Energy. 

(135) “Electrical Distribution Utility(ies)” means an entity that owns and/or operates 

an electrical distribution system, including: 1) a public utility as defined in the 

Public Utilities Code section 216 (referred to as an Investor Owned Utility or 

IOU); or 2) a local publicly owned electric utility (POU) as defined in Public 

Utilities Code section 224.3; or 3) an Electrical Cooperative (COOP) as 

defined in Public Utilities Code section 2776, that provides electricity to retail 

end users in California. 

(136) “Electric arc furnace” or "EAF" means a furnace that produces molten steel 

and heats the charge materials with electric arcs from carbon electrodes. 

Furnaces that continuously feed direct-reduced iron ore pellets as the primary 

source of iron are not affected facilities within the scope of this definition. 

(137) “Electric Power Entity” or “EPE” means those entities specified in section 

95101(d) of this article, including electricity importers and exporters; retail 

providers, including multi-jurisdictional retail providers; the California 

Department of Water Resources (DWR); the Western Area Power 

Administration (WAPA); and the Bonneville Power Administration (BPA). 

(138)“Electricity exporter” means electric power entities that deliver exported 

electricity. The entity that exports electricity is identified on the NERC e-Tag 

as the purchasing-selling entity (PSE) on the last segment of the tag’s 

physical path, with the point of receipt located inside the state of California 

and the point of delivery located outside the state of California. Electricity 

exporters include Energy Imbalance Market (EIM) Entity Scheduling 

Coordinators serving the EIM market that can result in exports from 

California. 

(139) “Electricity generating facility” means a facility that generates electricity and 

includes one or more generating units at the same location. 

(140) “Electricity generating unit” or “EGU” means any combination of physically 

connected generator(s), reactor(s), boiler(s), combustion turbine(s), or other 

prime mover(s) operated together to produce electric power. An EGU may 

include a unit that generate electricity from fuel combustion or from other 

renewable energy sources, such as solar and wind. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 23 February 2015 

(141) “Electricity importers” deliver imported electricity. For electricity that is 

scheduled with a NERC e-Tag to a final point of delivery inside the state of 

California, the electricity importer is identified on the NERC e-Tag as the 

purchasing-selling entity (PSE) on the last segment of the tag’s physical path 

with the point of receipt located outside the state of California and the point of 

delivery located inside the state of California. For facilities physically located 

outside the state of California with the first point of interconnection to a 

California balancing authority’s transmission and distribution system when the 

electricity is not scheduled on a NERC e-Tag, the importer is the facility 

operator or scheduling coordinator. Federal and state agencies are subject to 

the regulatory authority of ARB under this article and include Western Area 

Power Administration (WAPA), Bonneville Power Administration (BPA), and 

California Department of Water Resources (DWR). Electricity Importers 

include EIM Participating Resource Scheduling Coordinators serving the EIM 

market whose transactions result in electricity imports into California. 

(142) “Electricity sold into the CAISO markets” means electricity sold into California 

Independent System Operator (CAISO) markets, including but not limited to 

the day-ahead market, real time market, integrated forward market, and 

energy imbalance market. Transactions excluded as CAISO sales pursuant 

to section 11.29(a)(iii) of the CAISO Fifth Replacement Tariff dated May 1, 

2014 do not fall under this definition. 

(143) “Electricity transaction” means the purchase, sale, import, export or exchange 

of electric power. 

(144) “Electricity wheeled through California” or “wheeled electricity” means 

electricity that is generated outside the state of California and delivered into 

California with the final point of delivery outside California. Electricity wheeled 

through California is documented on a single NERC e-Tag showing the first 

point of receipt located outside the state of California, an intermediate point of 

delivery located inside the state of California, and the final point of delivery 

located outside the state of California. 

(145) “Eligible renewable energy resource” is as defined in section 95802(a) of the 

cap-and-trade regulation. 

(146) “Emission factor” means a unique value for determining an amount of a 

greenhouse gas emitted for a given quantity of activity (e.g., metric tons of 

carbon dioxide emitted per barrel of fossil fuel burned.) 

(147) “Emissions” means the release of greenhouse gases into the atmosphere 

from sources and processes in a facility, including from the combustion of 

transportation fuels such as natural gas, petroleum products, and natural gas 

liquids. 

(148)“Emissions data report” or “greenhouse gas emissions data report” or “report” 

means the report prepared by an operator or supplier each year and 

submitted by electronic means to ARB that provides the information required 

by this article. The emissions data report is for the submission of required 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 24 February 2015 

data for the calendar year prior to the year in which the report is due. For 

example, a 2013 emissions data report would cover emissions and product 

data for the 2013 calendar year and would be reported in 2014. 

(149) “Emissions data verification statement” means the final statement rendered 

by a verification body attesting whether a reporting entity’s covered emissions 

data in their emissions data report is free of material misstatement, and 

whether the emissions data conforms to the requirements of this article. 

(150) “Emulsion” means a mixture of water, crude oil, associated gas, and other 

components from the oil extraction process that is transferred from an existing 

platform that is permanently affixed to the ocean floor and that is located 

outside the distance specified in the “offshore” definition of this article, to an 

onshore petroleum and natural gas production facility. For purposes of 

Appendix B, emulsion means a mixture of crude oil, condensate, or produced 

water in any proportion. 

(151)“End user” means a final purchaser of an energy product, such as electricity, 

thermal energy, or natural gas not for the purposes of retransmission or 

resale. In the context of natural gas consumption, an “end user” is the point 

to which natural gas is delivered for consumption. 

(152) “Energy Imbalance Market” or “EIM” means the operation of the CAISO’s 

real-time market to manage transmission congestion and optimize 

procurement of energy to balance supply and demand for the combined 

CAISO and EIM footprint. 

(153) “Energy Imbalance Market, Participating Resource Scheduling Coordinator” 

or “EIM” Participating Resource Scheduling Coordinator means the 

participating resource owner or operator, or a third-party designated by the 

resource owner or operator that is certified by the CAISO and enters into the 

pro forma EIM Participating Resource Scheduling Coordinator Agreement, 

under which it is responsible for meeting the requirements specified in the 

CAISO Tariff on behalf of the resource owner or operator. 

(154) “Enforceable” means the authority for ARB to hold a particular party liable and 

to take appropriate action if any of the provisions of this article are violated. 

(155) “Engineering estimation,” for the purposes of sections 95150 to 95157 of this 

article, means an estimate of emissions based on engineering principles 

applied to measured and/or approximated physical parameters such as 

dimensions of containment, actual pressures, actual temperatures, and 

compositions. 

(156) “Enhanced oil recovery” or “EOR” means the use of certain methods such as 

steam (thermal EOR), water flooding or gas injection into existing wells to 

increase the recovery of crude oil from a reservoir. In the context of this rule, 

EOR also applies to injection of critical phase carbon dioxide into a crude oil 

reservoir to enhance the recovery of oil. 

(157) “Enterer” means an entity that imports into California motor vehicle fuel, diesel 

fuel, fuel ethanol, biodiesel, non-exempt biomass-derived fuel or renewable 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 25 February 2015 

fuel and who is the importer of record under federal customs law or the owner 

of fuel upon import into California if the fuel is not subject to federal customs 

law. Only enterers that import the fuels specified in this definition outside the 

bulk transfer/terminal system are subject to reporting under the regulation. 

(158) “Entity” means a person, firm, association, organization, partnership, business 

trust, corporation, limited liability company, company, or government agency. 

(159) “Equipment” means any stationary article, machine, or other contrivance, or 

combination thereof, which may cause the issuance or control the issuance of 

air contaminants; equipment shall not mean portable equipment, tactical 

support equipment, or electricity generators designated as backup generators 

in a permit issued by an air pollution control district or air quality management 

district. 

(160) “Equipment leak” means those emissions which could not reasonably pass 

through a stack, chimney, vent, or other functionally-equivalent opening. 

(161) “Equipment leak detection” means the process of identifying emissions from 

equipment, components, and other point sources. 

(162) “Ethane” is a paraffinic hydrocarbon with molecular formula C2H6. 

(163) “Ethanol” is an anhydrous alcohol with molecular formula C2H5OH. 

(164) “Ethylene” is an olefinic hydrocarbon with molecular formula C2H4. 

(165) “Exchange agreement” means a commitment between electricity market 

participants to swap energy for energy. Exchange transactions do not involve 

transfers of payment or receipts of money for the full market value of the 

energy being exchanged, but may include payment for net differences due to 

market price differences between the two parts of the transaction or to settle 

minor imbalances. 

(166) “Exclusive marketer” means a marketer that has exclusive rights to market 

electricity for a generating facility or group of generating facilities. 

(167) “Executive Officer” means the Executive Officer of the California Air 

Resources Board, or his or her delegate. 

(168) “Exported electricity” means electricity generated inside the state of California 

and delivered to serve load located outside the state of California. This 

includes electricity delivered from a first point of receipt inside California, to 

the first point of delivery outside California, with a final point of delivery 

outside the state of California. Exported electricity delivered across balancing 

authority areas is documented on NERC e-Tags with the first point of receipt 

located inside the state of California and the final point of delivery located 

outside the state of California. Exported electricity does not include electricity 

generated inside the state of California then transmitted outside of California, 

but with a final point of delivery inside the state of California. Exported 

electricity does not include electricity generated inside the state of California 

that is allocated to serve the California retail customers of a multi-jurisdictional 

retail provider, consistent with a cost allocation methodology approved by the 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 26 February 2015 

California Public Utilities Commission and the utility regulatory commission of 

at least one additional state in which the multi-jurisdictional retail provider 

provides retail electric service. 

(169) “External combustion” means fired combustion in which the flame and 

products are separated from contact with the process fluid to which the 

energy is delivered. Process fluids may be air, hot water, or hydrocarbons. 

External combustion equipment may include fired heaters, industrial boilers, 

and commercial and domestic combustion units. 

(170) “Facility,” unless otherwise specified in relation to natural gas distribution 

facilities and onshore petroleum and natural gas production facilities as 

defined in section 95102(a), means any physical property, plant, building, 

structure, source, or stationary equipment located on one or more contiguous 

or adjacent properties in actual physical contact or separated solely by a 

public roadway or other public right-of-way and under common ownership or 

common control, that emits or may emit any greenhouse gas. Operators of 

military installations may classify such installations as more than a single 

facility based on distinct and independent functional groupings within 

contiguous military properties. 

(171) “Facility,” with respect to natural gas distribution for the purposes of sections 

95150 to 95158 of this article, means the collection of all distribution pipelines 

and metering-regulating stations that are operated by a local distribution 

company (LDC) within the State of California that is regulated as a separate 

operating company by a public utility commission or that are operated as an 

independent municipally-owned distribution system. 

(172) “Facility,” with respect to onshore petroleum and natural gas production for 

the purposes of sections 95150 to 95158 of this article, means all petroleum 

and natural gas equipment on a well-pad, associated with a well pad or to 

which emulsion is transferred and CO2 EOR operations that are under 

common ownership or common control including leased, rented, or contracted 

activities by an onshore petroleum and natural gas production owner or 

operator and that are located in a single basin as defined in section 95102(a). 

When a commonly owned cogeneration plant is within the basin, the 

cogeneration plant is only considered part of the onshore petroleum and 

natural gas production facility if the onshore petroleum and natural gas 

production facility operator or owner has a greater than fifty percent 

ownership share in the cogeneration plant. Where a person or entity owns or 

operates more than one well in a basin, then all onshore petroleum and 

natural gas production equipment associated with all wells that the person or 

entity owns or operates in the basin would be considered one facility. 

(173) “Farm taps” are pressure regulation stations that deliver gas directly from 

transmission pipelines to rural customers. In some cases a nearby LDC may 

handle the billing of the gas to the customer(s). 

(174) “Feedstock” means the raw material supplied to a process. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 27 February 2015 

(175) “Field,” in the context of oil and gas systems, means oil and gas fields 

identified in the United States as defined by the Energy Information 

Administration Oil and Gas Field Code Master List 2008, DOE/EIA 0370(08), 

January 2009, which is hereby incorporated by reference. 

(176) “Field accuracy assessment” means a test, check, or engineering analysis 

intended to confirm that a flow meter or other mass or volume measurement 

device is operating within an acceptable accuracy range. A field accuracy 

assessment should be conducted in a manner that does not interrupt 

operations or require removal of the meter or require primary element 

inspection. The selected method for field accuracy assessment will vary 

based on meter type and piping system design, and may be performed by the 

facility operator, a third party meter servicing firm, or the original equipment 

manufacturer. 

(177) “Final point of delivery” means the sink specified on the NERC e-Tag, where 

defined points have been established through the NERC Registry. When 

NERC e-Tags are not used to document electricity deliveries, as may be the 

case within a balancing authority, the final point of delivery is the location of 

the load. Exported electricity is disaggregated by the final point of delivery on 

the NERC e-Tag. 

(178) “First deliverer of electricity” or “first deliverer” means the owner or operator of 

an electricity generating facility in California or an electricity importer. 

(179) “First point of delivery in California” means the first defined point on the 

transmission system located inside California at which imported electricity and 

electricity wheeled through California may be measured, consistent with 

defined points that have been established through the NERC Registry. 

(180) “First point of receipt” means the generation source specified on the NERC eTag, where defined points have been established through the NERC Registry. 

When NERC e-Tags are not used to document electricity deliveries, as may 

be the case within a balancing authority, the first point of receipt is the 

location of the individual generating facility or unit, or group of generating 

facilities or units. Imported electricity and wheeled electricity are 

disaggregated by the first point of receipt on the NERC e-Tag. 

(181) “Flare” means a combustion device, whether at ground level or elevated, that 

uses an open flame to burn combustible gases with combustion air provided 

by uncontrolled ambient air around the flame. 

(182) “Flare combustion” means unburned hydrocarbons including CH4, CO2, and 

N2O emissions resulting from the incomplete combustion of gas in flares. 

(183) “Flare combustion efficiency” means the fraction of liquid and gases sent to 

the flare, on a volume or mole basis, that is combusted at the flare burner tip. 

(184) “Flare stack emissions” means CO2 and N2O from partial combustion of 

hydrocarbon gas sent to a flare plus CH4 emissions resulting from the 

incomplete combustion of hydrocarbon gas in the flare. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 28 February 2015 

(185) “Flash Analysis,” for purposes of Appendix B, means laboratory 

methodologies for measuring the volume and composition of gases released 

from liquids, including the molecular weight of the total gaseous sample, the 

weight percent of individual compounds, and a Gas-Oil Ratio or Gas-Water 

Ratio required to calculate the specified emission rates as described in 

Section 10 of Appendix B. 

(186) “Flash point” of a volatile liquid is the lowest temperature at which it can 

vaporize to form an ignitable mixture in air. 

(187) “Flashing,” for purposes of Appendix B, means the release of hydrocarbons 

and carbon dioxide from liquid to surrounding air when the liquid changes 

temperature and pressure, also known as phase change. 

(188) “Floating-Piston Cylinder,” for purposes of Appendix B, means a cylinder used 

for gathering produced water. The cylinder contains an internal piston 

controlled by gas pressure. The piston prevents sample liquid from flashing 

within the sampling cylinder and provides a means of extracting the sample 

liquid. 

(189) “Flow meter” means a measurement device consisting of one or more 

individual components that is designed to measure the bulk fluid movement of 

liquid or gas through a piped system at a designated point. Bulk fluid 

movement can be measured with a variety of devices in units of mass flow or 

volume. 

(190) “Flow monitor” means a component of the continuous emission monitoring 

system that measures the volumetric flow of exhaust gas. 

(191) “Flowback Fluid,” for purposes of Appendix B, means chemicals, fluids, or 

propellants injected underground under pressure to stimulate or hydraulically 

fracture a crude oil or natural gas well or reservoir and that flows back to the 

surface as a fluid after injection is completed. 

(192) “Fluid catalytic cracking unit” or “FCCU” means a process unit in a refinery in 

which petroleum derivative feedstock is charged and fractured into smaller 

molecules in the presence of a catalyst, or reacts with a contact material to 

improve feedstock quality for additional processing, and in which the catalyst 

or contact material is regenerated by burning off coke and other deposits. 

The unit includes, but is not limited to, the riser, reactor, regenerator, air 

blowers, spent catalyst, and all equipment for controlling air pollutant 

emissions and recovering heat. 

(193) “Fluid coking” means a thermal cracking process utilizing the fluidized-solids 

technique to remove carbon (coke) for continuous conversion of heavy, lowgrade oils into lighter products. 

(194) “Fluorinated greenhouse gas” means sulfur hexafluoride (SF6), nitrogen 

trifluoride (NF3), and any fluorocarbon except for controlled substances as 

defined at 40 CFR Part 82, subpart A, (May 1995), which is hereby 

incorporated by reference, and substances with vapor pressures of less than 

1 mm of Hg absolute at 25°C. With these exceptions , “fluorinated GHG” 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 29 February 2015 

includes any hydrofluorocarbon, any perfluorocarbon, any fully fluorinated 

linear, branched or cyclic alkane, ether, tertiary amine or aminoether, any 

perfluoropolyether, and any hydrofluoropolyether. 

(195) “Forced extraction of natural gas liquids” means removal of ethane or higher 

carbon number hydrocarbons existing in the vapor phase in natural gas, by 

removing ethane or heavier hydrocarbons derived from natural gas into 

natural gas liquids by means of a forced extraction process. Forced 

extraction processes include refrigeration, absorption (lean oil), cryogenic 

expander, and combinations of these processes. Forced extraction does not 

include in and of itself, natural gas dehydration, or the collection or gravity 

separation of water or hydrocarbon liquids from natural gas at ambient 

temperatures, or the condensation of water or hydrocarbon liquids through 

passive reduction in pressure or temperature, or portable dewpoint 

suppression skids. 

(196) “Forest-derived wood and wood waste” means wood harvested pursuant to 

the California Forest Practice Rule, Title 14, California Code of Regulations, 

Chapters 4, 4.5, and 10 or pursuant to the National Environmental Policy Act. 

(197) “Fossil fuel” means natural gas, petroleum, coal, or any form of solid, liquid, or 

gaseous fuel derived from such material. 

(198) “Fractionates” means the process of separating natural gas liquids into their 

constituent liquid products. 

(199) “Fractionator” means plants that produce fractionated natural gas liquids 

(NGLs) extracted from produced natural gas and separate the NGLs 

individual component products: ethane, propane, butanes and pentane-plus 

(C5+). Plants that only process natural gas but do not fractionate NGLs 

further into component products are not considered fractionators. Some 

fractionators do not process production gas, but instead fractionate bulk 

NGLs received from natural gas processors. Some fractionators both 

process natural gas and fractionate bulk NGLs received from other plants. 

(200) “Fuel” means solid, liquid or gaseous combustible material. Volatile organic 

compounds burned in destruction devices are not fuels unless they can 

sustain combustion without use of a pilot fuel, and such destruction does not 

result in a commercially useful end product. 

(201) “Fuel analytical data” means data collected about fuel usage (including mass, 

volume, and flow rate) and fuel characteristics (including heating value, 

carbon content, and molecular weight) to support emissions calculation. 

(202) “Fuel characteristic data” means, for the purpose of this article, properties of a 

fuel used for calculating GHG emissions including carbon content, high heat 

value, and molecular weight. 

(203) “Fuel combusting electricity generating or cogeneration unit” means an 

electricity generating unit, which may include a cogeneration or bigeneration 

unit, that produces electricity from fuel combustion. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 30 February 2015 

(204) “Fuel ethanol” means ethanol that meets ASTM D-4806-08 “Standard 

Specification for Denatured Fuel Ethanol for Blending with Gasolines for Use 

as Automotive Spark-Ignition Engine Fuel” (2008), specifications, which is 

hereby incorporated by reference, for blending with gasolines for use as 

automotive spark-ignition engine fuel. 

(205) “Fuel flowmeter system” means a monitoring system which provides a 

continuous record of the flow rate of fuel oil or gaseous fuel. A fuel flowmeter 

system consists of one or more fuel flowmeter components, all necessary 

auxiliary components (e.g., transmitters, transducers, etc.), and a data 

acquisition and handling system (DAHS). 

(206) “Fuel production facility” means a facility, other than a refinery, in which motor 

vehicle fuel, diesel fuel or biomass-based fuel is produced. 

(207) “Fuel supplier” means a supplier of petroleum products, a supplier of 

biomass-derived transportation fuels, a supplier of natural gas including 

operators of interstate and intrastate pipelines, a supplier of liquefied natural 

gas, or a supplier of liquid petroleum gas as specified in this article. 

(208) “Fuel transaction” means the record of the exchange of fuel possession, 

ownership, or title from one entity to another. 

(209) “Fugitive emissions” means those emissions which are unintentional and 

could not reasonably pass through a stack, chimney, vent, or other 

functionally-equivalent opening. 

(210) “Fugitive emissions detection” means the process of identifying emissions 

from equipment, components, and other point sources. 

(211) “Fugitive equipment leak” means the unintended or incidental emissions of 

greenhouse gases from the production, transmission, processing, storage, 

use or transportation of fossil fuels, greenhouse gases, or other equipment. 

(212) "Fugitive source" means a source of fugitive emissions. 

(213) “Full verification” means all verification services as provided in section 95131. 

(214) “Gas” means the state of matter distinguished from the solid and liquid states 

by: relatively low density and viscosity; relatively great expansion and 

contraction with changes in pressure and temperature; the ability to diffuse 

readily; and the spontaneous tendency to become distributed uniformly 

throughout any container. 

(215) “Gas conditions” means the actual temperature, volume, and pressure of a 

gas sample. 

(216) “Gas gathering/booster stations” means centralized stations where produced 

natural gas from individual wells is co-mingled, compressed for transport to 

processing plants, transmission and distribution systems, and other 

gathering/booster stations which co-mingle gas from multiple production 

gathering/booster stations. Such stations may include gas dehydration, 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 31 February 2015 

gravity separation of liquids (both hydrocarbon and water), pipeline pig 

launchers and receivers, and gas powered pneumatic devices. 

(217) “Gas-to-oil ratio” or “GOR” means the ratio of gas produced from a barrel of 

crude oil or condensate when cooling and depressurizing these liquids to 

standard conditions, expressed in terms of standard cubic feet of gas per 

barrel of oil. 

(218) “Gas-to-water ratio” or “GWR” means the ratio of gas produced from a barrel 

of produced water when cooling and depressurizing produced water to 

standard conditions, expressed in terms of standard cubic feet of gas per 

barrel of water. 

(219) “Gas well” means a well completed for production of natural gas from one or 

more gas zones or reservoirs. Such wells contain no completions for the 

production of crude oil. 

(220) “Generated electricity” means electricity generated by an electricity 

generating unit at the reporting facility. Generated electricity does not include 

any electricity that is generated outside the facility and delivered into the 

facility with final destination outside of the facility. 

(221) “Generated energy” means electricity or thermal energy generated by the 

electricity generating, cogeneration, or bigeneration units included in the 

reporting facility. 

(222) “Generating unit” means any combination of physically connected 

generator(s), reactor(s), boiler(s), combustion turbine(s), or other prime 

mover(s) operated together to produce electric power. 

(223) “Generation providing entity” or “GPE” means a facility or generating unit 

operator, full or partial owner, party to a contract for a fixed percentage of net 

generation from the facility or generating unit, party to a tolling agreement 

with the owner, or exclusive marketer recognized by ARB that is either the 

electricity importer or exporter with prevailing rights to claim electricity from 

the specified source. 

(224) “Geothermal” means heat or other associated energy derived from the natural 

heat of the earth. 

(225) "Global warming potential" or "GWP" means the ratio of the time-integrated 

radiative forcing from the instantaneous release of one kilogram of a trace 

substance relative to that of one kilogram of a reference gas, i.e., CO2. 

(226) “Graduated Cylinder,” for purposes of Appendix B, means a measuring 

instrument for measuring fluid volume, such as a glass container (cup or 

cylinder or flask) which has sides marked with or divided into amounts. 

(227) “Greenhouse gas” or “GHG” means carbon dioxide (CO2), methane (CH4), 

nitrous oxide (N2O), sulfur hexafluoride (SF6), hydrofluorocarbons (HFCs), 

perfluorocarbons (PFCs), and other fluorinated greenhouse gases as defined 

in this section. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 32 February 2015 

(228) “Greenhouse gas emission reduction” or “GHG emission reduction” or 

“greenhouse gas reduction” or “GHG reduction” means a calculated decrease 

in GHG emissions relative to a project baseline over a specified period of 

time. 

(229) “Greenhouse gas removal enhancement” or “GHG removal” means the 

calculated total mass of a GHG removed, relative to a project baseline, from 

the atmosphere over a specified period of time. 

(230) “Greenhouse gas reservoir” or “GHG reservoir” means a physical unit or 

component of the biosphere, geosphere or hydrosphere with the capability to 

store, accumulate, or release of a GHG removed from the atmosphere by a 

GHG sink or a GHG captured from a GHG emission source. 

(231) “Greenhouse gas sink” or “GHG sink” means a physical unit or process that 

removes a GHG from the atmosphere. 

(232) “Grid” or “electric power grid” means a system of synchronized power 

providers and consumers connected by transmission and distribution lines 

and operated by one or more control centers. 

(233) “Grid-dedicated facility” means an electricity generating facility in which all net 

power generated is destined for distribution on the grid through retail 

providers or electricity marketers, ultimately serving wholesale or retail 

customers of the grid. 

(234) “Gross generation” or “gross power generated” means the total electrical 

output of the generating facility or unit, expressed in megawatt hours (MWh) 

per year. 

(235) “HD-5” or “special duty propane” means a consumer grade of liquefied 

petroleum gas containing a minimum of 90% propane, a maximum of 5% 

propylene, and a maximum of 2.5% butane as specified in ASTM D1835-05. 

(236) “HD-10” means the fuel that meets the specifications for propane used in 

transportation fuel found in Title 13, California Code of Regulations, section 

2292.6. 

(237) “Heat input rate” means the product (expressed in MMBtu/hr) of the gross 

calorific value of the fuel (expressed in MMBtu/mass of fuel) and the fuel feed 

rate into the combustion device (expressed in mass of fuel/hr) and does not 

include the heat derived from preheated combustion air, recirculated flue 

gases, or exhaust from other sources. 

(238) “Heavy crude oil” or “heavy crude” means a category of crude oil 

characterized by relatively high viscosity, a higher carbon-to-hydrogen ratio, 

and a relatively higher density having an API gravity of less than 20. 

(239) “High-bleed pneumatic devices” means automatic, continuous or intermittent 

bleed flow control devices powered by pressurized natural gas and used for 

maintaining a process condition such as liquid level, pressure, delta-pressure 

and temperature. Part of the gas power stream that is regulated by the 

process condition flows to a valve actuator controller where it vents 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 33 February 2015 

continuously or intermittently (bleeds) to the atmosphere at a rate in excess of 

6 standard cubic feet per hour. 

(240) “High heat value” or “HHV” means the high or gross heat content of the fuel 

with the heat of vaporization included. The water vapor is assumed to be in a 

liquid state. 

(241) “Horizontal well” means a well bore that has a planned deviation from 

primarily vertical to primarily horizontal inclination or declination tracking in 

parallel with and through the target formation. 

(242) “Hydrocarbons” means chemical compounds containing predominantly 

carbon and hydrogen. 

(243) “Hydrofluorocarbons” or “HFCs” means a class of GHGs consisting of 

hydrogen, fluorine, and carbon. 

(244) “Hydrogen” means the lightest of all gases, occurring chiefly in combination 

with oxygen in water; exists also in acids, bases, alcohols, petroleum, and 

other hydrocarbons. 

(245) “Hydrogen plant” means a facility that produces hydrogen with steam 

hydrocarbon reforming, partial oxidation of hydrocarbons, or other processes. 

(246) “Imported electricity” means electricity generated outside the state of 

California and delivered to serve load located inside the state of California. 

Imported electricity includes electricity delivered across balancing authority 

areas from a first point of receipt located outside the state of California, to the 

first point of delivery located inside the state of California, having a final point 

of delivery in California. Imported electricity includes electricity imported into 

California over a multi-jurisdictional retail provider’s transmission and 

distribution system, or electricity imported into the state of California from a 

facility or unit physically located outside the state of California with the first 

point of interconnection to a California balancing authority’s transmission and 

distribution system. Imported electricity includes electricity that is a result of 

cogeneration located outside the state of California. Imported electricity does 

not include electricity wheeled through California, defined pursuant to this 

section. Imported electricity does not include electricity imported into the 

California Independent System Operator (CAISO) balancing authority area to 

serve retail customers that are located within the CAISO balancing authority 

area, but outside the state of California. Imported Electricity does not include 

electricity imported into California by an Independent System Operator to 

obtain or provide emergency assistance under applicable emergency 

preparedness and operations reliability standards of the North American 

Electric Reliability Corporation or Western Electricity Coordinating Council. 

Imported electricity shall include Energy Imbalance Market dispatches 

designated by the CAISO’s optimization model and reported by the CAISO to 

EIM Participating Resource Scheduling Coordinators as electricity imported to 

serve retail customers load that are located within the State of California. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 34 February 2015 

(247) “Importer of record” means the owner or purchaser of the goods that are 

imported into California. 

(248) “Independently operated and sited cogeneration/bigeneration facility” means 

a cogeneration or bigeneration facility that is not located on the same facility 

footprint as its thermal host and has different operational control and different 

ownership than the thermal host. 

(249)“Independently operated cogeneration/bigeneration facility co-located with the 

thermal host” means a cogeneration or bigeneration facility that is located on 

the same property footprint as its thermal host but has different operational 

control and different ownership than the thermal host. 

(250) “Independent reviewer” has the same meaning as “lead verifier independent 

reviewer.” 

(251) “Industrial/institutional/commercial facility with electricity generation capacity” 

means a facility whose primary business is not electricity generation and 

includes one or more electricity generating, cogeneration, or bigeneration 

units. 

(252) “Intermittent bleed pneumatic devices” means automated flow control devices 

powered by pressurized natural gas and used for automatically maintaining a 

process condition such as liquid level, pressure, delta-pressure and 

temperature. These are snap-acting or throttling devices that discharge all or 

a portion of the full volume of the actuator intermittently when control action is 

necessary, but do not bleed continuously. Intermittent bleed devices which 

bleed at a cumulative rate of 6 standard cubic feet per hour or greater are 

considered high bleed devices for the purposes of this regulation. 

(253) “Internal combustion” means the combustion of a fuel that occurs with an 

oxidizer (usually air) in a combustion chamber. In an internal combustion 

engine the expansion of the high-temperature and high-pressure gases 

produced by combustion, applies direct force to a component of the engine, 

such as pistons, turbine blades, or a nozzle. This force moves the 

component over a distance, generating useful mechanical energy. Internal 

combustion equipment may include gasoline and diesel industrial engines, 

natural gas-fired reciprocating engines, and gas turbines. 

(254) “Interstate pipeline” means any entity that owns or operates a natural gas 

pipeline delivering natural gas to consumers in the state and is subject to rate 

regulation by the Federal Energy Regulatory Commission. 

(255) “Intrastate pipeline” means any pipeline or piping system wholly within the 

state of California that is delivering natural gas to end-users and is not 

regulated as a public utility gas corporation by the California Public Utility 

Commission (CPUC), not a publicly-owned natural gas utility and is not 

regulated as an interstate pipeline by the Federal Energy Regulatory 

Commission. For purposes of this article, intrastate pipeline operators that 

physically deliver gas to end users in California are considered to be Local 

Distribution Companies. Facilities that receive gas from an upstream LDC 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 35 February 2015 

and redeliver a portion of the gas to one or more adjacent facilities are not 

considered intrastate pipelines. 

(256) “Inventory position” means a contractual agreement with the terminal operator 

for the use of the storage facilities and terminaling services for the fuel. 

(257) "ISO" means the International Organization for Standardization. 

(258) “Isobutane” is a paraffinic branch chain hydrocarbon with molecular formula 

C4H10. 

(259) “Isobutylene” is an olefinic branch chain hydrocarbon with molecular formula 

C4H8. 

(260) “Isopentane” is the methylbutane or 2-methylbutane, branched chain, isomer 

of C5H12 under the International Union of Pure and Applied Chemistry 

(IUPAC) nomenclature. 

(261) “Jurisdiction” means U.S. state or Canadian province. For purposes of this 

article, “U.S. state” means U.S. State, the District of Columbia, the 

Commonwealth of Puerto Rico, the Virgin Islands, Guam, and American 

Samoa and includes the Commonwealth of the Northern Mariana Islands. 

For purposes of this article, “province” means any Canadian province or 

territory. 

(262) “Kerosene” is a light petroleum distillate with a maximum distillation 

temperature of 400°F at the 10-percent recovery poi nt, a final maximum 

boiling point of 572°F, a minimum flash point of 10 0°F, and a maximum 

freezing point of -22°F. Included are No. 1-K and N o. 2-K, distinguished by 

maximum sulfur content (0.04 and 0.30 percent of total mass, respectively), 

as well as all other grades of kerosene called range or stove oil. “Kerosene” 

does not include kerosene-type jet fuel. 

(263) “Kerosene-type jet fuel” means a kerosene-based product used in commercial 

and military turbojet and turboprop aircraft. The product has a maximum 

distillation temperature of 400 °F at the 10 percen t recovery point and a final 

maximum boiling point of 572 °F. Included are Jet A , Jet A–1, JP–5, and JP–

8. 

(264) “Kiln” means an oven, furnace, or heated enclosure used for thermally 

processing a mineral or mineral-based substance. 

(265) “Kilowatt hour” or “kWh” means the electrical energy unit of measure equal to 

one thousand watts of power supplied to, or taken from, an electric circuit 

steadily for one hour. (A watt is a unit of electrical power equal to one 

ampere under pressure of one volt, or 1/746 horsepower.) 

(266) “Last point of delivery in California” means the last defined point on the 

transmission system located inside California at which exported electricity 

may be measured, consistent with defined points that have been established 

through the NERC Registry. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 36 February 2015 

(267) “Lead verifier” means a person that has met all of the requirements in section 

95132(b)(2) and who may act as the lead verifier of a verification team 

providing verification services or as a lead verifier providing an independent 

review of verification services rendered. 

(268) “Lead verifier independent reviewer” or “independent reviewer” means a lead 

verifier within a verification body who has not participated in conducting 

verification services for a reporting entity, offset project developer, or 

authorized project designee for the current reporting year who provides an 

independent review of verification services rendered to the reporting entity as 

required in section 95131. The independent reviewer is not required to meet 

the requirements for a sector specific verifier. 

 (269) “Legacy contract” shall have the meaning defined in section 95802(a) of the 

cap-and-trade regulation. 

(270) “Legacy contract transition assistance” means allowances provided under 

section 95894 of the cap-and-trade regulation to an entity which has applied 

for allowances on the basis of its legacy contract(s). 

(271) “Less intensive verification” means the verification services provided in interim 

years between full verifications; less intensive verification of a reporting 

entity’s emissions data report only requires data checks and document 

reviews of a reporting entity’s emissions data report based on the analysis 

and risk assessment in the most current sampling plan developed as part of 

the most current full verification services. This level of verification may only 

be used if the verifier can provide findings with a reasonable level of 

assurance. 

(272) "Light Crude Oil" means a category of crude oil characterized by relatively low 

viscosity, a lower carbon-to-hydrogen ratio, and a relatively lower density 

having an API gravity of greater than or equal to 20. 

(273) “Liquefied natural gas” or “LNG” means natural gas (primarily methane) that 

has been liquefied by reducing its temperature to -260 degrees Fahrenheit at 

atmospheric pressure. 

(274) “Liquefied petroleum gas” or “LP-Gas” or “LPG” means a flammable mixture 

of hydrocarbon gases used as a fuel. LPG is a natural gas liquid (NGL) that 

is primarily a mixture of propane and butane, with small amounts of propene 

(propylene) and ethane. The most common specification categories are 

propane grades HD-5, HD-10, and commercial grade propane, and 

propane/butane mix. LPG also includes both odorized and non-odorized 

liquid petroleum gas, and is also referred to as propane. 

(275) “Linkage” is as defined in section 95802(a) of the cap-and-trade regulation. 

(276) “Linked jurisdiction” means a jurisdiction which has entered into a linkage 

agreement pursuant to subarticle 12 of the cap-and-trade regulation. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 37 February 2015 

(277) “LNG boiloff gas” means natural gas in the gaseous phase that vents from 

LNG storage tanks due to ambient heat leakage through the tank insulation 

and heat energy dissipated in the LNG by internal pumps. 

(278) “Local distribution company” or “LDC,” for purposes of this article, means a 

company that owns or operates distribution pipelines, not interstate pipelines, 

that physically deliver natural gas to end users and includes public utility gas 

corporations, publicly-owned natural gas utilities and intrastate pipelines that 

are delivering natural gas to end users. 

(279) “Lookback period” means the specified time period of historical data that the 

operators must use for missing data substitution as required by the regulation. 

(280) “Low-bleed pneumatic devices” means automated flow control devices 

powered by pressurized natural gas and used for maintaining a process 

condition such as liquid level, pressure, delta-pressure and temperature. Part 

of the gas power stream that is regulated by the process condition flows to a 

valve actuator controller where it vents continuously or intermittently bleeds to 

the atmosphere at a rate equal to or less than six standard cubic feet per 

hour. 

(281) “Low Btu gas” means gases recovered from casing vents, vapor recovery 

systems, crude oil and petroleum product storage tanks and other parts of the 

crude oil refining and natural gas production process. 

(282) “Marketer” means a purchasing-selling entity that delivers electricity and is not 

a retail provider. 

(283) “Market-shifting leakage,” in the context of an offset project, means increased 

GHG emissions or decreased GHG removals outside an offset project’s 

boundary due to the effects of an offset project on an established market for 

goods or services. 

(284) “Material misstatement” means any discrepancy, omission, or misreporting, or 

aggregation of the three, identified in the course of verification services that 

leads a verification team to believe that the total reported covered emissions 

(metric tons of CO2e) or total reported covered product data contains errors 

greater than 5%, as applicable, in an emissions data report. Material 

misstatement is calculated separately for covered emissions and covered 

product data, as specified in section 95131(b)(12)(A). 

(285) “Maximum potential fuel flow rate” or “maximum fuel consumption rate” 

means the maximum fuel use rate the source is capable of combusting, 

measured in physical unit of the fuel (e.g. million standard cubic feet for 

gases, gallons for liquids, short tons for non-biomass solids, and bone dry 

short tons for biomass-derived solids). When the source consists of multiple 

units, the maximum potential fuel use rate is the sum of the maximum 

potential fuel use rates of all the units aggregated as a source. 

(286) “Megawatt hour” or “MWh” means the electrical energy unit of measure equal 

to one million watts of power supplied to, or taken from, an electric circuit 

steadily for one hour. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 38 February 2015 

(287) “Meter/regulator run” means a series of components used in regulating 

pressure or metering natural gas flow or both. 

(288) “Metering/regulating station” means a station that meters the flowrate, 

regulates the pressure, or both, of natural gas in a natural gas distribution 

facility. This does not include customer meters, customer regulators, or farm 

taps. 

(289) “Methane” or “CH4” means a GHG consisting on the molecular level of a 

single carbon atom and four hydrogen atoms. 

(290) “Metric ton” or “MT” means a common international measurement for mass, 

equivalent to 2204.6 pounds or 1.1 short tons. 

(291) “Midgrade gasoline” means gasoline that has an octane rating greater than or 

equal to 88 and less than or equal to 90. This definition applies to the 

midgrade categories of conventional-summer, conventional-winter, 

reformulated-summer, and reformulated-winter. For midgrade categories of 

RBOB-summer, RBOB-winter, CBOB-summer, and CBOB-winter, this 

definition refers to the expected octane rating of the finished gasoline after 

oxygenate has been added to the RBOB or CBOB. 

(292) “Missing data period” means a period of time during which a piece of data is 

not collected, is invalid, or is collected while the measurement device is not in 

compliance with the applicable quality-assurance requirements. In the 

context of periodic fuel sampling, missing data period is the entire sampling 

period (e.g. week, month, or quarter) for which corresponding fuel 

characteristic data are not obtained. In the context of periodic fuel 

consumption monitoring and recording, a missing data period consists of the 

consecutive time intervals (e.g. hours, days, weeks, or months) for which fuel 

consumption during the time period is not monitored and recorded. 

(293) “MMBtu” means million British thermal units. 

(294) “Motor gasoline (finished)” means a complex mixture of volatile hydrocarbons, 

with or without additives, suitably blended to be used in spark ignition 

engines. Motor gasoline includes conventional gasoline, reformulated 

gasoline, and all types of oxygenated gasoline. Gasoline also has seasonal 

variations in an effort to control ozone levels. This is achieved by lowering 

the Reid Vapor Pressure (RVP) of gasoline during the summer driving 

season. Depending on the region of the country the RVP is lowered to below 

9.0 psi or 7.8 psi. The RVP may be further lowered by state regulations. 

(295) “Motor vehicle fuel” means gasoline. It does not include aviation gasoline, jet 

fuel, diesel fuel, kerosene, liquefied petroleum gas, natural gas in liquid or 

gaseous form, or racing fuel. 

(296) “Mscf” means thousand standard cubic feet. 

(297) “Multi-jurisdictional retail provider” means a retail provider that provides 

electricity to consumers in California and in one or more other states in a 

contiguous service territory or from a common power system. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 39 February 2015 

(298) “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 wastes include yard waste, 

refuse-derived fuel, and motor vehicle maintenance materials. 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), paper, 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. 

(299) “NAICS” means North American Industry Classification System. 

(300) “Nameplate generating capacity” means the maximum rated output of a 

generator under specific conditions designated by the manufacturer. 

Generator nameplate capacity is usually indicated in units of kilovolt-amperes 

(kVA) and in Kilowatts (kW) on a nameplate physically attached to the 

generator. 

(301) “Naphthas” (< 401°F) is a generic term applie d to a petroleum fraction with an 

approximate boiling range between 122°F and 400°F. The naphtha fraction 

of crude oil is the raw material for gasoline and is composed largely of 

paraffinic hydrocarbons. 

(302) “Natural gas” means a naturally occurring mixture or process derivative of 

hydrocarbon and non-hydrocarbon gases found in geologic formations 

beneath the earth’s surface, of which its constituents include, methane, 

heavier hydrocarbons and carbon dioxide. Natural gas may be field quality 

(which varies widely) or pipeline quality. For the purposes of this article, the 

definition of natural gas includes similarly constituted fuels such as field 

production gas, process gas, and fuel gas. 

(303) “Natural gas distribution facility” means the collection of all distribution 

pipelines, metering stations, and regulating stations that are operated by a 

local distribution company (LDC) that is regulated as a separate operating 

company by a public utility commission or that are operated as an 

independent municipally-owned distribution system. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 40 February 2015 

(304) “Natural gas driven pneumatic pump” means a pump that uses pressurized 

natural gas to move a piston or diaphragm, which pumps liquids on the 

opposite side of the piston or diaphragm. 

(305) “Natural gas liquids” or “NGLs” means those hydrocarbons in natural gas that 

are separated from the gas as liquids through the process of absorption, 

condensation, adsorption, or other methods. Natural gas liquids can be 

classified according to their vapor pressures as low (condensate), 

intermediate (natural gasoline), and high (liquefied petroleum gas) vapor 

pressure. Generally, such liquids consist of ethane, propane, butanes, 

pentanes, and higher molecular weight hydrocarbons. Bulk NGLs refers to 

mixtures of NGLs that are sold or delivered as undifferentiated product from 

natural gas processing plants. 

(306) “Natural gas liquid fractionator” means an installation that fractionates natural 

gas liquids (NGLs) into their constituent liquid products (ethane, propane, 

normal butane, isobutene or pentanes plus) for supply to downstream 

facilities. 

(307) “Natural gas supplier” means, for the purposes of this article, the local 

distribution company or interstate pipeline that owns or operates the 

distribution pipelines that physically deliver natural gas to end users. 

(308) “Natural gasoline” means a mixture of liquid hydrocarbons (mostly pentanes 

and heavier hydrocarbons) extracted from natural gas. It includes 

isopentane. Natural gasoline is a natural gas liquid of intermediate vapor 

pressure. 

(309) “NERC e-Tag” means North American Electric Reliability Corporation (NERC) 

energy tag representing transactions on the North American bulk electricity 

market scheduled to flow between or across balancing authority areas. 

(310) “Net generation” or “net power generated” means the gross generation minus 

station service or unit service power requirements, expressed in megawatt 

hours (MWh) per year. In the case of cogeneration, this value is intended to 

include internal consumption of electricity for the purposes of a production 

process, as well as power put on the grid. 

(311) “Nitrous oxide” or “N2O” means a GHG consisting at the molecular level of

two nitrogen atoms and a single oxygen atom. 

(312) “Nonconformance” means the failure to use the methods or emission factors 

specified in this article to calculate emissions, or the failure to meet any other 

requirements of the regulation. 

(313) “Non-exempt biomass-derived CO2” means CO2 emissions resulting from the 

combustion of fuel not listed under section 95852.2(a) of the cap-and-trade 

regulation, or that does not meet the requirements of section 95131(i) of this 

article.
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 41 February 2015 

(314) “Non-exempt biomass-derived fuel” means fuel not listed under section 

95852.2(a) of the cap-and-trade regulation, or that does not meet the 

requirements of section 95131(i) of this article. 

(315) “Non-fuel based renewable electricity generating unit” means a unit that 

generates electricity not from fuel sources, but from renewable energy 

sources, such as solar, wind, or hydropower. For the purpose of this article, a 

non-fuel based renewable electricity generating unit does not include other 

types of generation explicitly listed in section 95112(a)-(f). 

(316) "Non-submitted/non-verified emissions data report" means an emissions data 

report that is not submitted to ARB by the applicable reporting deadline, or for 

which a verification statement has not been issued by the applicable 

verification deadline. 

(317) “North American Industry Classification System (NAICS) code(s)” means the 

six-digit code(s) that represent the product(s)/activity(s)/service(s) at a facility 

or supplier as defined in North American Industrial Classification System 

Manual 2007, available from the U.S. Department of Commerce, National 

Technical Information Service. 

(318) “Offset project” means all equipment, materials, items, or actions that are 

directly related to or have an impact upon GHG reductions, project emissions 

or GHG removal enhancements within the offset project boundary. 

(319) “Offset project boundary” is defined by and includes all GHG emission 

sources, GHG sinks or GHG reservoirs that are affected by an offset project 

and under control of the Offset Project Operator or Authorized Project 

Designee. GHG emissions sources, GHG sinks or GHG reservoirs not under 

control of the Offset Project Operator or Authorized Project Designee are not 

included in the offset project boundary. 

(320) “Offset project data report” means the report prepared by an Offset Project 

Operator or Authorized Project Designee each year that provides the 

information and documentation required by this article or a compliance offset 

protocol. 

(321) “Offset project operator” means the entity(ies) with legal authority to 

implement the offset project. 

(322) “Offset project specific verifier” means an individual who has been accredited 

by ARB to verify offset projects of a specific offset project type. 

(323) “Offset protocol” means a documented set of procedures and requirements to 

quantify ongoing GHG reductions or GHG removal enhancements achieved 

by an offset project and calculate the project baseline. Offset protocols 

specify relevant data collection and monitoring procedures, emission factors 

and conservatively account for uncertainty and activity-shifting and marketshifting leakage risks associated with an offset project. 

(324) “Offshore,” for purposes of this article, means all waters within three nautical 

miles of the California baseline, starting at the California-Oregon border and 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 42 February 2015 

ending at the California-Mexico border at the Pacific Ocean, inclusive. For 

purposes of this definition, “California baseline” means the mean lower low 

water line along the California Coast. 

(325) “Oil well” means a well completed for the production of crude oil from at least 

one oil zone or reservoir. 

(326) “Oil and gas systems specialist” means a verifier accredited to meet the 

requirements of section 95131(a)(2) for providing verification services to 

operators petroleum refineries, hydrogen production units or facilities, and 

petroleum and natural gas systems listed in section 95101(e). 

(327) “Onshore petroleum and natural gas production facility” means all petroleum 

or natural gas equipment on a well pad, or associated with a well pad or to 

which emulsion is transferred and CO2 EOR operations that are under 

common ownership or common control including leased, rented, or contracted 

activities by an onshore petroleum and natural gas production owner or 

operator that are located in a single basin as defined in 40 CFR §98.238. 

When a commonly owned cogeneration plant is within the basin, the 

cogeneration plant is only considered part of the onshore petroleum and 

natural gas production facility if the onshore petroleum and natural gas 

production facility operator or owner has a greater than fifty percent 

ownership share in the cogeneration plant. Where a person or operating 

entity owns or operates more than one well in a basin, then all onshore 

petroleum and natural gas production equipment associated with all wells that 

the person or entity owns or operates in the basin would be considered one 

facility. 

(328) “Onshore petroleum and natural gas production owner or operator” means the 

person or entity who holds the permit to operate petroleum and natural gas 

wells on the drilling permit or an operating permit where no drilling permit is 

issued, which operates an onshore petroleum and/or natural gas production 

facility (as described in section 95102(a)). Where petroleum and natural gas 

wells operate without a drilling or operating permit, the person or entity that 

pays the State or Federal business income taxes is considered the owner or 

operator. 

(329) “On-site” or “onsite” in the context of GHG reporting means within the facility 

boundary. 

(330) “Operating pressure” means the containment pressure that characterizes the 

normal state of gas or liquid inside a particular process, pipeline, vessel or 

tank. 

(331) “Operational control” for a facility subject to this article means the authority to 

introduce and implement operating, environmental, health and safety policies. 

In any circumstance where this authority is shared among multiple entities, 

the entity holding the permit to operate from the local air pollution control 

district or air quality management district is considered to have operational 

control for purposes of this article. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 43 February 2015 

(332) “Operator” means the entity, including an owner, having operational control of 

a facility. For onshore petroleum and natural gas production, the operator is 

the operating entity listed on the state well drilling permit, or a state operating 

permit for wells where no drilling permit is issued by the state. 

(333) “Operating Pressure,” for purposes of Appendix B means the working 

pressure that characterizes the conditions of crude oil, condensate, or 

produced water inside a particular process, pipeline, vessel or tank. In 

general, low pressure liquid is under less than approximately 200 psig of 

pressure. 

(334) “Outside of the facility boundary” means not within the physical boundary of 

the facility (regardless of ownership or operational control), or not in the same 

operational control of the reporting entity if within the same physical boundary 

of the facility. For example, an entity outside of the facility boundary may 

include another facility not in the reporting entity’s operational control, another 

facility under the same operational control but considered a separate facility 

according to the definition of “facility” in this section, or an on-site industrial 

operation (e.g. a cogeneration system) within the facility fence line but that is 

operated by another operator and for which the on-site industrial operation 

has not been included in the reporting entity’s GHG report. 

(335) “Parasitic load” means the amount of electricity consumed by auxiliary 

equipment that supports the electricity generation or cogeneration process. 

The equipment may include fans, pumps, drive motors, pollution control 

equipment, lighting, computer, CEMS, and other equipment. 

(336) “Particular end-user” means a final purchaser of an energy product (e.g. 

electricity or thermal energy) for whom the energy product is delivered for 

final consumption and not for the purposes of retransmission or resale. 

(337) “Pentane” is the n-pentane, straight chain, isomer of C5H12 under the 

International Union of Pure and Applied Chemistry (IUPAC) nomenclature. 

(338) “Pentanes plus” or “C5+” means a mixture of hydrocarbons that is a liquid at 

ambient temperature and pressure, and consists mostly of pentanes (five 

carbon chain) and higher carbon number hydrocarbons. Pentanes plus 

includes normal pentane, isopentane, hexanes-plus (natural gasoline), and 

plant condensate. 

(339) “Perfluorocarbons” or “PFCs” means a class of greenhouse gases consisting 

on the molecular level of carbon and fluorine. 

(340) “Percent Water Cut,” for purposes of Appendix B, means the percentage of 

water by volume, of the total emulsion throughput as measured using ASTM 

D-4007-08. The percent water cut is expressed as a percentage. 

(341) “Performance review” means an assessment conducted by ARB of an 

applicant seeking to become accredited as a verification body, verifier, lead 

verifier, offset project specific verifier, or sector specific verifier pursuant to 

section 95132 of this article. Such an assessment may include a review of 

applicable past sampling plans, verification reports, verification statements, 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 44 February 2015 

conflict of interest submittals, and additional information or documentation 

regarding the applicant’s fitness for qualification. 

(342) “Petroleum” means oil removed from the earth and the oil derived from tar 

sands and shale. 

(343) “Petroleum coke” means a black solid residue, obtained mainly by cracking 

and carbonizing of petroleum derived feedstocks, vacuum bottoms, tar and 

pitches in processes such as delayed coking or fluid coking. It consists 

mainly of carbon (90 to 95 percent), has low ash content, and may be used as 

a feedstock in coke ovens. This product is also known as marketable coke. 

(344) “Petroleum refinery” or “refinery” means any facility engaged in producing 

gasoline, gasoline blending stocks, naphtha, kerosene, distillate fuel oils, 

residual fuel oils, lubricants, or asphalt (bitumen) through distillation of 

petroleum or through redistillation, cracking, or reforming of unfinished 

petroleum derivatives. Facilities that distill only pipeline transmix (off-spec 

material created when different specification products mix during pipeline 

transportation) are not petroleum refineries, regardless of the products 

produced. 

(345) “Physical address,” with respect to a United States parent company as 

defined in this section, means the street address, city, State and zip code of 

that company's physical location. 

(346) “Pipeline dig-in” means unintentional puncture or rupture to a buried natural 

gas transmission and distribution pipeline during excavation activities. 

(347) “Pipeline quality natural gas” means, for the purpose of calculating emissions 

under this article, natural gas having a high heat value greater than 970 

Btu/scf and equal to or less than 1,100 Btu/scf, and which is at least ninety 

percent methane by volume, and which is less than five percent carbon 

dioxide by volume. 

(348) “Point of delivery” or “POD” means the point on an electricity transmission or 

distribution system where a deliverer makes electricity available to a receiver, 

or available to serve load. This point can be an interconnection with another 

system or a substation where the transmission provider’s transmission and 

distribution systems are connected to another system, or a distribution 

substation where electricity is imported into California over a multijurisdictional retail provider’s distribution system. 

(349) “Point of receipt” or “POR” means the point on an electricity transmission or 

distribution system where an electricity receiver receives electricity from a 

deliverer. This point can be an interconnection with another system or a 

substation where the transmission provider’s transmission and distribution 

systems are connected to another system. 

(350) “Point source” means any separately identifiable stationary point from which 

greenhouse gases are emitted. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 45 February 2015 

(351) “Portable” means designed and capable of being carried or moved from one 

location to another. Indications of portability include wheels, skids, carrying 

handles, dolly, trailer, or platform. Equipment is not portable if any one of the 

following conditions exists: 

(A) The equipment is attached to a foundation. 

(B) The equipment or a replacement resides at the same location for more 

than 12 consecutive months. 

(C) The equipment is located at a seasonal facility and operates during the 

full annual operating period of the seasonal facility, remains at the facility 

for at least two years, and operates at that facility for at least three 

months each year. 

(D) The equipment is moved from one location to another in an attempt to 

circumvent the portable residence time requirements of this definition. 

(352) “Portland cement” means hydraulic cement (cement that not only hardens by 

reacting with water but also forms a water-resistant product) produced by 

pulverizing clinkers consisting essentially of hydraulic calcium silicates, 

usually containing one or more of the forms of calcium sulfate as an interground addition. 

(353) “Position holder” means an entity that holds an inventory position in motor 

vehicle fuel, ethanol, distillate fuel, biodiesel, or renewable diesel as reflected 

in the records of the terminal operator or a terminal operator that owns motor 

vehicle fuel or diesel fuel in its terminal. “Position holder” does not include 

inventory held outside of a terminal, fuel jobbers (unless directly holding 

inventory at the terminal), retail establishments, or other fuel suppliers not 

holding inventory at a fuel terminal. 

(354) “Positive emissions data verification statement” means a verification 

statement rendered by a verification body attesting that the verification body 

can say with reasonable assurance that the covered emissions data in the 

submitted emissions data report is free of material misstatement and that the 

emissions data conforms to the requirements of this article. 

(355) “Positive product data verification statement” means a verification statement 

rendered by a verification body attesting that the verification body can say 

with reasonable assurance that the covered product data in the submitted 

emissions data report is free of material misstatement and that the product 

data conforms to the requirements of this article. 

(356) “Positive verification statement” means a verification statement rendered by a 

verification body attesting that the verification body can say with reasonable 

assurance that the submitted emissions data report is free of material 

misstatement and that the emissions data report conforms to the 

requirements of this article. This definition applies to the emissions data 

verification statement and the product data verification statement. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 46 February 2015 

(357) “Power” means electricity, except where the context makes clear that another 

meaning is intended. 

(358) “Power contract” or “written power contract,” as used for the purposes of 

documenting specified versus unspecified sources of imported and exported 

electricity, means a written document, including associated verbal or 

electronic records if included as part of the written power contract, arranging 

for the procurement of electricity. Power contracts may be, but are not limited 

to, power purchase agreements, enabling agreements, electricity 

transactions, and tariff provisions, without regard to duration, or written 

agreements to import or export on behalf of another entity, as long as that 

other entity also reports to ARB the same imported or exported electricity. A 

power contract for a specified source is a contract that is contingent upon 

delivery of power from a particular facility, unit, or asset-controlling supplier’s 

system that is designated at the time the transaction is executed. 

(359) “Premium grade gasoline” is gasoline having an antiknock index, i.e., octane 

rating, greater than 90. This definition applies to the premium grade 

categories of conventional-summer, conventional-winter, reformulatedsummer, and reformulated-winter. For premium grade categories of RBOBsummer, RBOB-winter, CBOB-summer, and CBOB-winter, this definition 

refers to the expected octane rating of the finished gasoline after oxygenate 

has been added to the RBOB or CBOB. 

(360) “Primary fuel” means the fuel that provides the greatest percentage of the 

annual heat input to a stationary fuel combustion unit. 

(361) “Primary Vessel,” for purposes of Appendix B means a separator or tank that 

receives crude oil, condensate, produced water, natural gas, or emulsion from 

one or more crude oil, condensate, or natural gas wells or field gathering 

systems. 

(362) “Prime mover” means the type of equipment such as an engine or water 

wheel that drives an electric generator. “Prime movers” include, but are not 

limited to, reciprocating engines, combustion or gas turbines, steam turbines, 

microturbines, and fuel cells. 

(363) “Process” means the intentional or unintentional reactions between 

substances or their transformation, including, but not limited to, the chemical 

or electrolytic reduction of metal ores, the thermal decomposition of 

substances, and the formation of substances for use as product or feedstock. 

(364) “Process emissions” means the emissions from industrial processes (e.g., 

cement production, ammonia production) involving chemical or physical 

transformations other than fuel combustion. For example, the calcination of 

carbonates in a kiln during cement production or the oxidation of methane in 

an ammonia process results in the release of process CO2 emissions to the 

atmosphere. Emissions from fuel combustion to provide process heat are not 

part of process emissions, whether the combustion is internal or external to 

the process equipment. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 47 February 2015 

(365) “Process emissions specialist” means a verifier accredited to meet the 

requirements of section 95131(a)(2) for providing verification services to 

operators of facilities engaged in cement production, glass production, lime 

manufacturing, pulp and paper manufacturing, iron and steel production, nitric 

acid production, and lead production. 

(366) “Process gas” means any gas generated by an industrial process such as 

petroleum refining. 

(367) “Process Heater” means equipment for the heating of process streams 

(gases, liquids, or solids) other than water through heat provided by fuel 

combustion. 

(368) “Process unit” means the equipment assembled and connected by pipes and 

ducts to process raw materials and to manufacture either a final or an 

intermediate product used in the onsite production of other products. The 

process unit also includes the purification of recovered byproducts. 

(369) “Process vent” means an opening where a gas stream is continuously or 

periodically discharged during normal operation. 

(370) “Produced water” means the resulting water that is produced as a byproduct 

of crude oil or natural gas production. 

(371) “Producer” means a person who owns, leases, operates, controls or 

supervises a California production facility. 

(372) “Product data” means the sector-specific data specified in subarticles 2 and 5 

of this article, including requirements in 40 CFR Part 98. 

(373) “Product data verification statement” means the final statement rendered by a 

verification body attesting whether a reporting entity’s covered product data in 

their emissions data report is free of material misstatement, and whether the 

product data conforms to the requirements of this article. 

(374) “Professional judgment” means the ability to render sound decisions based on 

professional qualifications and relevant greenhouse gas accounting and 

auditing experience. 

(375) “Project baseline” means, in the context of a specific offset project, a 

conservative estimate of business-as-usual GHG emission reductions or 

GHG removal enhancements for the offset project’s GHG emission sources, 

GHG sinks, or GHG reservoirs within the offset project boundary. 

(376) “Propane” is a paraffinic hydrocarbon with molecular formula C3H8. 

(377) “Propylene” is an olefinic hydrocarbon with molecular formula C3H6. 

(378) “Public utility gas corporation” is a gas corporation defined in California Public 

Utilities Code section 222 that is also a public utility as defined in California 

Public Utilities Code section 216. 

(379) “Publicly-owned natural gas utility” means a municipality or municipal 

corporation, a municipal utility district, a public utility district, or a joint powers 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 48 February 2015 

authority that includes one or more of these agencies that furnishes natural 

gas services to end users. 

(380) “Pump” means a device used to raise pressure, drive, or increase flow of 

liquid streams in closed or open conduits. 

(381) “Pump seal emissions” means hydrocarbon gas released from the seal face 

between the pump internal chamber and the atmosphere. 

(382) “Pump seals” means any seal on a pump drive shaft used to keep methane 

and/or carbon dioxide containing light liquids from escaping the inside of a 

pump case to the atmosphere. 

(383) “Purchasing-selling entity” or “PSE” means the entity that is identified on a 

NERC e-Tag for each physical path segment. 

(384) “Pure” means consisting of at least 97 percent by mass of a specified 

substance. For facilities burning biomass fuels, this means the fraction of 

biomass carbon accounts for at least 97 percent of the total amount of carbon 

in the fuel burned at the facility. 

(385) “PURPA Qualifying Facility” means a facility that has acquired a “qualifying 

facility (QF)” certification pursuant to 18 CFR §292.207 under the Public Utility 

Regulatory Policies Act of 1978 (PURPA). 

(386) “QA/QC” means quality assurance and quality control. 

(387) “Qualified exports” is as defined in section 95802(a) of the cap-and-trade 

regulation. 

(388) “Qualified positive emissions data verification statement” means a statement 

rendered by a verification body attesting that the verification body can say 

with reasonable assurance that the covered emissions data in the submitted 

emissions data report is free of material misstatement and is in conformance 

with section 95131(b)(9), but the emissions data may include one or more 

other nonconformances with the requirements of this article which do not 

result in a material misstatement. 

(389) “Qualified positive product data verification statement” means a statement 

rendered by a verification body attesting that the verification body can say 

with reasonable assurance that the covered product data in the submitted 

emissions data report is free of material misstatement and is in conformance 

with section 95131(b)(9), but the product data may include one or more other 

nonconformance(s) with the requirements of this article which do not result in 

a material misstatement. 

(390) “Qualified positive verification statement” means a statement rendered by a 

verification body attesting that the verification body can say with reasonable 

assurance that the submitted emissions data report is free of material 

misstatement and is in conformance with section 95131(b)(9), but the 

emissions data report may include one or more other nonconformance(s) with 

the requirements of this article which do not result in a material misstatement. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 49 February 2015 

This definition applies to the qualified positive emissions data verification 

statement and the qualified positive product data verification statement. 

(391) “Qualified Thermal Output” means the thermal energy generated by a 

cogeneration unit or district heating facility that is sold to particular end-users 

and reported pursuant to MRR section 95112(a)(5)(A) and the thermal energy 

used on-site by industrial processes or operations and heating and cooling 

operations that is not in support of or a part of the electricity generation or 

cogeneration system and is reported pursuant to MRR sections 

95112(a)(5)(C). Qualified thermal output does not include thermal energy 

that is vented, radiated, wasted, or discharged before it is utilized at industrial 

processes or operations, or, for a facility with a cogeneration unit, any thermal 

energy generated by equipment that is not an integral part of the 

cogeneration unit. 

(392) “Quality-assured data” or “quality-assured value” means the data are obtained 

from a monitoring system that is operating within the performance 

specifications and the quality assurance/quality control procedures set forth in 

the applicable rules, for example 40 CFR Part 60 (July 1, 2009) or Part 75, 

(July 1, 2009), which is hereby incorporated by reference, without 

unscheduled maintenance, repair, or adjustment. 

(393) “Rack” means a mechanism for delivering motor vehicle fuel or diesel from a 

refinery or terminal into a truck, trailer, railroad car, or other means of nonbulk transfer. 

(394) “RBOB-summer” or “reformulated blendstock for oxygenate blendingsummer” means a petroleum product which, when blended with a specified 

type and percentage of oxygenate, meets the definition of reformulatedsummer. 

(395) “RBOB-winter” or “reformulated blendstock for oxygenate blending-winter” 

means a petroleum product which, when blended with a specified type and 

percentage of oxygenate, meets the definition of reformulated-winter. 

(396) “Reasonable assurance” means a high degree of confidence that submitted 

data and statements are valid. 

(397) “Reciprocating compressor” means a piece of equipment that increases the 

pressure of a process natural gas or CO2 by positive displacement, employing 

linear movement of a shaft driving a piston in a cylinder. 

(398) “Reciprocating compressor rod packing” means a series of flexible rings in 

machined metal cups that fit around the reciprocating compressor piston rod 

to create a seal limiting the amount of compressed natural gas or CO2 that 

escapes to the atmosphere. 

(399) “Reciprocating internal combustion engine” or “RICE” or “piston engine” 

means an engine that uses heat from the internal combustion of fuel to create 

pressure that drives one or more reciprocating pistons, creating mechanical 

energy. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 50 February 2015 

(400) “Re-condenser” means heat exchangers that cool compressed boil-off gas to 

a temperature that will condense natural gas to a liquid. 

(401) “Refiner” means, for purposes of this article, an individual entity or a 

corporate-wide entity that delivers transportation fuels to end users in 

California that were produced by petroleum refineries owned by that entity or 

a subsidiary of that entity. 

(402) “Refinery fuel gas” or “still gas” means gas generated at a petroleum refinery 

or any gas generated by a refinery process unit, and that is combusted 

separately or in any combination with any type of gas or used as a chemical 

feedstock. 

(403) “Reformulated Gasoline Blendstock for Oxygenate Blending” or “RBOB” has 

the same meaning as defined in title 13 of the California Code of Regulations, 

section 2260(a). 

(404) “Reformulated-summer” means 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 and 40 CFR §80.41, and summer 

RVP standards required under 40 CFR §80.27 or as specified by the state. 

Reformulated gasoline excludes RBOB as well as other blendstock. 

(405) “Reformulated-winter” means 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 and 40 CFR §80.41, but which do 

not meet summer RVP standards required under 40 CFR §80.27 or as 

specified by the state. Note: This category includes Oxygenated Fuels 

Program Reformulated Gasoline (OPRG). Reformulated gasoline excludes 

RBOB as well as other blendstock. 

(406) “Regular grade gasoline” is gasoline having an antiknock index, i.e., octane 

rating, greater than or equal to 85 and less than 88. This definition applies to 

the regular grade categories of conventional-summer, conventional-winter, 

reformulated-summer, and reformulated-winter. For regular grade categories 

of RBOB-summer, RBOB-winter, CBOB-summer, and CBOB-winter, this 

definition refers to the expected octane rating of the finished gasoline after 

oxygenate has been added to the RBOB or CBOB. 

(407) "Relative Accuracy Test Audit" means a method of determining the correlation 

of continuous emissions monitoring system data to simultaneously collected 

reference method test data, for example as required in 40 CFR Part 60 (July 

1, 2009) and 40 CFR Part 75 (July 1, 2009). 

(408) “Rendered animal fat” or “tallow” means fats extracted from animals which are 

generally used as a feedstock in making biodiesel. 

(409) “Renewable diesel” means a motor vehicle fuel or fuel additive that is all of 

the following: 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 51 February 2015 

(A) Registered as a motor vehicle fuel or fuel additive under 40 CFR Part 79; 

(B) Not a mono-alkyl ester; 

(C) Intended for use in engines that are designed to run on conventional 

diesel fuel; and 

(D) Derived from nonpetroleum renewable resources. 

(410) “Renewable energy” means energy from sources that constantly renew 

themselves or that are regarded as practically inexhaustible. Renewable 

energy includes energy derived from solar, wind, geothermal, hydroelectric, 

wood, biomass, tidal power, sea currents, and ocean thermal gradients. 

(411) “Renewable Energy Credit” or “REC” has the same meaning defined in the 

California Energy Commission’s “Renewable Portfolio Standard Eligibility,” 7th

edition, Commission Guidebook, April, 2013; CEC-300‐2013‐005‐ED7‐CMF. 

(412) “Renewable liquid fuels” means fuel ethanol, biomass-based diesel fuel, other 

renewable diesel fuel and other renewable fuels. 

(413) “Reporting entity” means a facility operator, supplier, or electric power entity 

subject to the requirements of this article. 

(414) “Reporting period” means the calendar year which coincides with the data 

year for the GHG report. 

(415) “Reporting year” or “report year” means data year. 

(416) “Reservoir” means a porous and permeable underground natural formation 

containing oil or gas. A reservoir is characterized by a single natural 

pressure. 

(417) “Residual fuel oil” means a general classification for the heavier oils, known 

as No. 5 and No. 6 fuel oils, that remain after the distillate fuel oils and lighter 

hydrocarbons are distilled away in refinery operations. 

(418) “Residue gas and residue gas compression” means, respectively, production 

lease natural gas from which gas liquid products and, in some cases, nonhydrocarbon components have been extracted such that it meets the 

specifications set by a pipeline transmission company, and/or a distribution 

company; and the compressors operated by the processing facility, whether 

inside the processing facility boundary fence or outside the fence-line, that 

deliver the residue gas from the processing facility to a transmission pipeline. 

(419) “Retail end-use customer” or “retail end user” means a residential, 

commercial, agricultural, or industrial electric customer who buys electricity to 

be consumed as a final product and not for resale. 

(420) “Retail provider” means an entity that provides electricity to retail end users in 

California and is an electric corporation as defined in Public Utilities Code 

section 218, electric service provider as defined in Public Utilities Code 

section 218.3, local publicly owned electric utility as defined in Public Utilities 

Code section 224.3, a community choice aggregator as defined in Public 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 52 February 2015 

Utilities Code section 331.1, or the Western Area Power Administration. For 

purposes of this article, electric cooperatives, as defined by Public Utilities 

Code section 2776, are excluded. 

(421) “Retail sales” means electricity sold to retail end users. 

(422) “Sales oil” means produced crude oil or condensate measured at the 

production lease automatic custody transfer (LACT) meter or custody transfer 

tank gauge. 

(423) “Secondary Vessel,” for purposes of Appendix B means a separator or tank 

that receives crude oil, condensate, produced water, natural gas, or emulsion 

from one or more primary vessel separators or tanks. 

(424) “Sector” means a broad industrial categorization such as specified in section 

95101. 

(425) “Sector specific verifier” means a verifier accredited pursuant to section 

95132(b)(5)(A) as one or more of the following types of specialists defined 

pursuant to this section: a transactions specialist, an oil and gas systems 

specialist, or a process emissions specialist. 

(426) “Separator” means a sump or vessel used to separate crude oil, condensate, 

natural gas, produced water, emulsion or solids. 

(427) “Short ton” means a common international measurement for mass, equivalent 

to 2,000 pounds. 

(428) “Shutdown” means the cessation of operation of an emission source for any 

purpose. 

(429) “Simplified block diagram” means a diagram consisting of boxes, shapes, 

lines, arrows, and labels that meets the requirements of section 95112(a)(6). 

A simplified block diagram is not an architectural drawing or an engineering 

drawing that shows the likeness of the physical objects being depicted and 

their actual locations and sizes in scale; it is a simplified graphical 

representation of the objects being depicted, their relative locations, and how 

they are connected through flows of energy or energy carrier (e.g. steam, 

water, electricity, or fuel). 

(430) “Sink” or “sink to load” or “load sink” means the sink identified on the physical 

path of NERC e-Tags, where defined points have been established through 

the NERC Registry. Exported electricity is disaggregated by the sink on the 

NERC e-Tag, also referred to as the final point of delivery on the NERC eTag. 

(431) “Sorbent” means a material used to absorb or adsorb liquids or gases. 

(432) “Sour natural gas” means natural gas that contains significant concentrations 

of hydrogen sulfide (H2S) and/or carbon dioxide that exceed the 

concentrations specified for commercially saleable natural gas delivered from 

transmission and distribution pipelines. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 53 February 2015 

(433) “Source” means greenhouse gas source; any physical unit, process, or other 

use or activity that releases a greenhouse gas into the atmosphere. 

(434) “Source category” means categories of emission sources as defined by 

Tables A-3, A-4, and A-5 of 40 CFR Part 98. 

(435) “Source of generation” or “generation source” means the generation source 

identified on the physical path of NERC e-Tags, where defined points have 

been established through the NERC Registry. Imported electricity and 

wheels are disaggregated by the source on the NERC e-Tag, referred to as 

the first point of receipt. 

(436) “Specified source of electricity” or “specified source” means a facility or unit 

which is permitted to be claimed as the source of electricity delivered. The 

reporting entity must have either full or partial ownership in the facility/unit or 

a written power contract to procure electricity generated by that facility/unit. 

Specified facilities/units include cogeneration systems. Specified source also 

means electricity procured from an asset-controlling supplier recognized by 

the ARB. 

(437) “SSM” means periods of startup, shutdown and malfunction. 

(438) “Stand-alone electricity generating facility” means an electricity generating 

facility whose primary business and sole industrial operation is electricity 

generation, and is not a cogeneration or bigeneration facility. 

(439) “Standard conditions” or “standard temperature and pressure (STP)” means 

either 60 or 68 degrees Fahrenheit and 14.7 pounds per square inch 

absolute. 

(440) “Standard cubic foot” or “scf” is a measure of quantity of gas, equal to a cubic 

foot of volume at 60 degrees Fahrenheit and either 14.696 pounds per square 

inch (1 atm) or 14.73 PSI (30 inches Hg) of pressure. 

(441) “Steam generator” means equipment that produces steam using an external 

heat source. 

(442) “Stationary” means neither portable nor self-propelled, and operated at a 

single facility. 

(443) “Storage tank” means any tank, other container, or reservoir used for the 

storage of organic liquids, excluding tanks that are permanently affixed to 

mobile vehicles such as railroad tank cars, tanker trucks or ocean vessels. 

(444) “Sub-facility” for purposes of reporting data disaggregated pursuant to section 

95156(a), means the geographic area, or areas, within a single township or 

within a group of contiguous or adjacent townships identified in the Public 

Land Survey System of the United States, where operations and equipment 

are located. The operator may disaggregate sub-facilities based on 

contiguous township areas to smaller sub-facilities according to similar 

operational, geological, or geographical characteristics. Sub-facility 

disaggregation may be retained from year to year, or may be updated when 

some of the operations cease or equipment is reconfigured within the 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 54 February 2015 

previously designated sub-facilities. Sub-facility disaggregation must be 

updated from previous reporting years if there are new operations or 

equipment that lies outside previous township boundaries. The Principal 

Meridian name, Township and Range designations, and the section numbers 

that apply to each sub-facility, must be identified in the operator’s GHG 

Monitoring Plan required pursuant to section 95105(c). The operator must 

also describe in the GHG Monitoring Plan any operational, geological or 

geographical characteristics used to determine sub-facility boundaries. 

(445) “Substitute power” or “substitute electricity” means electricity that is provided 

to meet the terms of a power purchase contract with a specified facility or unit 

when that facility or unit is not generating electricity. 

(446) “Sulfur hexafluoride” or “SF6” means a GHG consisting on the molecular level 

of a single sulfur atom and six fluorine atoms. 

(447) “Sump,” for purposes of Appendix B means a lined or unlined surface 

impoundment or depression in the ground that, during normal operations, is 

used for separating crude oil, condensate, produced water, emulsion, or 

solids. 

(448) “Supplemental firing” means an energy input to the cogeneration facility used 

only in the thermal process of a topping cycle plant, or in the electricity 

generating or manufacturing process of a bottoming cycle cogeneration 

facility. 

(449) “Supplier” means a producer, importer, exporter, position holder, interstate 

pipeline operator, or local distribution company of a fossil fuel or an industrial 

greenhouse gas. 

(450) “Sweet gas” means natural gas with low concentrations of hydrogen sulfide 

(H2S) and/or carbon dioxide (CO2) that does not require (or has already had) 

acid gas treatment to meet pipeline corrosion-prevention specifications for 

transmission and distribution. 

(451) “Tactical support equipment” is as defined in title 17, California Code of 

Regulations, section 93116.2(a)(36). 

(452) “Tank,” for the purposes of Appendix B, means a container, constructed 

primarily of non-earthen materials, used for holding or storing crude oil, 

condensate, produced water, or emulsion. 

(453) “Tentatively Identified Compound List,” for purposes of Appendix B means a 

list of target compounds that laboratories can use to evaluate uncommon 

gaseous compounds when performing a Gas Chromatograph/ Mass 

Spectrometry analysis. 

(454) “Terminal” means a motor vehicle fuel or diesel fuel storage and distribution 

facility that is supplied by pipeline or vessel, and from which fuel may be 

removed at a rack. “Terminal” includes a fuel production facility where motor 

vehicle or diesel fuel is produced and stored and from which fuel may be 

removed at a rack. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 55 February 2015 

(455) “Terminal operator” means any entity that owns, operates or otherwise 

controls a terminal that is supplied by pipeline or vessel and from which 

accountable fuel products may be removed at a rack.

(456) “Thermal energy” means the thermal output produced by a combustion 

source used directly as part of a manufacturing process, 

industrial/commercial process, or heating/cooling application, but not used to 

produce electricity. 

(456) “Thermal host” means the user of the steam or heat output of a cogeneration 

or bigeneration facility. 

(458) “Three-Phase Separator,” for purposes of Appendix B, means a pressurized 

vessel sealed from the atmosphere used to gravimetrically separate crude oil, 

produced water and gases. 

(459) “Throughput” for the purposes of Appendix B, means the average volume of 

liquid processed by a vessel over a period of time, such as barrels per day. 

The throughput of crude oil or condensate may need to be calculated using 

the Percent Water Cut. The throughput of crude oil or condensate is 

calculated as the difference in volume between these liquids and the 

produced water. 

(460) “Tier” means the level of calculation method from 40 CFR §98.33 that is 

required for a stationary combustion source in section 95115 of this article. 

(461) “Tier 1” means a stationary combustion calculation method that applies 

default values for emission factors and high heat value to generate an 

emissions estimate, as specified in 40 CFR §98.33. 

(462) “Tier 2” means a stationary combustion calculation method that applies a 

default value for an emission factor and a fuel’s measured high heat value (or 

a boiler efficiency for steam-generating solid fuels) to generate an emissions 

estimate, as specified in 40 CFR §98.33. 

(463) “Tier 3” means a stationary combustion calculation method that utilizes a 

fuel’s measured carbon content to generate an emissions estimate, as 

specified in 40 CFR §98.33. 

(464) “Tier 4” means a stationary combustion calculation method that utilizes 

quality-assured data from a continuous emission monitoring system to 

generate an emissions estimate, as specified in 40 CFR §98.33. This method 

may also capture process emissions from a common stack. 

(465) “Tolling agreement” means an agreement whereby a party rents a power 

plant from the owner. The rent is generally in the form of a fixed monthly 

payment plus a charge for every MW generated, generally referred to as a 

variable payment. 

(466) “Topping cycle” means a type of cogeneration system in which the energy 

input to the plant is first used to produce electricity, and at least some of the 

reject heat from the electricity production process is then used to provide 

useful thermal output. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 56 February 2015 

(467) “Total thermal output” means the total amount of usable thermal energy 

generated by a cogeneration or bigeneration unit that can potentially be made 

available for use in any industrial or commercial processes, heating or cooling 

applications, or delivered to other end users. This quantity excludes the heat 

content of returned condensate and makeup water, but includes the thermal 

energy used for supporting (but not directly used for) power generation, 

thermal energy used in other on-site processes or applications that are not in 

support of or a part of the electricity generation system, thermal energy 

provided or sold to particular end-user, and thermal energy that is otherwise 

not utilized. Thermal energy directly used for power generation (e.g., steam 

used to drive a steam turbine generator for electricity generation) is not 

included in total thermal output. 

(468) “Transactions specialist” means a verifier accredited to meet the requirements 

of section 95131(a)(2) for providing verification services to electric power 

entities; suppliers of petroleum products and biofuels; suppliers of natural 

gas, natural gas liquids, and liquefied petroleum gas; and suppliers of carbon 

dioxide. 

(469) “Transmission-distribution (T-D) transfer station” means a metering-regulating 

station where a local distribution company takes part or all of the natural gas 

from a transmission pipeline and puts it into a distribution pipeline. 

(470) “Transmission pipeline” means a high pressure cross country pipeline 

transporting saleable quality natural gas from production or natural gas from 

processing to natural gas distribution pressure let-down, metering, regulating 

stations, where the natural gas is typically odorized before delivery to 

customers. 

(471) “Traceable” means that a standard used to calibrate a device has an 

unbroken chain of comparisons to a stated reference (such as a standard set 

by the National Institute of Standards and Technology), with each comparison 

having a stated uncertainty 

(472) “Turbine” means any of various types of machines in which the kinetic energy 

of a moving fluid is converted into mechanical energy by causing a bladed 

rotor to rotate. 

(473) “Turbine meter” means a flow meter in which a gas or liquid flow rate through 

the calibrated tube spins a turbine from which the spin rate is detected and 

calibrated to measure the fluid flow rate. 

(474) “Two-Phase Separator,” for purposes of Appendix B, means a pressurized 

vessel sealed from the atmosphere used to gravimetrically separate crude oil 

and produced water that still contain entrained gases. 

(475) “Type of thermal energy product” means the form in which energy is 

transferred from a facility producing thermal energy to another facility, or if not 

transferred, the form in which the energy is used. Types of thermal energy 

products include steam, hot water, chilled water, and distilled water. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 57 February 2015 

(476) “Uncertainty” means the degree to which data or a data system is deemed to 

be indefinite or unreliable. 

(477) “Uncontrolled blowdown system” means the use of a blowdown procedure 

that does not result in the recovery of emissions for flaring or re-injection. 

(478) “Unconventional wells” means crude oil or gas wells in producing fields that 

employ hydraulic fracturing to enhance crude oil or gas production volumes. 

(479) “United States parent company(s)” mean the highest-level United States 

company(s) with an ownership interest in the reporting entity as of December 

31 of the reporting year. 

(480) “Unspecified source of electricity” or “unspecified source” means a source of 

electricity that is not a specified source at the time of entry into the transaction 

to procure the electricity. 

(481) “Upstream entity” means the last entity in the chain of title prior to the fuel 

being received by the reporting entity. 

(482) “Urban waste” means waste pallets, crates, dunnage, manufacturing and 

construction wood waste, tree trimmings, mill residues and range land 

maintenance residues. 

(483) “U.S. EPA” means the United States Environmental Protection Agency. 

(484) “Used oil” means a petroleum-derived or synthetically-derived oil whose 

physical properties have changed as a result of handling or use, such that the 

oil cannot be used for its original purpose. Used oil consists primarily of 

automotive oils (e.g., used motor oil, transmission oil, hydraulic fluids, brake 

fluid, etc.) and industrial oils (e.g., industrial engine oils, metalworking oils, 

process oils, industrial grease, etc.). 

(485) “Vapor recovery system” means any equipment located at the source of 

potential gas emissions to the atmosphere or to a flare, that is composed of 

piping, connections, and, if necessary, flow-inducing devices, and that is used 

for routing the gas back into the process as a product and/or fuel. 

(486) “Vegetable oil” means oils extracted from vegetation that are generally used 

as a feedstock in making biodiesel. 

(487) “Vented emissions” means intentional or designed releases of CH4 or CO2

containing natural gas or hydrocarbon gas (not including stationary 

combustion flue gas), including process designed flow to the atmosphere 

through seals or vent pipes, equipment blowdown for maintenance, and direct 

venting of gas used to power equipment (such as pneumatic devices). 

(488) “Verification” means a systematic, independent and documented process for 

evaluation of a reporting entity’s emissions data report against ARB’s 

reporting procedures and methods for calculation and reporting GHG 

emissions and product data. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 58 February 2015 

(489) “Verification body” means a firm accredited by ARB that is able to render a 

verification statement and provide verification services for reporting entities 

subject to reporting under this article. 

(490) “Verification services” means services provided during verification as 

specified in section 95131 beginning with the development of the verification 

plan or first site visit, including but not limited to reviewing a reporting entity’s 

emissions data report, ensuring its accuracy according to the standards 

specified in this article, assessing the reporting entity’s compliance with this 

article, and submitting a verification statement(s) to the ARB. 

(491) “Verification statement” means the final statement rendered by a verification 

body attesting whether a reporting entity’s emissions data report is free of 

material misstatement, and whether it conforms to the requirements of this 

article. This definition applies to the emissions data verification statement and 

the product data verification statement. 

(492) “Verification team” means all of those working for a verification body, 

including all subcontractors, to provide verification services for a reporting 

entity. 

(493) “Verified emissions data report” means an emissions data report that has 

been reviewed by a third-party verifier and has a verification statement, or 

statements, if applicable, submitted to the ARB. 

(494) “Verifier” means an individual accredited by ARB to carry out verification 

services as specified in section 95131. 

(495) “Verifier review” means a verifier conducts all reviews and services in section 

95131, except the material misstatement assessment under section 

95131(b)(12). If some of the sources are selected for data checks based on 

the sampling plan, the verifier will check for conformance with the 

requirements of this article. 

(496) “Vertical well” means a well bore that is primarily vertical but has some 

unintentional deviation to enter one or more subsurface targets that are offset horizontally from the surface location, intercepting the targets either 

vertically or at an angle. 

(497) “Vessel,” for the purposes of Appendix B, means any container, constructed 

primarily of non-earthen materials, used to separate or store crude oil, 

condensate, natural gas, produced water, or emulsion. 

(498) “Volatile organic compound” or “VOC” means any volatile compound of 

carbon, excluding carbon monoxide, carbon dioxide, carbonic acid, metallic 

carbides or carbonates, and ammonium carbonate, which participates in 

atmospheric photochemical reactions. 

(499) “VOCC3-C9,” for purposes of Appendix B, means Volatile Organic Compounds 

with three to nine carbon atoms. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 59 February 2015 

(500) “VOCC10+,” for purposes of Appendix B, means Volatile Organic Compounds 

with 10 or more carbon atoms. This value is needed for laboratory and 

quality control purposes. 

(501) “Weighted monthly average” means the sum of the products of two values 

measured during the same time period divided by the sum of the values not 

being averaged. For weighted average HHV it would be the sum of the 

products of volume and HHV measured during the same time period divided 

by the sum of the volumes. 

(502) “Well completions” means the process that allows for the flow of petroleum or 

natural gas from newly drilled wells to expel drilling and reservoir fluids and 

test the reservoir flow characteristics, steps which may vent produced gas to 

the atmosphere via an open pit or tank. Well completion also involves 

connecting the well bore to the reservoir, which may include treating the 

formation or installing tubing, packer(s), or lifting equipment, steps that do not 

significantly vent natural gas to the atmosphere. This process may also 

include high-rate flowback of injected gas, water, oil, and proppant used to 

fracture or re-fracture and prop open new fractures in existing lower 

permeability gas reservoirs, steps that may vent large quantities of produced 

gas to the atmosphere. 

(503) “Well testing venting and flaring” means venting and/or flaring of natural gas 

at the time the production rate of a well is determined for regulatory, 

commercial, or technical purposes. If well testing is conducted immediately 

after a well completion or workover, then it is considered part of well 

completion or workover. 

(504) “Well workover” means the process(es) of performing one or more of a variety 

of remedial operations on producing petroleum and natural gas wells to try to 

increase production. This process also includes high-rate flowback of 

injected gas, water, oil, and proppant used to re-fracture and prop-open new 

fractures in existing low permeability gas reservoirs, steps that may vent large 

quantities of produced gas to the atmosphere. 

(505) “Wellhead” means the piping, casing, tubing and connected valves protruding 

above the Earth’s surface for an oil and/or natural gas well. The wellhead 

ends where the flow line connects to a wellhead valve. Wellhead equipment 

includes all equipment, permanent and portable, located on the improved land 

area (i.e. well pad) surrounding one or multiple wellheads. 

(506) “Wet natural gas” means natural gas in which water vapor exceeds the 

concentration specified for commercially saleable natural gas delivered from 

transmission and distribution pipelines. This input stream to a natural gas 

dehydrator is referred to as “wet gas”. 

(507) “Wholesale sales” means sales to other LDCs. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 60 February 2015 

(b) For the purposes of this article, the following definitions associated with reported 

product data shall apply: 

(1) “Air dried ton of paper” means paper with 6 percent moisture content. 

(2) “Almond” means the edible seed of the almond (Prunus amygdalus). 

(3) “Aluminum alloy” is an alloy in which aluminum is the predominant metal and 

the alloying elements may typically be copper, magnesium, manganese, zinc, 

or other elemental additives or any combination of elements added.(4) 

(4) “Aluminum and aluminum alloy billet” means a solid bar of nonferrous metal, 

produced by casting molten aluminum alloys that is suitable for subsequent 

rolling, casting, or extrusion. 

(5) “Aseptic preparation” is a system in which a product is sterilized before filling 

into pre-sterilized packs under sterile conditions.

(6) “Aseptic tomato paste” means tomato paste packaged using aseptic 

preparation. Aseptic paste is normalized to 31 percent tomato soluble solids. 

Aseptic paste normalized to 31% TSS = (%TSS - raw TSS)/(31 - raw TSS) 

(7) “Aseptic whole and diced tomato” means the sum of whole and diced 

tomatoes packaged using aseptic preparation. Sum of aseptic whole and 

diced tomatoes = whole tomatoes + (diced tomatoes x 1.05)) 

(8) “Baked potato chip” means a potato chip made from potato dough that is 

rolled to a specified thickness, cut into a chip shape and then toasted in an 

oven. 

(9) "Barrel of oil equivalent," with respect to reporting of oil and gas production, 

means barrels of crude oil produced, plus associated gas and dry gas 

produced, converted to barrels at 5.8 MMBtu per barrel. 

(10) “Bathroom tissue” means a thin, soft, lightweight, sanitized paper used in 

bathrooms for personal cleanliness. Bathroom tissue is usually sold as a long 

strip of perforated paper wrapped around a paperboard core. 

(11) “Blending component” means a material blended into a primary refinery 

product, such as n-butane (EIA product codes 249 and 643), isobutane (EIA 

product codes 247 and 644), butylene (EIA product code 633), isobutylene 

(EIA product code 634), pentanes plus (EIA product code 220), ethyl tertiary 

butyl ether (ETBE) (EIA product code 142), methyl tertiary butyl ether (MTBE) 

(EIA product code 144), other oxygenates (EIA product code 445), and fuel 

ethanol (EIA product code 141). 

(12) "Butter" means the product made by gathering the fat of fresh or ripened milk 

or cream into a mass that also contains a small portion of other milk 

constituents including nonfat solids. Moisture and nonfat solids are essential 

constituents of butter. 

(13) "Buttermilk" means the low-fat portion of milk or cream remaining after the 

milk or cream has been churned to make butter. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 61 February 2015 

(14) “Buttermilk powder” means milk powder obtained by drying liquid buttermilk 

that was derived from the churning of butter and pasteurized prior to 

condensing. Buttermilk powder has a protein content of no less than 30%. It 

may not contain, or be derived from, nonfat dry milk, dry whey, or products 

other than buttermilk, and contains no added preservatives, neutralizing 

agents, or other chemicals. 

(15) “By-product hydrogen gas” means pure hydrogen gas produced as a result of 

a process or processes dedicated to producing other products (e.g. catalytic 

reforming). 

(16) “Calcined coke” means petroleum coke purified to a dry, pure form of carbon 

suitable for use as anode and other non-fuel applications. 

(17) "Calcium ammonium nitrate solution" means calcium nitrate that contains 

ammonium nitrate and water. Calcium ammonium nitrate solution is generally 

used as agricultural fertilizer. 

(18) “Casein” means a group of proteins found in milk which is coagulated by 

enzymes and acid to form cheese. 

(19) "Cheese" means a food product derived from milk that is produced in a wide 

range of flavors, textures, and forms by coagulation of the milk protein casein. 

(20) “Clinker” means the mass of fused material produced in a cement kiln from 

which finished cement is manufactured by milling and grinding. 

(21) "Cold rolled and annealed steel sheet" means steel that is cold rolled and 

then annealed. Cold rolling means the changes in the structure and shape of 

steel through rolling, hammering or stretching the steel at a low temperature. 

Annealing is a heat or thermal treatment process by which a previously coldrolled steel coil is made more suitable for forming and bending. The steel 

sheet is heated to a designated temperature for a sufficient amount of time 

and then cooled. 

(22) "Cold rolling of steel" means the changes in the structure and shape of steel 

through rolling, hammering or stretching the steel at a low temperature. 

(23) "Concentrated milk" means the liquid food obtained by partial removal of 

water from milk. The milkfat and total milk solids contents of the food are not 

less than 7.5 and 25.5 percent, respectively. It is pasteurized, but is not 

processed by heat so as to prevent spoilage. It may be homogenized. 

(24) "Condensed milk" means the food obtained by partial removal of water only 

from a mixture of milk and nutritive carbohydrate sweeteners. The finished 

food contains not less than 8 percent by weight of milkfat, and not less than 

28 percent by weight of total milk solids. The quantity of nutritive 

carbohydrate sweetener used is sufficient to prevent spoilage. The food is 

pasteurized and may be homogenized. 

(25) “Container Glass pulled" means the quantity of glass removed from the 

melting furnace in the container glass manufacturing process where 

"container glass" is defined as glass products intended for packaging. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 62 February 2015 

(26) “Corn” means the kernels of the dent corn plant (Zea mays var. indentata.) 

that have been shelled and contain no more than 10.0 percent of other grains. 

(27) “Corn chip” is a food product made from masa (ground corn dough) that is 

rolled to a specific thickness, cut into a chop shape, lightly toasted in an oven, 

and then deep fried. 

(28) “Corn curl” is a food product made from a deep-fried extrusion of masa 

(ground corn dough). 

(29) “Corn entering wet milling process” means corn entering the process in which 

feed corn is steeped in liquid in order to help separate the kernel’s various 

components into starch, germ, fiber and protein (gluten) and then process the 

components into useful products such as starch, syrup, high fructose corn 

syrup, animal feed, and by-products such as gluten meal and germ. 

(30) “Cream” means that portion of milk, rich in milk fat, which rises to the surface 

of milk that is left standing or which is separated from milk by centrifugal 

force. 

(31) “Dairy product solids for animal feed” means modified dairy by-products 

derived from the fluid milk production process that are purposely processed 

for animal consumption obtained by the removal of water, protein and/or 

lactose, and/or minerals. 

(32) “Dehydrated chili pepper” means chili pepper that has been dehydrated to no 

more than 12 percent water by volume in order to extend the shelf life and to 

concentrate the flavor. Chili peppers are the fruit of plants from the genus 

Capsicum, and are members of the nightshade family Solanaceae. 

(33) “Dehydrated garlic” means garlic that has been dehydrated to no more than 

6.8 percent water by volume in order to extend the shelf life and to 

concentrate the flavor. Garlic is an onion-like plant (Allium sativum) having a 

bulb that breaks up into separable cloves with a strong distinctive odor and 

flavor. 

(34) “Dehydrated onion” mean onion that has been dehydrated to no more than 

5.5 percent water by volume in order to extend the shelf life and to 

concentrate the flavor. Onion (Allium cepa) is a plant that has a fan of hollow, 

bluish-green leaves and the bulb at the base of the plant begins to swell when 

a certain day-length is reached. 

(35) “Dehydrated parsley” means parsley that has been dehydrated to no more 

than 5 percent water by volume in order to extend the shelf life and to 

concentrate the flavor. Parsley (Petroselinum crispum) is a species of 

Petroselinum in the family Apiaceae widely cultivated as an herb, a spice, and 

a vegetable. 

(36) “Dehydrated spinach” means spinach that has been dehydrated to no more 

than 7 percent water by volume in order to extend the shelf life and to 

concentrate the flavor. Spinach (Spinacia oleracea) is an edible flowering 

plant in the family of Amaranthaceae. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 63 February 2015 

(37) “Delicate task wiper” means tissue-based wipers used for the delicate 

cleaning of lenses, surfaces, and equipment in labs, research facilities, 

hospitals, and manufacturing settings. 

(38) "Deproteinized whey" means products manufactured through the cold 

ultrafiltration of sweet dairy whey, removing a portion of the protein from 

sweet whey to result in a non-hygroscopic, free-flowing and clean flavored 

powder containing greater than 80% carbohydrate (lactose) levels. 

(39) “Diced Tomatoes” means the food prepared from mature tomatoes 

conforming to the characteristics of the fruit Lycopersicum esculentum P. Mill, 

of red or reddish varieties. The tomatoes are peeled and diced, and shall 

have had the stems and calicies removed and shall have been cored, except 

where the internal core is insignificant to texture and appearance. 

(40) “Distilled spirit” means a spirit made from the separation of alcohol and a 

fermented product. 

(41) “Dolime" is calcined dolomite. 

(42) “Dry color concentrate” means precipitated solids extracted from fruits and 

vegetables whose uses are for altering the color of materials and/or food. 

(43) “Ductile iron pipe” means pipe made of cast ferrous material in which a major 

part of the carbon content occurs as free graphite in a substantially nodular or 

spheroidal form. Pipes are used mainly to convey substances which can flow. 

(44) “EIA product code” means the code used to report a specific product to the 

U.S. Energy Information Administration (EIA) through EIA reporting forms. 

(45) “Facial Tissue” means a class of soft, absorbent, disposable tissue papers that 

is suitable for use on the face. 

(46) "Fiberglass pulled" means the quantity of glass removed from the melting 

furnace in the fiberglass manufacturing process where "fiberglass" is defined 

as insulation products for thermal, acoustic, and fire applications manufactured 

using glass. 

(47) "Flat glass pulled" means the quantity of glass removed from the melting 

furnace in the flat glass manufacturing process where "flat glass" is defined as 

glass initially manufactured in a sheet form. 

(48) “Freshwater diatomite filter aids” means inorganic mineral powders derived by 

processing freshwater diatomite which is fossilized single-celled algae found in 

lake beds. Filter aids are used in combination with filtration hardware to 

enhance filtration performance to separate unwanted solids from fluids. 

(49) “Fried potato chip” means a thin slice of potato that is deep fried until crunchy. 

(50) "Galvanized steel sheet" means steel coated with a thin layer of zinc to 

provide corrosion resistance for such products as garbage cans, storage 

tanks, or framing for buildings. Sheet steel normally must be cold-rolled prior 

to the galvanizing stage. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 64 February 2015 

(51) “Granulated refined sugar” means white refined sugar (99.9% sucrose), made 

by dissolving and purifying raw sugar then drying it to prevent clumping. 

(52) “Grape juice concentrate” means the liquid from crushed grapes, from the 

botanical genus Vitas, processed to remove water. 

(53) “Grape seed extract” means the extract from grape seeds containing 

concentrations of proanthocyanidin. 

(54) “Gypsum” means a mineral with the chemical formula CaSO4·2H2O. 

(55) “Horsepower tested” means the total horsepower of all turbine and generator 

set units tested prior to sale. 

(56) "Hot rolled steel sheet" means steel produced from the rolling mill that reduces 

a hot slab into a coil of specified thickness at a relatively high temperature. 

(57) “Imported protein” means protein found in pre-concentrated whey that is 

imported from other dairy facilities for further processing. 

(58) “Intermediate dairy ingredients” means intermediate (non-final) dairy product 

imported from other dairy facilities that enter the rehydrating process, which 

uses water and heat to manufacture powdered products. 

(59) “Lactose” means a white to creamy white crystalline product, possessing a 

mildly sweet taste. It may be anhydrous, contain one molecule of water of 

hydration, or be a mixture of both forms. 

(60) “Lager beer” means beer produced with bottom fermenting yeast strains, 

Saccharomyces uvarum (or carlsbergensis) at colder fermentation 

temperatures than ales. 

(61) “Lead and lead alloys” means lead or the metal alloy that combines lead and 

other elements such as antimony, selenium, arsenic, copper, tin, or calcium. 

(62) “Limestone” means a sedimentary rock composed largely of the minerals 

calcite and aragonite, which are different crystal forms of calcium carbonate 

(CaCO3). 

(63) “Liquid Color Concentrate” means a fluid extract from fruits and vegetables 

reduced by driving off water and the use of which is for altering the color of 

materials and/or food. 

(64) “Liquid Hydrogen" means hydrogen in a liquid state. 

(65) “Milk” means the lacteal secretion, practically free from colostrum, obtained by 

the complete milking of one or more healthy cows. Milk that is in final package 

form for beverage use shall have been pasteurized or ultra-pasteurized, and 

shall contain not less than 8 1⁄4 percent milk solids not fat and not less than 3 

1⁄4 percent milk fat. Milk may have been adjusted by separating part of the milk 

fat from, or by adding cream to, concentrated milk, dry whole milk, skim milk, 

concentrated skim milk, or nonfat dry milk. Milk may be homogenized. 

(66) “Nitric acid” means HNO3 of 100% purity. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 65 February 2015 

(67) “Nonfat dry milk and skimmed milk powder (high heat)” means milk powder 

obtained by removing water from pasteurized skim milk. It contains no more 

than 5% moisture (by weight) and no more than 1.5% milkfat (by weight). It is 

derived from cumulative heat treatment of 88 oC for 30 minutes and includes 

undenatured whey protein nitrogen content equal to or less than 1.5 mg/g 

powder. 

(68) “Nonfat dry milk and skimmed milk powder (low heat)” means milk powder 

obtained by removing water from pasteurized skim milk. It contains no more 

than 5% moisture (by weight) and no more than 1.5% milkfat (by weight). It is 

derived from cumulative heat treatment of milk no higher than 70 oC for 2 

minutes and includes undenatured whey protein nitrogen content equal to or 

greater than 6 mg/g powder. 

(69) “Nonfat dry milk and skimmed milk powder (medium heat)” means milk powder 

obtained by removing water from pasteurized skim milk. It contains no more 

than 5% moisture (by weight) and no more than 1.5% milkfat (by weight). It is 

derived from cumulative heat treatment of 70-78 oC for 20 minutes and 

includes undenatured whey protein nitrogen content equal to or greater than 

1.51 mg/g powder up to 5.99 mg/g powder. 

(70) “Non-Aseptic tomato juice” means tomato juice packaged using methods other 

than aseptic preparation. 

(71) “Non-aseptic tomato paste and tomato puree” means the sum of tomato paste 

and tomato puree packaged using methods other than aseptic preparation. 

Non-aseptic paste and puree is normalized to 24 percent tomato soluble 

solids. Non-aseptic paste and puree normalized to 24% TSS = (%TSS - raw 

TSS)/(24 - raw TSS). 

(72) “Non-aseptic whole and diced tomato” means the sum of whole and diced 

tomatoes packaged using methods other than aseptic preparation. Sum of 

non-aseptic whole and diced tomatoes = whole tomatoes + (diced tomatoes x 

1.05). 

(73) “Non-thermal enhanced oil recovery” or “non-thermal EOR” means the 

process of using methods other than thermal EOR, which may include water 

flooding or CO2 injection, to increase the recovery of crude oil from a reservoir. 

(74) “On-purpose hydrogen gas” means pure molecular hydrogen gas produced 

by a process or processes dedicated to producing hydrogen (e.g., steam 

methane reforming). 

(75) “Paper Towel” means a disposable towel made of absorbent tissue paper. 

(76) “Pickled steel sheet” means hot rolled steel sheet that is sent through a series 

of hydrochloric acid baths that remove the oxides, and includes both finished 

pickled steel, and steel produced by the facility as an intermediate product for 

further processing. 

(77) “Pistachio” means the nuts of the pistachio tree Pistacia vera. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 66 February 2015 

(78) "Plaster" is calcined gypsum that is produced and sold as a finished product 

and is not used in the production of plasterboard at the same facility. 

(79) "Plasterboard" is a panel made of gypsum plaster pressed between two thick 

sheets of paper. 

(80) “Poultry deli product” means the products, including corn dogs, sausages, and 

franks, that contain a significant portion of pre-processed poultry, that are 

cooked and sold wholesale or retail, or transferred to other facilities. 

(81) “Pretzel” is a crisp biscuit made from dough formed into a knot or stick, 

flavored with salt, passed through a caustic hot water bath and baked in an 

oven. 

(82) “Primary refinery product” means aviation gasoline (EIA product codes 111 

and 112), motor gasoline (finished) (EIA product codes 125, 127, 130, 149, 

and 166), motor gasoline blendstocks (EIA product codes 117, 118, 138, and 

139), kerosene-type jet fuel (EIA product code 213), distillate fuel oil (EIA 

product codes 465, 466, and 467), renewable liquid fuels (EIA product codes 

203, 205, and 207), and asphalt (EIA product code 931). For the purpose of 

calculating this value for each refinery, ARB will convert blendstocks into their 

finished fuel volumes by multiplying blendstocks by an assumed blending 

ratio. 

(83) “Proof Gallons” means one liquid gallon of distilled spirits that is 50% alcohol 

at 60 degrees F. 

(84) “Protein meal and fat” means meal, feather meal, and fat rendered product 

from poultry tissues including meat, viscera, bone, blood, and feathers. 

(85) “Raw TSS” means the average annual percent tomato soluble solids of raw 

tomatoes to be processed in a tomato processing facility. 

(86) “Rare earth elements” means a set of seventeen chemical elements in the 

periodic table, specifically the fifteen lanthanides (Lanthanum, Cerium, 

Praseodymium, Neodymium, Promethium, Samarium, Europium, Gadolinium, 

Terbium, Dysprosium, Holmium, Erbium, Thulium, and Lutetium) plus 

Scandium and Yttrium. 

(87) “Rare earth oxide equivalent” means the mass of oxide if all of the rare earth 

elements in the product are isolated and converted to their oxide form. 

(86) “Rare earth elements” means a set of seventeen chemical elements in the 

periodic table, specifically the fifteen lanthanides (Lanthanum, Cerium, 

Praseodymium, Neodymium, Promethium, Samarium, Europium, Gadolinium, 

Terbium, Dysprosium, Holmium, Erbium, Thulium, and Lutetium) plus 

Scandium and Yttrium. 

(89) "Recycled boxboard" means containers of solid fiber made from recycled 

fibers, including cereal boxes, shoe boxes, and protective paper packaging for 

dry foods. It also includes folding paper cartons, set-up boxes, and similar 

boxboard products. Recycled boxboard is made from recycled fibers. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 67 February 2015 

(90) "Recycled linerboard" means types of paperboard made from recycled fibers 

that meet specific tests adopted by the packaging industry to qualify for use as 

the outer facing layer for corrugated board, from which shipping containers are 

made. 

(91) "Recycled medium" means the center segment of corrugated shipping 

containers, being faced with linerboard on both sides. Recycled medium is 

made from recycled fibers. 

(92) “Salt” means sodium chloride, determined as chloride and calculated as 

percent sodium chloride, by the method prescribed in “Official Methods of 

Analysis of the Association of Official Analytical Chemists,” 13th Ed., 1980, 

sections 32.025 to 32.030, under the heading “Method III (Potentiometric 

Method).” 

(93) “Seamless rolled ring” means a metal product manufactured by punching a 

hole in a thick, round piece of metal, and then rolling and squeezing (or in 

some cases, pounding) it into a thin ring. Ring diameters can be anywhere 

from a few inches to 30 feet. 

(94) "Skim milk" means the product that results from the complete or partial 

removal of milk fat from milk. 

(95) "Soda ash equivalent" means the total mass of all soda ash, biocarb, borax, VBor, DECA, PYROBOR, Boric Acid, Sodium Sulfate, Potassium Sulfate, 

Potassium Chloride, and Sodium Chloride produced. 

(96) "Steel produced using an electric arc furnace" means steel produced by an 

electric arc furnace or "EAF." EAF means a furnace that produces molten steel 

and heats the charge materials with electric arcs from carbon electrodes. 

Furnaces that continuously feed direct-reduced iron ore pellets as the primary 

source of iron are not affected facilities within the scope of this definition of 

EAF. 

(97) “Stucco” means hemihydrate plaster (CaSO4●1⁄2H2O) produced by heating 

(“calcining”) raw gypsum, thereby removing three-quarters of its chemically 

combined water. 

(98) “Thermal enhanced oil recovery” or “thermal EOR” means the process of using 

injected steam to increase the recovery of crude oil from a reservoir. 

(99) "Tin Plate" means thin sheet steel with a very thin coating of metallic tin. Tin 

plate also includes Tin Free Steel or TFS which has an extremely thin coating 

of metallic chromium and chromium oxide. Tin plate is used primarily in can 

making. 

(100) “Tissue” means a class of papers which are characteristically gauzy in 

texture and, in some cases, fairly transparent. They may be glazed, 

unglazed, or creped, and are used for a variety of purposes. Examples of 

different types of tissue papers include sanitary grades such as toilet, facial, 

napkin, towels, wipes, and special sanitary papers.
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 68 February 2015 

(101) "Tissue produced adjusted by water absorbency capacity" means the mass 

of tissue adjusted by water absorbency capacity derived by using the 

following metric: Tissue produced adjusted by water absorbency capacity = 

Air dried ton of tissue produced x grams of water absorbed by a gram of 

tissue product. 

(102) “Tomato juice” is the liquid obtained from mature tomatoes conforming to the 

characteristics of the fruit Lycopersicum esculentum P. Mill, of red or reddish 

varieties. Tomato juice may contain salt, lemon juice, sodium bicarbonate, 

water, spices and/or flavoring. This food shall contain not less than 5.0 

percent by weight tomato soluble solids. 

(103) “Tomato paste” is the food prepared from mature tomatoes conforming to the 

characteristics of the fruit Lycopersicum esculentum P. Mill, of red or reddish 

varieties. Tomato paste is prepared by concentrating tomato ingredients until 

the food contains not less than 24.0 percent tomato soluble solids. 

(104) “Tomato puree” is the semisolid food prepared from mature tomatoes 

conforming to the characteristics of the fruit Lycopersicum esculentum P. 

Mill, of red or reddish varieties. Tomato paste is prepared by concentrating 

tomato ingredients until the food contains not less than 8.0 percent but less 

than 24.0 percent tomato soluble solids. 

(105) “Tomato soluble solids” (TSS) means the sucrose value as determined by 

the method prescribed in the “Official Methods of Analysis of the Association 

of Official Analytical Chemists,” 13th Ed., 1980, sections 32.014 to 32.016 

and 52.012. For instances where no salt has been added, the sucrose value 

obtained from the referenced tables shall be considered the percent of 

tomato soluble solids. If salt has been added either intentionally or through 

the application of the acidified break, determine the percent of such added 

sodium chloride as specified in the definition of salt. Subtract the percentage 

sodium chloride from the percentage of total soluble solids found (sucrose 

value from the refractive index tables) and multiply the difference by 1.016. 

The resultant value is considered the percent of “tomato soluble solids.” 

(106) “Ultrafiltered milk” means raw or pasteurized milk or nonfat milk that is 

passed over one or more semipermeable membranes to partially remove 

water, lactose, minerals, and water soluble vitamins without altering the 

casein-to-whey protein ratio of the milk or nonfat milk and resulting in a liquid 

product. 

(107) “Waste gas” means a natural gas that contains a greater percentage of 

gaseous chemical impurities than the percentage of methane. For purposes 

of this definition, gaseous chemical impurities may include carbon dioxide, 

nitrogen, helium, or hydrogen sulfide. 

(108) “Water absorption capacity” means the mass of water that is absorbed per 

unit mass of the test piece using the methodology specified by ISO 

12625-8:2010 except for the humidity and temperature conditions, which 

shall be 50% relative humidity ±2%, and 23 degrees C ±1 degree C. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 69 February 2015 

(109) "Whey protein concentrate" means the substance obtained by the removal of 

sufficient nonprotein constituents from pasteurized whey so that the finished 

dry product contains greater than 25% protein. Whey protein concentrate is 

produced by physical separation techniques such as precipitation, filtration, 

or dialysis. The acidity of whey protein concentrate may be adjusted by the 

addition of safe and suitable pH adjusting ingredients. 

(110) “Whole chicken and chicken parts” means the whole chicken or chicken 

parts (including breasts, thighs, wings, and drums) that are packaged for 

wholesale, or retail sales, or transferred to other facilities. 

(111) “Whole Tomatoes” is the food prepared from mature tomatoes conforming to 

the characteristics of the fruit Lycopersicum esculentum P. Mill, of red or 

reddish varieties. The tomatoes are peeled but kept whole, and shall have 

had the stems and calicies removed and shall have been cored, except 

where the internal core is insignificant to texture and appearance. 

 (c) For the purposes of this article, the following definitions associated with refining and 

related processes shall apply: 

(1) “Air separation unit” means a refinery unit which separates air into its 

components including oxygen utilizing a cryogenic or other method. 

(2) “Alkylation/poly/dimersol” means a range of processes transforming 

C3/C4/C5 molecules into C7/C8/C9 molecules over an acidic catalyst. This 

can be accomplished by alkylation with sulfuric acid or hydrofluoric acid, 

polymerization with a C3 or C3/C4 olefin feed, or dimersol. 

(3) “Ammonia recovery unit” means a refinery unit in which ammonia-rich sour 

water stripper overhead is treated to separate ammonia suitable for reuse in 

the refinery, for fertilizer, for other sales, for the reduction of NOx emissions, 

or other commercial activities. This unit is the second stage of a two stage 

sour water stripping unit. The ammonia recovery unit may include the 

adsorber, stripper and fractionator. 

(4) “Aromatic saturation of distillates” means the saturation of aromatic rings over 

a fixed catalyst bed at low or medium pressure in the presence of hydrogen. 

(5) “AROMAX®” means a special application of catalytic reforming for the 

specific purpose of producing light aromatics. 

(6) “Aromatics production” means extraction of light aromatics from reformate 

and/or hydrotreated pyrolysis gasoline by a solvent. 

(7) “Asphalt production” means the processing required to produce asphalts and 

bitumen, including bitumen oxidation (mostly for road paving). This includes 

polymer-modified asphalt. 

(8) “Atmospheric Crude Distillation” means primary atmospheric distillation of 

crude oil and other feedstocks. The atmospheric crude distillation unit 

includes any ancillary equipment such as a crude desalter, naphtha splitting, 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 70 February 2015 

gas plant and wet treatment of light streams for mercaptan removal and may 

have more than one distillation column. 

(9) “Benzene saturation” means a selective hydrogenation of benzene in gasoline 

streams over a fixed catalyst bed at moderate pressure. 

(10) “C4 isomer production” means conversion of n-butane into isobutane over a 

fixed catalyst bed in the presence of hydrogen at low to moderate pressure. 

(11) “C5/C6 isomer production - including ISOSIV” means conversion of normal 

paraffins into isoparaffins over a fixed catalyst bed in the presence of 

hydrogen at low to moderate pressure. 

(12) “Complexity weighted barrel” or “CWB” means a metric created to evaluate 

the greenhouse gas efficiency of petroleum refineries and related processes. 

The CWB value for an individual refinery is calculated using actual refinery 

throughput to specified process units and emission factors for these process 

units. The emission factor is denoted as the CWB factor and is 

representative of the greenhouse gas emission intensity at an average level 

of energy efficiency, for the same standard fuel type for each process unit for 

production, and for average process emissions of the process units across a 

sample of refineries. Each CWB factor is expressed as a value weighted 

relative to atmospheric crude distillation. 

(13) “Conradson carbon level” means a measurement describing the mass of 

carbon residue which an oil deposits when evaporated, as defined by ASTM 

D189 - 06(2010)e1 “Standard Test Method for Conradson Carbon Residue of 

Petroleum Products” (2010), which is hereby incorporated by reference. 

(14) “Conventional naphtha hydrotreating” means desulfurization of virgin and 

cracked naphthas over a fixed catalyst bed at moderate pressure in the 

presence of hydrogen. For cracked naphthas this also involves saturation of 

olefins. 

(15) “Cryogenic LPG recovery” means a refinery unit in which liquefied petroleum 

gas (LPG) is extracted from refinery gas streams through cooling and 

removing the condensate heavy fractions. The processes and equipment for 

this unit may include refrigeration, drier, compressor, absorber, stripper and 

fractionation. 

(16) “Cumene production” means the alkylation of benzene with propylene. 

(17) “Cyclohexane production” means hydrogenation of benzene to cyclohexane 

over a catalyst at high pressure. 

(18) “Delayed Coker” means a refinery unit which conducts a semi-continuous 

process where the heat of reaction is supplied by a fired heater. Coke is 

produced in alternate drums that are swapped at regular intervals. Coke is 

cut out of full coke drums as a product. For the purposes of analysis, facilities 

include coke handling and storage. 

(19) “Desalination” means a refinery’s desalination of seawater or contaminated 

water. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 71 February 2015 

(20) “Desulfurization of C4–C6 Feeds” means desulfurization of light naphthas 

over a fixed catalyst bed, at moderate pressure in the presence of hydrogen. 

(21) “Desulfurization of pyrolysis gasoline/naphtha” means selective or nonselective desulfurization of pyrolysis gasoline (by-product of light olefins 

production) and other streams over a fixed catalyst bed, at moderate pressure 

in the presence of hydrogen. 

(22) “Diolefin to olefin saturation of gasoline” means selective saturation of 

diolefins over a fixed catalyst bed, at moderate pressure in the presence of 

hydrogen to improve stability of thermally cracked and coker gasolines. 

(23) “Distillate hydrotreating” means desulfurization of distillate blends of 

components such as diesel and heating oil over a fixed catalyst bed at low or 

medium pressure in the presence of hydrogen. 

(24) “Ethylbenzene production” means the process of combining benzene and 

ethylene to form ethylbenzene. 

(25) “FCC gasoline hydrotreating with minimum octane loss” means selective 

desulfurization of FCC gasoline cuts with minimum olefins saturation, over a 

fixed catalyst bed, at moderate pressure and in the presence of hydrogen. 

(26) “Flare gas recovery” means a refinery unit in which flare gas is captured and 

compressed for other uses. Usually recovered flare gas is treated and routed 

to the refinery fuel gas system. The equipment for this process may include 

the compressor and separator. 

(27) “Flexicoker” means a refinery unit which conducts a proprietary process 

incorporating a fluid coker and where coke is gasified to produce a low BTU 

gas which is used to supply the refinery heaters and surplus coke is drawn off 

as a product. 

(28) “Flue gas desulfurizing” means a process in which sulfur dioxide is removed 

from flue gases with contaminants. This often involves an alkaline sorbent 

which captures sulfur dioxide and transforms it into a solid product. Flue gas 

desulfurizing systems can be of the regenerative type or the non-regenerative 

type. The processes and equipment for this process may include the 

contactor, catalyst/reagent regeneration, scrubbing circulation and solids 

handling. 

(29) “Fluid Catalytic Cracking” means cracking of a hydrocarbon stream typically 

consisting of gasoils and residual feedstocks over a catalyst. The finely 

divided catalyst is circulated in a fluidized state from the reactor where it 

becomes coated with coke to the regenerator where coke is burned off. The 

hot regenerated catalyst returning to the reactor may supply the heat for the 

endothermic cracking reaction and for most of the downstream fractionation 

of cracked products. 

(30) “Fluid Coker” means a continuous process where the fluidized powder-like 

coke is transferred between the cracking reactor and the coke burning vessel 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 72 February 2015 

and burned for process heat production. Surplus coke is drawn off as a 

product. 

(31) “Fuel gas sales treating & compression” means treatment and compression of 

refinery fuel gas for sale to a third party. 

(32) “Houdry catalytic cracking” means a method of catalytic cracking which uses 

a fixed or moving bed of pellets of an aluminum silicate type catalyst. The 

catalyst is not fluidized. 

(33) “Hydrodealkylation” means dealkylation of toluene and xylenes into benzene 

over a fixed catalyst bed in the presence of hydrogen at low to moderate 

pressure. 

(34) “Kerosene hydrotreater” means a refinery process unit which treats and 

upgrades kerosene and gasoil streams using aromatic saturation of distillates, 

distillate hydrotreating, middle distillate dewaxing, the S-ZorbTM process for 

kerosene and gasoil or selective hydrotreating of C3-C5 streams for 

alkylation. 

(35) “Lube catalytic dewaxing” means the catalytic breakdown of long paraffinic 

chains in intermediate streams for the manufacture of lube oils. 

(36) “Lube solvent dewaxing” means the solvent removal of long paraffinic chains 

(wax) from intermediate streams in the manufacture of lube oils. This may 

include solvent regeneration. Different processes use different solvents, such 

as chlorocarbon, MEK/toluene, MEK/MIBK, or propane.

(37) “Lube solvent extraction” means the solvent extraction of aromatic 

compounds from intermediate streams for the manufacture of base lube oils. 

This includes solvent regeneration. Different processes use different 

solvents, such as Furfural, NMP, phenol, or sulfur dioxide. 

(38) “Lube/Wax hydrofining” means the hydrotreating of lube oil fractions and wax 

for improving the quality of the lube and wax. 

(39) “Lubricant hydrocracking” means hydrocracking of heavy feedstocks for the 

manufacture of lube oils. 

(40) “Methanol synthesis” means the recombination of CO2 and hydrogen to 

produce methanol. Methanol synthesis is only applicable when a refinery 

produces hydrogen via partial oxidation. 

(41) “Middle distillate dewaxing” means the cracking of long paraffinic chains in 

gasoils to improve cold flow properties over a fixed catalyst bed at low or 

medium pressure in the presence of hydrogen. This process includes the 

desulfurization step. 

(42) “Mild Residual FCC” means fluid catalytic cracking when the feed has a 

Conradson carbon level of 2.25% to 3.5% by weight. 

(43) “Naphtha/Distillate Hydrocracker” means a refinery process unit which 

conducts cracking of a hydrocarbon stream typically consisting of gasoils and 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 73 February 2015 

distillates over a fixed catalyst bed, at high pressure and in the presence of 

hydrogen. The process combines cracking and hydrogenation reactions. 

(44) “Naphtha hydrotreater” means a refinery process unit that treats and 

upgrades naphtha/gasoline and lighter streams using any combination of one 

or more of the following processes: benzene saturation, desulfurization of 

C4–C6 feeds, conventional naphtha hydrotreating, diolefin to olefin saturation 

of gasoline, FCC gasoline hydrotreating with minimum octane loss, olefinic 

alkylation of thio sulfur, desulfurization of pyrolysis gasoline/naphtha. For 

naphtha/distillates, selective hydrotreating or the S-ZorbTM process may be 

used. 

(45) “Non-Crude Input” means the total volume of barrels of raw materials 

processed in process units at the refinery, excluding returns from a lube 

refiner or a chemical plant within a refining/petrochemical complex and 

excluding non-processed blendstock. 

(45) “Olefinic alkylation of thio sulfur” means a gasoline desulfurization process in 

which thiophenes and mercaptans are catalytically reacted with olefins to 

produce higher-boiling sulphur compounds removable by distillation. This 

process does not utilize hydrogen. 

(46) “Other FCC” means early catalytic cracking processes on fixed catalyst beds, 

including Houdry catalytic cracking and Thermofor catalytic cracking. 

(47) “Oxygenates” means ethers that are produced by reacting an alcohol with 

olefins. 

(48) “Paraxylene production” means the physical separation of paraxylene from 

mixed xylenes. 

(49) “Process CWB” means the total complexity-weighted barrels of a refinery 

excluding those contributed by the process units called total refinery input and 

non-crude input. 

(50) “Propane/Propylene splitter (propylene production)” means a refinery unit that 

conducts separation of propylene from other mostly olefinic C3/C4 molecules 

generally produced in an FCC or coker. This unit produces chemical or 

polymer grade propylene. 

(51) “POX syngas for fuel” means the production of synthesis gas by gasification 

(partial oxidation) of heavy residues. This includes syngas clean-up. 

(52) “Reactor for selective hydrotreating” means a special configuration where a 

distillation/fractionation column contains a solid catalyst that converts diolefins 

in FCC gasoline to olefins or where the catalyst bed is in a preheat train 

reactor vessel in front of the column. 

(53) “Reformer - including AROMAX” means a refinery unit which increases the 

octane rating of naphtha by dehydrogenation of naphthenic rings and paraffin 

isomerisation over a noble metal catalyst at low pressure and high 

temperature. The process also produces hydrogen. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 74 February 2015 

(54) “Residual FCC” means fluid catalytic cracking when the feed has a 

Conradson carbon level of greater than or equal to 3.5% by weight. 

(55) “Residual hydrotreater” means a refinery unit which conducts desulfurization 

of residues over a fixed catalyst bed at high pressure and in the presence of 

hydrogen. It results in a limited degree of conversion of the residue feed into 

lighter products. 

(56) “Residual Hydrocracker” means a refinery unit which conducts hydrocracking 

of residual feedstocks. Different processes involve continuous or semicontinuous catalyst replenishment. The residual hydrocracker unit must 

process residuum with a Conradson carbon level of at least 3.5% by weight. 

(57) “S-ZorbTM process for kerosene and gasoil” means desulfurization of gasoil 

using an absorption process. This process does not utilize hydrogen. 

(58) “S-ZorbTM process for naphtha/distillates” means desulfurization of 

naphtha/gasoline streams using a proprietary fluid-bed hydrogenation 

adsorption process in the presence of hydrogen. 

(59) “Selective hydrotreating of C3-C5 streams for alkylation” means selective 

saturation of diolefins for alkylation over a fixed catalyst bed, at moderate 

pressure and in the presence of hydrogen, or hydrotreatment of distillates for 

conversion of diolefins to olefins. 

(61) “Solomon Energy Intensity Index®” or “Solomon EII” or “EII” means a 

petroleum refinery energy efficiency metric that compares actual energy 

consumption for a refinery with the “standard” energy consumption for a 

refinery of similar size and configuration. The “standard” energy consumption 

is calculated based on an analysis of worldwide refining capacity as contained 

in the database maintained by Solomon Associates. The ratio of a facility’s 

actual energy to the standard energy is multiplied by 100 to arrive at the 

Solomon EII for a refinery. 

(62) “Solomon Energy Review” means a data submittal and review conducted by a 

petroleum refinery and Solomon Associates. This process uses the refinery 

energy utilization, throughput and output to determine the Solomon EII of the 

refinery. 

(63) “Solvent deasphalter” means a refinery unit which uses a solvent such as 

propane, butane or a heavier solvent to remove asphaltines from a residual oil 

stream and produce asphalt and a deasphalted gasoil. 

(64) “Special Fractionation” means fractionation processes excluding solvents, 

propylene and aromatics fractionation, which are accomplished by a 

deethanizer, depropanizer, deisobutanizer, debutanizer, deisopentanizer, 

depentanizer, deisohexanizer, dehexanizer, deisoheptanizer, deheptanizer, 

naphtha splitter, alkylate splitter or reformate splitter. 

(65) “Standard FCC” means fluid catalytic cracking when the feed has a Conradson 

carbon level of less than 2.25% by weight. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 75 February 2015 

(66) “Sulfur Recovery” means a process where hydrogen sulfide is converted to 

elemental sulfur.” 

(67) “Sulfuric acid regeneration” means a catalytic process in which spent acid is 

regenerated to concentrated sulfuric acid. The equipment for this process may 

include the combustor, waste heat boiler, converter, absorber, SO3 recycle, 

gas cleaning including electrostatic precipitator and amine regenerator. 

(68) “Thermal Cracking” means thermal cracking of distillate feedstocks. A thermal 

cracking unit may include a vacuum flasher. Units that combine visbreaking 

and thermal cracking of distillate generate a contribution for both processes 

based on the residue and the distillate throughput respectively. 

(69) “Thermofor catalytic cracking” means a method of catalytic cracking in which 

gravity is used to pass the catalyst through the feedstock or to pass the 

feedstock through the catalytic reactor bed. The catalyst is not fluidized. 

(70) “Toluene disproportionation/transalkylation means a fixed-bed catalytic 

process for the conversion of toluene to benzene and xylene in the presence 

of hydrogen. 

(71) “Total Refinery Input” means the total volume of the following brought in to the 

refinery: crude oil and condensate, excluding basic sediment and water; 

finished product additives such as dyes, diesel pour point depressants and 

cetane improvers; antiknock compounds; and other raw materials, including 

crude diluents, feedstock from outside the refinery which is processed in other 

process units or blend stock blended into refinery products. 

(72) “Vacuum Distillation” means distillation of atmospheric residues under 

vacuum. Some units may have more than one main distillation column. 

(73) “Visbreaker” means a refinery unit which conducts mild thermal cracking of 

residual feedstocks to produce some distillates and reduce the viscosity of the 

cracked residue. It may include a vacuum flasher. Units that combine 

visbreaking and thermal cracking of distillate generate a contribution for both 

processes based on the residue and the distillate throughput respectively. 

(74) “VGO Hydrotreater” means a refinery unit which conducts desulfurization of a 

hydrocarbon stream typically made up of vacuum gasoils and cracked gasoils, 

principally destined to be used as FCC feed, over a fixed catalyst bed at 

medium or high pressure in the presence of hydrogen. 

(75) “Wax deoiling” means solvent removal of lighter hydrocarbons from wax 

obtained from lube dewaxing. Different proprietary processes use different 

solvents, such as MEK/toluene, MEK/MIBK, or propane. 

(76) “Xylene isomerization” means isomerization of mixed xylenes to paraxylene. 

NOTE: Authority cited: Sections 38510, 38530, 39600, 39601, 39607, 39607.4 and 

41511, Health and Safety Code. Reference: Sections 38530, 39600 and 41511, Health 

and Safety Code. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 76 February 2015 

§ 95103. Greenhouse Gas Reporting Requirements. 

The facilities, suppliers, and entities specified in section 95101 must monitor emissions 

and submit emissions data reports to the Air Resources Board following the 

requirements specified in 40 CFR §98.3 and §98.4, except as otherwise provided in this 

part. 

(a) Abbreviated Reporting for Facilities with Emissions Below 25,000 Metric Tons of 

CO2e. A facility operator may submit an abbreviated emissions data report under 

this article if all of the following conditions have been met: the facility operator does 

not have a compliance obligation under the cap-and-trade regulation during any 

year of the current compliance period; the operator is not subject to the reporting 

requirements of 40 CFR Part 98 specified in this article; and the facility total 

stationary combustion, process, fugitives and venting emissions are below 25,000 

metric tons of CO2e in 2011 and each subsequent year. This provision does not 

apply to suppliers or electric power entities. Abbreviated reports must include the 

information in paragraphs (1)-(7) below, and comply with the requirements specified 

in paragraphs (8)-(11) below: 

(1) Facility name, assigned ARB identification number, physical street address 

including the city, state and zip code, air basin, air district, county, geographic 

location, natural gas supplier name, natural gas supplier customer 

identification number, natural gas supplier service account identification 

number or other primary account identifier, and annual billed MMBtu (10 

therms = 1 MMBtu). 

(2) Facility GHG stationary combustion emissions for all stationary fuel 

combustion units and calculated according to any method in 40 CFR 

§98.33(a), expressed in metric tons of total CO2, CO2 from biomass-derived 

fuels, CH4, and N2O. If the facility includes multiple stationary fuel combustion 

units that belong to more than one unit type category listed in section 

95115(h), the operator may report the multiple units in aggregate but must 

indicate the percentage of the aggregated fuel consumption attributed to each 

unit type category. In addition, if the facility includes an electricity generating 

unit, the facility operator must report the electricity generating unit separate 

from other stationary fuel combustion sources by following the unit 

aggregation provisions in sections 95112(b) and 95103(a)(6). The operator 

has the option of using engineering estimation or any combination of existing 

meters to meet the requirements of this paragraph. 

(3) Total facility GHG process emissions aggregated for all process emissions 

sources and calculated according to the requirements in the following parts, 

expressed in metric tons of total CO2, CO2 from biomass-derived fuels, CH4, 

and N2O, as applicable: 

(A) 40 CFR §98.143 for glass production; 

(B) 40 CFR §98.163 for hydrogen production; 

(C) 40 CFR §98.173 for iron and steel production; 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 77 February 2015 

(D) 40 CFR §98.273 for pulp and paper manufacturing; 

(E) Subarticle 5 of this article for petroleum and natural gas systems. 

(4) Identification of the methods chosen for determining emissions. 

(5) Any facility operating data or process information used for the GHG emission 

calculations, including fuel use by fuel type, reported in million standard cubic 

feet for gaseous fuels, gallons for liquid fuels, short tons for solid fuels, and 

bone-dry short tons for biomass-derived solid fuels. If applicable, include high 

heat values and carbon content values used to calculate emissions. Missing 

fuel use or fuel characteristics data must be substituted according to the 

requirements of 40 CFR §98.35. 

(6) For facilities with on-site electricity generation or cogeneration, the applicable 

information specified in sections 95112(a)-(b) of this article. Geothermal 

facilities must also report the information specified in section 95112(e). 

Operators of hydrogen fuel cells must report the information specified in 

section 95112(f). 

(7) A signed and dated certification statement provided by the designated 

representative of the owner or operator, according to the requirements of 40 

CFR §98.4(e)(1). 

(8) Abbreviated emissions data reports submitted under this provision must be 

certified as complete and accurate no later than June 1 of each calendar year. 

(9) Subsequent revisions according to the requirements of 40 CFR §98.3(h) must 

be submitted if an error is discovered after the submission of the emissions 

data report. If the error correction would cause the emissions total to exceed 

25,000 metric tons of CO2e, a report that meets the full requirements of this 

article must be submitted within ninety days of discovery. 

(10) For abbreviated reports submitted under this provision, records must be kept 

according to the requirements of 40 CFR §98.3(g), except that a written GHG 

Monitoring Plan is not required. 

(11) An abbreviated emissions data report is not subject to the third-party 

verification requirements of this article. 

(b)-(d) Reserved

(e) Reporting Deadlines. Except as provided in section 95103(a)(7)-(8), each facility 

operator or supplier must submit an emissions data report no later than April 10 of 

each calendar year. Each electric power entity must submit an emissions data 

report no later than June 1 of each calendar year. 

(f) Verification Requirement and Deadlines. The requirements of this paragraph apply 

to each reporting entity submitting an emissions data report that indicates emissions 

equaled or exceeded 25,000 metric tons of CO2e, including CO2 from biomassderived fuels and geothermal sources, or each reporting entity that has or has had a 

compliance obligation under the cap-and-trade regulation in any year of the current 

compliance period. The requirements of this paragraph also apply to electric power 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 78 February 2015 

entities that are electricity importers or exporters that have not met the requirements 

for cessation in section 95101(i)(4). The reporting entity subject to verification must 

obtain third-party verification services for that report from a verification body that 

meets the requirements specified in Subarticle 4 of this article. Such services must 

be completed and separate verification statements for emissions data and for 

product data, as applicable, must be submitted by the verification body to the 

Executive Officer by September 1 each year. Each reporting entity must ensure 

that these verification statements are submitted by this deadline. Contracting with a 

verification body without providing sufficient time to complete the verification 

statements by the applicable deadline will not excuse the reporting entity from this 

responsibility. These requirements are additional to the requirements in 40 CFR 

§98.3(f). 

(g) Non-submitted/Non-verified Emissions Data Reports. When a reporting entity that 

holds a compliance obligation under the cap-and-trade regulation fails to submit an 

emissions data report or fails to obtain a positive emissions data verification 

statement or qualified positive emissions data verification statement by the 

applicable deadline, the Executive Officer shall develop an assigned emissions level 

for the reporting entity as set forth in section 95131(c)(5)(A)-(C). 

(h) Reporting in 2015. All provisions of the regulation are in full effect for 2014 data 

reporting in 2015 and beyond, except the following:

(1) Operators of petroleum refineries may use best available methods for 

reporting 2014 data for primary refinery products and calcined coke pursuant 

to sections 95113(l)(1) and 95113(l)(2), respectively. 

(i) Calculation and Reporting of De Minimis Emissions. A facility operator or supplier 

may designate as de minimis a portion of GHG emissions representing no more 

than 3 percent of a facility’s total CO2 equivalent emissions (including emissions 

from biomass-derived fuels and feedstocks), not to exceed 20,000 metric tons of 

CO2e. The operator or supplier may estimate de minimis emissions using 

alternative methods of the operator’s choosing, subject to the concurrence of the 

verification body that the methods used are reasonable, not biased toward 

significant underestimation or overestimation of emissions, and unlikely to exceed 

the de minimis limits. The operator or supplier must separately identify and include 

in the emissions data report the emissions from designated de minimis sources. 

The operator must determine CO2 equivalence according to the global warming 

potentials provided in Table A-1 of 40 CFR Part 98.

(j) Calculating, Reporting, and Verifying Emissions from Biomass-Derived Fuels. The 

operator or supplier must separately identify and report all biomass-derived fuels as 

described in section 95852.2(a) of the cap-and-trade regulation. Except for 

operators that use the methods of 40 CFR §98.33(a)(2)(iii) or §98.33(a)(4), the 

operator or supplier must separately identify, calculate, and report all direct 

emissions of CO2 resulting from the combustion of biomass-derived fuels as 

specified in sections 95112 and 95115 for facilities, and sections 95121 and 95122 

for suppliers. A biomass-derived fuel not listed in section 95852.2(a) of the capand-trade regulation must be identified as non-exempt biomass-derived fuel. For a 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 79 February 2015 

fuel listed under section 95852.2 of the cap-and-trade regulation, reporting entities 

must also meet the verification requirements in section 95131(i) of this article and 

the requirements of section 95852.1.1 of the cap-and-trade regulation, or the fuel 

must be identified as non-exempt biomass-derived fuel. Carbon dioxide 

combustion emissions from non-exempt biomass-derived fuel will be identified as 

non-exempt biomass-derived CO2. The responsibility for obtaining verification of a 

biomass-derived fuel falls on the entity that is claiming there is not a compliance 

obligation for the fuel, as indicated in section 95852.2 of the cap-and-trade 

regulation. 

(1) When reporting solid waste, the reporting entity must separately report the 

mass, in short tons, of urban waste, agricultural waste, and municipal solid 

waste. 

(2) When reporting the use of forest derived wood and wood waste as identified in 

section 95852.2(a)(4) of the cap-and-trade regulation and harvested pursuant 

to any of the California Forest Practice Rules Title 14, California Code of 

Regulations, Chapters 4, 4.5 and 10 of the Federal National Environmental 

Policy Act, the reporting entity must report: the bone-dry mass received; 

information about the supplier, including the name, physical address, mailing 

address, contact person with phone number and e-mail address; and the 

corresponding identification number under which the wood was removed. 

(3) When reporting biomethane, the operator or supplier who is reporting biomass 

emissions from biomethane fuel must also report the following information for 

each contracted delivery: 

(A) Name and address of the biomethane vendor from which biomethane is 

purchased; 

(B) Annual MMBtu delivered by each biomethane vendor. 

 The operator must also report the name, address, and facility type of the 

facility from which the biomethane is produced. In addition, relevant 

documentation including invoices, shipping reports, allocation and balancing 

reports, storage reports, in-kind nomination reports, and contracts must be 

made available for verifier or ARB review to demonstrate the receipt of eligible 

biomethane. 

(4) Reporting of fuel consumption from non-exempt biomass-derived fuel is 

subject to the requirements of section 95103(k) and reporting of emissions 

from non-exempt biomass-derived fuels is subject to the requirements of 

sections 95110 to 95158. 

(k) Measurement Accuracy Requirement. The operator or supplier subject to the 

requirements of 40 CFR §98.3(i) must meet those requirements for data used for 

calculating non-covered emissions and non-covered product data, except as 

otherwise specified in this paragraph. In addition, the following accuracy 

requirements apply to data used for calculating covered emissions and covered 

product data. The operator or supplier with covered product data or covered 

emissions equal to or exceeding 25,000 metric tons of CO2e or a compliance 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 80 February 2015 

obligation under the cap-and-trade regulation in any year of the current compliance 

period must meet the requirements of paragraphs (k)(1)-(10) below for calibration 

and measurement device accuracy. Inventory measurement, stock measurement, 

or tank drop measurement methods are subject to paragraph (11) below. The 

requirements of paragraphs (k)(1)-(11) apply to fuel consumption monitoring 

devices, feedstock consumption monitoring devices, process stream flow 

monitoring devices, steam flow devices, product data measuring devices, mass and 

fluid flow meters, weigh scales, conveyer scales, gas chromatographs, mass 

spectrometers, calorimeters, and devices for determining density, specific gravity, 

and molecular weight. The provisions of paragraph (k)(1)-(11) do not apply to: 

stationary fuel combustion units that use the methods in 40 CFR §98.33(a)(4) to 

calculate CO2 mass emissions; emissions reported as de minimis under section 

95103(i); and devices that are solely used to measure parameters used to calculate 

emissions that are not covered emissions or that are not covered product data. The 

provisions of paragraphs (k)(1)-(9) and (k)(11) do not apply to stationary fuel 

combustion units that use the methods in 40 CFR Part 75 Appendix G §2.3 to 

calculate CO2 mass emissions, but the provisions in paragraph (k)(10) are 

applicable to such units. 

(1) Except as otherwise provided in sections 95103(k)(7) through (9), all flow 

meter and other measurement devices used to provide data for the GHG 

emissions calculations or covered product data must be calibrated prior to the 

year data collection is required to begin using the procedures specified in this 

section, and subsequently recalibrated according to the frequency specified in 

paragraph (4). Flow meters and other measurement devices that were 

calibrated prior to January 1, 2012 using procedures specified in previous 

versions of the Mandatory Reporting Regulation or methods specified in 40 

CFR Part 98 must be subsequently recalibrated according to the frequency 

specified in paragraph (4). A flow meter device consists of a number of 

individual components which might include a flow constriction component, 

mechanical component, and temperature and pressure measurement 

components. Each meter or measurement device must meet the applicable 

accuracy specification in section 95103(k)(6), however each individual 

component of a flow meter device is not required to meet the accuracy 

specifications. The procedures and methods used to quality-assure the data 

from each measurement device must be documented in the written monitoring 

plan required by section 95105(c). 

(2) All flow meters and other measurement devices that provide data used to 

calculate GHG emissions or product data must be calibrated according to 

either the manufacturer’s recommended procedures or a method specified in 

an applicable subpart of 40 CFR 98. The calibration method(s) used must be 

documented in the monitoring plan required under section 95105(c), and are 

subject to verification under this article and review by ARB to ensure that 

measurements used to calculate GHG emissions or product data have met the 

accuracy requirements of this section. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 81 February 2015 

(3) For facilities and suppliers that become subject to this article after January 1, 

2012, all flow meters and other measurement devices that provide data used 

to calculate GHG emissions or product data must be installed and calibrated 

no later than the date on which data collection is required to begin under this 

article. 

(4) Except as otherwise provided in sections 95103(k)(7) through (9), subsequent 

recalibrations of the flow meter and other measurement devices subject to the 

requirements of this section must be performed no less frequently than at one 

of the following time intervals, whichever is shortest: 

(A) The frequency specified in a subpart of 40 CFR Part 98 that is applicable 

under this article. 

(B) The frequency recommended by the manufacturer. 

(C) Once during every three-year compliance period of the cap-and-trade 

regulation, with the time between successive calibrations not to be less 

than 30 months or greater than 48 months. 

(D) Immediately upon replacement of a previously calibrated meter. 

(E) Immediately upon replacement or repair of a device that is deemed out of 

calibration as determined in paragraph (6). 

(F) If the device manufacturer explicitly states in the product documentation 

that calibration is required at a period exceeding three years, the operator 

may follow the procedures in paragraph (9) to obtain Executive Officer 

approval to relieve the operator from having to comply with provisions (A) 

and (C) of this subparagraph. 

(5) All standards used for calibration must be traceable to the National Institute of 

Standards and Technology or other similar national government body 

responsible for measurement standards. 

(6) In addition to the specific calibration requirements specified below, and, if 

applicable, the field accuracy assessment requirements specified below, all 

flow meter and other measurement devices covered by this part, regardless of 

type, must be selected, installed, operated, and maintained in a manner to 

ensure accuracy within ±5 percent. 

(A) Perform all mass and volume measurement device calibration as 

specified in the original equipment manufacturers (OEM) documentation. 

If OEM documentation is unavailable, calibrate as specified in 40 CFR 

§98.3(i)(2)-(3), except that a minimum of three calibration points must be 

used spanning the normal operating conditions. When using the three 

calibration points, one point must be at or near the zero point, one point 

must be at or near the upscale point, and one point at or near the midpoint of the devices operating range. If OEM documentation does not 

specify a method or is unavailable, and calibration methods specified in 

40 CFR §98.3(i)(2)-(3) are not possible for a particular device, the 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 82 February 2015 

procedures in section 95109(b) must be followed to obtain approval for 

an alternative calibration procedure. Additionally: 

1. Pressure differential devices must be inspected at a frequency 

specified in paragraph (k)(4) of this section. The inspection must be 

conducted as described in the appropriate part of ISO 5167-2 (2003), 

or AGA Report No 3 (2003) Part 2, both of which are incorporated by 

reference, or a method published by an organization listed in 40 CFR 

§98.7 applicable to the analysis being conducted. If the device fails 

any one of the tests then the meter shall be deemed out of 

calibration. If OEM guidance for a particular pressure differential 

device recommends against disassembly and inspection of the 

device, disassembly and inspection requirements in this paragraph 

do not apply. Documentation of OEM guidance must be made 

available to verifiers and ARB upon request. 

a. Records of all tests must be preserved pursuant to section 95105 

and made available to verifiers and ARB upon request. 

b. Where inspection requirements apply, the primary element must 

also be photographed on both sides prior to any treatment or 

cleanup of the element to clearly show the condition of the 

element as it existed in the pipe. 

2. Devices used to measure total pressure and temperature must be 

calibrated using methods specified in section 95103(k)(2) and at a 

frequency specified in section 95103(k)(4). 

3. If temperature and/or total pressure measurements are not available 

or are taken at a remote location, the uncertainty caused by this must 

be factored into the evaluation of the overall measurement accuracy 

required under section 95103(k)(6). 

(B) Operators and suppliers may conduct an annual field accuracy 

assessment of mass and volume measurement devices to test for field 

accuracy in years between successive calibrations to ensure the device 

is maintaining measurement accuracy within ±5 percent. When 

performing a field accuracy assessment, the as-found condition must be 

recorded to ensure the device is measuring with accuracy within ±5 

percent. Should a device be found to be operating outside the ±5 percent 

accuracy bounds, the device shall be deemed out of calibration. Records 

of all field accuracy assessments must clearly indicate the assessment 

procedure and the as-found condition, be preserved pursuant to section 

95105, and be made available to verifiers and ARB upon request. Device 

accuracy may be assessed using one of the following options: 

1. Engineering analysis; 

2. OEM calibration guidance or other OEM recommended methods; 

3. Standard industry practices; or 

4. Portable instruments. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 83 February 2015 

(C) Pursuant to paragraph (k)(10) of this section, in the event of a failed 

calibration or recalibration, operators or suppliers who choose not to 

perform the annual field accuracy assessment specified in paragraph 

(6)(B) of this section for one or more mass or volume measurement 

devices must demonstrate data accuracy going back multiple years to the 

most recent successful calibration. Multiple years of data may be 

deemed invalid if accuracy cannot be demonstrated by other means, 

including strap-on meters or engineering methods. For operators and 

suppliers who conduct the annual field accuracy assessment, and a 

device is found to be out of calibration, accuracy must be demonstrated 

back to the most recent successful calibration or the most recent 

successful field accuracy assessment, whichever is most recent. 

(7) The requirements of section 95103(k) do not apply under the following 

circumstances: 

(A) Financial transaction meters are exempted from the calibration 

requirements of section 95103(k) if the supplier and purchaser do not 

have any common owners and are not owned by subsidiaries or affiliates 

of the same company. Financial transaction meters where the supplier 

and the purchaser do have common owners or are owned by subsidiaries 

or affiliates of the same company are exempt from the calibration 

requirements of section 95103(k) if one of the following is true: 

1. The financial transaction meter is also used by other companies that 

do not share common ownership with the fuel supplier; or 

2. The financial transaction meter is sealed with a valid seal from the 

county sealer of weights and measures or from a county certified 

designee; or 

3. The financial transaction meter is operated by a third party. 

(B) Upstream ethanol and additive meters used to ensure proper blendstock 

percentage for finished gasoline are exempted from the calibration 

requirements of section 95103(k). 

(C) Non-financial transaction meters used by Public Utility Gas Corporations 

for purposes of reporting natural gas supplier emissions are exempt from 

the calibration requirements in sections 95103(k)(1)-(6) if the supplier can 

demonstrate that the meters are operated and maintained in 

conformance with a standard that meets the measurement accuracy 

requirements of the California Public Utilities Commission General Order 

58A (1992). 

(8) For units and processes that operate continuously with infrequent outages, it 

may not be possible to meet deadlines for the initial or subsequent calibrations 

of a flow meter or other fuel measurement or sampling device, or inspection of 

orifice plates without disrupting normal process operation. In such cases, the 

owner or operator may submit a written request to the Executive Officer to 

postpone calibration or inspection until the next scheduled maintenance 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 84 February 2015 

outage. Such postponements are subject to the procedures of section 

95103(k)(9) and must be documented in the monitoring plan that is required 

under section 95105(c). 

(9) In cases of continuously operating units and processes where calibration or 

inspection is not possible without operational disruption, the operator must 

demonstrate by other means to the satisfaction of the Executive Officer that 

measurements used to calculate GHG emissions and product data still meet 

the accuracy requirements of section 95103(k)(6). The Executive Officer must 

approve any postponement of calibration or required recalibration beyond 

January 1, 2012. 

(A) A written request for postponement must be submitted to the Executive 

Officer not less than 30 days before the required calibration, recalibration 

or inspection date. The Executive Officer may request additional 

documentation to validate the operator’s claim that the device meets the 

accuracy requirements of this section. The operator shall provide any 

additional documentation to ARB within ten (10) working days of a 

request by ARB. 

(B) The request must include: 

1. The date of the required calibration, recalibration, or inspection; 

2. The date of the last calibration or inspection; 

3. The date of the most recent field accuracy assessment, if applicable; 

4. The results of the most recent field accuracy assessment, if 

applicable, clearly indicating a pass/fail status; 

5. The proposed date for the next field accuracy assessment, if 

applicable; 

6. The proposed date for calibration, recalibration, or inspection which 

must be during the time period of the next scheduled shutdown. If 

the next shutdown will not occur within three years, this must be 

noted and a new request must be received every three years until the 

shutdown occurs and the calibration, recalibration or inspection is 

completed. 

7. A description of the meter or other device, including at a minimum: 

a. make, 

b. model, 

c. install date, 

d. location, 

e. annual emissions calculated or annual product data reported 

using data from the device, 

f. sources for which the device is used to calculate emissions or 

product data, 

g. calibration or inspection procedure, 

h. reason for delaying calibration or inspection, 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 85 February 2015 

i. proposed method to assure the accuracy requirements of 

section 95103(k)(6) are met, 

j. name, title, phone number and e-mail of contact person capable 

of responding to questions regarding the device. 

(10) If the results of an initial calibration, recalibration, or field accuracy assessment 

fail to meet the required accuracy specification, and the emissions or product 

data estimated using the data provided by the device represent more than 5 

percent of total facility emissions or product data on an annual basis, the 

operator must demonstrate by other means to the satisfaction of the verifier or 

ARB that measurements used to calculate GHG emissions and product data 

still meet the ± 5% accuracy requirements going back to the last instance of 

successful field accuracy assessment or calibration of the device. Where the 

results of an initial calibration, recalibration, or field accuracy assessment fail 

to meet the accuracy specifications, the verifier shall note at a minimum a 

nonconformance as part of the emissions data verification statement. 

(11) When using an inventory measurement, stock measurement, or tank drop 

measurement method to calculate volumes and masses the method must be 

accurate to ±5 percent for the time periods required by this article, including 

annually for covered product data. Techniques used to quantify amounts 

stored at the beginning and end of these time periods are not subject to the 

calibration requirements of this section. Uncertainties in beginning and end 

amounts are subject to verifier review for material misstatement under section 

95131(b)(12) of this article. If any devices used to measure inputs and outputs 

do not meet the requirements of paragraphs (1)-(10) above, the verifier must 

account for this uncertainty when evaluating material misstatements. 

Reported values must be calculated using the following equations: 

Fuel consumed (volume or mass) = (inputs during time period – outputs 

during time period) + (amount stored at beginning of time period) – 

(amount stored at end of time period) 

Product produced (volume or mass) = (outputs during time period - inputs 

during time period) + (amount stored at end of time period - amount stored 

at beginning of time period) 

(l) Reporting and Verifying Product Data. The reporting entity must separately identify, 

quantify, and report all product data as specified in sections 95110-95124 and 

95156 of this article. It is the responsibility of the reporting entity to obtain 

verification services for the product data. Product data will be evaluated for 

conformance and material misstatement independent of GHG emissions data. 

Covered product data is evaluated for material misstatement and conformance, 

while the remaining reported product data is evaluated for conformance only. 

Reporting entities must exclude inaccurate covered product data, and may elect to 

exclude accurate covered product data. Reporting entities that exclude covered 

product data must report a description of the excluded data and an estimated 

magnitude using best available methods. The excluded covered product data will 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 86 February 2015 

not be used for the material misstatement assessment or for the total covered 

product data variable described in section 95131(b)(12)(A). Operators of cement 

plants may not exclude covered product data. 

(m) Changes in Methodology. Except as specified below, where this article permits a 

choice between different methods for the monitoring and calculation of GHGs and 

product data, the operator or supplier must make this choice by January 1, 2013, 

or January 1 of the first data year reporting under this article, and continue to use 

the method chosen for all future emissions data reports, unless the use of an 

alternative monitoring or calculation method is approved in advance by the 

Executive Officer. 

(1) The operator or supplier is permitted to permanently improve the emissions or 

product data monitoring or calculation method after January 1, 2013 through 

a change to a higher-tier monitoring or calculation method, such as the 

addition of a continuous emissions monitoring system. Permanent 

improvements to emissions monitoring or calculation methods do not require 

approval in advance by the Executive Officer; however, the operator or 

supplier must notify ARB prior to January 1 of the year the new method is 

implemented. Permanent changes to a lower-tier emissions monitoring or 

calculation method, and to all covered product data monitoring or calculation 

methods, must be approved in advance by the Executive Officer per the 

requirements in parts 95103(m)(2)-(3). 

(2) When proposing a permanent change in a monitoring or calculation method to 

the Executive Officer, an operator or supplier must indicate why the change in 

method is being proposed, include a detailed description of what data are 

affected by the alternate procedure, and include a demonstration of 

differences in estimated data under the two methods. 

(3) When permitted, a change in method must be made after the completion of 

monitoring for a data year and apply to the start of the subsequent data year, 

except in the circumstances described in part (m)(4). 

(4) The operator or supplier is permitted to temporarily modify the emissions or 

product data monitoring or calculation method when necessary for the 

avoidance of missing data or to comply with the missing data provisions of 

this article. In the event of an unforeseen breakdown in fuel analytical data 

monitoring equipment or CEMS equipment, operators and suppliers must use 

the procedures in section 95129(h) and section 95129(i), respectively, for 

seeking approval of interim data collection procedures. For all other 

instances that temporary methods are used, ARB must be notified by the 

reporting deadline of the following information: a description of the temporary 

method, the affected data, and the duration that the temporary method was 

used. A temporary method may be used for a period not to exceed 365 days 

unless the method is submitted and approved by the Executive Officer as a 

permanent method per the requirements in parts 95103(m)(2)-(3). Operators 

and suppliers must be able to demonstrate during verification that the 

temporary method provides data accuracy within ± 5% as specified in section 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 87 February 2015 

95103(k)(6). Covered product data that does not meet the required accuracy 

specification must be excluded using the procedure in section 95103(l) to 

avoid an adverse verification statement. 

(5) When regulatory changes impose new or revised reporting requirements or 

calculation methods on an operator or supplier, the monitoring and calculation 

method must be in place on January 1 of the year in which data is first 

required to be collected pursuant to the reporting requirements. 

(n) Changes in Ownership or Operational Control. If a reporting entity undergoes a 

change of ownership or operational control, the following requirements apply 

regarding notifications to ARB and reporting responsibilities. 

(1) ARB Notifications. Prior to the change of ownership or operational control, the 

previous owner or operator of the reporting entity and the new owner or 

operator of the reporting entity must provide the following information to ARB. 

Required information must be submitted to the ARB email account: 

ghgreport@arb.ca.gov

(A) The previous owner or operator must notify ARB via email of the 

ownership or operational control change including the name of the new 

owner or operator and the date of the ownership or operational control 

change. 

(B) The new owner or operator must notify ARB via email of the ownership or 

operational control change, including the following information: 

1. Previous owner or operator; 

2. New owner or operator; 

3. Date of ownership or operator change. 

4. Name of a new Designated Representative pursuant to section 

95104(b) for the affected entity’s account in the California Reporting 

Greenhouse Gas Reporting Tool (Cal e-GGRT) specified in section 

95104(e); 

(2) Reporting Responsibilities. The owner or operator of record at the time of a 

reporting or verification deadline specified in this article has the responsibility 

for complying with the requirements of this article, including certifying that the 

emissions data report is accurate and complete, obtaining verification 

services, and completing verification. 

(A) The owner or operator of record at the time of a reporting deadline is 

responsible for submitting the emissions data report covering the 

complete calendar year data. 

(B) If an ownership change takes place during the calendar year, reported 

data must not be split or subdivided for the year, based on ownership. A 

single annual data report must be submitted for the entity by the current 

owner or operator. This report must represent required data for the entire, 

calendar year. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 88 February 2015 

(C) Previous owners or operators are required to provide data and records to 

new owners or operators that is necessary and required for preparing 

annual emissions data reports required by this article. 

(o) Addresses. The following address shall be substituted for the addresses provided 

in 40 CFR §98.9 for both U.S. mail and package deliveries: 

 Executive Officer 

 Attn: Emission Inventory Branch 

 California Air Resources Board 

 P.O. Box 2815 

 Sacramento, CA 95812 

NOTE: Authority cited: Sections 38510, 38530, 39600, 39601, 39607, 39607.4 and 

41511, Health and Safety Code. Reference: Sections 38530, 39600 and 41511, Health 

and Safety Code. 

§ 95104. Emissions Data Report Contents and Mechanism. 

The reporting entities specified in section 95101 must develop, submit, and certify 

greenhouse gas emissions data reports to the Air Resources Board each year in accord 

with the following requirements. 

(a) General Contents. In addition to the items specified at 40 CFR §98.3(c), each 

reporting entity must include in the emissions data report the following California 

information: ARB identification number, air basin, air district, county, geographic 

location, and indicate whether the reporting entity qualifies for small business status 

pursuant to California Government Code 11342.610. Electricity generating units 

must also provide Energy Information Administration and California Energy 

Commission identification numbers, as applicable. Reporters subject to the AB 32 

Cost of Implementation Fee Regulation (title 17, California Code of Regulations, 

section 95200 to 95207), must report the official responsible for fees payment and 

the billing address for fees. 

(b) Designated Representative. Each reporting entity must designate a reporting

representative and adhere to the requirements of 40 CFR §98.4 for this 

representative and for any named alternate designated representatives.

(c) Corporate Parent and NAICS Codes. Each reporting entity must submit information 

to meet the requirements specified in amendments to 40 CFR Part 98 on Reporting 

of Corporate Parent Information, NAICS Codes and Cogeneration, as promulgated 

by U.S. EPA on September 22, 2010.

(d) Facility Level Energy Input and Output. The operator must include in the emissions 

data report information about the facility’s energy acquisitions and energy provided 

or sold as specified below. For the purpose of reporting under this paragraph, the 

operator may exclude any electricity that is generated outside the facility and 

delivered into the facility with final destination outside of the facility. The operator 

may also exclude electricity consumed by operations or activities that do not 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 89 February 2015 

generate any emissions, energy outputs, or products that are covered by this 

article, and that are neither a part of nor in support of electricity generation or any 

industrial activities covered by this article. The operator must report this information 

for the calendar year covered by the emissions data report, pro-rating purchases as 

necessary to include information for the full months of January and December. 

(1) Electricity purchases or acquisition from sources outside of the facility 

boundary (MWh) and the name and ARB identification number of each 

electricity provider, as applicable. 

(2) Thermal energy purchases or acquisitions from sources outside of the facility 

boundary (MMBtu) and the name and ARB identification number of each 

energy provider, as applicable. If the operator acquires thermal energy from a 

PURPA Qualifying Facility and vents, radiates, wastes, or discharges more 

than 10% of the acquired thermal energy before utilizing the energy in any 

industrial process, operation, or heating/cooling application, the operator must 

report the amount of thermal energy actually needed and utilized, in addition to 

the amount of thermal energy received from the provider. 

(3) Electricity provided or sold, as specified in section 95112(a)(4), if applicable. 

(4) Thermal energy provided or sold to entities outside of the facility boundary: the 

operator must report the amount of thermal energy provided or sold (MMBtu), 

the names and ARB identification number of each end-user as applicable, and 

the type of unit that generates the thermal energy. If section 95112 applies to 

the operator, the operator must follow the requirements of section 95112(a)(5) 

in reporting the thermal energy generated by cogeneration or bigeneration 

units, and if applicable, also separately report the information required in 

paragraph 95104(d)(4) for the thermal energy provided or sold that is not 

generated by cogeneration or bigeneration units. 

 If the facility boundary includes more than one cogeneration system, boiler, or 

steam generator, and each unit/system or each group of units produces 

thermal energy for different particular end-users or on-site industrial processes 

and operations, the operator must report the disposition of generated thermal 

energy by unit/system or by group of units with the same dispositions, and by 

the type of thermal energy product provided. 

(e) Reporting Mechanism. Reporting entities shall submit emissions data reports, and 

any revisions to the reports, through the California Air Resources Board’s (ARB) 

Greenhouse Gas Reporting Tool, or any other reporting tool approved by the 

Executive Officer that will guarantee transmittal and receipt of data required by 

ARB’s Mandatory Reporting Regulation and Cost of Implementation Fee 

Regulation. Reporting entities are not responsible for reporting data required under 

this article that is not specified for reporting in the reporting tool. 

(f) Increases and Decreases in Facility Emissions. The operator of a facility identified 

in section 95101(a)(1)(A)-(B) that is subject to the cap-and-trade regulation must 

include the following information in the emissions data report: 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 90 February 2015 

(1) Whether a change in the facility’s operations or status resulted in an increase 

or decrease of more than five percent in emissions of greenhouse gases in 

relation to the previous data year. 

(2) Specify which of the following reason(s) would be the cause of the increase or 

decrease in greenhouse gas emissions: 

(A) Change in production; 

(B) Changes in facility operations in order to comply with: 

1. The cap-and-trade regulation; 

2. Other air pollution regulations; 

3. Other regulations, not related to air pollution or greenhouse gases; 

(C) Changes in efficiency due to: 

1. Process or material changes; 

2. The addition of control equipment; 

3. Other efficiency measures; 

(D) Other. 

(3) A narrative description of how each reason identified in section 95104(f)(2) 

caused the increase or decrease in emissions. Include in this description any 

changes in your air permit status. 

(4) This section is not subject to the third-party verification requirements of this 

article. 

NOTE: Authority cited: Sections 38510, 38530, 39600, 39601, 39607, 39607.4 and 

41511, Health and Safety Code. Reference: Sections 38530, 39600 and 41511, Health 

and Safety Code. 

§ 95105. Recordkeeping Requirements. 

Each reporting entity that is required to report greenhouse gases under this article, 

except as provided in section 95103(a)(9), must keep records as required by 40 CFR 

§98.3(g)-(h) with the following qualifications. 

(a) Duration. Reporting entities with a compliance obligation under the cap-and-trade 

regulation in any year of the current compliance period must maintain all records 

specified in 40 CFR §98.3(g), and records associated with revisions to emissions 

data reports as provided under 40 CFR §98.3(h), for a period of ten years from the 

date of emissions data report certification. The retained documents, including GHG 

emissions data and input data, must be sufficient to allow for verification of each 

emissions data report. Reporting entities that do not have a compliance obligation 

under the cap-and-trade regulation during any year of the current compliance period 

must maintain such records for a period of five years from the date of certification. 

(b) ARB Requests for Records. Copies of any records or other materials maintained 

under the requirements of 40 CFR Part 98 or this article must be made available to 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 91 February 2015 

the Executive Officer upon request, within twenty days of receipt of such request by 

the designated representative of the reporting entity. 

(c) GHG Monitoring Plan for Facilities and Suppliers. Each facility operator or supplier 

that reports under 40 CFR Part 98, each facility operator or supplier with emissions 

equal to or exceeding 25,000 MTCO2e (including biomass-derived CO2 emissions 

and geothermal emissions), and each facility operator or supplier with a compliance 

obligation under the cap-and-trade regulation in any year of the current compliance 

period, must complete and retain for review by a verifier or ARB a written GHG 

Monitoring Plan that meets the requirements of 40 CFR §98.3(g)(5). For facilities, 

the Plan must also include the following elements, as applicable: 

(1) All fuel use measurement devices used for emissions calculations or product 

data must be clearly identified, and the plan must indicate how data from these 

devices are incorporated into the emissions data report. 

(2) Original equipment manufacturer (OEM) documentation, or other 

documentation that identifies instrument accuracy and required maintenance 

and calibration requirements for all measurement devices used in the 

calculation of GHG emissions. 

(3) Identification of measurement device location, and the location of any 

additional devices or sampling ports required for calculating covered 

emissions and product data (e.g. temperature, total pressure, HHV). 

(4) The dates of measurement device calibration or inspection, and the dates of 

the next required calibration or inspection. 

(5) Identification of low flow cutoffs, as applicable. 

(6) A listing of the equation(s) used to calculate mass or volume flows, and from 

which any non-measured parameters are obtained. 

(7) Records of the most recent orifice plate inspection performed according to the 

requirements of ISO 5167-2 (2003), section 5, or AGA Report No 3 (2003) 

Part 2, which are hereby incorporated by reference.

(8) Training practices for personnel involved in GHG monitoring, including 

documented training procedures, and training materials. 

(9) Copies of methodologies used for all fuel-based emissions analyses, including 

the standardized methods chosen as specified in section 95109. 

(10) At the operator’s choosing, a fuel monitoring plan to verify on a regular basis 

the proper functioning of fuel measurement equipment that is used to 

determine facility GHG emissions. The operator wishing to preserve the 

option of using the missing data substitution procedures in section 95129(d)(2) 

in the event that such procedures become necessary to use, must monitor fuel 

measurement equipment and maintain records of its proper operation by 

recording fuel consumption data at least weekly. The operator exercising this 

option may fulfill periodic fuel monitoring either through manual monitoring or 

by using an automatic data acquisition system that electronically records, 

stores, and identifies measurement device malfunctioning periods. The 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 92 February 2015 

records of fuel consumption must be sufficient for the application of the 

missing data substitution procedure in section 95129(d)(2) if that option is later 

chosen by the operator. 

(d) GHG Inventory Program for Electric Power Entities that Import or Export Electricity. 

In lieu of a GHG Monitoring Plan, electric power entities that import or export 

electricity must prepare GHG Inventory Program documentation that is maintained 

and available for verifier review and ARB audit pursuant to the recordkeeping 

requirements of this section. The following information is required: 

(1) Information to allow the verification team to develop a general understanding 

of entity boundaries, operations, and electricity transactions; 

(2) Reference to management policies or practices applicable to reporting 

pursuant to section 95111; 

(3) List of key personnel involved in compiling data and preparing the emissions 

data report; 

(4) Training practices for personnel involved in reporting delivered electricity 

pursuant to section 95111 and responsible for data report certification, 

including documented training procedures; 

(5) Query of NERC e-Tag source data to determine the quantity of electricity 

(MWh) imported, exported, and wheeled for transactions in which they are the 

purchasing-selling entity on the last physical path segment that crosses the 

border of the state of California, access to review the raw e-Tag data, a 

tabulated summary, and query description; 

(6) Reference to other independent or internal data management systems and 

records, including written power contracts and associated verbal or electronic 

records, full or partial ownership, invoices, and settlements data used to 

document whether reported transactions are specified or unspecified and 

whether the requirements for adjustments to covered emissions pursuant to 

sections 95852(b)(1)(B), 95852(b)(4) and 95852(b)(5) of the cap-and-trade 

regulation are met; 

(7) Description of steps taken and calculations made to aggregate data into 

reporting categories required pursuant to section 95111; 

(8) Records of preventive and corrective actions taken to address verifier and 

ARB findings of past nonconformances and material misstatements; 

(9) Log of emissions data report modifications made after initial certification; and 

(10) A written description of an internal audit program that includes emissions data 

report review and documents ongoing efforts to improve the GHG Inventory 

Program. 

NOTE: Authority cited: Sections 38510, 38530, 39600, 39601, 39607, 39607.4 and 

41511, Health and Safety Code. Reference: Sections 38530, 39600 and 41511, Health 

and Safety Code. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 93 February 2015 

§ 95106. Confidentiality. 

(a) Emissions data submitted to the ARB under this article is public information and 

shall not be designated as confidential. Data reported to U.S. EPA under 40 CFR 

Part 98 which has been released to the public by U.S. EPA shall be considered 

public information by ARB. 

(b) Any entity submitting information to the Executive Officer pursuant to this article 

may claim such information as “confidential” by clearly identifying such information 

as “confidential.” Any claim of confidentiality by an entity submitting information 

must be based on the entity’s belief that the information marked as confidential is 

either trade secret or otherwise exempt from public disclosure under the California 

Public Records Act (Government Code section 6250 et seq.). All such requests for 

confidentiality shall be handled in accordance with the procedures specified in title 

17, California Code of Regulations, sections 91000 to 91022. 

NOTE: Authority cited: Sections 38510, 38530, 39600, 39601, 39607, 39607.4 and 

41511, Health and Safety Code. Reference: Sections 38530, 39600 and 41511, Health 

and Safety Code. 

§ 95107. Enforcement. 

(a) Penalties may be assessed for any violation of this article pursuant to Health and 

Safety Code section 38580. In seeking any penalty amount, ARB shall consider all 

relevant circumstances, including any pattern of violation, the size and complexity of 

the reporting entity’s operations, and the other criteria in Health and Safety Code 

section 42403(b). 

(b) Each day or portion thereof that any report required by this article remains 

unsubmitted, is submitted late, or contains information that is incomplete or 

inaccurate is a single, separate violation. For purposes of this section, “report” 

means any emissions data report, verification statement, or other document 

required to be submitted to the Executive Officer by this article. 

(c) Each metric ton of CO2e emitted but not reported as required by this article is a 

separate violation. ARB will not initiate enforcement action under this subparagraph 

until after any applicable verification deadline for the pertinent report. 

(d) Each failure to measure, collect, record or preserve information in the manner 

required by this article constitutes a separate violation, except where the reporting 

entity can demonstrate that the failure results solely from maintenance or calibration 

required by this article. 

(e) The Executive Officer may revoke or modify any Executive Order issued pursuant 

to this article as a sanction for a violation of this article. 

(f) The violation of any condition of an Executive Order that is issued pursuant to this 

article is a separate violation. 

(g) Any violation of this article may be enjoined pursuant to Health and Safety Code 

section 41513. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 94 February 2015 

NOTE: Authority cited: Sections 38510, 38530, 38580, 39600, 39601, 39607, 39607.4 

and 41511, Health and Safety Code. Reference: Sections 38530, 38580, 39600 and 

41511, Health and Safety Code. 

§ 95108. Severability. 

Each part of this article shall be deemed severable, and in the event that any provision 

of this article is held to be invalid, the remainder of this article shall continue in full force 

and effect. 

NOTE: Authority cited: Sections 38510, 38530, 39600, 39601, 39607, 39607.4 and 

41511, Health and Safety Code. Reference: Sections 38530, 39600 and 41511, Health 

and Safety Code. 

§ 95109. Standardized Methods. 

(a) Entities that are required to report greenhouse gas emissions pursuant to this article 

must use either those standardized methods and materials listed in 40 CFR §98.7, 

or another similar method published by an organization listed in 40 CFR §98.7 that 

is applicable to the analysis being conducted. For gaseous fuels, fuel 

characteristics may be determined using chromatographic analysis as specified in 

40 CFR §98.34(a)(6) and §98.34(b)(5). All methods used must be documented in 

the GHG Monitoring Plan that is as required by section 95105(c). 

(b) Alternative test methods that are demonstrated to the satisfaction of the Executive 

Officer to be equally or more accurate than the methods in section 95109(a) may be 

used upon written approval by the Executive Officer. 

NOTE: Authority cited: Sections 38510, 38530, 39600, 39601, 39607, 39607.4 and 

41511, Health and Safety Code. Reference: Sections 38530, 39600 and 41511, Health 

and Safety Code. 

 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 95 February 2015 

Subarticle 2. Requirements for the Mandatory Reporting of Greenhouse Gas 

Emissions from Specific Types of Facilities, Suppliers, and Entities 

§ 95110. Cement Production. 

The operator of a facility who is required to report under section 95101 of this article, 

and who is not eligible for abbreviated reporting under section 95103(a), must comply 

with Subpart H of 40 CFR Part 98 (§§98.80 to 98.88) in reporting annual stationary 

combustion and process emissions and other data from cement production to ARB, 

except as otherwise provided in this section. 

(a) CO2 from Fossil Fuel Combustion. When calculating CO2 emissions from fuel 

combustion, the operator must use a method in 40 CFR §98.33(a)(1) to 

§98.33(a)(4) as specified by fuel type in section 95115 of this article. 

(b) Monitoring, Data and Records. For each emissions calculation method chosen 

under section 95110(a), the operator must meet the applicable requirements for 

monitoring, missing data procedures, data reporting, and records retention that are 

specified in 40 CFR §98.34 to §98.37, except as modified in sections 95110(c)-(d), 

95115, and 95129 of this article. 

(c) Missing Data Substitution Procedures. The operator must comply with 40 CFR 

§98.85 when substituting for missing data, except as otherwise provided in 

paragraphs (1)-(3) below. 

(1) To substitute for missing data for emissions reported under section 95115 of 

this article (stationary combustion units and units using continuous emissions 

monitoring systems), the operator must follow the requirements of section 

95129 of this article. 

(2) If data for the carbonate content of clinker or cement kiln dust as required by 

40 CFR §98.83(d) are missing, and a new analysis cannot be undertaken, the 

operator must apply a substitute value according to the procedures in 

paragraphs (A)-(C) below. 

(A) If the data capture rate is at least 90 percent for the data year, the 

operator must substitute for each missing value using the best available 

estimate of the parameter, based on all available process data. 

(B) If the data capture rate is at least 80 percent but not at least 90 percent 

for the data year, the operator must substitute for each missing value with 

the highest quality assured value recorded for the parameter during the 

given data year, as well as the two previous data years. 

(C) If the data capture rate is less than 80 percent for the data year, the 

operator must substitute for each missing value with the highest quality 

assured value recorded for the parameter in all records kept according to 

section 95105(a). 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 96 February 2015 

(3) For each missing value of the monthly raw material consumption or monthly 

clinker production used to calculate emissions, the operator must apply a 

substitute value according to paragraphs (A)-(B) below. 

(A) If the data capture rate is at least 80 percent for the data year, the 

operator must substitute for each missing value according to 40 CFR 

§98.85(c) or 40 CFR §98.85(d), as applicable. 

(B) If the data capture rate is less than 80 percent for the data year, the 

operator must substitute for each missing value with the maximum short 

tons of clinker per day capacity of the system or the maximum short tons 

per day raw material throughput of the kiln, as applicable, and the 

number of days per month. 

(4) The operator must document and retain records of the procedure used for all 

missing data estimates pursuant to the recordkeeping requirements of section 

95105. 

(d) Additional Product Data. In addition to the information required by 40 CFR §98.86, 

the operator must report the parameters provided in paragraphs (1)-(4) below 

whether or not a CEMS is used to measure CO2 emissions. 

(1) Annual quantity clinker produced (short tons). 

(2) Annual quantity clinker consumed (short tons). 

(3) Annual quantity of limestone and gypsum (including both natural and synthetic 

gypsum) consumed for blending (short tons). 

(4) Annual quantity of cement substitute consumed, by type (short tons). This 

parameter is not subject to review for material misstatement under the 

requirements of section 95131(b)(12). 

NOTE: Authority cited: Sections 38510, 38530, 39600, 39601, 39607, 39607.4 and 

41511, Health and Safety Code. Reference: Sections 38530, 39600 and 41511, Health 

and Safety Code. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 97 February 2015 

§ 95111. Data Requirements and Calculation Methods for Electric Power 

Entities. 

The electric power entity who is required to report under section 95101 of this article 

must comply with the following requirements. 

(a) General Requirements and Content for GHG Emissions Data Reports for Electricity 

Importers and Exporters. 

(1) Greenhouse Gas Emissions. The electric power entity must report GHG 

emissions separately for each category of delivered electricity required, in 

metric tons of CO2 equivalent (MT of CO2e), according to the calculation 

methods in section 95111(b). 

(2) Delivered Electricity. The electric power entity must report imported, exported, 

and wheeled electricity in MWh disaggregated by first point of receipt or final 

point of delivery, as applicable, and must also separately report imported and 

exported electricity from unspecified sources and from each specified source. 

Substitute electricity defined pursuant to section 95102(a) must be separately 

reported for each specified source, as applicable. First points of receipt (POR) 

and final points of delivery (POD) must be reported using the standardized 

code used in NERC e-Tags, as well as the full name of the POR/POD. 

(3) Imported Electricity from Unspecified Sources. When reporting imported 

electricity from unspecified sources, the electric power entity must report for 

each first point of receipt the following information: 

(A) Whether the first point of receipt is located in a linked jurisdiction 

published on the ARB Mandatory Reporting website; 

(B) The amount of electricity from unspecified sources as measured at the 

first point of delivery in California; and 

(C) GHG emissions, including those associated with transmission losses, as 

required in section 95111(b). 

(4) Imported Electricity from Specified Facilities or Units. The electric power entity 

must report all direct delivery of electricity as from a specified source for 

facilities or units in which they are a generation providing entity (GPE) or have 

a written power contract to procure electricity. When reporting imported 

electricity from specified facilities or units, the electric power entity must 

disaggregate electricity deliveries and associated GHG emissions by facility or 

unit and by first point of receipt, as applicable. The reporting entity must also 

report total GHG emissions and MWh from specified sources and the sum of 

emissions from specified sources explicitly listed as not covered pursuant to 

section 95852.2 of the cap-and-trade regulation. The sale or resale of 

specified source electricity is permitted among entities on the e-tag market 

path insofar as each sale or resale is for specified source electricity in which 

sellers have purchased and sold specified source electricity, such that each 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 98 February 2015 

seller warrants the sale of specified source electricity from the source through 

the market path. 

(A) Claims of specified sources of imported electricity, defined pursuant to 

section 95102(a), are calculated pursuant to section 95111(b), must meet 

the requirements in section 95111(g), and must include the following 

information: 

1. Measured at Busbar. The amount of imported electricity from 

specified facilities or units as measured at the busbar; and 

2. Not Measured at Busbar. If the amount of imported electricity 

deliveries from specified facilities or units as measured at the busbar 

is not provided, report the amount of imported electricity as 

measured at the first point of delivery in California, including 

estimated transmission losses as required in section 95111(b), and 

the reason why measurement at the busbar is not known. 

(5) Imported Electricity Supplied by Asset-Controlling Suppliers. The reporting 

entity must separately report imported electricity supplied by asset-controlling 

suppliers recognized by ARB. The reporting entity must: 

(A) Report the asset-controlling supplier standardized PSE acronym or code, 

full name, and the ARB identification number; 

(B) Report asset-controlling supplier power that was not acquired as 

specified power, as unspecified power; 

(C) Report delivered electricity from asset-controlling suppliers as measured 

at the first point of delivery in the state of California; and, 

(D) Report GHG emissions calculated pursuant to section 95111(b), including 

transmission losses. 

(E) Tagging ACS Power. To claim power from an asset-controlling supplier, 

the asset-controlling supplier must be identified on the physical path of 

the NERC e-Tag as the PSE at the first point of receipt, or in the case of 

asset controlling suppliers that are exclusive marketers, as the PSE 

immediately following the associated generation owner. 

(6) Exported Electricity. The electric power entity must report exported electricity 

in MWh and associated GHG emissions in MT of CO2e for unspecified 

sources disaggregated by each final point of delivery outside the state of 

California, and for each specified source disaggregated by each final point of 

delivery outside the state of California, as well as the following information: 

(A) Exported electricity as measured at the last point of delivery located in 

the state of California, if known. If unknown, report as measured at the 

final point of delivery outside California. 

(B) Do not report estimated transmission losses. 

(C) Report whether the final point of delivery is located in a linked jurisdiction 

published on the ARB Mandatory Reporting website. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 99 February 2015 

(D) Report GHG emissions calculated pursuant to section 95111(b). 

(E) Separately report qualified exports as defined in section 95102(a). 

(7) Exchange Agreements. The electric power entity must report delivered 

electricity under power exchange agreements consistent with imported and 

exported electricity requirements of this section. Electricity delivered into the 

state of California under exchange agreements must be reported as imported 

electricity and electricity delivered out of California under exchange 

agreements must be reported as exported electricity. 

(8) Electricity Wheeled Through California. The electric power entity who is the 

PSE on the last physical path segment that crosses the border of the State of 

California on the NERC e-tag must separately report electricity wheeled 

through California, aggregated by first point of receipt, and must exclude 

wheeled power transactions from reported imports and exports. When 

reporting electricity wheeled through California, the power entity must include 

the quantities of electricity wheeled through California as measured at the first 

point of delivery inside the state of California. 

(9) Verification Documentation. The electric power entity must retain for purposes 

of verification NERC e-Tags, written power contracts, settlements data, and all 

other information required to confirm reported electricity procurements and 

deliveries pursuant to the recordkeeping requirements of section 95105. 

(10) Electricity Generating Units and Cogeneration Units in California. Electric 

power entities that also operate electricity generating units or cogeneration 

units located inside the state of California that meet the applicability 

requirements of this article must report GHG emissions to ARB under section 

95112. 

(11) Electricity Generating Units and Cogeneration Units Outside California. 

Operators and owners of electricity generating units and cogeneration units 

located outside the state of California who elect to report to ARB under section 

95112 must fully comply with the reporting and verification requirements of this 

article. 

(12) Electrical Distribution Utility Sales into CAISO. All electrical distribution utilities 

(EDU) except IOUs must report the annual MWh of all electricity sold into the 

CAISO markets for which an EDU has a compliance obligation, beginning with 

calendar years 2013 and 2014 reported in 2015. EDUs must report MWh by 

source of generation (if known), of the electricity sold into the CAISO markets 

and for which the EDU has a compliance obligation, and the emission factor (if 

known) for each source of generation. This requirement does not apply to 

EDUs that have had all of their directly allocated allowances allocated for the 

data year placed in their limited use holding account pursuant to section 

95892(b)(2) of the Cap-and-Trade Regulation. Verifiers must contact the Air 

Resources Board directly to confirm that a specific EDU is not subject to this 

requirement. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 100 February 2015 

(b) Calculating GHG Emissions.

(1) Calculating GHG Emissions from Unspecified Sources. For electricity from 

unspecified sources, the electric power entity must calculate the annual CO2

equivalent mass emissions using the following equation: 

Where: 

CO2e = Annual CO2 equivalent mass emissions from the unspecified 

electricity deliveries at each point of receipt identified (MT of CO2e). 

MWh = Megawatt-hours of unspecified electricity deliveries at each point of 

receipt identified. 

EFunsp = Default emission factor for unspecified electricity imports. 

EFunsp = 0.428 MT of CO2e/MWh 

TL = Transmission loss correction factor. 

TL = 1.02 to account for transmission losses between the busbar and 

measurement at the first point of receipt in California. 

(2) Calculating GHG Emissions from Specified Facilities or Units. For electricity 

from specified facilities or units, the electric power entity must calculate 

emissions using the following equation: 

Where: 

CO2e = Annual CO2 equivalent mass emissions from the specified 

electricity deliveries from each facility or unit claimed (MT of CO2e). 

MWh = Megawatt-hours of specified electricity deliveries from each facility 

or unit claimed. 

EFsp = Facility-specific or unit-specific emission factor published on the 

ARB Mandatory Reporting website and calculated using total 

emissions and transactions data as described below. The emission 

factor is based on data from the year prior to the reporting year. 

EFsp = 0 MT of CO2e for facilities below the GHG emissions compliance

threshold for delivered electricity pursuant to the cap-and-trade 

regulation during the first compliance period. 

TL = Transmission loss correction factor. 

TL = 1.02 to account for transmission losses associated with generation 

outside of a California balancing authority. 

TL = 1.0 if the reporting entity provides documentation that demonstrates 

to the satisfaction of a verifier and ARB that transmission losses (1) 

have been accounted for, (2) are supported by a California 

balancing authority, or (3) are compensated by using electricity 

sourced from within California. 

MWh TL EFunsp CO2e = × ×

MWh TL EFsp CO2e = × ×
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 101 February 2015 

The Executive Officer shall calculate facility-specific or unit-specific emission 

factors and publish them on the ARB Mandatory Reporting website using the 

following equation: 

EFsp = Esp /EG 

Where: 

Esp = CO2e emissions for a specified facility or unit for the report year 

(MT of CO2e). 

EG = Net generation from a specified facility or unit for the report year 

shall be based on data reported to the Energy Information 

Administration (EIA). 

If order to register a specified unit(s) source of power pursuant to section 

95111(g)(1), the reporting entity must provide to ARB unit level GHG 

emissions consistent with the data source requirements of this section and net 

generation data as reported to the EIA, along with contracts for delivery of 

power from the specified unit(s) to the reporting entity, and proof of direct 

delivery of the power by the reporting entity as an import to California. 

(A) For specified facilities or units whose operators are subject to this article 

or whose owners or operators voluntarily report under this article, Esp

shall be equal to the sum of CO2e emissions reported pursuant to section 

95112. 

(B) For specified facilities or units whose operators are not subject to 

reporting under this article or whose owners or operators do not 

voluntarily report under this article, but are subject to the U.S. EPA GHG 

Mandatory Reporting Regulation, Esp shall be based on GHG emissions 

reported to U.S. EPA pursuant to 40 CFR Part 98. Emissions from 

combustion of biomass-derived fuels will be based on EIA data until such 

time the emissions are reported to U.S. EPA. 

(C) For specified facilities or units whose operators are not subject to reporting 

under this article or whose owners or operators do not voluntarily report 

under this article, nor are subject to the U.S. EPA GHG Mandatory 

Reporting Regulation, Esp is calculated using heat of combustion data 

reported to the Energy Information Administration (EIA) 

Esp = 0.001 x Σ(Q x EF) 

Where: 

0.001 = conversion factor kg to MT 

Q = Heat of combustion for each specified fuel type from the specified 

facility or unit for the report year (MMBtu). For cogeneration, Q is the 

quantity of fuel allocated to electricity generation consistent with EIA 

reporting. For geothermal electricity, Q is the steam data reported to 

EIA (MMBtu). 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 102 February 2015 

EF = O2e emission factor for the specified fuel type as required by this 

article (kg CO2e /MMBtu). For geothermal electricity, EF is the 

estimated CO2 emission factor published by EIA. 

(D) Facilities or units will be assigned an emission factor by the Executive 

Officer based on the type of fuel combusted or the technology used when 

a U.S. EPA GHG Report or EIA fuel consumption report is not available, 

including new facilities and facilities located outside the U.S. 

(E) Meter Data Requirement. For verification purposes, electric power 

entities shall retain meter generation data to document that the power 

claimed by the reporting entity was generated by the facility or unit at the 

time the power was directly delivered. This provision is applicable to 

imports from specified sources for which ARB has calculated an emission 

factor of zero, and for imports from California Renewable Portfolio 

Standard (RPS) eligible resources, excluding: (1) contract or ownership 

agreements, known as grandfathered contracts that meet California RPS 

program requirements in Public Utilities Code Section 399.16(d) or 

California Code of Regulations, Title 20 Section 3202(a)(2)(A); 

(2) dynamically tagged power deliveries; (3) untagged power deliveries, 

including EIM imports; (4) nuclear power; (5) asset controlling supplier 

power; and (6) imports from hydroelectric facilities for which an entity’s 

share of metered output on an hourly basis is not established by power 

contract. Accordingly, a lesser of analysis is required pursuant to the 

following equation: 

Sum of Lesser of MWh = ΣHMsp min(MGsp, TGsp)

Where: 

ΣHMsp = Sum of the Hourly Minimum of MGsp and TGsp (MWh). 

MGsp = metered facility or unit net generation (MWh). 

Ssp = entity’s share of metered output. 

TGsp = tagged or transmitted energy at the transmission or subtransmission level imported to California (MWh). 

(3) Calculating GHG Emissions of Imported Electricity Supplied by AssetControlling Suppliers. Based on annual reports submitted to ARB pursuant to 

section 95111(f), ARB will calculate and publish on the ARB Mandatory 

Reporting website the system emission factor for all asset-controlling suppliers 

recognized by the ARB. The reporting entity must calculate emissions for 

electricity supplied using the following equation: 

Where: 

CO2e = Annual CO2 equivalent mass emissions from the specified 

electricity deliveries from ARB-recognized asset-controlling suppliers (MT 

of CO2e). 

MWh = Megawatt-hours of specified electricity deliveries. 

MWh TL EFACS CO2e = × ×
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 103 February 2015 

EFACS = Asset-Controlling Supplier system emission factor published on the 

ARB Mandatory Reporting website (MTCO2e/MWh). ARB will assign the 

system emission factors for all asset-controlling suppliers based on a 

previously verified GHG report submitted to ARB pursuant to section 

95111(f). The supplier-specific system emission factor is calculated 

annually by ARB. The calculation is derived from data contained in 

annual reports submitted pursuant to section 95111(f) that have received 

a positive or qualified positive verification statement. The emission factor 

is based on data from two years prior to the reporting year. 

TL = Transmission loss correction factor. 

TL = 1.02 when deliveries are not reported as measured at a first point of 

receipt located within the balancing authority area of the asset-controlling 

supplier. 

TL = 1.0 when deliveries are reported as measured at a first point of receipt 

located within the balancing authority area of the asset-controlling 

supplier. 

The Executive Officer shall calculate the system emission factor for assetcontrolling suppliers using the following equations: 

EFACS = Sum of System Emissions MT of CO2e / Sum of System MWh 

Sum of System Emissions, MT of CO2e = ΣEasp + Σ(PEsp * EFsp) + 

 Σ(PEunsp * EFunsp ) - Σ(SEsp * EFsp) 

Sum of System MWh = ΣEGasp + ΣPEsp + ΣPEunsp – ΣSEsp

Where: 

ΣEasp = Emissions from Owned Facilities. Sum of CO2e emissions from 

each specified facility/unit in the asset-controlling supplier’s fleet, 

consistent with section 95111(b)(2) (MT of CO2e). 

ΣEGasp = Net Generation from Owned Facilities. Sum of net generation 

for each specified facility/unit in the asset-controlling supplier’s fleet 

for the data year as reported to ARB under this article (MWh). 

PEsp = Electricity Purchased from Specified Sources. Amount of 

electricity purchased wholesale and taken from specified sources by 

the asset-controlling supplier for the data year as reported to ARB 

under this article (MWh). 

PEunsp = Electricity Purchased from Unspecified Sources. Amount of 

electricity purchased wholesale from unspecified sources by the 

asset-controlling supplier for the data year as reported to ARB under 

this article (MWh). 

SEsp = Electricity Sold from Specified Sources. Amount of wholesale 

electricity sold from specified sources by the asset-controlling 

supplier for the data year as reported to ARB under this article 

(MWh).

EFsp = CO2e emission factor as defined for each specified facility or unit 

calculated consistent with section 95111(b)(2) (MTCO2e/MWh). 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 104 February 2015 

EFunsp = Default emission factor for unspecified sources calculated 

consistent with section 95111(b)(1) (MTCO2e/MWh). 

(4) Calculating GHG Emissions of Imported Electricity for Multi-jurisdictional Retail 

Providers. Multi-jurisdictional retail providers must include emissions and 

megawatt-hours in the terms below from facilities or units that contribute to a 

common system power pool. Multi-jurisdictional retail providers do not include 

emissions or megawatt-hours in the terms below from facilities or units 

allocated to serve retail loads in designated states pursuant to a cost 

allocation methodology approved by the California Public Utilities Commission 

(CPUC) and the utility regulatory commission of at least one additional state in 

which the multi-jurisdictional retail provider provides retail electric service. 

Multi-jurisdictional retail providers must calculate emissions that have a 

compliance obligation using the following equation: 

CO2e = (MWhR x TLR - MWhWSP-CA - EGCA) x EFMJRP + 

MWWSP-notCA x TLWSP x EFunsp - CO2elinked

Where: 

CO2e = Annual CO2e mass emissions of imported electricity (MT of CO2e). 

MWhR = Total electricity procured by multi-jurisdictional retail provider to 

serve its retail customers in California, reported as retail sales for 

California service territory, MWh. 

MWhWSP-CA = Wholesale electricity procured in California by multijurisdictional retail provider to serve its retail customers in California, as 

determined by the first point of receipt on a NERC e-Tag and pursuant to 

a cost allocation methodology approved by the California Public Utilities 

Commission (CPUC) and the utility regulatory commission of at least one 

additional state in which the multi-jurisdictional retail provider provides 

retail electric service, MWh. 

MWhWSP-not CA = Wholesale electricity imported into California by multijurisdictional retail provider with a final point of delivery in California and 

not used to serve its California retail customers, MWh. 

EFMJRP = Multi-jurisdictional retail provider system emission factor calculated 

by ARB pursuant to subsection 95111(b)(3) and consistent with a cost 

allocation methodology approved by the California Public Utilities 

Commission (CPUC) and the utility regulatory commission of at least one 

additional state in which the multi-jurisdictional retail provider provides 

retail electric service. 

EFunsp = Default emission factor for unspecified sources calculated 

consistent with section 95111(b)(1) (MTCO2e/MWh). 

EGCA = Net generation measured at the busbar of facilities and units 

located in California that are allocated to serve its retail customers in 

California pursuant to a cost allocation methodology approved by the 

California Public Utilities Commission (CPUC) and the utility regulatory 

commission of at least one additional state in which the multijurisdictional retail provider provides retail electric service, MWh. 

TL = Transmission loss correction factor. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 105 February 2015 

TL WSP= 1.02 for transmission losses applied to wholesale power . 

TL R = Estimate of transmission losses from busbar to end user reported 

by multi-jurisdictional retail provider. 

CO2e linked = Annual CO2e mass emissions recognized by ARB pursuant to 

linkage under subarticle 12 of the cap-and-trade regulation (MT of CO2e). 

(5) Calculation of Covered Emissions. For imported electricity with covered 

emissions as defined pursuant to section 95102(a), the electric power entity 

must calculate and report covered emissions pursuant to the equation in 

95852(b)(1)(B) of the cap-and-trade regulation and include the following 

information: 

CO2e covered = Sum of covered emissions defined pursuant to section 95102(a) 

and calculated pursuant to the equation in section 95852(b)(1)(B) of the 

cap-and-trade regulation (MT of CO2e). 

CO2e unsp = Sum of CO2 equivalent mass emissions from imported electricity 

from unspecified sources (MT of CO2e). 

CO2e sp = Sum of CO2 equivalent mass emissions from imported electricity 

that meets the requirements in section 95111(g) for reporting electricity 

from specified sources (MT of CO2e). 

CO2e sp-not covered = Sum of CO2 equivalent mass emissions from imported 

electricity that meets the requirements in section 95111(g) for reporting 

electricity from specified sources and is explicitly listed as emissions 

without a compliance obligation pursuant to section 95852.2 of the capand-trade regulation (MT of CO2e). 

CO2e RPS adjust = Sum of CO2 equivalent mass emissions adjustment is 

calculated using the following equation for electricity generated by each 

eligible renewable energy resource located outside the state of California 

and registered with ARB by the reporting entity pursuant to section 

95111(g)(1), but not directly delivered as defined pursuant to section 

95102(a). Electricity included in the RPS adjustment must meet the 

requirements pursuant to section 95852(b)(4) of the cap-and-trade 

regulation (MT of CO2e). 

CO2eRPS_adjust = MWhRPS x EFunsp (MTCO2e/MWh) 

Where: 

MWhRPS = Sum of MWh generated by each eligible renewable energy 

resource located outside of the state of California, registered with ARB 

pursuant to section 95111(g)(1), and meeting requirements pursuant to 

section 95852(b)(4) of the cap-and-trade regulation. 

CO2e QE adjust = Sum of CO2 equivalent mass emissions adjustment for 

qualified exports as defined in section 95102(a) and that meet the 

requirements pursuant to section 95852(b)(5) of the cap-and-trade 

regulation (MT of CO2e). 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 106 February 2015 

CO2e linked = Sum of CO2e mass emissions recognized by ARB pursuant to 

linkage under subarticle 12 of the cap-and-trade regulation (MT of CO2e). 

(c) Additional Requirements for Retail Providers, excluding Multi-jurisdictional Retail 

Providers. Retail providers must include the following information in the GHG 

emissions data report for each report year, in addition to the information identified in 

sections 95111(a)-(b) and (g). 

(1) Retail providers must report California retail sales. A retail provider who is 

required only to report retail sales may choose not to apply the verification 

requirements specified in section 95103, if the retail provider deems the 

emissions data report non-confidential. 

(2) Retail providers may elect to report the subset of retail sales attributed to the 

electrification of shipping ports, truck stops, and motor vehicles if metering is 

available to separately track these sales from other retail sales. 

(3) For facilities or units located outside California in a jurisdiction where a GHG 

emissions trading system has not been approved for linkage pursuant to 

subarticle 12 of the cap-and-trade regulation, that are fully or partially owned 

by a retail provider that have GHG emissions greater than the default emission 

factor for unspecified imported electricity based on the most recent GHG 

emissions data report submitted to ARB or U.S. EPA, the retail provider must 

include: 

(A) Information required in section 95111(g)(1) in data years with no reported 

imported electricity from the facility or unit; 

(B) The quantity of electricity from the facility or unit sold by the retail provider 

or on behalf of the retail provider having a final point of delivery outside 

California, as measured at the busbar. 

(C) High GHG-Emitting Facilities or Units. For facilities or units that are 

operated by a retail provider or fully or partially owned by a retail provider, 

excluding multi-jurisdictional retail providers, and that have emissions 

greater than the default emission factor for unspecified electricity based 

on the most recent GHG emissions data report submitted to ARB or to 

U.S.EPA, the retail provider must report the following information: 

1. When the product of net generation (MWh) and ownership share is 

greater than imported electricity (MWh), emissions associated with 

electricity not imported into California must be reported as 

CO2e not imported = (EGsp*OS – Isp)*EFsp. 

Where: 

EGsp = facility or unit net generation, MWh. 

OS = fraction ownership share. 

Isp = imported electricity, MWh. 

EFsp. = facility or unit-specific emission factor, MT of CO2e/MWh. 

2. List the replacement generation sources, locations, and whether 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 107 February 2015 

they are new units when Isp< 90% of EGsp*OS and when a facility 

specified in the previous report year has no imported electricity in the 

current report year. 

(4) Retail providers that report as electricity importers or exporters also must 

separately report electricity imported from specified and unspecified sources 

by other electric power entities to serve their load, designating the electricity 

importer. In addition, all imported electricity transactions documented by 

NERC e-Tags where the retail provider is the PSE at the sink must be 

reported. 

(d) Additional Requirements for Multi-Jurisdictional Retail Providers. Multi-jurisdictional 

retail providers that provide electricity into California at the distribution level must 

include the following information in the GHG emissions data report for each report 

year, in addition to the information identified in section 95111(a)-(b). 

(1) A report of the electricity transactions and GHG emissions associated with the 

common power system or contiguous service territory that includes consumers 

in California. This includes the requirements in this section as applicable for 

each generating facility or unit in the multi-jurisdictional retail provider’s fleet; 

(2) The multi-jurisdictional retail provider must include in its emissions data report 

wholesale power purchased and taken (MWh) from specified and unspecified 

sources and wholesale power sold from specified sources according to the 

specifications in this section, and as required for ARB to calculate a supplierspecific emission factor; 

(3) Total retail sales (MWh) by the multi-jurisdictional retail provider in the 

contiguous service territory or power system that includes consumers in 

California; 

(4) Retail sales (MWh) to California customers served in California’s portion of the 

service territory; 

(5) GHG emissions associated with the imported electricity, including both 

California retail sales and wholesale power imported into California from the 

retail provider’s system, according to the specifications in this section; 

(6) Multi-jurisdictional retail providers that serve California load must claim as 

specified power all power purchased or taken from facilities or units in which 

they have operational control or an ownership share or written power contract; 

(7) Multi-jurisdictional retail providers that serve California load may elect to 

exclude information listed in 95111(g)(1)(E)-(J) when registering claims to 

specified power from facilities located outside California and participating in 

the Federal Energy Regulatory Commission’s PURPA Qualifying Facility 

program. 

(e) Additional Requirements for WAPA and DWR.

(1) In reporting its GHG emissions to ARB, the California Department of Water 

Resources shall include all applicable information identified in this article for 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 108 February 2015 

retail providers, including the amount of electricity used for pump loads, to 

operate the State Water Project. 

(2) In reporting its GHG emissions to ARB, the Western Area Power Agency shall 

include all applicable information identified in this article for retail providers, 

including the amount of electricity used for pump loads, to operate the Central 

Valley Project. 

(f) Requirements for Asset-Controlling Suppliers. Owners or operators of electricity 

generating facilities or exclusive marketers for certain generating facilities may 

apply for an asset-controlling supplier designation from ARB. Approved assetcontrolling suppliers may request that ARB calculate a supplier-specific emission 

factor pursuant to section 95111(b)(3). To apply for asset-controlling supplier 

designation, the applicant must: 

To apply for asset-controlling supplier designation, the applicant must: 

(1) Meet the requirements in this article, including reporting pursuant to section 

95112 as applicable for each generating facility or unit in the supplier’s fleet; 

(2) Include in its emissions data report wholesale power purchased and taken 

(MWh) from specified and unspecified sources and wholesale power sold from 

specified sources according to the specifications in this section, and as 

required for ARB to calculate a supplier-specific emission factor; 

(3) Retain for verification purposes documentation that the power sold by the 

supplier originated from the supplier’s fleet of facilities and either that the fleet 

is under the supplier’s operational control or that the supplier serves as the 

fleet’s exclusive marketer; 

(4) Provide the supplier-specific ARB identification number to electric power 

entities who purchase electricity from the supplier’s system. 

(5) To apply for and maintain asset-controlling supplier status, the entity shall 

submit as part of its emissions data report the following information, annually: 

(A) General business information, including entity name and contact 

information; 

(B) List of officer names and titles; 

(C) Data requirements per section 95111(b)(3); 

(D) Data requirements per section 95111(g)(1); 

(E) A list and description of electricity generating facilities for which the 

reporting entity is a generation providing entity pursuant to 95102(a); and, 

(F) An attestation, in writing and signed by an authorized officer of the 

applicant, as follows: 

 “I certify under penalty of perjury under the laws of the State of California 

that I am duly authorized by [name of entity] to sign this attestation on 

behalf of [name of entity], that [name of entity] meets the definition of an 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 109 February 2015 

asset-controlling supplier as specified in section 95102(a) of the 

Regulation for the Mandatory Reporting of Greenhouse Gas Emissions, 

title 17, California Code of Regulations, section 95100 et seq., and that 

the information submitted herein is true, accurate, and complete.” 

 Asset-controlling suppliers must annually adhere to all reporting and 

verification requirements of this article, or be removed from asset-controlling 

supplier designation. Asset-controlling suppliers will also lose their 

designation if they receive an adverse verification statement, but may reapply 

in the following year for re-designation. 

(g) Requirements for Claims of Specified Sources of Electricity, and for Eligible 

Renewable Energy Resources in the RPS Adjustment. 

Each reporting entity claiming specified facilities or units for imported or exported 

electricity must register its anticipated specified sources with ARB pursuant to 

subsection 95111(g)(1) and by February 1 following each data year to obtain 

associated emission factors calculated by ARB for use in the emissions data report 

required to be submitted by June 1 of the same year. If an operator fails to register 

aspecified source by the June 1 reporting deadline specified in section 95103(e), 

the operator must use the emission factor provided by ARB for a specified facility or 

unit in the emissions data report required to be submitted by June 1 of the same 

year. Each reporting entity claiming specified facilities or units for imported or 

exported electricity must also meet requirements pursuant to subsection 

95111(g)(2)-(5) in the emissions data report. Each reporting entity claiming an RPS 

adjustment, as defined in section 95111(b)(5), pursuant to section 95852(b)(4) of 

the cap-and-trade regulation must include registration information for the eligible 

renewable energy resources pursuant to subsection 95111(g)(1) in the emissions 

data report. Prior registration and subsection 95111(g)(2)-(5) do not apply to RPS 

adjustments. Registration information and the amount of electricity claimed in the 

RPS adjustment must be fully reconciled and corrections must be certified within 45 

days following the emissions data report due date. 

(1) Registration Information for Specified Sources and Eligible Renewable Energy 

Resources in the RPS Adjustment. The following information is required: 

(A) The facility names and, for specification to the unit level, the facility and 

unit names. 

(B) For sources with a previously assigned ARB identification number, the 

ARB facility or unit identification number or supplier number published on 

ARB’s mandatory reporting program website. For newly specified 

sources, ARB will assign a unique identification number. 

(C) If applicable, the facility and unit identification numbers as used for 

reporting to the U.S. EPA Acid Rain Program, U.S. EPA pursuant to 40 

CFR Part 98, U.S. Energy Information Administration, Federal Energy 

Regulatory Commission’s PURPA Qualifying Facility program, California 

Energy Commission, and California Independent System Operator, as 

applicable. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 110 February 2015 

(D) The physical address of each facility, including jurisdiction. 

(E) Provide names of facility owner and operator. 

(F) The percent ownership share and whether the facility or unit is under the 

electricity importer’s operational control. 

(G) Total facility or unit gross and net nameplate capacity when the electricity 

importer is a GPE. 

(H) Total facility or unit gross and net generation when the electricity importer 

is a GPE. 

(I) Start date of commercial operation and, when applicable, date of 

repowering. 

(J) GPEs claiming additional capacity at an existing facility must include the 

implementation date, the expected increase in net generation (MWh), and 

a description of the actions taken to increase capacity. 

(K) Designate whether the facility or unit is a newly specified source, a 

continuing specified source, or was a specified source in the previous 

report year that will not be specified in the current report year. 

(L) Provide the primary technology or fuel type as listed below: 

1. Variable renewable resources by type, defined for purposes of this 

article as pure solar, pure wind, and run-of-river hydroelectricity; 

2. Hybrid facilities such as solar thermal; 

3. Hydroelectric facilities ≤ 30 MW, not run-of-river; 

4. Hydroelectric facilities > 30 MW; 

5. Geothermal binary cycle plant or closed loop system; 

6. Geothermal steam plant or open loop system; 

7. Units combusting biomass-derived fuel, by primary fuel type; 

8. Nuclear facilities; 

9. Cogeneration by primary fuel type; 

10. Fossil sources by primary fuel type; 

11. Co-fired fuels; 

12. Municipal solid waste combustion; 

13. Other. 

(M) Provide the primary facility name, total number of Renewable Energy 

Credits (RECs), the vintage year and month, and serial numbers of the 

RECs as specified below: 

1. RECs associated with electricity procured from an eligible renewable 

energy resource and reported as an RPS adjustment as well as 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 111 February 2015 

whether the RECs have been placed in a retirement subaccount and 

designated as retired for the purpose of compliance with the 

California RPS program. 

2. RECs associated with electricity procured from an eligible renewable 

energy resource and reported as an RPS adjustment in a previous 

emissions data report year that were subsequently withdrawn from 

the retirement subaccount, or modified the associated emissions 

data report year the RPS adjustment was claimed, and the date of 

REC withdrawal or modification. 

3. RECs associated with electricity generated, directly delivered, and 

reported as specified imported electricity and whether or not the 

RECs have been placed in a retirement subaccount. 

(2) Emission Factors. The emission factor published on the ARB Mandatory 

Reporting website, calculated by ARB according to the methods in section 

95111(b), must be used when reporting GHG emissions for a specified source 

of electricity. 

(3) Delivery Tracking Conditions Required for Specified Electricity Imports. 

Electricity importers may claim a specified source when the electricity delivery 

meets any of the criteria for direct delivery of electricity defined in section 

95102(a), and one of the following sets of conditions: 

(A) The electricity importer is a GPE; or 

(B) The electricity importer has a written power contract for electricity 

generated by the facility or unit. 

(4) Additional Information for Specified Sources. For each claim to a specified 

source of electricity, the electricity importer must indicate whether one or more 

of the following descriptions applies: 

(A) Deliveries from specified sources previously reported as consumed in 

California. Specified source of electricity has been reported in a 2009 

verified data report and is claimed for the current data year by the same 

electricity importer, based on a written power contract or status as a GPE 

in effect prior to January 1, 2010 that remains in effect, or that has been 

renegotiated for the same facility or generating unit for up to the same 

share or quantity of net generation within 12 months following prior 

expiration; or a specified facility for which imported electricity was 

reported as greater than 80 percent of net generation in the 2009 or 2010 

data years; 

(B) Deliveries from existing federally owned hydroelectricity facilities by 

exclusive marketers. Electricity from specified federally owned 

hydroelectricity facility delivered by exclusive marketers; 

(C) Deliveries from existing federally owned hydroelectricity facilities 

allocated by contract. Specified federally owned hydroelectricity source 

delivered by electricity importers with a written power contract in effect 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 112 February 2015 

within 12 months after changes in rights due to federal power allocation 

or redistribution policies, including acts of Congress, and not related to 

price bidding, that remains in effect or has been renegotiated for the 

same facility for up to the same share or quantity of net generation within 

12 months following prior contract expiration; 

(D) Deliveries from new facilities. Specified source of electricity is first 

registered pursuant to section 95111(g)(1) and delivered by an electricity 

importer within 12 months of the start date of commercial operation and 

the electricity importer making a claim in the current data year is either a 

GPE or purchaser of electricity under a written power contract; 

(E) Deliveries from existing facilities with additional capacity. Specified 

source of electricity is first registered pursuant to section 95111(g)(1) and 

delivered by a GPE within 12 months of the start date of an increase in 

the facility’s generating capacity due to increased efficiencies or other 

capacity increasing actions. 

(5) Substitute electricity. Report substitute electricity received from specified and 

unspecified sources pursuant to the requirements of this section. 

NOTE: Authority cited: Sections 38510, 38530, 39600, 39601, 39607, 39607.4 and 

41511, Health and Safety Code. Reference: Sections 38530, 39600 and 41511, Health 

and Safety Code. 

§ 95112. Electricity Generation and Cogeneration Units. 

The operator of a facility who is required to report under section 95101 of this article, 

and who is not eligible for abbreviated reporting under section 95103(a), must report as 

specified below and comply with Subparts C and D of 40 CFR Part 98 (§§98.30 to 

98.48), as applicable, in reporting emissions and other data from electricity generating 

and cogeneration units to ARB, except as otherwise provided in this section. 

Notwithstanding the above, the operator of a facility with total facility nameplate 

generating capacity of less than 1 MW may elect to follow section 95115 in reporting 

electricity generating units as general combustion sources, in lieu of the requirements of 

section 95112. If engineering estimation is used to report disposition of generated 

energy or energy flow data that are not used directly to determine emissions, facility 

operators must demonstrate accuracy of the chosen engineering estimation method. 

(a) Information About the Electricity Generating Facility. Notwithstanding any limitations 

in 40 CFR Parts 75 or 98, the operator of an electricity generating facility is required 

to include in the emissions data report the information listed in this paragraph, 

unless otherwise specified in paragraphs (e) and (g) of this section for geothermal 

facilities and facilities with renewable energy generation. Reporting of information 

specified in section 95112(a)(4)-(6) is optional for facilities that do not provide or sell 

any generated energy outside of the facility boundary. However, facility operators 

that are applying for or receiving the legacy contract transition assistance under the 

cap-and-trade regulation, or that are applying for or receiving the limited exemption 

for emissions from the production of qualified thermal output under the cap-and-
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 113 February 2015 

trade regulation, must report the information in sections 95112(a)(4)-(6), even if they 

do not provide or sell any generated energy outside of the facility boundary. 

(1) If applicable, facility identification numbers assigned by the California Energy 

Commission, U.S. Energy Information Administration, Federal Energy 

Regulatory Commission’s PURPA Qualifying Facility program, and California 

Independent System Operator; 

(2) Total facility nameplate generating capacity in megawatts (MW); 

(3) Indicate whether the facility is a stand-alone electricity generating facility, an 

independently operated cogeneration/bigeneration facility co-located with the 

thermal host, an independently operated and sited cogeneration/bigeneration 

facility, or an industrial/institutional/commercial facility with electricity 

generation capacity, as applicable. Also indicate whether the facility is a griddedicated facility, a facility that does not provide any generated energy outside 

of the facility boundary, as applicable. 

(4) The disposition of generated electricity in MWh, reported at the facility-level, 

including for each of the following disposition categories, if applicable: 

(A) Generated Electricity For Grid. Generated electricity provided or sold to a 

retail provider or electricity marketer who distributes the electricity over 

the electric power grid for wholesale or retail customers of the grid. The 

operator must report the name of the retail provider or electricity 

marketer; 

(B) Generated Electricity For Other Users. Generated electricity provided or 

sold directly to particular end-users (as defined in section 95102). A 

reportable end-user includes any entity, under the same or different 

operational control, that is not a part of the facility. Report each enduser’s facility name, NAICS code, and ARB ID if applicable; 

(C) Generated Electricity For On-Site Industrial Applications Not Related to 

Electricity Generation. If the facility includes industrial processes or 

operations that are neither in support of or a part of the power generation 

system, report the amount of generated electricity used by those on-site 

industrial processes or operations. 

Separately report the amount of generated electricity that is used to 

produce cooling energy if: 

1. The facility provides cooling energy (e.g., chilled water) to a particular 

end-user outside of the facility boundary; or 

2. The facility includes on-site industrial processes or operations that 

are neither in support of or a part of the power generation system, 

and a portion of the generated electricity is used to produce cooling 

energy for such on-site industrial process or operations. 

If the facility includes equipment that utilizes generated electricity to 

produce cooling (e.g., absorption chiller) for the sole purpose of 

maintaining temperature in the electricity generation or cogeneration 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 114 February 2015 

system, account for such electricity as a part of the difference between 

gross generation and net generation (parasitic load) pursuant to section 

95112(b)(2). 

If a facility includes more than one electricity generating unit or 

cogeneration system, and each unit/system or each group of units 

generate electricity for different particular end-users or retail providers or 

electricity marketers, the operator must separately report the disposition 

of generated electricity by unit/system or by group of units. For the 

purpose of separate reporting of disposition, the operator may group 

similar units together if the generated electricity from the group of units is 

provided to the same destination. 

(5) The operator of a cogeneration or bigeneration unit must report the disposition 

of the thermal energy (MMBtu) generated by the cogeneration unit or 

bigeneration unit (“generated thermal energy”), reported at the facility-level, 

including for each of the following disposition categories, if applicable: 

(A) Generated Thermal Energy For Other Users. Thermal energy provided or 

sold to particular end-users (as defined in section 95102). A reportable 

end-user includes any entity, under the same or different operational 

control, that is not a part of the facility. Report each end-user’s facility 

name, NAICS code, ARB ID if applicable, and the types of thermal 

energy product provided. Exclude from this quantity the amount of 

thermal energy that is vented, radiated, wasted, or discharged before the 

energy is provided to the end-user. 

(B) Parasitic Steam Use. Thermal energy used for supporting power 

production that has been included in the quantity reported under 

paragraph 95112(b)(3) but that is not accounted for in the quantities 

reported under paragraphs 95112(a)(5)(A) and (C). This thermal energy 

quantity must not include steam directly used for power production, such 

as the steam used to drive a steam turbine generator to generate 

electricity. Activities for supporting power generation may include steam 

used for power augmentation, NOx control, sent to a de-aerator, or sent 

to a cooling tower. 

(C) Generated Thermal Energy For On-Site Industrial Applications Not 

Related to Electricity Generation. If the facility includes other industrial 

processes or operations that are neither in support of or a part of the 

electricity generation or cogeneration system, report the amount of 

generated thermal energy that is used by those on-site industrial 

processes or operations and heating or cooling applications. Exclude 

from this quantity the amount of thermal energy that is vented, radiated, 

wasted, or discharged before it is utilized at industrial processes or 

operations. This quantity does not include the amount of thermal energy 

generated by equipment that is not an integral part of the cogeneration 

unit. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 115 February 2015 

Separately report the amount of generated thermal energy that is used to 

produce cooling energy or distilled water if: 

1. The facility provides cooling energy (e.g., chilled water) or distilled 

water to a particular end-user outside of the facility boundary, or 

2. The facility includes on-site industrial processes or operations that 

are neither in support of or a part of the power generation system, 

and a portion of the generated thermal energy is used to produce 

cooling energy or distilled water for such on-site industrial process or 

operations. 

If the facility includes equipment that utilizes generated thermal energy to 

produce cooling (e.g., absorption chiller) for the sole purpose of 

maintaining temperature in the electricity generation or cogeneration 

system, follow section 95112(a)(5)(B) in reporting such use of generated 

thermal energy. 

If a facility includes more than one cogeneration or bigeneration 

unit/system, and each unit/system or each group of units generate 

thermal energy for different particular end-users or on-site industrial 

processes or operations, the operator must report the disposition of 

generated thermal energy by unit/system or by group of units with the 

same dispositions. For the purpose of separate reporting of disposition, 

the operator may group similar units together if the generated thermal 

energy from the group of units is provided to the same destination. 

(6) For the first year of reporting, operators of cogeneration or bigeneration units 

must submit a simplified block diagram depicting the following, as applicable: 

individual equipment included in the generation system (e.g. turbine, engine, 

boiler, heat recovery steam generator); direction of flows of energy specified in 

paragraphs (a)(4)-(5), (b)(2)-(4) and (b)(7)-(8) of this section, with the forms of 

energy carrier (e.g. steam, water, fuel) labeled; and relative locations of fuel 

meters and other fuel quantity measurements. If the cogeneration or 

bigeneration system is modified after the initial submission of the diagram, the 

operator must resubmit an updated diagram to ARB. 

(b) Information About Electricity Generating Units. Notwithstanding any limitations in 

40 CFR Parts 75 or 98, the operator of an electricity generating unit must include in 

the emissions data report the information listed in this paragraph. For aggregation 

of electricity generating units, the operator must meet the applicable criteria in 40 

CFR §98.36(c)(1)-(4), unless otherwise specified in sections 95115(h) and 

95112(b). For an electricity generation system (a cogeneration system, a 

bigeneration system, a combined cycle electricity generation system, or a system 

with boilers and steam turbine generators), the operator may aggregate all the units 

that are integrated into the system for the purpose of reporting data to ARB. 

Operators of Part 75 units may also aggregate units to the system level according 

to this paragraph, notwithstanding the limitation in 40 CFR §98.36(d)(1)(i). If there 

is more than one system present at the facility, each system must be reported 

separately. For electricity generating units that are not part of an integrated 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 116 February 2015 

generation system, aggregation of electricity generating units is limited to units of 

the same type, as specified in section 95115(h). Operators of geothermal facilities, 

hydrogen fuel cells, and renewable electricity generating units must follow 

paragraph (e), (f), or (g) of this section, whichever is applicable, instead of 

paragraph (b) of this section. For bottoming cycle cogeneration units, the operator 

is not required to report the data specified in section 95112(b)(4)-(6) except for any 

fuels combusted for supplemental firing as specified in section 95112(b)(7). 

(1) Basic information about the generating unit, including: 

(A) Nameplate generating capacity in megawatts (MW); 

(B) Prime mover technology; 

(C) For aggregation of units, provide a description of the individual equipment 

included in the aggregation; 

(D) If the unit generates both electricity and thermal energy, indicate whether 

the unit is a cogeneration or a bigeneration unit. If the unit is a 

cogeneration unit, indicate whether it is topping or bottoming cycle. 

(2) Net and gross power generated, in megawatt hours (MWh). The difference 

between net generation and gross generation is the parasitic load of electricity 

generation or cogeneration. The net generation quantity represents the 

amount of generated electricity that can be provided to the disposition 

categories in section 95112(a)(4). 

(3) If the unit is a cogeneration or bigeneration unit, the operator must report the 

total thermal output (MMBtu), as defined in section 95102, that was generated 

by the unit and can be potentially utilized in other industrial operations that are 

not electricity generation. Exclude from this quantity the heat content of 

returned condensate and makeup water and steam used to drive a steam 

turbine generator for electricity generation. The total thermal output quantity 

represents the amount of generated thermal energy that can be provided to 

the thermal energy disposition categories in section 95112(a)(5). 

(4) Fuel consumption by fuel type, reported in units of million standard cubic feet 

for gases, gallons for liquids, short tons for non-biomass solids, and bone dry 

short tons for biomass-derived solids. 

(5) If not already required to be reported under 40 CFR §98.36(b) for Subarticle C 

units and §98.46 for Subarticle D units, annual CO2, CH4, and N2O emissions 

from the unit, expressed in metric tons of each gas. 

(6) If used to calculate CO2 emissions and not already required to be reported 

under 40 CFR §98.36(e)(2)(ii)(C) and (iv)(C), report weighted or arithmetic 

average carbon content and high heat value by fuel type, whichever is used in 

calculating emissions as specified in 40 CFR §98.33. 

(7) For cogeneration systems, where supplemental firing has been applied to 

support electricity generation or thermal output, report the information in 

paragraphs (b)(4)-(6). Indicate by fuel type the portion of the total fuel 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 117 February 2015 

consumption (MMBtu) that is used for supplemental firing, and indicate the 

purpose of the supplemental firing. 

(8) Other heat input for electricity generation. If the electricity generation unit 

uses additional heat input that is not already accounted for in paragraphs 

95112(b)(4)-(6) (for example, if steam or heat is acquired from outside of the 

electricity generation system boundary or acquired from another facility for the 

generation of electricity), report the amount of acquired steam or heat 

(MMBtu). For bottoming cycle cogeneration units only, also report the input 

steam to the steam turbine (MMBtu) and the output of the heat recovery steam 

generator (MMBtu). 

(c) Emissions from Fuel Combustion and Sorbent. When calculating CO2, CH4, and 

N2O emissions from fuel combustion, the operator who is subject to Subpart C or D 

of 40 CFR Part 98 must use a method in 40 CFR §98.33(a)(1)-(4) as specified by 

fuel type in section 95115 of this article, except that for CO2 emissions the operator 

who is subject to Subpart D of 40 CFR Part 98 may elect instead to follow the 

provisions in 40 CFR §98.43, within the limitations of section 95103(m) of this 

article. 

(1) The operator of a Subpart D unit must report emissions from fuels combusted 

within the data year but not reported pursuant to 40 CFR Part 75 

requirements, such as prior to initial provisional or monitoring certification of 

CEMS. The operator must use a method in 40 CFR §98.33(a)(1)-(4) as 

specified by fuel type in section 95115, or if applicable, according to the de 

minimis provisions in section 95103(i) of this article. 

(2) The operator of a Subpart D unit with contractual deliveries of biomethane or 

biogas is subject to the requirements in section 95131(i) of this article and 

must follow the procedure in sections 95115(e)(4)-(5) in calculating emissions 

from biomethane, biogas, and natural gas. 

(3) The operator of a Subpart D unit who reports CO2 emissions using emission 

calculation methods specified in 40 CFR Part 75, and who operates a unit with 

a wet flue gas desulfurization system, must indicate the portion of the total 

reported CO2 emissions that is generated from sorbent injection for acid gas 

removal. 

(d) Monitoring, Data and Records. For each emissions calculation method chosen 

under section 95112(c), the operator must meet the applicable requirements for 

monitoring, missing data procedures, data reporting, and records retention that are 

specified in 40 CFR §98.34 to §98.37, except as modified in sections 95112, 95115, 

and 95129 of this article. 

(e) CO2 and CH4 Emissions from Geothermal Facilities. Operators of geothermal 

generating facilities must report CO2 and CH4 emissions from geothermal energy 

sources, the amount of geothermal steam utilized (MMBtu) if steam quantity is used 

in calculating emissions, and applicable requirements in section 95112(a)(1)-(4), 

(b)(1)(A)-(C), and (b)(2). 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 118 February 2015 

 The operator must calculate annual emissions of CO2 and CH4 from geothermal 

energy sources using source specific emission factors derived from a measurement 

plan approved by the ARB. The operator must submit to the Executive Officer a 

measurement plan at least 45 days prior to the first test date. The measurement 

plan must include testing at least annually, and more frequently as needed. Upon 

approval of the measurement plan by the Executive Officer, the test procedures in 

that plan must be performed as specified in the plan. The Executive Officer and the 

local air pollution control officer must be notified at least 20 days in advance of 

subsequent tests. 

(f) Hydrogen Fuel Cells. Operators of stationary hydrogen fuel cell units must include 

the following information in the annual GHG emissions data report: 

(1) Basic information about the generating unit specified in section 

95112(b)(1)-(2); 

(2) Fuel or feedstock consumption by fuel/feedstock type, reporting in units of 

million standard cubic feet for gases, gallons for liquids, short tons for nonbiomass solids, and bone dry short tons for biomass-derived solids; 

(3) The provider of each fuel or feedstock, and the user’s customer account 

number; 

(4) Cogeneration information in section 95112(b)(3), if applicable. 

(5) CO2 emissions from the hydrogen fuel cell, calculated using one of the 

following methods: 

(A) The fuel and feedstock mass balance approach in 40 CFR 98.163(b). If 

the fuel’s carbon content is not known, the facility operator may use the 

default carbon content percentage value listed in Table 1 of section 

95129(c). 

(B) For natural gas and biogas, if the fuel heat input is measured by the 

facility operator or by the fuel supplier, the operator may use the following 

equation to estimate emissions. 

CO2 (MT/year) = H (MMBtu/year) x EF (kg CO2/MMBtu) x 0.001 (MT/kg) 

Where 

CO2 = Annual CO2 emissions from fuel and feedstock consumption (metric 

tons/year) 

H = Total fuel heat input for the year (MMBtu/year)

EF = Default CO2 emission factor. Use 53.02 kg CO2/ MMBtu for natural gas. 

Use 52.07 kg CO2/MMBtu for biogas. 

0.001 = Conversion factor from kg to metric tons. 

(C) For biogas fuels, the facility operator may elect to use the best available 

estimation and engineering estimation approach to calculate emissions. 

(g) On-site Renewable Electricity Generation. The requirements in this paragraph 

apply to facilities that meet the applicability for reporting under section 95101 and 

are not otherwise exempted from reporting under section 95101(f). If such facility 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 119 February 2015 

includes non-fuel-based renewable electricity generating units with nameplate 

generating capacity of greater than 0.5 MW, the operator must report the nameplate 

generating capacity (MW), gross power generated (MWh) by the non-fuel-based 

renewable electricity generating units, and the applicable information in 95112(a). 

For facility operators that do not operate other electricity generating units that are 

subject to the requirements in paragraphs (a)-(f) of section 95112, reporting of 

information specified in section 95112(a)(4)(C) and (a)(5)-(6) is optional. 

(h) Missing Data Substitution Procedures. To substitute for missing data for emissions 

reported under sections 95112 or 95115 of this article (stationary combustion units 

and units using continuous emissions monitoring systems), the operator must follow 

the requirements of section 95129 of this article. Facilities reporting under 40 CFR 

Part 75 must substitute for missing data under the requirements of that part, as 

specified in 40 CFR §98.45. 

(i) Additional Reporting Requirements for Legacy Contract Applicants. The additional 

requirements in section 95112(i) apply to every facility operator that is applying for 

legacy contract transition assistance under the cap-and-trade regulation. A legacy 

contract generator with an industrial counterparty and a legacy contract generator 

without an industrial counterparty must submit a simplified block diagram in every 

year that the facility operator applies for legacy contract transition assistance. 

Legends or attachments may be used when labeling the diagram. If any of the 

amounts requested are sums of measurements made by different devices, the 

amounts for each device must be shown in the diagram and the summation 

described in an attachment. 

(1) The diagram must depict the following elements:

(A) For the data year, all of the information described in sections 

95112(a)(4)-(5), as applicable, regardless of whether the facility operator, 

or the equipment, is itself otherwise subject to sections 95112(a)(4)-(5). 

This information reflects electricity and thermal energy flows, including 

information identifying the recipient(s) of the electricity and/or thermal 

energy. Also report the quantities of any other products provided or sold 

under the legacy contract, using the units in which they are reported 

elsewhere in this regulation, if applicable. The diagram must indicate 

where each of these energy flows or products is measured. In addition, 

the following information must be included: 

1. Each of the amounts reported under section 95112(i)(1)(A) must be 

labeled indicating whether or not it was provided under the legacy 

contract; and 

2. All thermal energy products must be labeled with the type of thermal 

energy product (e.g., steam, hot water, chilled water, distilled water). 

(B) The individual equipment included in the system for which the facility 

operator is applying for legacy contract transition assistance, and other 

equipment that is not an integral part of that system but produces or 

consumes energy that is sent to or received from that system and is 

owned or operated by the facility operator. Boilers, individual generators 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 120 February 2015 

such as heat recovery steam generators, turbines if separate from 

generators, ice plants, chillers, purifiers and other equipment that meet 

these criteria must each be shown separately in the diagram. In addition, 

label each piece of equipment with the amount of fuel consumed (in 

MMBtu) by that piece of equipment during the data year, if any, and the 

resulting greenhouse gas emissions in CO2e as reported elsewhere 

under this regulation. The diagram must also indicate the fuel meter 

where this fuel use was measured, and the amount measured. 

(C) An outline showing the boundary of the activities covered by the legacy 

contract. 

NOTE: Authority cited: Sections 38510, 38530, 39600, 39601, 39607, 39607.4 and 

41511, Health and Safety Code. Reference: Sections 38530, 39600 and 41511, Health 

and Safety Code. 

§ 95113. Petroleum Refineries. 

The operator of a facility who is required to report under section 95101 of this article, 

and who is not eligible for abbreviated reporting under section 95103(a), must comply 

with Subpart Y of 40 CFR Part 98 (40 CFR §§98.250 to 98.258) in reporting emissions 

and other data from petroleum refineries to ARB, except as otherwise provided in this 

section. Petroleum refinery operators and refiners are considered separate reporting 

entities for the purposes of this article. 

(a) CO2 from Fossil Fuel Combustion. When calculating CO2 emissions from fuel 

combustion under subpart C as specified at 40 CFR §98.252(a), the operator must 

use a method in 40 CFR §98.33(a)(1) to §98.33(a)(4) as specified by fuel type in 

section 95115 of this article. CO2 emissions from refinery fuel gas combustion must 

be calculated using a Tier 3 or Tier 4 methodology of subpart C, as specified in 40 

CFR §98.252(a). 

(b) Monitoring, Data and Records. For each emissions calculation method chosen 

under section 95113(a), the operator must meet the applicable requirements for 

monitoring, missing data procedures, data reporting, and records retention that are 

specified in 40 CFR §98.34 to §98.37, except as modified in sections 95113(k), 

95115, and 95129 of this article. 

(c) Refinery Fuel Gas Sampling. As required by 40 CFR §98.34(b)(3)(ii)(E), in cases 

where equipment necessary to perform daily sampling and analysis of carbon 

content and molecular weight for refinery fuel gas is not in place, such equipment 

must be installed and procedures established to implement daily sampling and 

analysis no later than January 1, 2013. 

(d) Calculating CO2 from Flares. For periods of normal flare operation, the operator 

must use Equation Y-1a, Y-1b, or Y-2 as specified in 40 CFR §98.253(b)(ii)(A) or 

98.253(b)(ii)(B). For periods of startup, shutdown, and malfunction (SSM) during 

which the operator was unable to measure the parameters required by Equations Y1a, Y-1b, or Y-2, the operator must determine the quantity of gas discharged to the 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 121 February 2015 

flare separately for each SSM, and calculate the CO2 emissions as specified in the 

equation shown below. For SSM periods the operator must use engineering 

calculations and process knowledge to estimate the carbon content of flared gas as 

required by §98.253(b)(iii)(A). The terms of the equation below are defined as they 

are for Equation Y-3 in 40 CFR §98.253(b)(iii)(C). 

 

(e) Calculating CO2 from FCCUs and Fluid Coking. The requirements of 40 CFR 

§98.253(c)(2) apply under this article regardless of the rated capacity of a fluid 

catalytic cracking unit or a fluid coking unit. The operator may not use Equation Y-8 

or the option provided under 40 CFR §98.253(c)(3) for units with rated capacities of 

10,000 barrels per stream day or less. 

(f) Uncontrolled Blowdown Systems. When calculating CH4 emissions for uncontrolled 

blowdown systems as required by 40 CFR §98.253(k), the operator must use the 

methods for process vents in 40 CFR §98.253(j). 

(g) Data Reporting Requirements for Flares. When the operator has calculated flare 

emissions for SSM periods using the modified equation specified in section 

95113(d), the operator reporting data under the requirements of 40 CFR 

§98.256(e)(8) must report only the total number of SSM events, the volume of gas 

flared, and the average molecular weight and carbon content of the flare gas for 

each SSM event, using the units specified. 

(h) Data Reporting Requirements for FCCUs and Coking Units. When the operator has 

calculated CO2 from fluid catalytic cracking units or fluid coking units consistent with 

section 95113(e), the operator shall not report the data required by 40 CFR 

§98.256(f)(9). 

(i) Data Reporting Requirements for Uncontrolled Blowdown Systems. When the 

operator has calculated CH4 from uncontrolled blowdown systems consistent with

section 95113(g), the operator must report the information required for process 

vents in 40 CFR §98.256(l), as applicable, in lieu of the information required by 40 

CFR §98.256(m)(2). 

(j) Records that must be retained. In addition to the requirements of 40 CFR §98.257, 

for each process vent for which the concentration of CO2, N2O and CH4 are 

determined to be below the thresholds in 40 CFR §98.253(j), the operator must 

maintain records of the method used to determine the CO2, N2O, and CH4

concentrations, and all supporting documentation necessary to demonstrate that 

the thresholds in 40 CFR §98.253(j) are not exceeded during the data year 

pursuant to the record keeping requirements of section 95105. 

(k) Missing Data Substitution Procedures. The operator must comply with 40 CFR 

§98.255 when substituting for missing data, except as otherwise provided in 

paragraphs (1)-(2) below. 

(1) To substitute for missing data for emissions reported under section 95115 of 

this article (stationary combustion units and units using continuous emissions 

[ ] ( ) 















= × × ∑ × × ×

=

n

1p

2 SSM p p MVC CCp CO 98.0 .0 001 44 12/ Flare MW /
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 122 February 2015 

monitoring systems), the operator must follow the requirements of section 

95129 of this article. 

(2) For all other data required for emissions calculations in this section, the 

operator must follow the requirements of paragraphs (A)-(B) below. 

(A) If the analytical data capture rate is at least 90 percent for the data year, 

the operator must substitute for each missing value using the best 

available estimate of the parameter, based on all available process data. 

(B) If the analytical data capture rate is at least 80 percent but not at least 90 

percent for the data year, the operator must substitute for each missing 

value with the highest quality assured value recorded for the parameter 

during the given data year, as well as the two previous data years. 

(C) If the analytical data capture rate is less than 80 percent for the data 

year, the operator must substitute for each missing value with the highest 

quality assured value recorded for the parameter in all records kept 

according to section 95105(a). 

(l) Additional Product and Process Data. 

(1) Primary refinery products. The operator must report on-site production 

quantities of each primary refinery product for the data year by EIA number. 

The operator must also report for the data year by EIA number the quantity of 

each primary refinery product and blending component that was produced 

elsewhere and brought on-site. Liquid products must be reported in barrels, 

and solid products must be reported in short tons. When reporting the 

production quantity of a primary refinery product, sales data may be used, but 

must be adjusted by the change in inventory during the data year to accurately 

reflect the amount of material actually produced during the data year. Sales 

data may be used to report quantities of primary refinery product and blending 

component produced elsewhere and brought on-site. For each primary 

refinery product and blending component that was produced elsewhere and 

brought on-site, the operator must designate if any was used for a purpose 

other than blending into a primary refinery product, such as being used as a 

fuel or as a process unit feedstock. The quantity of primary refinery product or 

blending component that is produced elsewhere and brought on-site may not 

be included in the reported on-site production quantity of primary refinery 

product, unless the reporter has identified that the quantity of primary refinery 

product or blending component that is produced elsewhere and brought onsite is used for a purpose other than blending into a primary refinery product. 

(2) Calcined coke. The operator must report the production quantity for the data 

year of calcined coke (metric tons). The operator must specify whether the 

calciner is integrated with the petroleum refinery operation. 

(3) Finished Products. The operator must report production quantities for the data 

year of each petroleum product listed in Table C-1 of 40 CFR Part 98 each 

additional transportation fuel product listed in Table MM-1 of 40 CFR Part 98 

(standard cubic feet for gaseous products, barrels for liquid products, short 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 123 February 2015 

tons for solid products). These products will not be subject to review for 

material misstatement under the requirements of section 95131(b)(12). 

Primary products will be evaluated for conformance and assessment of 

material misstatement through 2014 data year verifications. Beginning with 

2015 data reported in 2016, primary refinery products will be evaluated for 

conformance only and will not be evaluated for material misstatement. 

(4) Energy Intensity Index. For refineries that participate in the Solomon Energy 

Reviews, the operator must report its most current Solomon EII values for the 

applicable data year. Each refinery operator must demonstrate to the verifier 

that the Solomon EII value reported is the correct value by providing 

documentation from Solomon & Associates. 

(5) Complexity Weighted Barrel (CWB) Calculation. 

(A) Reporting CWB Throughputs. The operator must report the annual 

throughput for each CWB unit in Table 1 of this section using the 

appropriate units listed in column 3 of Table 1 of this section. Reported 

throughputs based on feed must include only fresh feed and exclude 

recycled streams. The coke-on-catalyst volume percent also must be 

reported for each catalytic cracking unit. Beginning with data year 2013, 

CWB is considered covered product data and subject to material 

misstatement. 

(B) Total facility CWB. The total facility CWB production must be calculated 

according to the following formula. 

	 = 
 +  + 			

Where CWBTotal is the total complexity weighted barrels for a 

petroleum refinery, and CWBProcess, CWBOff-Sites, and CWBNon-Crude 

Sensible Heat must be calculated as follows: 

CWBProcess = ∑(CWBFactor x Throughput) 

CWBOff-Sites = (0.327) x (Total Refinery Input in thousands of barrels 

per year) + (0.0085) x (CWBProcess) 

CWBNon-Crude Sensible Heat = (0.44) x (Non-Crude Input in thousands of 

barrels per year) 

In these equations, CWBFactor is the CWB Factor for a CWB unit from 

Table 1 of this section. Throughput is the process throughput for each 

CWB unit identified in Table 1 of this section reported pursuant to 

section 95113(l)(3)(A). Total Refinery Input and Non-Crude Input are the 

annual volumes of raw materials as defined in section 95102(c). Total 

Refinery Input and Non-Crude Input must each be reported in units of 

thousands of barrels per year and must exclude hydrogen, natural gas, 

and any input to a hydrogen production plant. 

(C) Correction to CWBFactor for Fluid Catalytic Cracking. The following 

equation must be used to adjust CWBFactor for Fluid Catalytic Cracking 

(FCC) units and mild residual FCC units that result in coke on the 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 124 February 2015 

catalyst: 


, = 
 +	 ! × #$

Where: 

CWBFactor, FCC = The corrected CWB factor used to calculate the 

contribution to CWBProcess for a fluid catalytic cracking unit. 

CWBFactor = The uncorrected CWB factor for a catalytic cracking unit 

from Table 1 of this section. 

A = The coke-on-catalyst factor for a fluid catalytic cracking unit listed 

in the fourth column of Table 1 of this section. 

COC = The coke-on-catalyst volume percent reported to three 

significant figures and calculated by: 

COC = 100 x (Volume of coke consumed in the FCC)/(Volume of 

fresh feed to the FCC) 

(D) Density. In cases where a density measurement is needed for purposes 

of converting a throughput from barrel to mass units, the following 

applies: 

1. For a throughput with a known density, utilize the applicable default 

value from Section 3-1, Physical Constants of Organic Compounds, 

of the CRC Handbook of Chemistry and Physics, CRC Press Inc., 

Boca Raton 83rd Edition, 2002 – 2003, incorporated herein by 

reference; 

2. If the throughput density is not known, it must be determined 

following the requirements of section 95103(k). 

(E) Measurement Accuracy. All throughputs must follow the accuracy 

requirements outlined in sections 95103(k)(1)-(10). No single refinery 

activity may be reported under more than one CWB function. For 2014 

data reported in 2015, postponement requests for a CWB meter or device 

pursuant to sections 95103(k)(8)-(9) must be received by the 2014 

reporting deadline in section 95103(e) instead of the timeframe in section 

95103(k)(9)(A). 

(m) The operator must report the quantity of: 

(1) CARBOB produced and imported, as defined by “California reformulated 

gasoline blendstock for oxygenate blending” in section 95202 of the AB 32 

Cost of Implementation Fee Regulation, for use in California and the 

designated volume of oxygenate associated with the reported CARBOB; 

(2) Finished California gasoline produced and imported, as defined by “California 

gasoline” in section 95202 of the AB 32 Cost of Implementation Fee 

Regulation, for use in California; and 

(3) California Diesel produced and imported, as defined by “California diesel” in 

section 95202 of the AB 32 Cost of Implementation Fee Regulation, for use in 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 125 February 2015 

California and the volume of biodiesel and/or renewable diesel associated with 

the reported fuels. 

Table 1. CWB Functions and Factors 

CWB unit

Throughput 

Basis

Unit of Measure CWB Factor

EIA 

 Number

Process Subtypes

Atmospheric Crude 

Distillation

Feed thousands of barrels/year 1 401

Mild Crude Unit, Standard Crude 

Unit

Vacuum Distillation Feed thousands of barrels/year 0.91 402

Mild Vacuum Fractionation, 

Standard Vacuum Column, 

Vacuum Fractionating Column, 

Vacuum Flasher Column, 

Heavy Feed Vacuum Unit

Visbreaker Feed thousands of barrels/year 1.6 403

Processing Atmospheric Residual 

(w/o a Soaker Drum), Processing 

Atmospheric Residual (with a 

Soaker Drum), Processing Vacuum 

Bottoms Feed (w/o a Soaker 

Drum), Vacuum Bottoms Feed 

(with a Soaker Drum)

Delayed Coker Feed thousands of barrels/year 2.55 405 Delayed Coking 

Fluid Coker Feed thousands of barrels/year 10.3

404

Fluid Coking 

Flexicoker Feed thousands of barrels/year 23.6 Flexicoking 

Fluid Catalytic Cracking Feed thousands of barrels/year

1.150,

407

Fluid Catalytic Cracking (Feed 

ConCarbon <2.25 wt%)

Coke-onCatalyst Factor 

=

1.041

Mild Residual FCC Feed thousands of barrels/year

0.6593,

Mild Residualuum Catalytic 

Cracking (Feed ConCarbon 2.25-

3.5 wt %)

Coke-onCatalyst Factor 

= 

1.1075

Other FCC Feed

thousands of barrels/year 4.65

Houdry Catalytic Cracking

Other FCC Feed Thermofor Catalytic Cracking 

Thermal Cracking Feed thousands of barrels/year 2.95 406 Thermal Cracking

Naphtha/Distillate 

Hydrocracker

Feed thousands of barrels/year 3.15 439 / 440

Mild Hydrocracking (Normally less 

than 1,500 psig and consumes 

between 100 and 1,000 SCF H2/b)

Severe Hydrocracking

Naphtha Hydrocracking 

Residual Hydrocracker 

(H-Oil; LC-Fining and 

Hycon)

Feed thousands of barrels/year 4.4 441

H-Oil

LC-FiningTM and Hycon 

Naphtha Hydrotreater Feed thousands of barrels/year 0.91 420/425/426

Benzene Saturation

Desulfurization of C4–C6 Feeds
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 126 February 2015 

Conventional Naphtha 

Hydrotreating

Diolefin to Olefin Saturation of 

Gasoline

FCC gasoline hydrotreating with 

minimum octane loss

Olefinic Alkylation of Thio Sulfur

Selective Hydrotreating of Pyrolysis 

Gasoline/Naphtha Combined with 

Desulfurization

Pyrolysis Gasoline/Naphtha 

Desulfurization

Selective Hydrotreating of Pyrolysis 

Gasoline/Naphtha Combined with 

Desulfurization

Reactor for Selective Hydrotreating

S-ZorbTM Process 

Kerosene Hydrotreater Feed thousands of barrels/year 0.75 421

Aromatic Saturation of Kerosene

Conventional Hydrotreating of 

Kerosene/Jet Fuel

High Severity Hydrotreating 

Kerosene/Jet Fuel

Diesel/Selective 

Hydrotreater 

Feed thousands of barrels/year 0.9 422 / 423

Aromatic Saturation of Distillates

Conventional Distillate 

Hydrotreating

High Severity Distillate 

Hydrotreating

Ultra-High Severity Hydrotreating

Middle Distillate Dewaxing

S-ZorbTM Process 

Diolefin to Olefin Saturation of 

Alkylation Feed

Selective Hydrotreating of C3-C5 

Streams for Alkylation

Residual Hydrotreater Feed thousands of barrels/year 1.8 424

Desulfurization of Atmospheric 

Residual

Desulfurization of Vacuum 

Residual

VGO Hydrotreater Feed thousands of barrels/year 1 413

Hydrodesulfurization/denitrification 

Hydrodesulfurization

Reformer - including 

AROMAX

Feed thousands of barrels/year 3.5 430 / 431

Continuous Regeneration, Cyclic, 

Semi-Regenerative, and AROMAX

Solvent Deasphalter Feed thousands of barrels/year 2.8 432

Conventional Solvent, Supercritical 

Solvent 

Alkylation/Poly/Dimersol

C5+ Alkylate

thousands of barrels/year 5 415

Alkylation with Hydrofluoric Acid

Alkylation with Sulfuric Acid

C5+ Product

Polymerization C3 Olefin Feed

Polymerization C3/C4 Feed

Dimersol
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 127 February 2015 

C4 Isomer Production Feed thousands of barrels/year 1.25 615/644 C4 Isomerization 

C5/C6 Isomer 

Production - including 

ISOSIV

Feed thousands of barrels/year 1.8 438

C5/C6 Isomerization

ISOSIV

POX Syngas for Fuel

Product

millions of standard cubic 

feet/year

1

2.75

POX Syngas for Fuel

POX Syngas for Fuel Air Separation Unit

Sulfur Recovery

Product 

Sulfur

thousands of long 

tons/year

140 435

sulfur Recovery Unit

Tail Gas Recovery Unit

Sulfur Sprung H2S Springer Unit

Aromatics Production 

(All)

Feed thousands of barrels/year 3.3 437

Aromatics Solvent Extraction: 

Extraction Distillation

Aromatics Solvent Extraction: 

Liquid/Liquid Extraction

Aromatics Solvent Extraction: 

Liq/Liq w/ Extr. Distillation

Benzene Column

Toluene Column 

Xylene Rerun Column 

Heavy Aromatics Column

Hydrodealkylation Feed thousands of barrels/year 2.5 Hydrodealkylation

Toluene 

Disproportionation/ 

Transalkylation

Feed thousands of barrels/year 1.9

Toluene Disproportionation / 

Transalkylation

Cyclohexane production

Cyclohexane 

Product

thousands of barrels/year 2.8 Cyclohexane

Xylene Isomerization Feed thousands of barrels/year 1.9 Xylene Isomerization

Paraxylene Production

Paraxylene 

Product

thousands of barrels/year

6.5

Paraxylene Adsorption

thousands of barrels/year Paraxylene Crystallization

Feed

thousands of barrels/year Xylene Splitter

thousands of barrels/year Orthoxylene Rerun Column

Ethylbenzene 

production

Ethylbenzene 

Product

thousands of barrels/year

1.6

Ethylbenzene Manufacture

Feed thousands of barrels/year Ethylbenzene Distillation

Cumene production

Cumene 

Product

thousands of barrels/year 5 Cumene

Lubricant solvent 

extraction

Feed thousands of barrels/year 2.2

815/854

Extraction: Solvent is Duo-Sol, 

Furfural, NMP, Phenol, or SO2

Lubricant solvent 

dewaxing

Feed thousands of barrels/year 4.55

Dewaxing: Solvent is 

Chlorocarbon, MEK/Toluene, 

MEK/MIBK, or Propane

Lubricant Catalytic 

Dewaxing

Feed thousands of barrels/year 1.6

Catalytic Wax Isomerization and 

Dewaxing, Selective Wax Cracking 

Lubricant Hydrocracking Feed thousands of barrels/year 2.5

Lube Hydrocracker with Multifraction Distillation, Lube 

Hydrocracker with Vacuum Stripper

Lubricant Wax Deoiling Product thousands of barrels/year 11.8

Deoiling: Solvent is Chlorocarbon, 

MEK/Toluene, MEK/MIBK, or 

Propane
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 128 February 2015 

Lubricant and Wax 

Hydrofining

Feed thousands of barrels/year 1.15

Lube Hydrofinishing with Vacuum 

Stripper

Lube Hydrotreating with MultiFraction Distillation, Lube 

Hydrotreating Vacuum Stripper 

Wax Hydrofinishing with Vacuum 

Stripper, Wax Hydrotreating with 

Multi-Fraction Distillation, Wax 

Hydrotreating with Vacuum 

Stripper 

Asphalt Production

Total Asphalt 

Production

thousands of barrels/year 2.7 931 Asphalt Production

Oxygenates Product thousands of barrels/year 4.9

Distillation Units

Extraction Units

ETBE

TAME 

Methanol Synthesis Product thousands of barrels/year -36 Methanol Synthesis

Desalination

Product

millions of gallons/year 32.7 Desalination

(Water)

Special Fractionation Feed thousands of barrels/year 0.8

All Special Fractionation ex 

Solvents, Propylene, and 

Aromatics

Propane/Propylene 

Splitter (Propylene 

Production)

Feed thousands of barrels/year 2.1

Chemical Grade 

Polymer grade

Fuel Gas Sales Treating 

& Compression (hp)

Horsepower hp 0.92

Fuel Gas Sales Treating & 

Compression

Sulfuric Acid 

Regeneration

Product

thousands of short 

tons/year

37.8 Sulfuric Acid Regeneration

Ammonia Recovery Unit Product

thousands of short 

tons/year

453 Ammonia Recovery Unit: PHOSAM

Cryogenic LPG 

Recovery

Feed

millions of standard cubic 

feet/year

0.25 Cryogenic LPG Recovery

Flare Gas Recovery Feed

millions of standard cubic 

feet/year

0.13 Flare Gas Recovery

Flue Gas Desulfurizing Feed

millions of standard cubic 

feet/year

0.02 Flue Gas Desulfurizing

CO2 Liquefaction CO2 product

thousands of short 

tons/year

-160 . CO2 liquefaction

-

-

 1 Standard cubic feet are dry @ 60° F and 14.696 psi a or 15 °C and 1 atmosphere. 

NOTE: Authority cited: Sections 38510, 38530, 39600, 39601, 39607, 39607.4 and 

41511, Health and Safety Code. Reference: Sections 38530, 39600 and 41511, Health 

and Safety Code. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 129 February 2015 

§ 95114. Hydrogen Production. 

The operator of a facility who is required to report under section 95101 of this article, 

and who is not eligible for abbreviated reporting under section 95103(a), must comply 

with Subpart P of 40 CFR Part 98 (40 CFR §§98.160 to 98.168) in reporting emissions 

and other data from molecular hydrogen production to ARB, except as otherwise 

provided in this section. GHG emissions and output associated with hydrogen 

production must be reported separately from other emissions and output associated 

with a petroleum refinery. 

(a) Definition of Source Category. This source category is defined consistent with 

40 CFR §98.160(b) and (c). This category is further defined as a hydrogen 

production source that produces molecular hydrogen whether sold to other entities 

or consumed on-site. 

(b) CO2 from Fossil Fuel Combustion. When calculating CO2 emissions from fuel 

combustion under subpart C as specified at 40 CFR §98.162(b)-(c), the operator 

must use a method in 40 CFR §98.33(a)(1) to §98.33(a)(4) as specified by fuel type 

in section 95115 of this article. 

(c) Monitoring, Data and Records. For each emissions calculation method chosen 

under section 95114(b), the operator must meet the applicable requirements for 

monitoring, missing data procedures, data reporting, and records retention that are 

specified in 40 CFR §98.34 to §98.37, except as modified in sections 95114(h), 

95115, and 95129 of this article. 

(d) CO2 Process Emissions. When calculating CO2 under the fuel and feedstock 

material balance approach specified at 40 CFR §98.163(b), the operator must apply 

the weighted average carbon content values obtained (the term CCn in Equations 

P-1 through P-3) according to the frequencies specified in section 95114(e). 

(e) Sampling Frequencies. When monitoring GHG emissions as specified at 40 CFR 

§98.163, and reporting data as specified at §98.166, the operator must report the 

following: 

(1) Carbon, atomic hydrogen, and molecular hydrogen content for each feedstock 

using engineering estimates based on measured data as specified below: 

(A) For gaseous feedstock the operator must use weighted average carbon 

content, atomic hydrogen content (excluding hydrogen atoms contained 

in steam), and molecular hydrogen content from the results of one or 

more analyses for month n for natural gas or a standardized fuel or 

feedstock specified in Table 1 of section 95115, or from monthly analysis 

for other gaseous fuels and feedstocks such as refinery fuel gas; 

(B) For liquid feedstock the operator must use weighted average carbon 

content and atomic hydrogen content from the results of one or more 

analyses for month n for a standardized fuel or feedstock specified in 

Table 1 of section 95115, or from monthly sampling for other liquid fuels 

or feedstocks; 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 130 February 2015 

(C) For solid feedstock the operator must use weighted average carbon 

content and atomic hydrogen content from the results of monthly 

sampling. 

(2) When monitoring GHG emissions without a CEMS as specified in 40 CFR 

§98.163(b), the operator must determine the carbon content and molecular 

weight values for fuels and feedstocks according to the frequencies specified 

below: 

(A) When reporting CO2 emissions for gaseous fuel and feedstock the 

operator must use a weighted average carbon content from the results of 

one or more analyses for month n for natural gas or a standardized fuel 

or feedstock specified in Table 1 of section 95115, or from daily sampling 

for month n for other gaseous fuels or feedstocks such as refinery fuel 

gas. 

(B) When reporting CO2 emissions for liquid fuel and feedstock, the operator 

must use a weighted average carbon content from the results of one or 

more analyses for month n for a standardized fuel or feedstock specified 

in Table 1 of section 95115, or from daily sampling for month n for other 

liquid fuels or feedstocks. Daily liquid samples may be combined to 

generate a monthly composite sample for carbon analysis. 

(C) When reporting CO2 emissions for solid fuel and feedstock, the operator 

must use the weighted average carbon content from the results of 

monthly sampling for month n for a standardized fuel or feedstock 

specified in Table 1 of section 95115, or from daily sampling for month n 

for other solid fuels and feedstock. Daily solid samples may be combined 

to generate a monthly composite sample for carbon analysis. 

(f) Weighted Average Sampling. Where this section requires sampling of a parameter 

on a more frequent basis than 40 CFR Part 98, the operator or supplier must 

comply with the following: 

(1) The samples must be spaced apart as evenly as possible over time, taking 

into account the operating schedule of the relevant unit or facility. 

(2) The operator or supplier must calculate and report a weighted average of the 

values derived from the samples by using the following formula: 

Where: 

VE = The value of the parameter to be reported under 40 C.F.R. Part 98 for 

period E. 

j = Each period during period E for which a sample is required by this article. 

n = The number of periods j in period E. 

∑

∑

=

=

×

= n

j

j

n

j

j j

E

M

V M

V

1

1

( )
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 131 February 2015 

Vj = The value of the sample for period j. 

Mj = The mass of the sampled material processed or otherwise used by the 

relevant unit or facility in period j. 

(3) The operator or supplier must keep records of the date and result for each 

sample or composite sample and mass measurement used in the equation 

above and of the calculation of each weighted average included in the 

emissions data report, pursuant to the record keeping requirements of section 

95105. 

(g) Data Reporting Requirements. When reporting data as specified in 40 CFR 

§98.166, the operator must also report the mass of carbon and methane for which 

GHG emissions are calculated and reported by the facility using other calculation 

methods provided in this regulation (e.g., carbon in waste diverted to a fuel system 

or flare, where the CO2 and CH4 emissions are calculated and reported using other 

methods specified in this regulation). To avoid double-counting, these emissions 

must be subtracted from the total facility emissions. 

(h) Missing Data Substitution Procedures. The operator must comply with 40 CFR 

§98.165 when substituting for missing data, except for 2013 and later emissions 

data reports as otherwise provided in paragraphs (1)-(2) below. 

(1) To substitute for missing data for emissions reported under section 95115 of 

this article (stationary combustion units and units using continuous emissions 

monitoring systems); the operator must follow the requirements of section 

95129 of this article. 

(2) For all other data required for emissions calculations in this section, the 

operator must follow the requirements of paragraphs (A)-(C) below. 

(A) If the analytical data capture rate is at least 90 percent for the data year, 

the operator must substitute for each missing value using the best 

available estimate of the parameter, based on all available process data. 

(B) If the analytical data capture rate is at least 80 percent but not at least 90 

percent for the data year, the operator must substitute for each missing 

value with the highest quality assured value recorded for the parameter 

during the given data year, as well as the two previous data years. 

(C) If the analytical data capture rate is less than 80 percent for the data 

year, the operator must substitute for each missing value with the highest 

quality assured value recorded for the parameter in all records kept 

according to section 95105(a). 

(i) Transferred CO2. The operator must calculate and report the mass of all CO2

captured, transferred off-site, and reported by the hydrogen production facility as a 

supplier of CO2 using reporting provisions found in section 95123. Refineries and 

hydrogen production facilities must subtract this reported mass of CO2 that is 

captured and sold or transferred off-site from their facility emissions report to avoid 

double counting. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 132 February 2015 

(j) Additional Product Data. Operators must report the annual mass of hydrogen gas 

produced (metric tons) and liquid hydrogen sold (metric tons). For hydrogen gas 

produced, annual masses of on-purpose hydrogen gas and by-product hydrogen 

gas produced must be reported (metric tons). Operators must also specify if the 

hydrogen plant is an integrated refinery operation. Operators must report all 

hydrogen sold or otherwise transferred to another facility and include the purchaser 

(or receiver) and quantity sold or transferred to each facility. 

(k) Methane and nitrous oxide emissions from stationary combustion. Operators must 

calculate and report fuel high heat value (in units of MMBtu/kg, MMBtu/scf, or 

MMBtu/gallon for solid, gaseous, or liquid fuels respectively), and CH4 and N2O 

from fuel stationary combustion sources as set-forth in 40 CFR §98.33(c). 

(l) Hydrogen producers shall use the methodology found in section 95113(d) to 

calculate and report CO2, CH4, and N2O emissions from all flaring at their facility. 

NOTE: Authority cited: Sections 38510, 38530, 39600, 39601, 39607, 39607.4 and 

41511, Health and Safety Code. Reference: Sections 38530, 39600 and 41511, Health 

and Safety Code. 

§ 95115. Stationary Fuel Combustion Sources. 

The operator of a facility who is required to report under section 95101 of this article, 

and who is not eligible for abbreviated reporting under section 95103(a), must comply 

with Subpart C of 40 CFR Part 98 (§§98.30 to 98.38) in reporting stationary fuel 

combustion emissions and related data to ARB, except as otherwise provided in this 

section. 

(a) CO2 from Steam Producing Units. The operator of a steam producing unit 

combusting municipal solid waste or solid biomass fuels may use Equation C-2c of 

40 CFR §98.33(a)(2)(B)(iii), unless required to use Tier 3 or 4 by 40 CFR Part 98 or 

Part 75. Operators of steam producing units combusting fossil-based solid fuels 

must select applicable Tier 3 or Tier 4 methods. 

(b) CEMS CO2 Monitoring. Notwithstanding the allowed use of oxygen concentration 

monitors in 40 CFR §98.33(a)(4)(iv), an operator installing a continuous emissions 

monitoring system that includes a stack gas volumetric flow rate monitor after 

January 1, 2012, and who reports CO2 emissions using this system, must install 

and use a CO2 monitor. An operator without a CO2 monitor who uses a CEMS and 

O2 concentrations to calculate and report a unit’s CO2 emissions, and who conducts 

a Relative Accuracy Test Audit (RATA) for the unit, must at least annually include in 

the RATA the direct monitoring of CO2 concentration and flow, and the calculation 

of CO2 mass per hour. The operator must retain these results pursuant to the 

recordkeeping requirements of section 95105 and make them available to ARB 

upon request. The requirements of this paragraph do not apply to facilities for 

which pipeline natural gas is the only fuel consumed. 

(c) Choice of Tier for Calculating CO2 Emissions. Notwithstanding the provisions of 40 

CFR §98.33(b), the operator’s selection of a method for calculation of CO2
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 133 February 2015 

emissions from combustion sources is subject to the following limitations by fuel 

type and unit size. The operator is permitted to select a higher tier than that 

required for the fuel type or unit size as specified below. 

(1) The operator may select the Tier 1 or Tier 2 calculation method specified in 40 

CFR §98.33(a) for any fuel listed in Table 1 of this section that is combusted in 

a unit with a maximum rated heat input capacity of 250 MMBtu/hr or less, 

subject to the limitation at 40 CFR §98.33(b)(1)(iv), or for biomass-derived 

fuels listed in Table C-1 of 40 CFR Part 98 when these emissions are not 

subject to a compliance obligation under the cap-and-trade, except as limited 

by section 95115(e). 

(2) The operator may select the Tier 2 calculation method specified in 40 CFR 

§98.33(a)(2) for natural gas when it is pipeline quality as defined in section 

95102 of this article, and for distillate fuels listed in Table 1 of this section. 

Tier 1 may be selected when the fuel supplier is providing pipeline quality 

natural gas measured in units of therms or million Btu. Equation C-2c of 40 

CFR §98.33(a) may be selected for the units specified in paragraph (a) of this 

section. 

(3) The operator may select any calculation method specified in 40 CFR 

§98.33(a) when calculating emissions that are shown to be de minimis under 

section 95103(i) of this article, or for a fuel providing less than 10 percent of 

the annual heat input to a unit with a maximum rated heat input capacity of 

250 MMBtu/hr or less, unless not permitted under 40 CFR §98.33(b). 

(4) The operator must use either the Tier 3 or the Tier 4 calculation method 

specified under 40 CFR §98.33(a)(3)-(4) for any other fuel, including nonpipeline quality natural gas and fuel with emissions identified as non-exempt 

biomass-derived CO2, subject to the limitations of 40 CFR §98.33(b)(4)-(5) 

requiring use of the Tier 4 method. The operator using Tier 3 must determine 

annual average carbon content with weighted fuel use values, as required by 

Equation C-2b of 40 CFR §98.33. When fuel mass or volume is measured by 

lot, the term “n” in Equation C-2b is substituted as the number of lots received 

in the year. 

(d) Source Test Option for N2O and CH4. In lieu of other methods specified in this 

article, a facility operator may conduct site-specific source testing to derive emission 

factors and determine annual emissions of N2O or CH4 from any combustion 

source. Alternatively, the operator may use the results of an applicable test method 

specified in title 17, California Code of Regulations, section 95471. For source 

testing: 

(1) The facility operator must submit to the Executive Officer a test plan at least 

45 days prior to the first test date. The test plan must provide for testing at 

least annually, and more frequently as needed to account for seasonal 

variations in fuels or processes. 

(2) The plan must specify conduct of performance and stack tests consistent with 

the requirements of approved ARB or U.S. EPA test methods. Process rates 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 134 February 2015 

during the test must be determined in a manner that is consistent with the 

procedures used for GHG report accounting purposes.

(3) Upon approval of the test plan by the Executive Officer, the test procedures in 

that plan must be repeated as specified in the plan. The Executive Officer and 

the local air pollution control officer must be notified at least ten days in 

advance of subsequent tests. 

(e) Procedures for Biomass CO2 Determination. Reporting entities must use the 

following procedures when calculating emissions from biomass-derived fuels that 

are intermixed with fossil fuels: 

(1) When combusting municipal solid waste (MSW) or any other fuel for which the 

biomass fraction is not known, the operator must follow the procedures 

specified in 40 CFR §98.33(e)(3) to specify a biomass fraction. 

(2) For the analysis conducted under the requirements of 40 CFR §98.34(e) for 

partially biogenic fuels other than MSW, the operator may choose to analyze 

monthly fuel samples. The operator must collect such samples weekly and 

combine a portion of each weekly sample to form a monthly composite 

mixture. The monthly composite mixture must be homogenized and well 

mixed prior to withdrawal of a sample for analysis.

(3) When calculating emissions from a biomethane and natural gas mixture as 

described in 40 CFR §98.33(a)(2) using the annual MMBtu of fuel combusted 

in place of the product of Fuel and HHV in Equation C-2a, the operator must 

calculate emissions based on contractual deliveries of biomethane subject to 

the requirements of 95131(i), using the natural gas emission factor in the 

following equations: 

Ebiomass=EFnatural	gas×MMBtubiomethane×0.001

Where: 

Ebiomass = The annual biomass CO2, CH4 or N2O emissions from 

biomethane (metric tons) 

Enatual gas = The annual fossil CO2, CH4 or N2O emissions from 

natural gas (metric tons) 

EFnatural gas = The natural gas emission factor from Tables C-1 and C-2 

of 40 CFR Part 98 (kg/MMBtu) 

MMBtuannual = The total delivered MMBtus for the reporting year 

based on utility bills or meters meeting the accuracy requirements of 

section 95103(k) 

MMBtubiomethane = The total biomethane deliveries subject to the 

requirements of section 95131(i) for the reporting year based on 

contractual deliveries 

(4) When calculating emissions from a biomethane and natural gas mixture as 

described in 40 CFR §98.33(a)(4) using a continuous emission monitoring 

system (CEMS), or when calculating those emissions according to Subpart D 

of 40 CFR Part 98, the reporting entity must calculate the biomethane 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 135 February 2015 

emissions as described in subparagraph (3) of this section, with the remainder 

of emission being natural gas emissions. 

(5) When calculating emissions from a biogas and natural gas mixture using 40 

CFR §98.33(a)(4) or the carbon content method described in 40 CFR 

§98.33(a)(3), or when calculating those emissions according to Subpart D of 

40 CFR Part 98, the reporting entity must calculate biogas emissions using a 

carbon content method as described in 40 CFR §98.33(a)(3), with the 

remainder of emissions being natural gas emissions. 

(f) Fuel Sampling Frequencies. The operator who collects and analyzes fuel samples 

to conduct the monitoring analyses required under 40 CFR §98.34 must sample at 

the frequencies specified in that section, except in the following cases. 

(1) Natural gas that is outside the range of pipeline quality as defined in section 

95102 must be sampled and analyzed at least monthly by the reporting entity 

or the fuel supplier. 

(2) Under 40 CFR §98.34(b)(3)(ii)(E), in cases where equipment necessary to 

perform daily sampling and analysis of carbon content and molecular weight 

for refinery fuel gas is not in place, such equipment must be installed and 

procedures established to implement daily sampling and analysis no later than 

January 1, 2013. 

(3) The operator is estimating CO2 emissions using a CEMS under 40 

CFR §98.33(a)(4). 

(g) Fuel Use for CEMS Units. The operator who estimates and reports CO2 emissions 

using a CEMS under 40 CFR §98.33(a)(4) must also report the quantity of each 

type of fuel combusted in the unit or group of units (as applicable) during the 

reporting year, in standard cubic feet for gaseous fuels, gallons for liquid fuels, short 

tons for solid fuels, and bone dry short tons for biomass-derived solids. Fuel use 

monitoring devices for units covered under this paragraph are exempt from the 

provisions of section 95103(k) of this article. 

(h) Aggregation of Units. Facility operators may elect to aggregate units according to 

40 CFR §98.36(c), except as otherwise provided in this paragraph. Facility 

operators that are reporting under more than one source category in paragraphs 

95101(a)(1)(A)-(B) and that elect to follow 40 CFR §98.36(c)(1), (c)(3) or (c)(4), 

must not aggregate units that belong to different source categories. For the 

purpose of unit aggregation, units subject to 40 CFR 98 Subpart C that are 

associated with one source category must not be grouped with other Subpart C 

units associated with another source category, except when 40 CFR §98.36(c)(2) 

applies. Aggregation of stationary fuel combustion units is limited to units of the 

same type, where the unit type categories are: boiler, reciprocating internal 

combustion engine, turbine, process heater, and other (none of the above). Units 

subject to section 95112 must use the criteria for aggregation in section 95112(b). 

Facility operators that choose to aggregate units according to the common stack 

provision in 40 CFR §98.36(c)(2) may report emissions according to 40 CFR 

§98.36(c)(2), but they must separately report the fuel use by fuel type as a 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 136 February 2015 

percentage of the aggregated fuel consumption attributed to each individual unit or 

each group of units of the same type, such that the grouping of units still meets the 

limitations for unit aggregation specified elsewhere in this paragraph. 

(i) Pilot Lights. Notwithstanding the exclusion of pilot lights from this source category 

in 40 CFR §98.30(d), the operator must include emissions from pilot lights in the 

emissions data report when operated 300 hours or more in the data year. The 

operator may apply appropriate methods from 40 CFR §98.33 or engineering 

methods to calculate these emissions when pilot lights are unmetered. Pilot lights 

fueled from a common fuel source may be aggregated for reporting. Pilot lights 

may be reported as de minimis consistent with the requirements of section 95103(i). 

Pilot lights are not subject to the measurement device calibration requirements of 

section 95103, but pilot light emissions calculations are subject to verification. 

(j) Electricity Generating and Cogeneration Units. The operator of a facility that 

includes electricity generating and cogeneration units meeting the applicability 

criteria of section 95101 must meet the requirements specified in section 95112 of 

this article. 

(k) Natural Gas Supplier Information. The operator who is reporting emissions from the 

combustion of natural gas must report the name(s) of the supplier(s) of natural gas 

to the facility, the operator’s natural gas supplier customer account number(s), 

natural gas supplier service account identification number(s) or other primary 

account identifier(s), and the annual MMBtu delivered to each account according to 

billing statements (10 therms = 1 MMBtu), and if the natural gas was received 

directly from an interstate pipeline supplier. In the case that the natural gas is 

purchased from an entity other than the natural gas supplier, the operator must 

report the supplier name and customer or service account identification number, but 

may report the annual MMBtu delivered based on the seller’s billing statement. 

(l) Information on Natural Gas Supplied to Downstream Users. The operator who is 

reporting emissions from the combustion of natural gas must report whether any of 

the natural gas reported pursuant to section 95115(k) was supplied to downstream 

users outside of the operator’s facility boundary. If so, the operator must report the 

name of the facility and the annual MMBtu delivered to each user according to 

billing statements or financial records. 

(m) Procedures for Missing Data. To substitute for missing data for emissions reported 

under section 95115 of this article, the operator must follow the requirements of 

section 95129. 

(n) Additional Product Data. Operators of the following types of facilities must also 

report the production quantities indicated below. 

(1) The operator of a facility engaged in hot rolling and/or cold rolling of steel must 

report the quantity of hot rolled steel sheet, pickled steel sheet, cold rolled and 

annealed steel sheet, galvanized steel sheet, and tin plate produced in the 

data year (short tons). For cold rolled and annealed steel sheet, the operator 

must also report a description of the process used to produce the products, 

such as continuous annealing process or batch annealing. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 137 February 2015 

(2) The operator of a soda ash manufacturing facility must report the quantity of 

soda ash, biocarb, borax, V-Bor, DECA, PYROBOR, boric acid, and sulfate 

produced in the data year (short tons). 

(3) The operator of a gypsum manufacturing facility must report the quantity of 

plaster that is sold as a separate finished product and the amount of stucco 

used to produce saleable plasterboard produced in the data year (short tons) 

(4) The operator of a turbine and turbine generator set testing facility must report 

the nameplate power of the units tested (horsepower tested). 

(5) The operator of a poultry processing facility must report the quantity of whole 

chicken and chicken parts, poultry deli products, and protein meal and fat 

produced in the data year (short tons). 

(6) The operator of a facility that manufactures dehydrated flavors must report the 

production of dehydrated onion, dehydrated garlic, dehydrated chili peppers, 

dehydrated parsley, and dehydrated spinach in the data year (short tons). 

(7) The operator of a beer brewery must report the production of lager beer in the 

data year (gallons). 

(8) The operator of a snack food manufacturing facility must report the production 

of fried potato chips, baked potato chips, corn chips, corn curls, and pretzels in 

the data year (short tons). 

(9) The operator of a sugar manufacturing facility must report the production of 

granulated refined sugar in the data year (short tons) 

(10) The operator of a tomato processing facility must report the quantity of aseptic 

tomato paste (short ton of 31% TSS), aseptic whole and diced tomato (short 

ton), non-aseptic tomato paste and tomato puree (short ton of 24% TSS), nonaseptic whole and diced tomato (short ton), and non-aseptic tomato juice 

(short ton) produced in the data year. 

(11) The operator of a pipe foundry must report the production of ductile iron pipes 

produced in the data year (short tons). 

(12) The operator of a facility producing aluminum billets must report the production 

of aluminum and aluminum alloy billets in the data year (short tons). 

(13) The operator of a facility mining or processing of rare earth minerals must 

report the production of rare earth oxide equivalents in the data year (short 

tons). 

(14) The operator of a facility mining or processing freshwater diatomite filter aids 

must report the production of freshwater diatomite filter aids in the data year 

(short tons). 

(15) The operator of a performing forging facility must report the production of 

seamless rolled ring during the data year (short tons). 

(16) The operator of a dairy product facility must report the production of milk, 

buttermilk, skim milk, cream, butter, condensed milk, buttermilk powder, 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 138 February 2015 

intermediate dairy ingredients, dairy product solids for animal feed, lactose, 

whey protein concentrate (WPC), deproteinized whey, cheese by cheese type, 

nonfat dry milk and skimmed milk powder by the type of heat treatment (low 

heat, medium heat, or high heat), and ultrafiltered milk products by product 

type during the data year (short tons). Butter re-melted and re-introduced to 

the manufacturing process may be reported as production. Buttermilk powder 

and nonfat dry milk and skimmed milk powder that is re-constituted and reintroduced to the manufacturing process may be reported as production. The 

operator must report the production of total WPC and WPC with high protein 

concentration using diafiltration process during the data year (short tons). The 

operator must also report the amount of imported protein. 

(17) The operator of an almond or pistachio processing facility must report the sum 

of pistachios hulled and dried and/or flavored and packaged (short tons) where 

the hulling and drying, flavoring and packaging is a continuous process, and 

the sum of almonds pasteurized, blanched and/or flavored and dried (short 

tons) where flavoring and drying is a continuous process. 

(18) The operator of a wet corn milling facility must report the production of corn 

entering wet milling process during the data year (short tons). 

(19) The operator of a winery must report the production of distilled spirits (proof 

gallons), dry color concentrate (short tons), grape juice concentrate (gallons), 

grape seed extract (short tons), and liquid color concentrate (gallons) during 

the data year. 

Table 1: Petroleum Fuels For Which Tier 1 or Tier 2 Calculation

Methodologies May Be Used Under Section 95115(c)(1)

Fuel Type Default High 

Heat Value 

Default CO2 Emission Factor 

 MMBtu/gallon kg CO2 /MMBtu 

Distillate Fuel Oil No. 1 0.139 73.25 

Distillate Fuel Oil No. 2 0.138 73.96 

Distillate Fuel Oil No. 4 0.146 75.04 

Kerosene 0.135 75.20 

Liquefied petroleum gases (LPG)1 0.092 62.98 

Propane 0.091 61.46 

Propylene 0.091 65.95 

Ethane 0.096 62.64 

Ethylene 0.100 67.43 

Isobutane 0.097 64.91 

Isobutylene 0.103 67.74 

Butane 0.101 65.15 

Butylene 0.103 67.73 

Natural Gasoline 0.110 66.83 

Motor Gasoline (finished) 0.125 70.22 

Aviation Gasoline 0.120 69.25 

Kerosene-Type Jet Fuel 0.135 72.22 

1Commercially sold as "propane" including grades such as HD5. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 139 February 2015 

NOTE: Authority cited: Sections 38510, 38530, 39600, 39601, 39607, 39607.4 and 

41511, Health and Safety Code. Reference: Sections 38530, 39600 and 41511, Health 

and Safety Code. 

§ 95116. Glass Production. 

The operator of a facility who is required to report under section 95101 of this article, 

and who is not eligible for abbreviated reporting under section 95103(a), must comply 

with Subpart N of 40 CFR Part 98 (§§98.140 to 98.148) in reporting stationary 

combustion and process emissions and related data from glass production to ARB, 

except as otherwise provided in this section. 

(a) CO2 from Fossil Fuel Combustion. When calculating CO2 emissions from fuel 

combustion, the operator must use a method in 40 CFR §98.33(a)(1) to 

§98.33(a)(4) as specified by fuel type in section 95115 of this article. 

(b) Monitoring, Data and Records. For each emissions calculation method chosen 

under section 95116(a), the operator must meet the applicable requirements for 

monitoring, missing data procedures, data reporting, and records retention that are 

specified in 40 CFR §98.34 to §98.37, except as modified in sections 95115, 

95116(c)-(d), and 95129 of this article. 

(c) Missing Data Substitution Procedures. The operator must comply with 40 CFR 

§98.145 when estimating missing data, except as otherwise provided in paragraphs 

(1)-(3) below. 

(1) To substitute for missing data for emissions reported under section 95115 of 

this article (stationary combustion units and units using continuous emissions 

monitoring systems), the operator must follow the requirements of section 

95129 of this article. 

(2) For each missing value of the monthly amounts of carbonate-based raw 

materials charged to any continuous glass melting furnace, the operator must 

apply a substitute value according to the procedures in paragraphs (A)-(B) 

below. 

(A) If the data capture rate is at least 80 percent for the data year, the 

operator must substitute for each missing value according to 40 CFR 

§98.145(a). 

(B) If the data capture rate is less than 80 percent for the data year, the 

operator must substitute for each missing value with the maximum short 

tons per day raw material capacity of the continuous glass melting 

furnace. 

(3) The operator must document and retain records of the procedure used for all 

missing data estimates pursuant to the recordkeeping requirements of section 

95105. 

(d) Additional Product Data. In addition to the information required by 40 CFR §98.146, 

the operator must report the additional parameters provided in paragraphs (1)-(3) 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 140 February 2015 

below whether or not a CEMS is used to measure CO2 emissions. 

(1) The operator of a flat glass manufacturing facility must report the annual 

quantity of glass pulled from the melting furnace (short tons). 

(2) The operator of a container glass manufacturing facility must report the annual 

quantity of glass pulled from the melting furnace (short tons). 

(3) The operator of a fiberglass manufacturing facility must report the annual 

quantity of glass pulled from the melting furnace (short tons). 

NOTE: Authority cited: Sections 38510, 38530, 39600, 39601, 39607, 39607.4 and 

41511, Health and Safety Code. Reference: Sections 38530, 39600 and 41511, Health 

and Safety Code. 

§ 95117. Lime Manufacturing. 

The operator of a facility who is required to report under section 95101 of this article, 

and who is not eligible for abbreviated reporting under section 95103(a), must comply 

with Subpart S of 40 CFR Part 98 (§§98.190 to 98.198) in reporting stationary 

combustion and process emissions and related data from lime manufacturing to ARB, 

except as otherwise provided in this section. 

(a) CO2 from Fossil Fuel Combustion. When calculating CO2 emissions from fuel 

combustion, the operator must use a method in 40 CFR §98.33(a)(1) to 

§98.33(a)(4), as specified by fuel type in section 95115 of this article. 

(b) Monitoring, Data and Records. For each emissions calculation method chosen 

under section 95117(a), the operator must meet the applicable requirements for 

monitoring, missing data procedures, data reporting, and records retention that are 

specified in 40 CFR §98.34 to §98.37, except as modified in sections 95115, 

95117(c)-(d), and 95129 of this article. 

(c) Missing Data Substitution Procedures. The operator must comply with 40 CFR 

§98.195 when substituting for missing data, except as otherwise provided in 

paragraphs (1)-(2) below. 

(1) To substitute for missing data for emissions reported under section 95115 of 

this article (stationary combustion units and units using continuous emissions 

monitoring systems), the operator must follow the requirements of section 

95129 of this article. 

(2) If CaO and MgO content data required by 40 CFR §98.193(b)(2) are missing 

and a new analysis cannot be undertaken, the operator must apply substitute 

values according to the procedures in paragraphs (A)-(C) below. 

(A) If the data capture rate is at least 90 percent for the data year, the 

operator must substitute for each missing value using the best available 

estimate of the parameter, based on all available process data for the 

reporting year. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 141 February 2015 

(B) If the data capture rate is at least 80 percent but not at least 90 percent 

for the data year, the operator must substitute for each missing value with 

the highest quality assured value recorded for the parameter during the 

given data year, as well as the two previous data years. 

(C) If the data capture rate is less than 80 percent for the data year, the 

operator must substitute for each missing value with the highest quality 

assured value recorded for the parameter in all records kept according to 

section 95105(a). 

(3) For each missing value of the quantity of lime produced (by lime type) and 

quantity of lime byproduct/waste produced and sold used to calculate 

emissions pursuant to 40 CFR §98.193, the operator must apply a substitute 

value according to the procedures in paragraphs (A)-(B) below. 

(A) If the data capture rate is at least 80 percent for the data year, the 

operator must substitute for each missing value according to 40 CFR 

§98.195(a). 

(B) If the data capture rate is less than 80 percent for the data year, the 

operator must substitute for each missing value with the maximum 

capacity of the system. 

(4) The operator must document and retain records of the procedure used for all 

missing data estimates pursuant to the recordkeeping requirements of section 

95105. 

(d) Additional Product Data. The operator of a lime manufacturing facility must report 

the annual quantity of lime and dolime produced (short tons). 

(e) Produced CO2 Used On-Site. If a CEMS is not used to measure CO2 emissions, the 

facility operator shall report data required by 40 CFR §98.196(b)(17), with the 

clarification that the referenced annual amount of CO2 captured for use in the onsite process, reflects CO2 process emissions generated by the facility that are not 

released to the atmosphere. The produced CO2 emissions must be computed as 

specified in 40 CFR §98.193(b)(2). The method used to determine the amount of 

CO2 captured on-site and not emitted must be provided as specified in 40 CFR 

§98.196(b)(17)(ii), which could include monitoring of system acidity or basicity (pH), 

analysis of process samples for calcium oxide, or evaluation of the relative 

quantities of reactants and products in the lime production and CO2 reabsorption 

process (i.e., chemical stoichiometry). 

NOTE: Authority cited: Sections 38510, 38530, 39600, 39601, 39607, 39607.4 and 

41511, Health and Safety Code. Reference: Sections 38530, 39600 and 41511, Health 

and Safety Code. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 142 February 2015 

§ 95118. Nitric Acid Production. 

The operator of a facility who is required to report under section 95101 of this article, 

and who is not eligible for abbreviated reporting under section 95103(a), must comply 

with Subpart V of 40 CFR Part 98 (§§98.220 to 98.228) in reporting stationary 

combustion and process emissions and related data from nitric acid production to ARB, 

except as otherwise provided in this section. 

(a) CO2 from Fossil Fuel Combustion. When calculating CO2 emissions from fossil fuel 

combustion at a stationary combustion unit under 40 CFR §98.222(b), the operator 

must use a method in 40 CFR §98.33(a)(1) to §98.33(a)(4) as specified by fuel type 

in section 95115 of this article. 

(b) Monitoring, Data and Records. For each emissions calculation method chosen 

under section 95118(a), the operator must meet the applicable requirements for 

monitoring, missing data procedures, data reporting, and records retention that are 

specified 40 CFR §98.34 to §98.37, except as modified in sections 95115, 

95118(c)-(d), and 95129 of this article. 

(c) Missing Data Substitution Procedures. The operator must comply with 40 CFR 

§98.225 when substituting for missing data, except as otherwise provided in 

paragraphs (1)-(3) below. 

(1) To substitute for missing data for emissions reported under section 95115 of 

this article (stationary combustion units and units using continuous emissions 

monitoring systems), the operator must follow the requirements of section 

95129 of this article. 

(2) For each missing value of nitric acid production used to calculate emissions 

pursuant to 40 CFR §98.223, the operator must substitute the missing data 

values according to the procedures in paragraphs (A)-(B) below. 

(A) If the analytical data capture rate is at least 80 percent for the data year, 

the operator must substitute for each missing value according to 40 CFR 

§98.225(a) and the number of days per month. 

(B) If the analytical data capture rate is less than 80 percent for the data 

year, the operator must substitute for each missing value with the 

maximum capacity of the system and the number of days per month. 

(3) The operator must document and keep records of the procedures used for 

estimating missing data pursuant to the recordkeeping requirements of section 

95105. 

(d) Additional Product Data. The operator of a nitric acid manufacturing facility must 

report the annual production of nitric acid (HNO3) and calcium ammonium nitrate 

solution (short tons). 

NOTE: Authority cited: Sections 38510, 38530, 39600, 39601, 39607, 39607.4 and 

41511, Health and Safety Code. Reference: Sections 38530, 39600 and 41511, Health 

and Safety Code. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 143 February 2015 

§ 95119. Pulp and Paper Manufacturing. 

The operator of a facility who is required to report under section 95101 of this article, 

and who is not eligible for abbreviated reporting under section 95103(a), must comply 

with Subpart AA of 40 CFR Part 98 (40 CFR §§98.270 to 98.278) in reporting stationary 

combustion and process emissions and related data from pulp and paper manufacturing 

to ARB, except as otherwise provided in this section. 

(a) CO2 from Fossil Fuel Combustion. When calculating CO2 emissions from fossil fuel 

combustion in a chemical recovery furnace at a kraft or soda facility under 40 CFR 

§98.273(a)(1), a chemical recovery unit at a sulfite or stand-alone semichemical 

facility under 40 CFR §98.273(b)(1), a pulp mill lime kiln at a kraft or soda facility 

under 40 CFR §98.273(c)(1), or other stationary fuel combustion sources, the 

operator must use a method in 40 CFR §98.33(a)(1) to §98.33(a)(4) as specified by 

fuel type in section 95115 of this article. 

(b) Monitoring, Data and Records. For each emissions calculation method chosen 

under section 95119(a), the operator must meet the applicable requirements for 

monitoring, missing data procedures, data reporting, and records retention that are 

specified in 40 CFR §98.34 to §98.37, except as modified in sections 95115, 

95119(c)-(d), and 95129 of this article. 

(c) Procedures for Missing Data. The operator must comply with 40 CFR §98.275 

when substituting for missing data, as otherwise provided in paragraphs (1)-(3) 

below. 

(1) To substitute for missing data for emissions reported under section 95115 of 

this article (stationary combustion units and units using continuous emissions 

monitoring systems), the operator must follow the requirements of section 

95129 of this article. 

(2) For each missing value for the use of makeup chemicals (carbonates), the 

operator must apply a substitute value according to the procedures in 

paragraphs (A)-(B) below. 

(A) If the data capture rate is at least 80 percent for the data year, the 

operator must substitute for each missing value according to 40 CFR 

§98.275(c). 

(B) If the data capture rate is less than 80 percent for the data year, the 

operator must substitute for each missing value with the maximum metric 

tons per day capacity of the system. 

(3) The operator must document and retain records of the procedure used for all 

missing data estimates pursuant to the recordkeeping requirements of section 

95105. 

(d) Additional Product Data. In addition to the information required by 40 CFR §98.276, 

the operator must report the annual production (air dried short tons) of recycled 

boxboard, recycled linerboard, and recycled medium, and the annual saleable 

production of tissue (air dried short tons) by type (bathroom tissue, facial tissue, 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 144 February 2015 

delicate task wipers, and/or paper towels). The operator producing tissue products 

must also report: 

(1) A description of the process used to produce tissue, such as through use of an 

air dryer. 

(2) Water absorption capacity of each bathroom tissue product with a distinct 

water absorption capacity manufactured in the data year, measured at least 

once during the data year using the methodology specified by ISO 12625-

8:2010, except the humidity and temperature conditions, which shall be 50% 

relative humidity ±2%, and 23 degrees C ±1 degree C, respectively. 

(3) For bathroom tissue, material misstatement shall be assessed using the 

following equation: 

Material misstatement for bathroom tissue = 

:#!



;<

Where: 

Oi = annual product output in air dried saleable ton for each tissue 

product (i) with a distinct water absorption capacity; and 

WACi = water absorption capacity for each tissue product (i) with a distinct 

water absorption capacity. 

All other pulp and paper manufacturing products shall be assessed on the reported 

air dried short tons. 

NOTE: Authority cited: Sections 38510, 38530, 39600, 39601, 39607, 39607.4 and 

41511, Health and Safety Code. Reference: Sections 38530, 39600 and 41511, Health 

and Safety Code. 

§ 95120. Iron and Steel Production. 

The operator of a facility who is required to report under section 95101 of this article, 

and who is not eligible for abbreviated reporting under section 95103(a), must comply 

with Subpart Q of 40 CFR Part 98 (40 CFR §§98.170 to 98.188) in reporting stationary 

combustion and process emissions and related data from iron and steel production to 

ARB, except as otherwise provided in this section. 

(a) CO2 from Fossil Fuel Combustion. When calculating CO2 emissions from fossil fuel 

combustion at a stationary combustion unit under 40 CFR §98.172(a), the operator 

must use a method in 40 CFR §98.33(a)(1) to §98.33(a)(4) as specified by fuel type 

in section 95115 of this article. 

(b) Monitoring, Data and Records. For each emissions calculation method chosen 

under section 95120(a), the operator must meet the applicable requirements for 

monitoring, missing data procedures, data reporting, and records retention that are 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 145 February 2015 

specified in 40 CFR §98.34 to §98.37, except as modified in sections 95115, 

95120(c)-(d), and 95129 of this article. 

(c) Missing Data Substitution Procedures. The operator must comply with 40 CFR 

§98.175 when substituting for missing data, except as otherwise provided in 

paragraphs (1)-(2) below. 

(1) To substitute for missing data for emissions reported under section 95115 of 

this article (stationary combustion units and units using continuous emissions 

monitoring systems), the operator must follow the requirements of section 

95129 of this article. 

(2) If monthly mass or volume of carbon-containing inputs and outputs are 

missing when using the carbon mass balance procedure in 40 CFR 

§98.173(b)(1), the operator must apply substitute values according to the 

procedures in paragraphs (A)-(B) below. 

(A) If the data capture rate is at least 80 percent for the data year, the 

operator must substitute for each missing value based on the best 

available estimate based on information used for accounting purposes 

(such as purchase records). 

(B) If the data capture rate is less than 80 percent for the data year, the 

operator must substitute for each missing value with the maximum 

throughput capacity of the system. 

(3) The operator must document and retain records of the procedure used for all 

missing data estimates pursuant to the recordkeeping requirements of section 

95105. 

(d) Additional Product Data. In addition to the information required by 40 CFR §98.176, 

the operator must report the annual production of iron and steel products in short 

tons, a description of the product(s), and, the process used to produce the products, 

such as use of an electric arc furnace. 

NOTE: Authority cited: Sections 38510, 38530, 39600, 39601, 39607, 39607.4 and 

41511, Health and Safety Code. Reference: Sections 38530, 39600 and 41511, Health 

and Safety Code. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 146 February 2015 

§ 95121. Suppliers of Transportation Fuels. 

Any position holder, refiner, enterer, or biofuel production facility who is required to 

report under section 95101 of this article must comply with Subpart MM of 40 CFR Part 

98 (§§98.390 to 98.398) in reporting emissions and related data to ARB, except as 

otherwise provided in this section. 

(a) GHGs to Report. 

(1) In addition to the CO2 emissions specified under 40 CFR §98.392, all refiners 

that produce liquefied petroleum gas must report the CO2, CH4, N2O and CO2e 

emissions that would result from the complete combustion or oxidation of the 

annual quantity of liquefied petroleum gas sold or delivered, except for fuel for 

which a final destination outside California can be demonstrated. 

(2) Refiners, position holders of fossil fuels and biomass-derived fuels that supply 

fuel at California terminal racks, enterers that import transportation fuels 

outside the bulk transfer/terminal system, and biofuel production facilities that 

produce and deliver biomass-derived fuels outside the bulk transfer/terminal 

system in California must report the CO2, CO2 from biomass-derived fuels, 

CH4, N2O, and CO2e emissions that would result from the complete 

combustion or oxidation of each Blendstock, Distillate Fuel Oil or biomassderived fuel (Biomass-Based Fuel and Biomass) listed in Table 2 of this 

section. However, reporting is not required for fuel in which a final destination 

outside California or where a use in exclusively aviation or marine applications 

can be demonstrated. No fuel shall be reported as finished fuel. Fuels must 

be reported as the individual Blendstock, Distillate Fuel Oil or biomass-derived 

fuel listed in Table 2 of this section. For purposes of this article, CARBOB 

blendstocks are reported as RBOB blendstocks. 

(b) Calculating GHG emissions.

(1) Refiners, position holders at California terminals, enterers that import fuel 

outside the bulk transfer system, and biofuel production facilities who produce 

and deliver fuel outside the bulk transfer/terminal system in California must 

use Equation MM-1 as specified in 40 CFR §98.393(a)(1) to estimate the CO2

emissions that would result from the complete combustion of the fuel. 

Emissions must be based on the quantity of fuel removed from the rack (for 

refiners and position holders), fuel imported or produced and not delivered to 

the bulk transfer/terminal system (by enterers and biofuel production facilities), 

and fuel sold to unlicensed entities as specified in section 95121(d)(3) (by 

refiners). For fuels that are blended, emissions must be reported for each 

individual Blendstock, Distillate Fuel Oil or biomass-derived fuel listed in Table 

2 of this section separately, and not as motor gasoline (finished), biofuel 

blends, or other similar finished fuel. Emissions from denatured fuel ethanol 

must be calculated as 100% ethanol only. The volume of denaturant is 

assumed to be zero and is not required to be reported. Emission factors must 

be taken from column C of 40 CFR 98 Table MM-1 or MM-2 as specified in 

Calculation Method 1 of 40 CFR §98.393(f)(1), except that the emission factor 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 147 February 2015 

for renewable diesel is equivalent to the emission factor for Distillate No. 2. If 

a position holder in diesel or biodiesel fuel does not have sealed or financial 

transaction meters at the rack, and the position holder is the sole position 

holder at the terminal, the position holder must calculate emissions based on 

the delivering entity’s invoiced volume of fuel or a meter that meets the 

requirements of section 95103(k) either at the rack or at a point prior to the 

fuel going into the terminal storage tanks. 

(2) Refiners that produce liquefied petroleum gas must use Equation MM-1 as 

specified in 40 CFR §98.393(a)(1) to estimate the CO2 emissions that would 

result from the complete combustion of the fuel supplied. For calculating the 

emissions from liquefied petroleum gas, the emissions from the individual 

components must be summed. Emission factors must be taken from column 

C of 40 CFR Part 98 Table MM-1 as specified in Calculation Method 1 of 40 

CFR §98.393(f)(1). 

(3) Refiners, position holders at California terminals, and enterers and biofuel 

production facilities that deliver fuel outside of the bulk transfer/terminal 

system must estimate and report CH4 and N2O emissions using Equation C–8 

and Table C-2 as described in 40 CFR §98.33(c)(1), except that the emission 

factors in Table 1 of this section will be used for each fuel required to be 

reported in section 95121(a)(2) above. 

Table 1. Transportation Fuel CH4 and N2O emission factors

Fuel CH4 (g/bbl) N2O (g/bbl) 

Blendstock 20 20 

Distillate 2 1 

Ethanol 37 27 

Biodiesel and 

Renewable Diesel 2 1 

(4) All fuel suppliers in this section must estimate CO2e emissions using the 

following equation: 

 

Where: 

CO2e = Carbon dioxide equivalent, metric tons/year. 

GHGi = Mass emissions of CO2, CH4, N2O from fuels combusted or 

oxidized. 

GWPi = Global warming potential for each greenhouse gas from Table A-1 

of 40 CFR Part 98. 

n = Number of greenhouse gases emitted. 

(c) Monitoring and QA/QC Requirements. For the emissions calculation method 

chosen under section 95121(b), the operator must meet all the monitoring and 

i i

n

1i

CO2e ∑ GHG x GWP

=

=
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 148 February 2015 

QA/QC requirements as specified in 40 CFR §98.394, and the requirements of 

40 CFR §98.3(i) as further specified in section 95103 of this article and below. 

(1) Position holders are exempt from 40 CFR §98.3(i) calibration requirements 

except when the position holder and entity receiving the fuel have common 

ownership or are owned by subsidiaries or affiliates of the same company. In 

such cases the 40 CFR §98.3(i) calibration requirements apply, unless: 

(A) The fuel supplier does not operate the fuel billing meter; 

(B) The fuel billing meter is also used by companies that do not share 

common ownership with the fuel supplier; or 

(C) The fuel billing meter is sealed with a valid seal from the county sealer of 

weights and measures and the operator has no reason to suspect 

inaccuracies. 

(2) As required by 40 CFR §98.394(a)(1)(iii), for fuels that are liquid at 60 degrees 

Fahrenheit and one standard atmosphere, the volume reported must be 

temperature- and pressure-adjusted to these conditions. For liquefied 

petroleum gas the volume reported must be temperature-adjusted to 60 

degrees Fahrenheit. 

(d) Data Reporting Requirements. In addition to reporting the information required in 

40 CFR §98.3(c), the following entities must also report the information identified 

below: 

(1) California position holders must report the annual quantity in barrels, as 

reported by the terminal operator, of each Blendstock, Distillate Fuel Oil, or 

biomass-derived fuel listed in Table 2 of this section, that is delivered across 

the rack in California, except for fuel for which a final destination outside 

California can be demonstrated. Denatured fuel ethanol will be reported with 

the entire volume as 100% ethanol only. The volume of denaturant is 

assumed to be zero and is not required to be reported. 

(2) California position holders that are also terminal operators and refiners must 

report the annual quantity in barrels delivered across the rack of each 

Blendstock, Distillate Fuel Oil, or biomass-derived fuel listed in Table 2 of this 

section, except for fuel for which a final destination outside California can be 

demonstrated. Denatured fuel ethanol will be reported with the entire volume 

as 100% ethanol only. The volume of denaturant is assumed to be zero and is 

not required to be reported. If there is only a single position holder at the 

terminal, and only diesel or biodiesel is being dispensed at the rack then the 

position holder must report the annual quantity of fuel using a meter meeting 

the requirements of section 95103(k) or billing invoices from the entity 

delivering fuel to the terminal. 

(3) Refiners that supply fuel within the bulk transfer system to entities not licensed 

by the California Board of Equalization as a fuel supplier must report the 

annual quantity in barrels delivered of each Blendstock, Distillate Fuel Oil, or 

biomass-derived fuel listed in Table 2 of this section, except for fuel for which 

a final destination outside California can be demonstrated. Denatured fuel 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 149 February 2015 

ethanol will be reported with the entire volume as 100% ethanol only. The 

volume of denaturant is assumed to be zero and is not required to be reported. 

(4) Enterers and biofuel production facilities delivering transportation fuels outside 

the bulk transfer/terminal system must report the annual quantity in barrels, as 

reported on the bill of lading or other shipping documents of each Blendstock, 

Distillate Fuel Oil, or biomass-derived fuel listed in Table 2 of this section, 

except for fuel for which a final destination outside California can be 

demonstrated. Denatured fuel ethanol will be reported with the entire volume 

as 100% ethanol only. The volume of denaturant is assumed to be zero and is 

not required to be reported. Biodiesel or renewable diesel blends containing 

no more than one percent petroleum diesel by volume will be reported as 

100% biodiesel or renewable diesel. 

(5) In addition to the information required in 40 CFR §98.396, refiners must also 

report the volume of liquefied petroleum gas in barrels supplied in California as 

well as the volumes of the individual components as listed in 40 CFR 98 Table 

MM-1, except for fuel for which a final destination outside California can be 

demonstrated. 

(6) All fuel suppliers identified in this section must also report CO2, CO2 from 

biomass-derived fuels, CH4, N2O and CO2e emissions in metric tons that 

would result from the complete combustion or oxidation of each petroleum fuel 

identified in 95121(a)(2), liquefied petroleum gas, or biomass-derived fuel 

reported in this section, calculated according to section 95121(b). 

(7) All fuel suppliers identified in this section, except for refiners that report 

pursuant to section 95113(m), must report the total quantity of CARBOB, 

California Gasoline, California diesel fuel, and biodiesel and/or renewable 

diesel that was imported from outside of California for use in California. In 

addition, for CARBOB imports, the designated percentage of oxygenate must 

be reported. 

(8) Fuel suppliers identified in this section, except for refiners that report pursuant 

to section 95113(m), must report the total quantity of biodiesel and/or 

renewable diesel blended in California diesel for use in California. 

(e) Procedures for Missing Data. For quantities of fuels that are purchased, sold, or 

transferred in any manner, fuel suppliers must follow the missing data procedures 

specified in 40 CFR §98.395. The supplier must document and retain records of 

the procedure used for all missing data estimates pursuant to the recordkeeping 

requirements of section 95105. 

 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 150 February 2015 

Table 2 

Blendstocks, Distillate Fuel Oils, and Biomass-Derived Fuels 

Subject to Reporting under section 95121 

CBOB—Summer 

Regular 

Midgrade 

Premium 

CBOB—Winter 

Regular 

Midgrade 

Premium 

RBOB (CARBOB)—Summer 

Regular 

Midgrade 

Premium 

RBOB (CARBOB)—Winter 

Regular 

Midgrade 

Premium 

Distillate Fuel Oils 

Distillate No. 1 

Distillate No. 2 

Liquefied Petroleum Gas (LPG) 

Ethane 

Ethylene 

Propane 

Propylene 

Butane 

Butylene 

Isobutane 

Isobutylene 

Pentanes Plus 

Biomass-Derived Fuel 

Ethanol (100%) 

Biodiesel (≥99%, methyl ester) 

Renewable Diesel (≥99%) 

Rendered Animal Fat 

Vegetable Oil 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 151 February 2015 

NOTE: Authority cited: Sections 38510, 38530, 39600, 39601, 39607, 39607.4 and 

41511, Health and Safety Code. Reference: Sections 38530, 39600 and 41511, Health 

and Safety Code. 

§ 95122. Suppliers of Natural Gas, Natural Gas Liquids, Liquefied Petroleum 

Gas, Compressed Natural Gas, and Liquefied Natural Gas. 

Any supplier of natural gas or natural gas liquids who is required to report under section 

95101 must comply with Subpart NN of 40 CFR Part 98 (§§98.400 to 98.408) in 

reporting emissions and related data to ARB, except as otherwise provided in this 

section. 

(a) GHGs to Report. 

(1) In addition to the CO2 emissions specified under 40 CFR §98.402(a), natural 

gas liquid fractionators must report the CO2, CH4, N2O and CO2e emissions 

that would result from the complete combustion or oxidation of liquefied 

petroleum gas sold or delivered to others that was produced on-site, except for 

products for which a final destination outside California can be demonstrated. 

(2) In addition to the CO2 emissions specified under 40 CFR §98.402(b), local

distribution companies including intrastate pipelines delivering gas to 

California end-users must report the CO2, CO2 from biomass-derived fuels, 

CH4, N2O, and CO2e emissions from the complete combustion or oxidation of 

the annual volume of natural gas delivered to all entities on their distribution 

systems in California. 

(3) The California consignee for imported liquefied petroleum gas, compressed 

natural gas, or liquefied natural gas must report the CO2, CH4, N2O and CO2e 

emissions that would result from the complete combustion or oxidation of the 

annual quantity of liquefied petroleum gas, compressed natural gas, and 

liquefied natural gas imported into the state, except for products for which a 

final destination outside California can be demonstrated. 

(4) Operators of liquefied natural gas production facilities that receive natural gas 

supply from interstate pipelines must report the CO2, CH4, N2O and CO2e 

emissions that would result from the complete combustion or oxidation of all 

liquefied natural gas sold or delivered to others, except for product for which a 

final destination outside California can be demonstrated. 

(b) Calculating GHG Emissions. 

(1) Natural gas liquid fractionators must use calculation methodology 2 as 

specified in 40 CFR §98.403(a)(2) to estimate the CO2 emissions that would 

result from the complete combustion of all natural gas liquid products supplied 

except that Table MM-1 must be used in place of Table NN-2. For calculating 

the emissions from liquefied petroleum gas, the fractionators must sum the 

emissions from the individual constituents of liquefied petroleum gas sold or 

delivered to others that was produced on-site, except for products for which a 

final destination outside of California can be demonstrated. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 152 February 2015 

(2) For the calculation of CO2i in section 95122(b)(6), local distribution companies 

must estimate CO2 emissions at the state border or city gate for pipeline 

quality natural gas using calculation methodology 1 as specified in 40 CFR 

§98.403(a)(1), except that the product of HHV and Fuel is replaced by the 

annual MMBtu of natural gas received. 

(3) For the calculation of CO2j in section 95122(b)(6), public utility gas 

corporations and publicly owned natural gas utilities must estimate annual CO2

emissions from instate receipts of pipeline quality natural gas from other public 

utility gas corporations, interstate pipelines and intrastate transmission 

pipelines, and annual CO2 emissions from all natural gas redelivered to other 

public utility gas corporations or interstate pipelines. Annual CO2 emissions 

from redelivered natural gas to intrastate pipelines or publicly owned natural 

gas utilities must be estimated only if emissions from the redelivered natural 

gas equals or exceeds 25,000 MTCO2e calculated according to subparagraph 

(2) above. Emissions are calculated according to Equation NN-3 of 40 CFR 

§98.403(b)(1) except that CO2j will be the product of MMBtuTotal and the default 

emission factor from Table NN-1 or the product of MMBtuTotal and the reporter 

specific emission factor. MMBtuTotal must be calculated as follows: 

MMBtu=>?@A = MMBtuBCDCAEFCBG − MMBtuBCICEJ?K

Where 

MMBtuTotal = Total annual MMBtu used in equation NN-3 

MMBturedelivery = Total annual MMBtu of natural gas delivered to other 

companies as specified above 

MMBtureceipts = Total annual MMBtu of natural gas received from other 

companies as specified above 

(4) For the calculation of CO2l in section 95122(b)(6), emissions from receipts of 

pipeline quality natural gas from in-state natural gas producers and net volume 

of pipeline quality natural gas injected into storage are estimated according to 

Equation NN-5 of 40 CFR §98.403(b)(3) except that CO2l will be calculated as 

the product of the net annual MMBtu and a default emission factor from Table 

NN-1 or the product of the net annual MMBtu and a reporter specific emission 

factor. 

(5) Determination of pipeline quality natural gas is based on the annual weighted 

average HHV, determined according to Equation C-2b of 40 CFR 

§98.33(a)(2)(ii)(A), for natural gas from a single city gate, storage facility, or 

connection with an in-state producer, interstate pipeline, intrastate pipeline or 

local distribution company. If the HHV is outside the range of pipeline quality 

natural gas, emissions will be calculated using the appropriate subparagraph 

of section 95122(a) replacing the default emission factor with either a reporter 

specific emission factor as calculated in 40 CFR §98.404(b)(2) or one 

determined as follows: 

(A) For natural gas or biomethane with an annual weighted HHV below 970 

Btu/scf and not exceeding 3% of total emissions estimated under this 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 153 February 2015 

section, the local distribution company may use the reporter specific 

weighted yearly average higher heating value and the default emission 

factor or an emission factor as determined in 40 CFR §98.404(c)(3). If 

emissions exceed 3% of the total, then the Tier 3 method specified in 40 

CFR §98.33(a)(3)(iii) must be used with monthly carbon content samples 

to calculate the annual emissions from the portion of natural gas that is 

below 970 Btu/scf. 

(B) For natural gas or biomethane with an annual HHV above 1100 Btu/scf 

and not exceeding 3% of total emissions estimated under this section, the 

local distribution company must use the reporter specific weighted yearly 

average higher heating value and a default emission factor of 54.67 kg 

CO2/MMBtu or an emission factor as determined in 40 CFR 

§98.404(c)(3). If emissions exceed 3% of the total, then the Tier 3 

method specified in 40 CFR §98.33(a)(3)(iii) must be used with monthly 

carbon content samples to calculate the annual emissions from the 

portion of natural gas that is above 1100 Btu/scf. 

(6) When calculating total CO2 emissions for California, the equation below must 

be used: 

CO2 = ∑ CO2i − ∑ CO2j − ∑ CO2l

Where: 

CO2 = Total emissions. 

CO2i = Emissions from natural gas received at the state border or 

 city gate, calculated pursuant to section 95122(b)(2). 

CO2j = Emissions from natural gas received for redistribution to or 

 received from other natural gas transmission companies, 

 calculated pursuant to section 95122(b)(3). 

CO2l = Emissions from storage and direct deliveries from producers 

 calculated pursuant to section 95122(b)(4). 

(7) Natural gas liquid fractionators and local distribution companies must estimate 

and report CH4 and N2O emissions using equation C-8 and Table C-2 as 

described in 40 CFR §98.33(c)(1) for all fuels where annual CO2 emissions 

are required to be reported by 40 CFR §98.406 and this section. Local 

distribution companies must use the annual MMBtu determined in paragraphs 

(2)-(4) above in place of the product of the Fuel and HHV in equation C-8 

when calculating emissions. 

(8) Local distribution companies must separately and individually calculate enduser emissions of CH4, N2O, CO2 from biomass-derived fuels, and CO2e by 

replacing CO2 in the equation in section 95122(b)(6) with CH4, N2O, CO2 from 

biomass-derived fuels, and CO2e. CO2 emissions from biomass-derived fuel 

are based on the fuel the LDC has contractually purchased on behalf of and 

delivered to end users. Emissions from contractually purchased biomethane 

are calculated using the methods for natural gas required by this section, 

including the use of the emission factor for natural gas found in 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 154 February 2015 

40 CFR§98.408, table NN-1. Biomass-derived fuels directly purchased by end 

users and delivered by the LDC must be reported as natural gas by the LDC. 

(9) The California consignee for imported liquefied petroleum gas must use 

calculation methodology 2 described in 40 CFR §98.403(a)(2) for calculating 

CO2 emissions except that for liquefied petroleum gas table MM-1 of 40 CFR 

Part 98 must be used in place of Table NN-2. For liquefied petroleum gas, the 

consignee must sum the emissions from the individual components of the gas 

to calculate the total emissions. If the composition is not supplied by the 

producer, the consignee must use the default value for liquefied petroleum gas 

presented in Table C-1 of 40 CFR Part 98. The California consignee for 

compressed natural gas or liquefied natural gas must estimate CO2 using 

calculation methodology 1 as specified in 40 CFR §98.403(a)(1), except that 

the product of HHV and Fuel is replaced by the annual MMBtu of the imported 

compressed natural gas and liquefied natural gas. 

(10) The California consignee for imported liquefied petroleum gas, compressed 

natural gas, or liquefied natural gas must estimate and report CH4 and N2O 

emissions using equation C-8 and Table C-2 as described in 40 CFR 

§98.33(c)(1). 

(11) Operators of liquefied natural gas production facilities described in section 

95122(a)(4) must estimate CO2 using calculation methodology 1 as specified 

in 40 CFR §98.403(a)(1), except that the product of HHV and Fuel is replaced 

by the annual MMBtu of the liquefied natural gas sold or delivered in 

California. 

(12) Operators of liquefied natural gas production facilities described in section 

95122(a)(4) must estimate and report CH4 and N2O emissions based on the 

MMBtu of liquefied natural gas sold or delivered using equation C-8 and Table 

C-2 as described in 40 CFR §98.33(c)(1). 

(13) All fuel suppliers in this section must also estimate CO2e emissions using the 

following equation: 

Where: 

CO2e = Carbon dioxide equivalent, metric tons/year. 

GHGi = Mass emissions of CO2, CH4, N2O from fuels combusted or 

 oxidized. 

GWPi = Global warming potential for each greenhouse gas from Table A-1 

 of 40 CFR Part 98. 

n = Number of greenhouse gases emitted. 

(c) Monitoring and QA/QC Requirements. For each emissions calculation method 

chosen under this section, the supplier must meet all monitoring and QA/QC 

requirements specified in 40 CFR §98.404, except as modified in sections 95103, 

95115, and below. 

CO e GHGi x GWPi

n

1i

2 ∑==
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 155 February 2015 

(1) All natural gas suppliers must measure required values at least monthly. 

(2) All natural gas suppliers must determine reporter specific HHV at least 

monthly, or if the local distribution company does not make its own 

measurements according to standard business practices it must use the 

delivering pipeline measurement. 

(3) All natural gas liquid fractionators must sample for composition at least 

monthly. 

(4) All California consignees of liquefied petroleum gas must record composition, 

if provided by the supplier, and quantity in barrels, corrected to 60 degrees 

Fahrenheit, for each shipment received. 

(d) Data Reporting Requirements. 

(1) For the emissions calculation method selected under section 95122(b), natural 

gas liquid fractionators must report, in addition to the data required by 40 CFR 

§98.406(a), the annual volume of liquefied petroleum gas, corrected to 60 

degrees Fahrenheit, that was produced on-site and sold or delivered to others, 

except for products for which a final destination outside California can be 

demonstrated. Natural gas liquid fractionators must report the annual quantity 

of liquefied petroleum gas produced and sold or delivered to others as the total 

volume in barrels as well as the volume of the individual components for all 

components listed in 40 CFR 98 Table MM-1. Fractionators must also include 

the annual CO2, CH4, N2O, and CO2e mass emissions (metric tons) from the 

volume of liquefied petroleum gas reported in 40 CFR §98.406(a)(5) as 

modified by this regulation, calculated in accordance with section 95122(b). 

(2) For the emissions calculation method selected under section 95122(b), local 

distribution companies must report all the data required by 40 CFR §98.406(b) 

subject to the following modifications: 

(A) Publicly-owned natural gas utilities that report in-state receipts at the city 

gate under 40 CFR §98.406(b)(1) must also identify each delivering entity 

by name and report the annual volumes received in Mscf and the annual 

energy in MMBtu. 

(B) Local distribution companies that report under 40 CFR §98.406(b)(1) 

through (b)(7) must also report the annual energy of natural gas in 

MMBtu associated with the volumes. 

(C) In addition to the requirements in 40 CFR §98.406(b)(8), local distribution 

companies must also include CO2, CO2 from biomass-derived fuels, CH4, 

N2O, and CO2e annual mass emissions in metric tons calculated in 

accordance with 40 CFR §98.403(a) and (b)(1) through (b)(3) as modified 

by section 95122(b). 

(D) In lieu of reporting the information specified in 40 CFR §98.406(b)(6), 

local distribution companies, including intrastate pipelines that deliver 

natural gas to downstream gas pipelines and other local distribution 

companies, must report the annual volumes in Mscf, annual energy in 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 156 February 2015 

MMBtu, and the information required in 40 CFR §98.406(b)(12). These 

requirements are in addition to the requirements of 40 CFR 

§98.406(b)(6). 

(E) In lieu of reporting the information specified in 40 CFR §98.406(b)(7), 

local distribution companies including intrastate pipelines must report the 

annual volumes in Mscf, annual energy in MMBtu, customer information 

required in 40 CFR §98.406(b)(12), and ARB ID number if available for all 

end-users registering supply equal to or greater than 188,500 MMBtu 

during the calendar year. In addition to reporting the information 

specified in 40 CFR §98.406(b)(13), local distribution companies 

including intrastate pipelines that deliver to end users must report the 

annual energy in MMBtu delivered to the following end-use categories: 

residential consumers; commercial consumers; industrial consumers; 

electricity generating facilities; and other end-users not identified as 

residential, commercial, industrial, or electricity generating facilities. 

Local distribution companies must also report the total energy in MMBtu 

delivered to all California end-users. 

(F) Local distribution companies that report under 40 CFR §98.406(b)(9) 

must report annual CO2, CO2 from biomass-derived fuel, CH4, N2O, and 

CO2e emissions (metric tons) that would result from the complete 

combustion or oxidation of the natural gas supplied to all entities 

calculated in accordance with section 95122(b). 

(3) In addition to the information required in 40 CFR §98.3(c), the operator of an 

interstate pipeline, which is not a local distribution company, must report the 

customer name, address, and ARB ID along with annual volumes of natural 

gas, in Mscf, and the annual energy of natural gas in MMBtu for natural gas 

delivered to each customer, including themselves. 

(4) In addition to the information required in 40 CFR §98.3(c), the operator of an 

intrastate pipeline that delivers natural gas directly to end users must follow 

the reporting requirements described under Subpart NN of 40 CFR Part 98 

and this section for local distribution companies. In lieu of the city gate 

information specified by section 95122(b)(2), the intrastate pipeline operator 

must report the summed volumes (Mscf) and energy (MMBtu) of natural gas 

delivered to each entity receiving gas from the intrastate pipeline for purposes 

of estimating the CO2i parameter as specified in section 95122(b)(6). 

Additionally, intrastate pipeline operators are required to estimate a value for 

CO2j as specified in section 95122(b)(3) for natural gas delivered to local 

distribution companies, interstate pipelines, and other intrastate pipelines. The 

CO2l parameter as specified in section 95122(b)(4) must have a value of 0 for 

calculating emissions as required by section 95122(b)(6). 

(5) In addition to the information required in 40 CFR §98.3(c), the California 

consignee for liquefied petroleum gas must report the annual quantity of 

liquefied petroleum gas imported as the total volume in barrels as well as the 

volume of its individual components for all components listed in 40 CFR 98 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 157 February 2015 

Table MM-1, if supplied by the producer, and report CO2, CH4, N2O, and CO2e 

annual mass emissions in metric tons using the calculation methods in section 

95122(b). All California consignees of compressed or liquefied natural gas 

and liquefied natural gas production facilities as described in section 

95122(a)(4) must report the annual quantities imported, or delivered and sold, 

respectively, in MMBtu, and report CO2, CH4, N2O, and CO2e annual mass 

emissions in metric tons separately for compressed natural gas and liquefied 

natural gas using the calculation methods in section 95122(b). 

(6) In addition to the information required in 40 CFR §98.3(c), all local distribution 

companies that report biomass emissions from biomethane fuel that was 

contractually purchased by the LDC on behalf of and delivered to end users, 

and all liquefied natural gas production facilities reporting biomass emission 

from biomethane, must report, for each contracted delivery, the information 

specified in section 95103(j)(3). 

(e) Procedures for estimating missing data. Suppliers must follow the missing data 

procedures specified in 40 CFR §98.405. The operator must document and retain 

records of the procedure used for all missing data estimates pursuant to the 

recordkeeping requirements of section 95105. 

NOTE: Authority cited: Sections 38510, 38530, 39600, 39601, 39607, 39607.4 and 

41511, Health and Safety Code. Reference: Sections 38530, 39600 and 41511, Health 

and Safety Code. 

§ 95123. Suppliers of Carbon Dioxide. 

Any supplier of carbon dioxide who is required to report under section 95101 of this 

article must comply with Subpart PP of 40 CFR Part 98 (§§98.420 to 98.428) in 

reporting to ARB, except as otherwise provided in this section. 

(a) When reporting imported and exported quantities of CO2 as required in 40 CFR 

§98.422, the supplier must report quantities of carbon dioxide imported into and 

exported from the State of California. Exports for purposes of geologic 

sequestration must be reported separately from exports for other purposes. 

(b) Missing Data Substitution Procedures. The supplier must comply with 40 CFR 

§98.425 when substituting for missing data, except as otherwise provided below. 

(1) For all data required for emissions calculations in this section, the supplier 

must follow the requirements of paragraphs (A)-(D) below. 

(A) If the data capture rate is at least 90 percent for the data year, the 

supplier must substitute for each missing value using the best available 

estimate of the parameter, based on all available process data. 

(B) If the data capture rate is at least 80 percent but not at least 90 percent 

for the data year, the supplier must substitute for each missing value with 

the highest quality assured value recorded for the parameter during the 

given data year, as well as the two previous data years. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 158 February 2015 

(C) If the data capture rate is less than 80 percent for the data year, the 

supplier must substitute for each missing value with the highest quality 

assured value recorded for the parameter in all records kept according to 

section 95105(a). 

(D) The supplier must document and retain records of the procedure used for 

all missing data estimates pursuant to the recordkeeping requirements of 

section 95105. 

NOTE: Authority cited: Sections 38510, 38530, 39600, 39601, 39607, 39607.4 and 

41511, Health and Safety Code. Reference: Sections 38530, 39600 and 41511, Health 

and Safety Code. 

§ 95124. Lead Production. 

The operator of a facility who is required to report under section 95101(a)(1)(B)(8.) of 

this article, and who is not eligible for abbreviated reporting under section 95103(a), 

must comply with Subpart R of 40 CFR Part 98 (§§98.180 to 98.188) in reporting 

stationary combustion and process emissions and related data from lead production to 

ARB, except as otherwise provided in this section. 

(a) CO2 from Fossil Fuel Combustion. When calculating CO2 emissions from fossil fuel 

combustion at a stationary combustion unit under 40 CFR §98.182(d), the operator 

must use a method in 40 CFR §98.33(a)(1) to §98.33(a)(4) as specified by fuel type 

in section 95115 of this article. 

(b) Monitoring, Data and Records. For each emissions calculation method chosen 

under section 95124(a), the operator must meet the applicable requirements for 

monitoring, missing data procedures, data reporting, and records retention that are 

specified in 40 CFR §98.34 to §98.37, except as modified in sections 95115, 

95118(c)-(d), and section 95129 of this article. 

(c) Missing Data Substitution Procedures. The operator must comply with 40 CFR 

§98.185 when substituting for missing data, except as otherwise provided in 

paragraphs (1)-(3) below. 

(1) To substitute for missing data for emissions reported under section 95115 of 

this article (stationary combustion units and units using continuous emissions 

monitoring systems), the operator must follow the requirements of section 

95129 of this article. 

(2) If the annual mass or carbon content of carbon-containing inputs are missing 

when using the process emissions calculation procedure in 40 CFR 

§98.183(b)(2), the operator must apply substitute values according to the 

procedures in paragraphs (A)-(B) below. 

(A) If the analytical data capture rate is at least 80 percent for the data year, 

the operator must substitute for each missing value according to 

40 CFR §98.185(a) and the number of days per month. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 159 February 2015 

(B) If the analytical data capture rate is less than 80 percent for the data 

year, the operator must substitute for each missing value with the 

maximum capacity of the system and the number of days per month. 

(3) The operator must document and keep records of the procedures used for 

estimating missing data pursuant to the recordkeeping requirements of section 

95105. 

(d) Additional Product Data. The operator of a lead production, recycling, recovery, or 

manufacturing facility must report production of lead and lead alloys during the data 

year (short tons). 

NOTE: Authority cited: Sections 38510, 38530, 39600, 39601, 39607, 39607.4 and 

41511, Health and Safety Code. Reference: Sections 38530, 39600 and 41511, Health 

and Safety Code. 

 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 160 February 2015 

Subarticle 3. Additional Requirements for Reported Data 

§ 95129. Substitution for Missing Data Used to Calculate Emissions from 

Stationary Combustion and CEMS Sources. 

In lieu of the requirements for estimating missing data in Subparts C and D of 40 CFR 

Part 98, the operator of a facility who is reporting emissions under section 95115 or 

95112 of this article, and who is not eligible for abbreviated reporting under section 

95103(a), must follow the applicable procedures of this section for estimating missing or 

invalid data. The operator must include the substituted data in the GHG emissions data 

report and maintain all records, calculations, and data used to estimate substituted data 

according to the requirements of section 95105 and 40 CFR Part 98. Alternatively, 

under the limited circumstances specified in this section for equipment breakdown, the 

operator may request approval of an interim data collection procedure as specified in 

section 95129(h)-(i). For units combusting pure biomass-derived fuels or for de minimis 

sources, the operator who is reporting emissions must follow either the requirements 

below or the requirements of 40 CFR §98.35. In the event that section 95129 becomes 

applicable to a source, compliance with the requirements of section 95129 does not 

relieve the operator from complying with other sections of this article. 

(a) Missing Data Substitution Procedures for Units Reporting Under 40 CFR Part 75. 

The operator of a unit that is reporting CO2 using 40 CFR Part 75 must follow the 

applicable missing data substitution procedures in Part 75 for CO2 concentration, 

stack gas flow rate, fuel flow rate, high heat value, and fuel carbon content, except 

as otherwise provided in this section. Paragraphs (b) through (g) of this section do 

not apply to these units for CO2 emissions, but do apply for CH4 and N2O emissions 

that are not de minimis if data required for calculating CH4 and N2O emissions are 

missing or invalid. 

(b) Missing Data Substitution Procedures for Other Units Equipped with CEMS. The 

operator of a stationary combustion unit who monitors and reports emissions and 

heat input data for that unit under section 95115 of this article using Tier 4 of 

Subpart C (40 CFR §98.33(a)(4)) must follow the applicable missing data 

substitution procedures in 40 CFR §75.31 to 75.37 (revised as of July 1, 2009). For 

the purpose of missing data substitution, for CEMS certified under 40 CFR Part 60, 

quality-assured data is defined according to the quality assurance/quality control 

procedures in 40 CFR Part 60. Paragraphs (c) through (h) of this section do not 

apply to units using Tier 4 for CO2 emissions, but do apply for CH4 and N2O 

emissions that are not de minimis if data required for calculating CH4 and N2O 

emissions are missing or invalid. 

(c) Missing Data Substitution Procedures for Fuel Characteristic Data. When the 

applicable emissions estimation methods of this article require periodic collection of 

fuel characteristic data (including carbon content, high heat value, and molecular 

weight) the operator must demonstrate every reasonable effort to obtain a fuel 

characteristic data capture rate of 100 percent for each data year. When fuel 

characteristic data of a required fuel sample are missing or invalid, the operator 

must first attempt to either reanalyze the original sample or perform the fuel 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 161 February 2015 

analysis on a backup sample, or replacement sample from the same collection 

period as specified in 40 CFR §98.34(a)(2)-(3), to obtain valid fuel characteristic 

data. If the sample collection period has elapsed and no valid fuel characteristic 

data can be obtained from a backup or replacement sample, the operator must 

substitute for the missing data the values obtained according to the procedures in 

section 95129(c)(1)-(3). The data capture rate for the data year must be calculated 

as follows for each type of fuel and each fuel characteristic parameter: 

Data capture rate = S / T x 100% 

Where: 

S = Number of fuel samples for which valid fuel characteristic data were 

obtained according to the applicable sampling requirements (including 

sampling schedule) 

T = Total number of fuel samples required by the applicable sampling 

requirements 

(1) If the fuel characteristic data capture rate is at least 90.0 percent for the data 

year, the operator must substitute the arithmetic average of the values of that 

parameter immediately preceding and immediately following the missing data 

incident that are representative of the fuel type. If the “after” value has not 

been obtained by the time that the GHG emissions data report is due, the 

operator must use the “before” value for missing data substitution. 

(2) If the fuel characteristic data capture rate is at least 80.0 percent but not more 

than 90.0 percent for the data year, the operator must substitute for each 

missed value with the highest valid value recorded for that type of fuel during 

the data year as well as the two previous data years. 

(3) If the operator is unable to obtain fuel characteristic data such that less than 

80.0 percent of a fuel characteristic data element are directly accounted for, 

the operator must then substitute for each missed data point as follows: 

(A) If historical fuel characteristics data are available and kept according to 

the requirements of section 95105, substitute with the greater of the 

following: 

1. The highest valid value recorded for that type of fuel for all records 

kept under the requirements of section 95105, or 

2. The default value in Table 1 of this section (for carbon content) or 

Table C-1 of 40 CFR Part 98 (for high heat value). If a substitute 

value is not available in Table 1 of this section or Table C-1 of 40 

CFR Part 98, the operator must substitute the highest value recorded 

for that type of fuel for all records kept pursuant to the requirements 

of section 95105. 

(B) For carbon content data, if historical fuel characteristics data are not 

available and a default value is not listed in Table 1 of this section, use 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 162 February 2015 

90% for other liquid and gaseous fuels and 100% for other solid fuels in 

substituting for missed carbon content data. 

Table 1. Default Carbon Content

Parameter Missing Data Value 

Anthracite Coal 90% 

Bituminous 85% 

Subbituminous/Lignite 75% 

Oil 90% 

Natural Gas 75% 

(d) Missing Data Substitution Procedures for Fuel Consumption Data. The operator 

subject to the requirements of this article must demonstrate every reasonable effort 

to obtain a total facility fuel consumption data capture rate of 100 percent for each 

year for each type of fuel. The total facility fuel consumption for the data year can 

be determined using any combination of meters and/or other fuel measurement 

devices or methods that individually meet the accuracy requirements of this article, 

provided that the total amount of fuel consumed at the facility level is completely 

accounted for during each time period that the facility is in operation. For each fuel 

type, when the total facility fuel consumption data that meet the accuracy 

requirements of this article are available during each time period that the facility is in 

operation, but such data are missing or invalid at the unit level, the operator must 

either estimate missing unit-level fuel consumption data using other available data 

parameters that are routinely measured at the facility (e.g., electrical load, steam 

production, operating hours, production output, or fuel consumption data at other 

measurement points), or use an applicable missing data substitution procedure 

from section 95129(d)(1)-(3). If during any time periods that the facility is in 

operation, a portion of the total facility fuel consumption is missing or cannot be 

determined at the accuracy required by this article, the operator must use the 

applicable missing data substitution procedure from section 95129(d)(1)-(3) below, 

so that the total facility fuel consumption quantity for the missing data periods is 

reconstructed. If a source is eligible for more than one procedure in section 

95129(d)(1)-(3), the operator has the option to choose one of the applicable 

procedures in section 95129(d)(1)-(3). The requirements in section 95129(d)(1)-(3) 

are optional for sources that are not required to meet the accuracy standard 

specified in section 95103(k) and for sources that do not utilize fuel consumption 

data for emission calculation. 

(1) Continuous Fuel Flow Rate Data Using Load Ranges. The sources that meet 

the following criteria are eligible for using the procedures in paragraph (d)(1): 

the sources combust gaseous or liquid fuels, produce electrical or thermal 

output, use a fuel flowmeter system to continuously measure fuel flow rate; 

and are equipped with a data acquisition and handling system (DAHS) that 

continuously records fuel flow rates and measured electrical or thermal output 

on an hourly basis, which enables segregation of the fuel flow rate data into 

bins. The operator of such sources that applies the requirements in this 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 163 February 2015 

paragraph must substitute missing fuel flow rate data according to this 

paragraph. 

 Whenever quality-assured fuel flow rate data are missing and there is no 

backup system available to record the fuel flow rate, the operator must use the 

following procedures to account for the flow rate of fuel combusted at the 

source for each hour during the missing data period. Before using these 

procedures, operators must establish load ranges for the affected sources 

using the procedures in paragraph (f) of this section. 

 When load ranges are used for estimating missing fuel flow rate data, the 

operator must create and maintain separate fuel-specific databases for the 

source. The database for each type of fuel combusted must include the hours 

in which the fuel is combusted alone at the source and the hours in which it is 

co-fired with any other fuel types. The database must record fuel flow rate and 

corresponding electrical output or thermal output, and assign these values into 

the established load bins. To be eligible to use the missing data procedures in 

this paragraph, measured electrical output or thermal output must be available 

for the hour(s) in which fuel flow rate data are missing. If output data are 

missing, the operator must follow the requirements of paragraph (d)(3). 

(A) Single Fuel Type. For missing data periods that occur when only one

type of fuel is being combusted, the operator must provide substitute data 

for each hour of the missing data period as follows: Substitute the 

arithmetic average of the hourly quality-assured fuel flow rate(s) 

measured and recorded by a fuel flowmeter system at the corresponding 

operating source load range during the previous 720 operating hours in 

which the source combusted only that same fuel. If 720 hours of fuel flow 

rate data are not available at the corresponding load range, the operator 

may combine available data with data from higher load ranges if available 

until 720 hours are reached. If 720 hours of quality-assured fuel flow rate 

data are not available when combined with higher load ranges, the 

operator must substitute the maximum potential fuel flow rate for each 

hour of the missing data period. 

(B) Multiple Fuel Types. For missing data periods that occur when two or 

more different types of fuel are being co-fired, the operator must provide 

substitute fuel flow rate data for each hour of the missing data period as 

follows: 

1. Substitute the maximum hourly quality-assured fuel flow rate(s) 

measured and recorded by a fuel flowmeter system at the 

corresponding operating source load range during the previous 720 

operating hours when the fuel for which the flow rate data are 

missing was co-fired with any other type of fuel. If 720 hours of fuel 

flow rate data are not available at the corresponding load range, data 

from higher load ranges if available may be combined until 720 hours 

are reached. If 720 hours of quality-assured fuel flow rate data are 

not available when combined with higher load ranges, the operator 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 164 February 2015 

must substitute the maximum potential fuel flow rate for each hour of 

the missing data period. 

2. If, during an hour in which different types of fuel are co-fired, qualityassured fuel flow rate data are missing for two or more of the fuels 

being combusted, apply the procedures in subparagraph (d)(1)(B)1. 

separately for each type of fuel. 

3. If the missing data substitution required in subparagraphs 

(d)(1)(B)1-2 causes the reported hourly heat input rate based on the 

combined fuel usage to exceed the maximum rated hourly heat input 

of the unit, adjust the substitute fuel flow rate value(s) so that the 

reported heat input rate equals the unit’s maximum rated hourly heat 

input. 

(C) Lookback Period. In any case where the missing data provisions of this 

section require substitution of data measured and recorded more than 

three years (26,280 clock hours) prior to the date and time of the missing 

data period, the operator must substitute the maximum potential fuel flow 

rate for each hour of the missing data period. In addition, for sources in 

operation less than three years (26,280 clock hours), until 720 hours of 

quality-assured fuel flowmeter data are available for the lookback periods 

described in subparagraphs (d)(1)(A) and (d)(1)(B), the methodology in 

section (d)(3) must be used to determine the appropriate substitute data 

values. 

(2) Fuel Consumption Data Without Load Ranges. The sources that meet the 

following criteria are eligible to use the procedures in this paragraph: the 

facility operator has established and implemented a fuel monitoring plan as a 

part of the GHG Monitoring Plan specified in section 95105(c)(5), has 

monitored fuel measurement equipment and maintained records of its proper 

operation by recording fuel consumption quantities at least weekly, and has 

compiled records of fuel consumption that are sufficient for the application of 

the procedures in this paragraph. For operators that apply the requirements in 

this paragraph, whenever quality-assured fuel consumption data are missing 

and there is no backup system available to record the fuel consumption, the 

operator must use the procedures in this paragraph to account for the 

consumption of fuel combusted at the unit during the missing data period. For 

fuels that are combusted less than 180 days in a calendar year, the operator 

must record fuel consumption at least daily on each day the fuel is combusted. 

For all other sources or fuels, the operator must record fuel consumption at 

least weekly. 

 The data capture rate for the data year must be calculated as follows for each 

unit with missing fuel consumption data: 

Data capture rate = S / T x 100% 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 165 February 2015 

Where: 

S = Number of fuel monitoring periods (e.g., days or weeks) in the data 

year for which valid measured fuel consumption data are available. 

Do not include fuel monitoring periods when the fuel was not 

combusted at the unit. 

T = Total number of fuel monitoring periods (e.g., days or weeks) in the 

data year that the fuel is combusted at the unit. 

(A) Single Fuel. For missing data periods that occur when only one type of 

fuel is being combusted, the operator must provide substitute data for 

each missing data period as follows: 

1. If the fuel consumption data capture rate is equal to or greater than 

95.0 percent during the data year, the operator must develop an 

estimate based on available process data that are routinely 

measured and recorded at the unit (e.g., electrical load, steam 

production, operating hours) or fuel consumption data recorded at 

other upstream or downstream measurement points. 

2. If the fuel consumption data capture rate is equal to or greater than 

90.0 percent but less than 95.0 percent during the data year, the 

operator must calculate substitute data as the 90th percentile value of 

the fuel consumption data recorded for the data year as well as the 

two previous data years. 

3. If the fuel consumption data capture rate is at least 80.0 percent but 

less than 90.0 percent during the data year, the operator must 

calculate substitute data as the 95th percentile value of the fuel 

consumption data recorded for the data year as well as the two 

previous data years. 

4. If the fuel consumption data capture rate is less than 80.0 percent 

during the data year, the operator must apply as substitute data the 

maximum potential fuel consumption rate. 

(B) Multiple Fuels. For missing data periods that occur when two or more 

different types of fuel are being co-fired, the operator must provide 

substitute fuel flow rate data for each missing data period as follows: 

1. If the fuel consumption data for a single fuel are missing, provide 

substitute fuel consumption data for the missing data period using 

the procedures in section 95129(d)(2)(A). 

2. If fuel consumption data are missing for two or more of the fuels 

being combusted, apply the procedures in section 95129(d)(2)(A) (as 

applicable) separately for each type of fuel. 

3. If the missing data substitution required in section 95129(d)(2)(A) 

causes the reported heat input rate based on the combined fuel 

usage to exceed the maximum rated heat input of the source, adjust 

the substitute fuel consumption value(s) so that the reported heat 

input rate equals the source’s maximum rated heat input. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 166 February 2015 

(C) Prorating Substitute Value. When applying the procedures in 

subparagraphs (d)(2)(A)-(B), if an individual missing data period is 

shorter than the fuel consumption data monitoring period, the operator 

must prorate the specified value for the fuel consumption data monitoring 

period by the missing data period. For example, for a unit with a missing 

data period length of one day but weekly fuel consumption monitoring 

schedule, the operator may divide the substitute value, estimated on a 

weekly basis, by the number of days the unit operates in a week to obtain 

the substitute value for the missing data day. 

(3) Alternate Missing Data Procedure for Fuel Consumption Data. This paragraph 

applies to fuel combusting units that cannot use the missing data procedures 

in paragraphs (d)(1) and (d)(2). If fuel consumption data are missing or invalid 

for a fuel combusting unit, and the total facility fuel consumption data cannot 

be determined at the accuracy required by this article for the particular missing 

data period, the operator must substitute for each hour of missing data using 

the maximum potential fuel consumption rate for the unit. If fuel consumption 

data at the facility level or at a higher aggregated-units level are available and 

meet the accuracy requirements of this article, the operator may estimate the 

missing unit-level fuel consumption data using available process data that are 

routinely measured at the facility (e.g., electrical load, steam production, 

operating hours) or fuel consumption data recorded at other upstream or 

downstream measurement points that meet the accuracy requirements of this 

article. 

(e) Missing Data Substitution Procedures for Steam Production. The operator of a 

steam-producing unit who calculates and reports emissions using Equation C-2c in 

40 CFR §98.33(a)(2) must apply the procedures in this paragraph to substitute for 

missing steam production data, unless a backup system to record steam production 

is available. For sources for which steam production data are not used to calculate 

emissions, the operator may develop an estimate using available process data that 

are routinely measured and recorded at the unit (e.g., electrical load, steam 

production, product output, operating hours) to estimate missing steam production. 

If hourly steam production data are not available at the facility, the operator must 

record steam production data at least weekly and use the weekly records for 

substituting the missing steam production data. The operator must prorate the 

steam data using the same procedure in paragraph (d)(2)(C). 

The data capture rate for the data year must be calculated as follows for each unit 

with a missing data period: 

Data capture rate = S / T x 100% 

Where: 

S = Number of monitoring intervals (e.g. hourly, daily, or weekly) with valid 

measured steam production data. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 167 February 2015 

T = Total number of monitoring intervals that the unit is operated in the data 

year. 

(1) If the steam production data capture rate is at least 90.0 percent during the 

data year, the operator must develop an estimate using available process data 

that are routinely measured and recorded at the unit (e.g., electrical load, 

steam production, product output, and operating hours). 

(2) If the steam production data capture rate is at least 80.0 percent but less than 

90.0 percent during the data year, the operator must calculate substitute data 

as the 90th percentile value of the steam production data recorded for the data 

year. 

(3) If the steam production data capture rate is less than 80.0 percent during the 

data year, the operator must substitute the highest valid steam production 

value recorded in all records kept according to section 95105(a). 

(f) Procedure for Establishing Load Ranges. This paragraph is applicable to units that 

produce electrical output or thermal output. For a single unit, the operator must 

establish ten operating load ranges, each defined in terms of percent of the 

maximum hourly average gross load of the unit, in gross megawatts (MW). (Do not 

use integrated hourly gross load in MWh.) For a cogenerating unit or other unit at 

which some portion of the heat input is not used to produce electricity, or for a unit 

for which hourly average gross load in MW is not recorded separately, the operator 

must use the hourly gross steam load of the unit, in pounds of steam per hour at the 

measured temperature (°F) and pressure (psia), inst ead of gross MW. 

 Beginning with the first hour of unit operation after installation and certification of the 

fuel flowmeter, for each hour of unit operation the operator must record a number, 1 

through 10, that identifies the operating load range corresponding to the integrated 

hourly gross load of the unit(s) recorded for each unit operating hour. The operator 

must calculate maximum values and percentile values determined by this procedure 

using bias adjusted values in the load ranges. When a bias adjustment is 

necessary for the fuel flowmeter, the operator must apply the adjustment factor to 

all data values placed in the load ranges. The operator must use the calculated 

maximum values and percentile values to substitute for missing flow rate according 

to the procedures in paragraph (d)(1) of this section. 

(g) Executive Officer Approved Load Range. An operator may petition the Executive 

Officer for approval to use an alternate load based methodology for substituting 

missing data to using the procedures in section 95129(d)(1). The operator must be 

able to prove to the satisfaction of the Executive Officer that there is a direct 

correlation between fuel consumption and the proposed load metric. At a minimum, 

the operator will have a system in place that electronically measures and records 

fuel consumption and load at least hourly. The alternate load metric must be a 

metric that can be accurately measured, correlated to fuel consumption, and divided 

into ten operating load ranges. In order to verify the feasibility of the methodology 

the Executive Officer will require at least three years of fuel consumption and load 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 168 February 2015 

data and may request up to the maximum years of data required to be retained 

under section 95105(a). 

(h) Procedure for Approval of Interim Fuel Analytical Data Collection Procedure During 

Equipment Breakdowns. 

(1) In the event of an unforeseen breakdown of the fuel characteristic data 

monitoring or fuel flow monitoring equipment used to estimate emissions 

under this article, the Executive Officer may authorize an operator to use an 

interim data collection procedure under the circumstances specified below. 

The operator must satisfactorily demonstrate to the Executive Officer that: 

(A) The breakdown may result in a loss of more than 10 percent of a fuel 

characteristic data element or a fuel usage data element for the data 

year, and back-up sampling for affected fuel characteristics is 

unavailable; 

(B) The affected monitoring equipment cannot be promptly repaired or 

replaced without shutting down a process unit significantly affecting 

facility operations, or the monitoring equipment must be replaced and 

replacement equipment is not immediately available; and, 

(C) The interim procedure will not remain in effect longer than is reasonably 

necessary for repair or replacement of the malfunctioning monitoring 

equipment. 

(2) An operator seeking approval of an interim data collection procedure must, 

within sixty days of the monitoring equipment breakdown, submit a written 

request to the Executive Officer that includes all of the following: 

(A) The proposed start date and end date of the interim procedure; 

(B) A detailed description of what data are affected by the breakdown; 

(C) A discussion of the accuracy of data collected during the interim 

procedure compared with the data collected under the usual procedure 

used by the operator; 

(D) A demonstration that the criteria in paragraph (h)(1) are satisfied, and 

operator certification that no feasible alternative procedure exists that 

would provide more accurate emissions data. 

(3) The Executive Officer may limit the duration of the interim data collection 

procedure to ensure the criteria in paragraph (h)(1) are met. 

(4) When reviewing an interim data collection procedure, the Executive Officer 

shall determine whether the accuracy of data collected under the procedure is 

reasonably equivalent to data collected from properly functioning monitoring 

equipment, and if it is not, the relative accuracy to assign for purposes of 

assessing possible material misstatement under section 95131 of this article. 

Data collected pursuant to an approved interim data collection procedure shall 

be considered captured data for purposes of compliance with the capture rate 

requirements in this section. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 169 February 2015 

(5) The Executive Officer shall provide written notification to the operator of 

approval or disapproval of the interim data collection procedure within sixty 

days of receipt of the request, or within thirty days of receipt of any additional 

information requested by the Executive Officer, whichever is later. 

(i) Procedure for Approval of Interim Data Collection Procedure During Breakdown for 

Units Equipped with CEMS. 

(1) In the event of an unforeseen breakdown of CEMS equipment at a combustion 

unit where the operator uses the Tier 4 Calculation Methodology (40 CFR 

§98.33(a)(4)) to monitor and report emissions under this article, the operator 

may request approval from the Executive Officer to temporarily use the Tier 2 

Calculation Methodology (40 CFR §98.33(a)(2)) for pipeline quality natural 

gas, biomass, or municipal solid waste, or the Tier 3 Calculation Methodology 

(40 CFR §98.33(a)(3)) for other fuels, to calculate emissions during the 

equipment breakdown period. The operator must satisfactorily demonstrate to 

the Executive Officer that: 

(A) The breakdown will result in a loss of more than 10 percent of the 

concentration, flow rate, or other information used to calculate and report 

annual emissions for the data year, and that back-up monitoring is 

unavailable; 

(B) The affected monitoring equipment cannot be promptly repaired or 

replaced without shutting down a process unit significantly affecting 

facility operations, or the monitoring equipment must be replaced and 

replacement equipment is not immediately available; and, 

(C) The interim procedure will not remain in effect longer than is reasonably 

necessary for repair or replacement of the malfunctioning monitoring 

equipment. 

(2) The operator must collect fuel samples and comply with all applicable 

requirements of the Tier 2 or Tier 3 Calculation Methodology in 40 CFR 

§98.33(a)(2) or (3), as modified by section 95115 of this article, during the 

equipment breakdown period. Fuel characteristics data provided by the fuel 

suppliers can be used if available. The operator must, within sixty days of the 

monitoring equipment breakdown, submit a written request to the Executive 

Officer that includes all the following information: 

(A) The proposed start date and end date of the interim procedure, including 

a demonstration that the interim procedure will not remain in effect longer 

than is reasonably necessary for repair or replacement of the 

malfunctioning equipment; 

(B) A detailed description of what data are affected by the breakdown; and, 

(C) An interim monitoring plan that meets the requirements of the Tiers 2 and 

3 Calculation Methodologies as applicable by fuel type in section 95115. 

(3) The Executive Officer may limit the duration of the interim data collection 

procedure to ensure the criteria in paragraph (i)(1) are met. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 170 February 2015 

(4) The Executive Officer shall provide written notification to the operator of 

approval or disapproval of the interim data collection procedure within sixty 

days of receipt of the request, or within thirty days of receipt of any additional 

information requested by the Executive Officer, whichever is later. 

NOTE: Authority cited: Sections 38510, 38530, 39600, 39601, 39607, 39607.4 and 

41511, Health and Safety Code. Reference: Sections 38530, 39600 and 41511, Health 

and Safety Code. 

 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 171 February 2015 

Subarticle 4. Requirements for Verification of Greenhouse Gas Emissions Data 

Reports and Requirements Applicable to Emissions Data Verifiers; Requirements 

for Accreditation of Emissions Data and Offset Project Data Report Verifiers 

§ 95130. Requirements for Verification of Emissions Data Reports. 

The reporting entity who is subject to verification must obtain the services of an 

accredited verification body for purposes of verifying each emissions data report 

submitted under this article, as specified in section 95103(f). 

(a) Annual Verification. 

(1) Reporting entities required to obtain annual verification services as specified in 

section 95103(f) are subject to full verification requirements in the first year 

that verification is required in each compliance period. Upon receiving a 

positive verification statement, or statements, if applicable, under full 

verification requirements, the reporting entity may choose to obtain less 

intensive verification services for the remaining years of the compliance 

period. Reporting entities subject to this section are also required to obtain full 

verification services if any of the following apply: 

(A) The emissions data report is for the 2011 data year; 

(B) There has been a change in the verification body; 

(C) An adverse verification statement or qualified positive verification 

statement was issued for the previous year for either emissions data or 

product data, or both; 

(D) A change of operational control of the reporting entity occurred in the 

previous year. 

(E) Nothing in this paragraph shall be construed as preventing a verification 

body from performing a full verification in instances where there are 

changes in sources or emissions. The verification body must provide 

information on the causes of the emission changes and justification in the 

verification report if a full verification was not conducted in instances 

where the total reported GHG emissions differ by greater than 25 percent 

relative to the preceding year’s emissions data report. 

(2) Reporting entities subject to annual verification under section 95130 shall not 

use the same verification body or verifier(s) for a period of more than six 

consecutive years, which includes any verifications conducted under this 

article and for the California Climate Action Registry; The Climate Registry; 

Climate Action Reserve; or other third-party verifications, validations, or audits 

conducted under impartiality provisions substantively equivalent to section 

95133, which may include third-party certification of environmental 

management systems to the ISO 14001 standard or third-party certification of 

energy management systems to the ISO 50001 standard. This limitation 

applies only to those third-party verifications, validations, or audits that include 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 172 February 2015 

the scope of activities or operations under the ARB identification number for 

the emissions data report. 

 The six year period begins on the date the reporting entity first contracts for 

any third-party verifications, validations, or audits under any protocols, 

including ARB verification services, for the scope of activities or operations 

under the ARB identification number for the emissions data report, and ends 

on the date the final verification statement is submitted. Even if these services 

are provided before the verification body or verifiers have received ARB 

accreditation, the six year period still begins when these services are 

contracted for, if accreditation is later received.

 The six year limit also applies to verification bodies and verifiers providing ARB 

or any other third-party verifications, validations, or audits that include the 

scope of activities or operations under the ARB identification number for the 

emissions data report and does not reset upon a change in reporting entity 

ownership or operational control. 

(3) If a reporting entity is required or elects to contract with another verification 

body or verifier(s), the reporting entity may contract verification services from 

the previous verification body or verifier(s) only after not using the previous 

verification body or verifier(s) for at least three years. 

NOTE: Authority cited: Sections 38510, 38530, 39600, 39601, 39607, 39607.4 and 

41511, Health and Safety Code. Reference: Sections 38530, 39600 and 41511, 

Health and Safety Code. 

§ 95131. Requirements for Verification Services. 

Verification services shall be subject to the following requirements. 

(a) Notice of Verification Services. After the Executive Officer has provided a 

determination that the potential for a conflict of interest is acceptable as specified in 

section 95133(f) and that verification services may proceed, the verification body 

shall submit a notice of verification services to ARB. The verification body may 

begin verification services for the reporting entity ten working days after the notice is 

received by the Executive Officer, or earlier if approved by the Executive Officer in 

writing. In the event that the conflict of interest statement and the notice of 

verification services are submitted together, verification services cannot begin until 

ten working days after the Executive Officer has deemed acceptable the potential 

for conflict of interest as specified in 95133(f). The notice shall include the following 

information: 

(1) A list of the staff who will be designated to provide verification services as a 

verification team, including the names of each designated staff member, the 

lead verifier, and all subcontractors, and a description of the roles and 

responsibilities each member will have during verification. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 173 February 2015 

(2) Documentation that the verification team has the skills required to provide 

verification services for the reporting facility. This shall include a 

demonstration that a verification team includes at least one member 

accredited as a sector specific verifier when required below: 

(A) For providing verification services to an electric power entity, a supplier of 

petroleum products or biofuels, a supplier of natural gas, natural gas 

liquids, or liquefied petroleum gas, or a supplier of carbon dioxide, at 

least one verification team member must be accredited by ARB as a 

transactions specialist; 

(B) For providing verification services to the operator of a petroleum refinery, 

hydrogen production unit or facility, or petroleum and natural gas system 

listed in section 95101(e), at least one verification team member must be 

accredited by ARB as an oil and gas systems specialist; 

(C) For providing verification services to the operator of a facility engaged in 

cement production, glass production, lime manufacturing, pulp and paper 

manufacturing, iron and steel production, nitric acid production, or lead 

production, at least one verification team member must be accredited by 

ARB as a process emissions specialist. 

(3) General information on the reporting entity, including: 

(A) The name of the reporting entity and the facilities and other locations that 

will be subject to verification services, reporting entity contact, address, 

telephone number, and e-mail address; 

(B) The industry sector and the North American Industry Classification 

System (NAICS) code for the reporting facility; 

(C) The date(s) of the on-site visit, if required in section 95130(a)(1), with 

facility address and contact information; 

(D) A brief description of expected verification services to be performed, 

including expected completion date. 

(4) If any of the information under section 95131(a)(1) or 95131(a)(3) changes 

after the notice is submitted to ARB, the verification body must notify ARB by 

submitting an updated conflict of interest self-evaluation form as soon as the 

change is made but at least five working days before the verification services 

start date. If any information submitted under section 95131(a)(1) or 

95131(a)(3) changes during the verification services, the verification body 

must notify ARB . In either instance, the conflict of interest must be 

reevaluated pursuant to section 95133(f) and ARB must approve any changes 

in writing. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 174 February 2015 

(b) Verification services shall include, but are not limited to, the following: 

(1) Verification Plan. The verification team shall develop a verification plan based 

on the following: 

(A) Information from the reporting entity. Such information shall include: 

1. Information to allow the verification team to develop a general 

understanding of facility or entity boundaries, operations, emissions 

sources, product data, and electricity or fuel transactions as 

applicable; 

2. Information regarding the training or qualifications of personnel 

involved in developing the emissions data report; 

3. Description of the specific methodologies used to quantify and report 

greenhouse gas emissions, product data, electricity and fuel 

transactions, and associated data as needed to develop the 

verification plan; 

4. Information about the data management system used to track 

greenhouse gas emissions, product data, electricity and fuel 

transactions, and associated data as needed to develop the 

verification plan; 

5. Previous verification reports. 

(B) Timing of verification services. Such information shall include: 

1. Dates of proposed meetings and interviews with reporting facility 

personnel; 

2. Dates of proposed site visits; 

3. Types of proposed document and data reviews; 

4. Expected date for completing verification services. 

(2) Planning Meetings with the Reporting Entity. The verification team shall 

discuss with the reporting entity the scope of the verification services and 

request any information and documents needed for initial verification services. 

The verification team shall review the documents submitted and plan and 

conduct a review of original documents and supporting data for the emissions 

data report. 

(3) Site Visits. At least one accredited verifier in the verification team, including 

the sector specific verifier, if applicable, shall at a minimum make one site visit, 

during each year full verification is required, to each facility for which an 

emissions data report is submitted. The verification team member(s) shall visit 

the headquarters or other location of central data management when the 

reporting entity is a retail provider, marketer, or fuel supplier. During the site 

visit, the verification team member(s) shall conduct the following: 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 175 February 2015 

(A) The verification team member(s) shall check that all sources specified in 

sections 95110 to 95123, and 95150 to 95157, as applicable to the 

reporting entity are identified appropriately. 

(B) The verification team member(s) shall review and understand the data 

management systems used by the reporting entity to track, quantify, and 

report greenhouse gas emissions and, when applicable, product data, 

and electricity and fuel transactions. The verification team member(s) 

shall evaluate the uncertainty and effectiveness of these systems. 

(C) The verification team shall carry out tasks that, in the professional 

judgment of the team, are needed in the verification process, including 

the following: 

1. Interviews with key personnel, such as process engineers and 

metering experts, as well as staff involved in compiling data and 

preparing the emissions data report; 

2. Making direct observations of equipment for data sources and 

equipment supplying data for sources determined in the sampling 

plan to be high risk; 

3. Assessing conformance with measurement accuracy, data capture, 

and missing data substitution requirements; 

4. Reviewing financial transactions to confirm fuel, feedstock, product 

data and electricity purchases and sales, and confirming the 

complete and accurate reporting of required data such as facility fuel 

suppliers, fuel quantities delivered, and if fuel was received directly 

from an interstate pipeline. 

(4) Review of Reporting Entity’s Operations, Product Data and Emissions. The 

verification team shall review facility operations to identify applicable 

greenhouse gas emissions sources and product data. This shall include a 

review of the emissions inventory and each type of emission source to ensure 

that all sources listed in sections 95110 to 95123 and sections 95150 to 95157 

of this article are properly included in the emissions data report. This shall 

also include a review of the product data to ensure that all product data listed 

in sections 95110 to 95123 and sections 95150 to 95157 of this article are 

included in the emissions data report as required by this article. The 

verification team shall also ensure that the reported current NAICS code(s) 

accurately represents the activities noted in Table 8-1 of the Cap-and-Trade 

Regulation, as applicable. 

(5) Other Reporting Entity Information. Reporting entities shall make available to 

the verification team all information and documentation used to calculate and 

report emissions, product data, fuels and electricity transactions, and other 

information required under this article, as applicable. 

(6) Electricity Importers and Exporters. The verification team shall review the 

GHG Inventory Program documentation required pursuant to section 

95105(d), electricity transaction records, including deliveries and receipts of 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 176 February 2015 

power via North American Electric Reliability Corporation (NERC) e-Tags, 

written power contracts, settlements data, and any other applicable 

information required to confirm reported electricity procurements and 

deliveries. 

(7) Sampling Plan. As part of confirming emissions data, product data, electricity 

transactions, or fuel transactions, the verification team shall develop a 

sampling plan that meets the following requirements: 

(A) The verification team shall develop a sampling plan based on a strategic 

analysis developed from document reviews and interviews to assess the 

likely nature, scale and complexity of the verification services for a 

reporting entity. The analysis shall review the inputs for the development 

of the submitted emissions data report, the rigor and appropriateness of 

data management systems, and the coordination within the reporting 

entity’s organization to manage the operation and maintenance of 

equipment and systems used to develop emissions data reports. 

(B) The verification team shall include in the sampling plan a ranking of 

emissions sources by amount of contribution to total CO2 equivalent 

emissions for the reporting entity, and a ranking of emissions sources 

with the largest calculation uncertainty. The verification team shall also 

include in the sampling plan a ranking of the product data by units 

specified in the appropriate section of this article and a ranking of the 

product data with the largest uncertainty. As applicable and deemed 

appropriate by the verification team, fuel and electricity transactions shall 

also be ranked or evaluated relative to the amount of fuel or power 

exchanged and uncertainties that may apply to data provided by the 

reporting entity. 

(C) The verification team shall include in the sampling plan a qualitative 

narrative of uncertainty risk assessment in the following areas as 

applicable under sections 95110 to 95123, 95129, and 95150 to 95157: 

1. Data acquisition equipment; 

2. Data sampling and frequency; 

3. Data processing and tracking; 

4. Emissions calculations; 

5. Product data; 

6. Data reporting; 

7. Management policies or practices in developing emissions data 

reports. 

(D) After completing the analyses required by sections 95131(b)(7)(A)-(C), 

the verification team shall include in the sampling plan a list which 

includes the following: 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 177 February 2015 

1. Emissions sources, product data, and/or transactions that will be 

targeted for document reviews, and data checks as specified in 

95131(b)(8), and an explanation of why they were chosen; 

2. Methods used to conduct data checks for each source, product data, 

or transaction; 

3. A summary of the information analyzed in the data checks and 

document reviews conducted for each emissions source, product 

data, or transaction targeted. 

The sampling plan list must be updated and finalized prior to the 

completion of verification services. The final sampling plan must describe 

in detail how the identified risks were addressed during the verification. 

(E) The verification team shall revise the sampling plan to describe tasks 

completed by the verification team as information becomes available and 

potential issues emerge with material misstatement or nonconformance 

with the requirements of this article. 

(F) The verification body shall retain the sampling plan in paper, electronic, 

or other format for a period of not less than ten years following the 

submission of each verification statement. The sampling plan shall be 

made available to ARB upon request. 

(G) The verification body shall retain all material received, reviewed, or 

generated to render a verification statement for a reporting entity for no 

less than ten years. The documentation must allow for a transparent 

review of how a verification body reached its conclusion in the verification 

statement. 

(8) Data Checks. To determine the reliability of the submitted emissions data 

report, the verification team shall use data checks. Such data checks shall 

focus on the largest and most uncertain estimates of emissions, product data 

and fuel and electricity transactions, and shall include the following: 

(A) The verification team shall use data checks to ensure that the appropriate 

methodologies and emission factors have been applied for the emissions 

sources, fuel and electricity transactions covered under sections 95110 to 

95123, 95129, and 95150 to 95158; 

(B) The verification team shall use data checks to ensure the accuracy of 

product data reported under sections 95110 to 95123, and 95150 to 

95158 of this article; 

(C) The verification team shall choose data checks for emissions sources, 

product data, and fuel and electricity transactions data, as applicable, 

based on their relative contributions to emissions and the associated 

risks of contributing to material misstatement or nonconformance, as 

indicated in the sampling plan; 

(D) The verification team shall use professional judgment in the number of 

data checks required for the team to conclude with reasonable assurance 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 178 February 2015 

whether the total reported covered emissions and covered product data 

are free of material misstatement. At a minimum, data checks must 

include the following: 

1. Tracing data in the emissions data report to its origin; 

2. Looking at the process for data compilation and collection; 

3. Recalculating emission estimates to check original calculations; 

4. Reviewing calculation methodologies used by the reporting entity for 

conformance with this article; and 

5. Reviewing meter and fuel analytical instrumentation measurement 

accuracy and calibration for consistency with the requirements of 

section 95103(k). 

(E) As applicable, the verification team shall review the following information 

when conducting data checks for product data: 

1. Product inventory and stock records; 

2. Product sales records and contracts; 

3. Onsite and offsite product delivery records; 

4. Purchase and delivery records for inputs to product(s); 

5. Product measurement records; and 

6. Other information or documentation that provides financial or direct 

measurement information about total product(s) reported. 

(F) The verification team is responsible for ensuring via data checks that 

there is reasonable assurance that the emissions data report conforms to 

the requirements of this article. In addition, and as applicable, the 

verifier’s review of conformance must confirm the following information is 

correctly reported: 

1. For facilities that combust natural gas, natural gas supplier customer 

account number, service account identification number, or other 

primary account identifier(s) reported pursuant to section 95115(k); 

2. For suppliers of natural gas, end-user names, account identification 

numbers, and natural gas deliveries in MMBtu, reported pursuant to 

section 95122(d)(4); 

3. Energy generation and disposition information reported pursuant to 

section 95112, if any of the following apply: 

a. The facility belongs to an industry sector listed in Table 8-1 of 

section 95870 of the cap-and-trade regulation; 

b. The facility is applying for legacy contract transition assistance 

under the cap-and-trade regulation; or 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 179 February 2015 

c. The facility is applying for the limited exemption of emissions from 

the production of qualified thermal output pursuant to the capand-trade regulation. 

(G) The verification team shall compare its own calculated results with the 

reported data in order to confirm the extent and impact of any omissions 

and errors. Any discrepancies must be investigated. The comparison of 

data checks must also include a narrative to indicate which sources, 

product data, and transactions were checked, the types and quantity of 

data that were evaluated for each source, product data, and transaction, 

the percentage of reported emissions covered by the data checks, the 

percentage of product data covered by the data checks, and any 

separate discrepancies that were identified in emission data or product 

data. 

(9) Emissions Data Report Modifications. As a result of data checks by the 

verification team and prior to completion of a verification statement(s), the 

reporting entity must fix all correctable errors that affect covered emissions, 

non-covered emissions, or covered product data in the submitted emissions 

data report, and submit a revised emissions data report to ARB. Failure to do 

so will result in an adverse verification statement. Failure to fix correctable 

errors that do not affect covered emissions, non-covered emissions, or 

covered product data represents a non-conformance with this article but does 

not, absent other errors, result in an adverse verification statement. The 

reporting entity shall maintain documentation to support any revisions made to 

the initial emissions data report. Documentation for all emissions data report 

submittals shall be retained by the reporting entity for ten years pursuant to 

section 95105. 

 The verification team shall use professional judgment in the determination of 

correctable errors as defined in section 95102(a), including whether 

differences are not errors but result from truncation or rounding or averaging. 

 If the verification team determines that the reported NAICS code(s) reviewed 

pursuant to section 95131(b)(4) is inaccurate, and the reporting entity does not 

submit a revised emissions data report to correct the current NAICS code(s), 

the result will be an adverse verification statement. 

 The verification team must document the source of any difference identified, 

including whether the difference results in a correctable error. 

(10) Findings. To verify that the emissions data report is free of material 

misstatements, the verification team shall make its own determination of 

emissions for checked sources and product data for checked data and shall 

determine whether there is reasonable assurance that the emissions data 

report does not contain a material misstatement in GHG emissions reported 

for the reporting entity, on a CO2 equivalent basis and/or a material 

misstatement in product data for the reporting entity, using the units required 

by the applicable parts of this article. To assess conformance with this article 

the verification team shall review the methods and factors used to develop the 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 180 February 2015 

emissions data report for adherence to the requirements of this article and 

ensure that other requirements of this article are met. 

(11) Log of Issues. The verification team must keep a log of any issues identified 

in the course of verification activities that may affect determinations of material 

misstatement and nonconformance. The issues log must identify the 

regulatory section related to the nonconformance, if applicable, and indicate if 

the issues were corrected by the reporting entity prior to completing the 

verification. Any other concerns that the verification team has with the 

preparation of the emissions data report, including with any de minimis method 

calculations, must be documented in the issues log. The log of issues must 

indicate whether each issue has a potential bearing on material misstatement, 

nonconformance, or both. 

(12) Material Misstatement Assessment. Assessments of material misstatement 

are conducted independently on total reported covered emissions and total 

reported covered product data (units from the applicable sections of this 

article). 

(A) In assessing whether an emissions data report contains a material 

misstatement, the verification team must separately determine whether 

the total reported covered emissions and total reported covered product 

data contain a material misstatement using the following equation(s): 

LMNOMPQ	MNNRN	 MSTUUTRPU$ = 	:VWTUONMXYPOTMU + #STUUTRPU + ZTUNMXRNQTP[	\]	100%

_RQY`	NMXRNQMa	ORbMNMa	MSTUUTRPU

 or 

LMNOMPQ	MNNRN	 XNRacOQ	aYQY$

= 	:VWTUONMXYPOTMU + #STUUTRPU + ZTUNMXRNQTP[	\]	100%

_RQY`	ORbMNMa	XNRacOQ	aYQY

Where: 

“Discrepancies” means any differences between the reported covered 

emissions or covered product data and the verifier’s review of covered 

emissions or covered product data for a data source or product data 

subject to data checks in section 95131(b)(8). 

“Omissions” means any covered emissions or covered product data the 

verifier concludes must be part of the emissions data report, but were not 

included by the reporting entity in the emissions data report. 

“Misreporting” means duplicate, incomplete or other covered emissions 

the verifier concludes should, or should not, be part of the emissions data 

report or duplicate or other product data the verifier concludes should not 

be part of the emissions data report. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 181 February 2015 

“Total reported covered emissions or covered product data” means the 

total annual reporting entity covered emissions or total reported covered 

product data for which the verifier is conducting a material misstatement 

assessment. 

(B) When evaluating material misstatement, verifiers must deem correctly 

substituted missing data to be accurate, regardless of the amount of 

missing data. 

(C) The omissions variable described in section 95131(b)(12)(A) does not 

apply to excluded covered product data as described in section 95103(l), 

such that excluded covered product data is not considered in the material 

misstatement assessment. 

(13) Review of Missing Data Substitution. If a source selected for a data check 

was affected by a loss of data used to calculate GHG emissions for the data 

year: 

(A) The verification team shall confirm that the reported emissions for that 

source were calculated using the applicable missing data procedures, or 

that an approved interim data collection procedure was used for the 

source. 

(B) If 20 percent or less of any single data elements used to calculate 

emissions are missing, and emissions are correctly calculated using the 

missing data requirements in sections 95110 to 95123, 95129, and 95150 

to 95158 these emissions will be considered accurate and as meeting the 

reporting requirements for that source. 

(C) If greater than 20 percent of any single data element used to calculate 

emissions are missing or any combination of data elements are missing 

that would result in more than 5% of a facility’s emissions being 

calculated using missing data requirements in sections 95110 to 95123, 

95129, and 95150 to 95158, the verifier must include a finding of nonconformance with the required emissions calculation methodology as part 

of the verification statement. 

(D) The verifier must note the date, time and source of any missing data 

substitutions discovered during the course of verification in the 

verification report. 

(14) Review of Product Data. The verifier’s review of product data must include the 

following, where applicable. 

(A) Verifiers must confirm that data substitutions were not used for covered 

product data. 

(B) For product data reported by operators of petroleum refineries subject to 

section 95113: 

1. Verifiers must evaluate conformance and material misstatement for 

2013 primary refinery products data reported in 2014. For the 2014 

data year, the total on-site production quantity of primary refinery 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 182 February 2015 

product for a refinery that has not reported a Solomon EII value 

pursuant to 95113(l)(4) (“non-EII refinery”) is covered product data 

and verifiers must evaluate conformance and material misstatement. 

For non-EII refineries in the 2014 data year, the quantity of each 

primary refinery product and blending component produced 

elsewhere and brought on-site and that is used for a purpose other 

than blending into a primary refinery product is not covered product 

data and is not subject to material misstatement. For the 2014 data 

year and subsequent years, the total on-site production quantity of 

primary refinery product for a refinery that has reported a Solomon 

EII value pursuant to 95113(l)(4) (“EII refinery”), and the quantities of 

primary refinery product and blending component produced 

elsewhere and brought on-site by an EII refinery, are not covered 

product data and verifiers only evaluate for conformance. For the 

2015 data year and subsequent years, primary refinery product data 

are not covered product data for any refinery and verifiers only 

evaluate for conformance. 

2. Verifiers must evaluate conformance for Solomon Energy Intensity 

Index (EII), if applicable, for all data years. 

3. Verifiers must separately evaluate conformance and separately 

assess material misstatement for the total facility complexity 

weighted barrel beginning with 2013 data reported in 2014 

4. Verifiers must submit two product data verification statements for 

2013 and 2014 data reports: 

a. A verification statement that includes the evaluation of primary 

refinery products and the Solomon EII, as applicable, as well as 

non-covered product data; 

b. A verification statement for the evaluation of complexity weighted 

barrel. 

5. Beginning with 2015 data reported in 2016, only the verification 

statement for the complexity weighted barrel is submitted. 

Evaluation of other product data conformance is included in the 

verification statement for complexity weighted barrel. 

(c) Completion of verification services must include: 

(1) Verification Statement. Upon completion of the verification services specified 

in section 95131(b), the verification body shall complete an emissions data 

verification statement and product data verification statement(s), and provide 

those statements to the reporting entity and ARB by the applicable verification 

deadline specified in section 95103(f). Before the emissions data verification 

statement and product data verification statement(s) are completed, the 

verification body shall have the verification services and findings of the 

verification team independently reviewed within the verification body by an 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 183 February 2015 

independent reviewer who is a lead verifier not involved in services for that 

reporting entity during that year. 

(2) Independent Review. The independent reviewer shall serve as a final check 

on the verification team’s work to identify any significant concerns, including: 

(A) Errors in planning, 

(B) Errors in data sampling, and 

(C) Errors in judgment by the verification team that are related to the draft 

verification statement. 

The independent reviewer must maintain independence from the verification 

services by not making specific recommendations about how the verification 

services should be conducted. The independent reviewer will review 

documents applicable to the verification services provided, and identify any 

failure to comply with requirements of this article or with the verification body’s 

internal policies and procedures for providing verification services. The 

independent reviewer must concur with the verification findings before the 

verification statement(s) can be issued. 

(3) Completion of Findings and Verification Report. The verification body is 

required to provide each reporting entity with the following: 

(A) A detailed verification report, which shall at a minimum include: 

1. A detailed description of the facility or entity including all emissions 

and product data sources and boundaries; 

2. A detailed description of data acquisition, tracking and emission 

calculation/product data systems; 

3. The verification plan; 

4. The detailed comparison of the data checks conducted during 

verification services for emissions and product data sources; 

5. The log of issues identified in the course of verification activities and 

their resolution; 

6. Any qualifying comments on findings during verification services; and 

7. The calculation performed in section 95131(b)(12)(A) for emissions 

and product data. 

The verification report shall be submitted to the reporting entity at the 

same time as or before the final emissions data verification statement 

and product data verification statement(s) are submitted to ARB. The 

detailed verification report shall be made available to ARB upon request. 

(B) The verification team shall have a final discussion with the reporting entity 

explaining its findings, and notify the reporting entity of any unresolved 

issues noted in the issues log before the verification statement(s) are 

finalized. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 184 February 2015 

(C) The verification body shall provide the verification statement(s) to the 

reporting entity and the ARB, attesting whether the verification body has 

found the submitted emissions data report to be free of material 

misstatements, and whether the emissions data report is in conformance 

with the requirements of this article. For every qualified positive 

verification statement, the verification body shall explain the nonconformances contained within the emissions data report and shall cite 

the section(s) in this article that corresponds to the non-conformance and 

why the non-conformances do not result in a material misstatement. For 

every adverse verification statement, the verification body must explain 

all non-conformances and material misstatements leading to the adverse 

verification statement and shall cite the section(s) in this article that 

corresponds to the non-conformance(s) and material misstatements. 

(D) The lead verifier in the verification team shall attest that the verification 

team has carried out all verification services as required by this article, 

and the lead verifier who has conducted the independent review of 

verification services and findings shall attest to his or her independent 

review on behalf of the verification body and his or her concurrence with 

the verification findings. 

1. The lead verifier must attest in the verification statement, in writing, to 

ARB as follows: 

“I certify under penalty of perjury under the laws of the State of 

California that the verification team has carried out all verification 

services as required by this article.” 

2. The lead verifier independent reviewer who has conducted the 

independent review of verification services and findings must attest in 

the verification statement, in writing, to ARB as follows: 

“I certify under penalty of perjury under the laws of the State of 

California that I have conducted an independent review of the 

verification services and findings on behalf of the verification body as 

required by this article and that the findings are true, accurate, and 

complete.” 

(4) Adverse Verification Statement and Petition Process. Prior to the verification 

body providing an adverse verification statement for emissions or product 

data, or both, to ARB, the verification body shall notify the reporting entity and 

the reporting entity shall be provided at least ten working days to modify the 

emissions data report to correct any material misstatements or 

nonconformance found by the verification team. The verification body must 

also provide notice to ARB of the potential for an adverse verification 

statement(s) at the same time it notifies the reporting entity. The modified 

report and verification statement(s) must be submitted to ARB before the 

verification deadline, even if the reporting entity makes a request to the 

Executive Officer as provided below in section 95131(c)(4)(A). 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 185 February 2015 

(A) If the reporting entity and the verification body cannot reach agreement 

on modifications to the emissions data report that result in a positive 

verification statement or qualified positive verification statement for the 

emissions or product data because of a disagreement on the 

requirements of this article, the reporting entity may petition the ARB 

Executive Officer before the verification deadline and before the 

verification statement is submitted to make a final decision as to the 

verifiability of the submitted emissions data report. The reporting entity 

may petition either emissions or product data, or both. At the same time 

that the reporting entity petitions the Executive Officer, the reporting entity 

must submit all information it believes is necessary for the ARB Executive 

Officer to make a final decision. 

(B) The Executive Officer shall make a final decision no later than October 10 

following the submission of a petition pursuant to section 95131(c)(4)(A). 

If at any point ARB requests information from the verification body or the 

reporting entity, the information must be submitted to ARB within five 

working days. ARB will notify both the reporting entity and the verification 

body of its determination, which may also include an assigned emissions 

level calculated pursuant to section 95131(c)(5), if applicable. 

(5) Assigned Emissions Level. When a reporting entity fails to receive a 

verification statement for a data year by the applicable deadline or receives an 

adverse emissions data verification statement, the Executive Officer shall 

develop an assigned emissions level for the data year for the reporting entity. 

Within five working days of a written request by the Executive Officer, the 

verification body (if applicable) shall provide any available verification services 

information or correspondence related to the emissions data. Within five 

working days of a request by the Executive Officer, the reporting entity shall 

provide the data that is required to calculate GHG emissions for the entity 

according to the requirements of this article, the preliminary or final detailed 

verification report prepared by the verification body (if applicable), and other 

information requested by the Executive Officer, including the operating days 

and hours of the reporting entity during the data year. The reporting entity 

shall also make available personnel who can assist the Executive Officer’s 

determination of an assigned emissions level for the data year. 

(A) In preparing the assigned emissions level for the reporting entity, the 

Executive Officer shall consider at a minimum the following information: 

1. The number, types and days and hours of operation of the sources 

operated by the reporting entity for the emissions data year; 

2. Any previous emissions data reports submitted by the reporting entity 

and verification statements rendered for those reports; 

3. The potential maximum fuel and process material input and output 

capacities for the reporting entity’s emissions sources during 

operating hours; 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 186 February 2015 

4. For electric power entities, wholesale and retail transactions that 

would affect an assigned emissions level, for the applicable data year 

and for previous years; 

5. Emissions, electricity transactions, fuel use, or product output 

information reported to ARB or other State, federal, or local agencies. 

(B) In preparing the assigned emissions level for the reporting entity, the 

Executive Officer may use the following methods, as applicable: 

1. The sector specific calculation methodologies in this article; 

2. In the event of missing data, the Executive Officer will rely on the 

missing data provisions of this article; and 

3. Any information reported under this article for this data year and past 

years. 

(C) The Executive Officer shall assign the emissions level for the reporting 

entity using the best information available, including the information in 

section 95131(c)(5)(A) and methods in section 95131(c)(5)(B), as 

applicable. The Executive Officer shall include an assigned emissions 

level in the decision made pursuant to section 95131(c)(4)(B), if 

applicable. 

(d) Upon provision of the verification statement, or statements, if applicable, to ARB, 

the emissions data report shall be considered final. No changes shall be made to 

the report as submitted to ARB, notwithstanding the requirements of 40 CFR 

§98.3(h), and all verification requirements of this article shall be considered 

complete except in the circumstance specified in section 95131(e). 

(e) If the Executive Officer finds a high level of conflict of interest existed between a 

verification body and a reporting entity, an error is identified, or an emissions data 

report that received a positive or qualified positive verification statement fails an 

ARB audit, the Executive Officer may set aside the positive or qualified positive 

verification statement issued by the verification body, and require the reporting 

entity to have the emissions data report re-verified by a different verification body 

within 90 days. This paragraph applies to verification statements for emissions and 

product data. In instances where an error to an emissions data report is identified 

and determined by ARB to not affect the emissions or covered product data, the 

change may be made without a set aside of the positive or qualified positive 

verification statement. 

(f) Upon request by the Executive Officer, the reporting entity shall provide the data 

used to generate an emissions data report, including all data available to a verifier 

in the conduct of verification services, within 20 working days. 

(g) Upon request of the Executive Officer, the verification body shall provide ARB the 

full verification report given to the reporting entity, as well as the sampling plan, 

contracts for verification services, and any other supporting documents and 

calculations, within 20 working days. 

(h) Upon written notification by the Executive Officer, the verification body shall make 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 187 February 2015 

itself and its personnel available for an ARB audit. 

(i) Verifying Biomass-derived Fuels. In the absence of certification of the biomassderived fuel by an accredited certifier of biomass-derived fuels, the verification body 

is subject to the requirements of subarticle 4 of this article as modified below when 

verifying biomass-derived fuel:

(1) General biomass-derived fuel verification requirements. The following 

requirements apply to the biomass-derived fuel verification: 

(A) Annual Verification. Biomass-derived fuel is subject to annual verification 

as specified in section 95103(f). 

(B) Verification Services for Biomass-derived Fuels. When a reporting entity 

reports that biomass-derived fuels are used, the biomass-derived fuels 

must be considered when providing all verification services required 

under section 95131(b) of this article. The verification team must: 

1. Review the reporting entity’s reported biomass-derived fuel 

emissions to ensure the biomass-derived fuels are properly listed in 

the emissions data report as required in section 95103(j) of this 

article and sections 95852.1.1 and 95852.2 of the cap-and-trade 

regulation. 

2. Conduct separate data checks that are consistent with the 

requirements in 95131(i)(2)(D) for the fuel type being verified using 

the following documentation, as appropriate: the invoice, nomination, 

scheduling, storage, in-kind fuel purchase, allocation, transportation 

and balancing reports or other documents used as evidence of the 

fuel delivery. 

a. The reporting entity may arrange for the documentation to be 

supplied directly to the verifier if there are confidentiality issues 

that would prevent these documents from being made available to 

the reporting entity. 

(C) Completion of Verification Services for Biomass-derived Fuels. 

1. All information used for the verification of biomass-derived fuels must 

be included in the independent review as required in section 

95131(c)(2) of this article. 

2. Conformance for biomass-derived fuels is evaluated against the 

requirements of this article and sections 95852.1.1 and 95852.2 of 

the cap-and-trade regulation. 

3. Reported carbon dioxide emissions from biomass-derived fuels are 

considered an omission in the evaluation for material misstatement 

when: 

a. The fuel does not conform with sections 95852.1.1 and 95852.2 of 

the cap-and-trade regulation and 

b. The emissions are listed as exempt biomass-derived CO2. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 188 February 2015 

(2) Specific biomass-derived fuel verification requirements. 

(A) For urban, agricultural and forest derived wood and wood waste, the 

verifier must determine the reporting entity met the requirements of 

section 95103(j). 

(B) For biodiesel and fuel ethanol, the verifier must determine the reporting 

entity met the requirements of section 95103(j) and the following 

requirements: 

1. At combustion sources that purchase biomass-derived fuels, verify 

records to demonstrate that volume purchased equals or exceeds 

volume reported. 

2. At combustion sources that produce their own fuel, verify: 

a. that raw material is sufficient to produce the quantity of fuel 

reported; 

b. that the facility has the ability to produce the biomass-derived fuel 

reported; 

c. that the emissions from the fuel are accurately reported and do 

not lead to the underreporting of fossil fuel emissions. 

(C) For municipal solid waste and tires, the verifier must determine the 

reporting entity met the requirements of section 95103(j). 

(D) For biomethane and biogas, the verifier must: 

1. Examine all nomination, invoice, scheduling, allocation, 

transportation, storage, in-kind fuel purchase and balancing reports 

from the producer to the reporting entity and have reasonable 

assurance that the reporting entity is receiving the identified fuel; 

2. Determine a contract is in place for the purchase of biogas or 

biomethane that meets all requirements of sections 95852.1.1 and 

95852.2 of the cap-and-trade regulation and that no fossil-derived 

fuel is used to supplement the biomass-derived fuel deliveries except 

for documented fuel purchases to avoid loss of metered volumes in 

connection with the transportation of the biomethane to the reporting 

entity; 

3. Ensure any discrepancies in the fuel volumes, heat values and/or 

energies will be carried over into the evaluation of material 

misstatement for the reporting entity; 

(3) Assessment. If the reporting entity is unable to demonstrate that the biomassderived fuel is consistent with the requirements in sections 95852.1.1 and 

95852.2 of the cap-and-trade regulation, the emission data report must be 

revised to list these biomass CO2 emissions as non-exempt biomass-derived 

CO2. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 189 February 2015 

NOTE: Authority cited: Sections 38510, 38530, 39600, 39601, 39607, 39607.4 and 

41511, Health and Safety Code. Reference: Sections 38530, 39600 and 41511, 

Health and Safety Code. 

§ 95132. Accreditation Requirements for Verification Bodies, Lead Verifiers, 

and Verifiers of Emissions Data Reports and Offset Project Data 

Reports. 

(a) The accreditation requirements specified in this subarticle shall apply to all 

verification bodies, lead verifiers, and verifiers that wish to provide verification 

services under this article and under the cap-and-trade regulation. 

(b) The Executive Officer may issue accreditation to verification bodies, lead verifiers, 

and verifiers that meet the requirements specified in this section. 

(1) Verification Body Accreditation Application. To apply for accreditation as a 

verification body, the applicant shall submit the following information to the 

Executive Officer: 

(A) A list of all verification staff and a description of their duties and 

qualifications, including ARB accredited verifiers on staff. The applicant 

shall demonstrate staff qualifications by listing each individual’s 

education, experience, professional licenses, and other pertinent 

information. 

1. A verification body shall employ and retain at least two verifiers that 

have been accredited as lead verifiers, as specified in section 

95132(b)(2). 

2. A verification body shall employ and retain at least five total full-time 

staff. 

(B) The applicant shall provide a list of any judicial proceedings, enforcement 

actions, or administrative actions filed against the body within the 

previous 5 years, with an explanation as to the nature of the proceedings. 

(C) The applicant shall provide documentation that the proposed verification 

body maintains a minimum of four million U.S. dollars of professional 

liability insurance and must maintain this insurance for three years after 

completing verification services. Neither general nor umbrella liability 

policies can be used for the professional liability insurance minimum for 

the purposes of this provision. 

(D) The applicant shall provide a demonstration that the body has policies 

and mechanisms in place to prevent conflicts of interest and to identify 

and resolve potential conflict of interest situations if they arise. The 

applicant shall provide the following information: 

1. Identification of services provided by the verification body, the 

industries that the body serves, and the locations where those 

services are provided; 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 190 February 2015 

2. A detailed organizational chart that includes the verification body, its 

management structure, and any related entities; 

3. The verification body’s internal conflict of interest policy that identifies 

activities and limits to monetary or non-monetary gifts that apply to all 

employees. 

(E) The applicant shall provide a demonstration that the body has procedures 

or policies to support staff technical training as it relates to verification. 

This training shall include participating in ARB verifier training on an 

ongoing basis. 

(F) The verification body shall notify ARB within 30 days of when it no longer 

meets the requirements for accreditation as a verification body in section 

95132(b)(1). The verification body may request that the Executive Officer 

provide additional time to hire additional staff to meet the requirements of 

this section. 

(G) If the applicant is a California air pollution control district or air quality 

management district, the requirements of section 95132(b)(1)(A)(2) and 

95132(b)(1)(B)-(D) do not apply, except that the applicant shall provide a 

demonstration that the district has policies and mechanisms in place to 

prevent conflicts of interest and resolve potential conflict of interest 

situations if they arise. 

(2) Lead Verifier Accreditation Application. To apply for accreditation as a lead 

verifier, the applicant shall submit documentation to the Executive Officer that 

provides the evidence specified in section 95132(b)(2)(A), and section 

95132(b)(2)(B), or (C): 

(A) Evidence that the applicant meets the criteria in 95132(b)(3); and, 

(B) Evidence that the applicant has been an ARB accredited verifier for two 

continuous years and has worked as a verifier in at least three completed 

verifications under the supervision of an ARB accredited lead verifier, 

with evidence of favorable assessment by ARB for services performed; 

or, 

(C) Evidence that at the time of the verification training examination, the 

applicant has worked as a project manager or lead person for not less 

than four years, of which two may be graduate level work: 

1. In the development of GHG or other air emissions inventories; or, 

2. As a lead environmental data or financial auditor in the private sector. 

(3) Verifier Accreditation Application. To apply for accreditation as a verifier, the 

applicant shall submit the following documentation to the Executive Officer: 

(A) Evidence demonstrating the minimum education background required to 

act as a verifier for ARB. Minimum education background means that the 

applicant has either: 

1. A bachelors level college degree or equivalent in science, 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 191 February 2015 

technology, business, statistics, mathematics, environmental policy, 

economics, or financial auditing; or 

2. Evidence demonstrating the completion of significant and relevant 

work experience or other personal development activities that have 

provided the applicant with the communication, technical and 

analytical skills necessary to conduct verification. 

(B) Evidence demonstrating sufficient workplace experience to act as a 

verifier, including evidence that the applicant has a minimum of two years 

of full-time work experience in a professional role involved in emissions 

data management, emissions technology, emissions inventories, 

environmental auditing, or other technical skills necessary to conduct 

verification. 

(4) The applicant must take an ARB approved general verification training and 

receive a passing score of greater than an unweighted 70% on an exit 

examination. If the applicant does not pass the exam after the training, they 

may retake the exam a second time. Only one retake of the examination is 

allowed before the applicant is required to retake the ARB approved general 

verification training course. Training under the previous version of the 

regulation does not qualify an applicant to retake an exam under this version 

without first taking the training for this revised regulation. 

(5) Sector Specific and Offset Project Specific Verifiers. 

(A) Sector Specific Verifier. The applicant seeking to be accredited as a 

sector specific verifier as specified in section 95131(a)(2) must, in 

addition to meeting the requirements for accredited lead verifier or verifier 

qualification, have at least two years of professional experience related to 

the sector in which they are seeking accreditation, take ARB sector 

specific verification training and receive a passing score of greater than 

an unweighted 70% on an exit examination. If the applicant does not 

pass the exam after the training, they may retake the exam a second 

time. Only one retake of the examination is allowed before the applicant 

is required to retake the ARB approved sector specific verification 

training. 

(B) Offset Project Specific Verifier. The applicant seeking to be accredited as 

an offset project specific verifier as specified in the cap-and-trade 

regulation must, in addition to meeting the requirements for accredited 

lead verifier or verifier qualification, meet one of the following 

requirements: 

1. Have at least two years of professional experience related to 

developing emission inventories, conducting technical analyses, or 

environmental audits of the offset project type, and take general ARB 

offset verification training and ARB offset project specific verification 

training for an offset project type, and receive a passing score of 

greater than an unweighted 70% on an exit examination. If the 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 192 February 2015 

applicant does not pass the exam after the training, they may retake 

the exam a second time. Only one retake of the examination is 

allowed before the applicant is required to retake the applicable ARBapproved offset verification training; or, 

2. Be a verifier in good standing for the Climate Action Reserve prior to 

October 28, 2011, taken Climate Action Reserve project specific 

verifier training, have performed at least two project verifications for a 

project type by October 28, 2011, and have taken general ARB offset 

verification training, and receive a passing score of greater than an 

unweighted 70% on an exit examination. If the applicant does not 

pass the exam after the training, they may retake the exam a second 

time. Only one retake of the examination is allowed before the 

applicant is required to retake the ARB approved general ARB offset 

verification training and offset project specific verification training. 

(6) Nothing in this section shall be construed as preventing the Executive Officer 

from requesting additional information or documentation from an applicant 

after receipt of the application for accreditation as a verification body, lead 

verifier, or verifier, or from seeking additional information from other persons or 

entities regarding the applicant’s fitness for qualification. 

(c) ARB Accreditation. 

(1) Within 90 days of receiving an application for accreditation as a verification 

body, lead verifier, verifier, sector specific verifier, or offset project specific 

verifier, the Executive Officer shall inform the applicant in writing either that the 

application is complete or that additional specific information is required to 

make the application complete. 

(2) Upon a finding by the Executive Officer that an application for accreditation as 

a verification body, verifier, lead verifier, sector specific verifier, or offset 

project specific verifier is complete, meets all applicable regulatory 

requirements, and passes a performance review as defined in section 

95102(a), the prescreening requirement is met and the applicant will be 

eligible to attend the verification training required by this section. 

(3) Within 45 days following completion of the application process and all 

applicable training and examination requirements, the Executive Officer shall 

act to issue an Executive Order to grant or withhold accreditation for the 

verification body, lead verifier, sector specific verifier, offset project specific 

verifier or verifier. 

(4) The Executive Order for accreditation is valid for a period of three years, 

whereupon the applicant may re-apply for accreditation as a verifier, lead 

verifier, sector specific verifier, offset project specific verifier, or verification 

body if the applicant has not been subject to ARB enforcement action under 

this article. All ARB approved general, sector specific, or offset project specific 

verification training and examination requirements applicable at the time of reapplication must be met for accreditation to be renewed by the Executive 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 193 February 2015 

Officer. In addition, the performance review requirement set forth in section 

95132(c)(2) must be met for accreditation to be renewed by the Executive 

Officer. 

(5) All verification body requirements in section 95132(b)(1) must be met for the 

Executive Officer to renew the verification body accreditation. 

(6) The Executive Officer and the applicant may mutually agree to longer time 

periods than those specified in subsections 95132(c)(1) or 95132(c)(3), and 

the applicant may submit additional supporting documentation before a 

decision has been made by the Executive Officer. 

(7) Within 15 working days of being notified of any corrective action in another 

voluntary or mandatory GHG program, an ARB accredited verification body, 

lead verifier, sector specific verifier, offset project specific verifier, or verifier 

shall provide written notice to the Executive Officer of the corrective action. 

That notification shall include reasons for the corrective action and the type of 

corrective action. The verification body or verifier must provide additional 

information to the Executive Officer upon request. 

(8) Verifiers shall take ARB approved training to continue to provide verification 

services after January 1, 2012. The verifier must receive a passing score of 

greater than an unweighted 70% on the exit examination. 

(d) Modification, Suspension, or Revocation of an Executive Order Approving a 

Verification Body, Lead Verifier, or Verifier, and Voluntary Withdrawal from the 

Accreditation Program. The Executive Officer may review and, for good cause, 

including any violation of subarticle 4 of this article or any similar action in an 

analogous GHG system, modify, suspend, or revoke an Executive Order providing 

accreditation to a verification body, lead verifier, or verifier. The Executive Officer 

shall not revoke an Executive Order without affording the verification body, lead 

verifier, or verifier the opportunity for a hearing in accordance with the procedures 

specified in title 17, California Code of Regulations, section 60055.1 et seq. 

(1) During suspension or revocation proceedings, the verification body, lead 

verifier, or verifier may not continue to provide verification services. 

(2) Within five working days of suspension or revocation of accreditation, a 

verification body must notify all reporting entities, offset project operators, or 

authorized project designees for whom it is providing verification services, or 

has provided verification services within the past 6 months of its suspension or 

revocation of accreditation. 

(3) A reporting entity, offset project operator, or authorized project designee who 

has been notified by a verification body of a suspended or revoked 

accreditation must contract with a new verification body for verification 

services. 

(4) An accredited verification body or individual verifier may request to voluntarily 

withdraw its accreditation by providing a written notice to the Executive Officer 

requesting such withdrawal. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 194 February 2015 

(e) Subcontracting. The following requirements shall apply to any verification body that 

elects to subcontract a portion of verification services. 

(1) All subcontractors must be accredited by ARB to perform the verification 

services for which the subcontractor has been engaged by the verification 

body. 

(2) The verification body must assume full responsibility for verification services 

performed by subcontractor verifiers. 

(3) A verification body shall not use subcontractors to meet the minimum staff 

total or lead verifier requirements as specified in section 95132(b)(1)(A)1. and 

section 95132(b)(1)(A)2. 

(4) A verifier acting as a subcontractor to another verification body shall not 

further subcontract or outsource verification services for a reporting entity. 

(5) A verification body that engages a subcontractor shall be responsible for 

demonstrating an acceptable level of conflict of interest, as provided in section 

95133, between its subcontractor and the reporting entity for which it will 

provide verification services. 

(6) A verification body may not use a subcontractor as the independent reviewer. 

NOTE: Authority cited: Sections 38510, 38530, 39600, 39601, 39607, 39607.4 and 

41511, Health and Safety Code. Reference: Sections 38530, 39600 and 41511, Health 

and Safety Code. 

§ 95133. Conflict of Interest Requirements for Verification Bodies. 

(a) The conflict of interest provisions of this section shall apply to verification bodies, 

lead verifiers, and verifiers accredited by ARB to perform verification services for 

reporting entities. Any individual person or company that is hired by a reporting 

entity to contract with a verification body on behalf of the reporting entity is subject 

to the conflict of interest assessment in this article. In such instances, the 

verification body must assess the potential conflict of interest between itself and the 

contracting entity as well as between itself and the reporting entity, and must also 

address the potential conflict of interest between the contracting entity and the 

reporting entity, including a written assessment provided and signed by the 

contracting entity. 

(b) The potential for a conflict of interest must be deemed to be high where: 

(1) The verification body and reporting entity share any management staff or 

board of directors membership, or any of the senior management staff of the 

reporting entity have been employed by the verification body, or vice versa, 

within the previous five years; or 

(2) Any employee of the verification body, or any employee of a related entity, or a 

subcontractor who is a member of the verification team has provided to the 

reporting entity any of the following services within the previous five years: 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 195 February 2015 

(A) Designing, developing, implementing, reviewing, or maintaining an 

inventory or information or data management system for facility air 

emissions, or, where applicable, electricity or fuel transactions, unless the 

review was part of providing greenhouse gas verification services; 

(B) Developing greenhouse gas emission factors or other greenhouse gasrelated engineering analysis, including developing or reviewing a 

California Environmental Quality Act (CEQA) greenhouse gas analysis 

that includes facility specific information; 

(C) Designing energy efficiency, renewable power, or other projects which 

explicitly identify greenhouse gas reductions as a benefit; 

(D) Designing, developing, implementing, conducting an internal audit, 

consulting, or maintaining a GHG emissions reduction or GHG removal 

offset project as defined in the cap-and-trade regulation; 

(E) Owning, buying, selling, trading, or retiring shares, stocks, or emissions 

reduction credits from an offset project that was developed by or resulting 

reduction credits are owned by the reporting entity; 

(F) Dealing in or being a promoter of credits on behalf of an offset project 

operator or authorized project designee where the credits are owned by 

or the offset project was developed by the reporting entity; 

(G) Preparing or producing greenhouse gas-related manuals, handbooks, or 

procedures specifically for the reporting entity; 

(H) Appraisal services of carbon or greenhouse gas liabilities or assets; 

(I) Brokering in, advising on, or assisting in any way in carbon or 

greenhouse gas-related markets; 

(J) Directly managing any health, environment or safety functions for the 

reporting entity; 

(K) Bookkeeping or other services related to accounting records or financial 

statements; 

(L) Any service related to development of information systems, including 

consulting on the development of environmental management systems, 

such as those conforming to ISO 14001 or energy management systems 

such as those conforming to ISO 50001, unless those systems will not be 

part of the verification process; 

(M) Appraisal and valuation services, both tangible and intangible; 

(N) Fairness opinions and contribution-in-kind reports in which the verification 

body has provided its opinion on the adequacy of consideration in a 

transaction, unless the resulting services will not be part of the verification 

process; 

(O) Any actuarially oriented advisory service involving the determination of 

amounts recorded in financial statements and related accounts; 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 196 February 2015 

(P) Any internal audit service that has been outsourced by the reporting 

entity or offset project operator that relates to the reporting entity’s 

internal accounting controls, financial systems or financial statements, 

unless the result of those services will not be part of the verification 

process; 

(Q) Acting as a broker-dealer (registered or unregistered), promoter or 

underwriter on behalf of the reporting entity; 

(R) Any legal services; 

(S) Expert services to the reporting entity, a trade or membership group to 

which the reporting entity belongs, or a legal representative for the 

purpose of advocating the reporting entity’s interests in litigation or in a 

regulatory or administrative proceeding or investigation. 

(T) Verification services that are not conducted in accordance with, or 

equivalent to, section 95133 requirements, unless the systems and data 

reviewed during those services, as well as the result of those services, 

will not be part of the verification process. 

“Member” for the purposes of this section means any employee or 

subcontractor of the verification body or related entities of the verification 

body. “Member” also includes any individual with majority equity share in 

the verification body or its related entities. “Related entity” for the 

purposes of this section means any direct parent company, direct 

subsidiary, or sister company. 

(3) The potential for conflict of interest shall be deemed to be high when any staff 

member of the verification body provides any type of non-monetary incentive 

to a reporting entity to secure a verification services contract. 

(4) The potential for a conflict of interest shall also be deemed to be high where 

any staff member of the verification body has provided verification services for 

the reporting entity except within the time periods in which the reporting entity 

is allowed to use the same verification body as specified in section 95130(a). 

(c) The potential for a conflict of interest shall be deemed to be low where the following 

conditions are met: 

(1) No potential for a high conflict of interest is found pursuant to section 

95133(b); and 

(2) Any services provided by any member of the verification body or verification 

team to the reporting entity, within the last five years, are valued at less than 

20 percent of the fee for the proposed verification services. Any verification 

conducted in accordance with, or equivalent to, section 95133 provided by the 

verification body or verification team outside the jurisdiction of ARB is 

excluded from this financial assessment but must be disclosed to ARB in 

accordance with section 95133(e). 

(3) Non-ARB verification services are deemed to be low risk if those services are 

conducted in accordance with, or equivalent to, section 95133, including, but 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 197 February 2015 

not limited to, third-party certification of environmental management system 

under ISO 14001 or energy management system under 50001 standards. 

(d) The potential for a conflict of interest shall be deemed to be medium where the 

potential for a conflict of interest is not deemed to be either high or low as specified 

in sections 95133(b) and 95133(c). The potential for conflict of interest will also be 

deemed to be medium where there are any instances of personal or familial 

relationships between the members of the verification body and management or 

staff of the reporting entity, and when a conflict of interest self-evaluation is 

submitted pursuant to section 95133(h). 

(1) If a verification body identifies a medium potential for conflict of interest and 

intends to provide verification services for the reporting entity, the verification 

body shall submit, in addition to the submittal requirements specified in section 

95133(e), a plan to avoid, neutralize, or mitigate the potential conflict of 

interest situation. At a minimum, the conflict of interest mitigation plan shall 

include: 

(A) A demonstration that any individuals with potential conflicts have been 

removed and insulated from the project. 

(B) An explanation of any changes to the organizational structure or 

verification body to remove the potential conflict of interest. A 

demonstration that any unit with potential conflicts has been divested or 

moved into an independent entity or any subcontractor with potential 

conflicts has been removed. 

(C) Any other circumstance that specifically addresses other sources for 

potential conflict of interest. 

(2) As provided in section 95133(f)(4), the Executive Officer shall evaluate the 

conflict of interest mitigation plan and determine whether verification services 

may proceed. 

(e) Conflict of Interest Submittal Requirements for Accredited Verification Bodies. 

(1) Before the start of any work related to providing verification services to a 

reporting entity, a verification body must first be authorized in writing by the 

Executive Officer to provide verification services. To obtain authorization the 

verification body shall submit to the Executive Officer a self-evaluation of the 

potential for any conflict of interest that the verification body, related entities, or 

any subcontractors performing verification services may have with the 

reporting entity for which it will perform verification services. The submittal 

shall include the following: 

(A) Identification of whether the potential for conflict of interest is high, low, or 

medium based on factors specified in sections 95133(b), (c), and (d); 

(B) Identification of whether the verification body, related entities, or any 

member of the verification team has previously provided verification 

services for the reporting entity or related entities and, if so, provide a 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 198 February 2015 

description of such services and the years in which such services were 

provided; 

(C) Identification of whether any member of the verification team, verification 

body, or related entity has engaged in services of any nature, other than 

ARB verification services, with the reporting entity or related entities 

either within or outside California during the previous five years. If 

services other than ARB verification services have previously been 

provided, the following information shall also be submitted: 

1. Identification of the nature and location of the work performed for the 

reporting entity or related entity and whether the work is similar to the 

type of work to be performed during verification, such as emissions 

inventory, auditing, energy efficiency, renewable energy, or other 

work with implications for the reporting entity’s greenhouse gas 

emissions pursuant to this article; 

2. The nature of past, present or future relationships of any member of 

the verification team, verification body, or related entities with the 

reporting entity or related entities including: 

a. Instances when any member of the verification team, verification 

body, or related entities has performed or intends to perform work 

for the reporting entity or related entities; 

b. Identification of whether work is currently being performed for the 

reporting entity or related entities, and if so, the nature of the 

work; 

c. How much work was performed for the reporting entity or related 

entities in the last five years, in dollars; 

d. Whether any member of the verification team, verification body, or 

related entities has contracts or other arrangements to perform 

work for the reporting entity or a related entity; 

e. How much work related to greenhouse gases the verification 

team has performed for the reporting entity or related entities in 

the last five years, in dollars. 

3. Explanation of how the amount and nature of work previously 

performed is such that any member of the verification team’s 

credibility and lack of bias should not be under question. 

(D) A list of names of the staff that would perform verification services for the 

reporting entity, and a description of any instances of personal or family 

relationships with management or employees of the reporting entity that 

potentially represent a conflict of interest; and, 

(E) Identification of any other circumstances known to the verification body, 

or reporting entity that could result in a conflict of interest. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 199 February 2015 

(F) Attest, in writing, to ARB as follows: 

“I certify under penalty of perjury under the laws of the State of California 

the information provided in the Conflict of Interest submittal is true, 

accurate, and complete.” 

(f) Conflict of Interest Determinations. The Executive Officer must review the selfevaluation submitted by the verification body and determine whether the verification 

body is authorized to perform verification services for the reporting entity. 

(1) The Executive Officer shall notify the verification body in writing when the 

conflict of interest evaluation information submitted under section 95132(e) is 

deemed complete. Within 30 working days of deeming the information 

complete, the Executive Officer shall determine whether the verification body 

is authorized to proceed with verification and must so notify the verification 

body. 

(2) If the Executive Officer determines the verification body or any member of the 

verification team meets the criteria specified in section 95133(b), the Executive 

Officer shall find a high potential conflict of interest and verification services 

may not proceed. 

(3) If the Executive Officer determines that there is a low potential conflict of 

interest, verification services may proceed. 

(4) If the Executive Officer determines that the verification body and verification 

team have a medium potential for a conflict of interest, the Executive Officer 

shall evaluate the conflict of interest mitigation plan submitted pursuant to 

section 95133(d), and may request additional information from the applicant to 

complete the determination. In determining whether verification services may 

proceed, the Executive Officer may consider factors including, but not limited 

to, the nature of previous work performed, the current and past relationships 

between the verification body, related entities, and its subcontractors with the 

reporting entity and related entities, and the cost of the verification services to 

be performed. If the Executive Officer determines that these factors when 

considered in combination demonstrate an acceptable level of potential 

conflict of interest, the Executive Officer will authorize the verification body to 

provide verification services. 

(g) Monitoring Conflict of Interest Situations. 

(1) After commencement of verification services, the verification body shall 

monitor and immediately make full disclosure in writing to the Executive Officer 

regarding any potential for a conflict of interest situation that arises. This 

disclosure shall include a description of actions that the verification body has 

taken or proposes to take to avoid, neutralize, or mitigate the potential for a 

conflict of interest. 

(2) The verification body shall continue to monitor arrangements or relationships 

that may be present for a period of one year after the completion of verification 

services. During that period, within 30 days of the verification body or any 

verification team member entering into any contract with the reporting entity or 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 200 February 2015 

related entity for which the body has provided verification services, the 

verification body shall notify the Executive Officer of the contract and the 

nature of the work to be performed, and revenue received. The Executive 

Officer, within 30 working days, will determine the level of conflict using the 

criteria in section 95133(a)-(d), if the reporting entity must reverify their 

emissions data report, and if accreditation revocation is warranted. 

(3) The verification body shall notify the Executive Office, within 30 days, of any 

emerging conflicts of interest during the time verification services are being 

provided. 

(A) If the Executive Officer determines that a disclosed emerging potential 

conflict is medium risk and this risk can be mitigated, the verification body 

is deemed to have met the conflict of interest requirements to continue to 

provide verification services to the reporting entity and will not be subject 

to suspension or revocation of accreditation as specified in section 

95132(d). 

(B) If the Executive Officer determines that a disclosed emerging potential 

conflict is medium or high risk and this risk cannot be mitigated, the 

verification body will not be able to continue to provide verification 

services to the reporting entity, and may be subject to suspension or 

revocation of accreditation under section 95132(d).

(4) The verification body shall report to the Executive Officer any changes in its 

organizational structure, including mergers, acquisitions, or divestitures, for 

one year after completion of verification services.

(5) The Executive Officer may invalidate a verification finding if a potential conflict 

of interest has arisen for any member of the verification team. In such a case, 

the reporting entity shall be provided 90 days to complete re-verification. 

(6) If the verification body or its subcontractor(s) are found to have violated the 

conflict of interest requirements of this article, the Executive Officer may 

rescind accreditation of the body, its verifier staff, or its subcontractor(s) as 

provided in section 95132(d). 

(h) Specific Requirements for Air Quality Management Districts and Air Pollution 

Control Districts. 

(1) If an air district has provided or is providing any services listed in section 

95133(b)(2) as part of its regulatory duties, those services do not constitute 

non-verification services or a potential for high conflict of interest for purposes 

of this subarticle; 

(2) Before providing verification services, an air district shall either submit a 

conflict of interest self-evaluation pursuant to section 95133(e) for each 

reporting entity for which it intends to provide verification services, or shall 

submit an annual self-evaluation to ARB no later than April 10 of each 

calendar year containing the information specified in section 95133(e)(1)(A)-

(F) for all reporting entities for which it intends to provide verification services; 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 201 February 2015 

(3) As part of its conflict of interest self-evaluation submittal under section 

95133(e), the air district shall certify that it will prevent conflicts of interests and 

resolve potential conflict of interest situations pursuant to its policies and 

mechanisms submitted under section 95132(b)(1)(G); 

(4) If an air district hires a subcontractor who is not an air district employee to 

provide verification services, the air district shall be subject to all of the 

requirements of section 95133. 

NOTE: Authority cited: Sections 38510, 38530, 39600, 39601, 39607, 39607.4 and 

41511, Health and Safety Code. Reference: Sections 38530, 39600 and 41511, Health 

and Safety Code. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 202 February 2015 

Subarticle 5. Reporting Requirements and Calculation Methods for Petroleum 

and Natural Gas Systems. 

§95150. Definition of the Source Category. 

(a) This source category consists of the following industry segments:

(1) Offshore petroleum and natural gas production. Offshore petroleum and 

natural gas production is any platform structure, affixed temporarily or 

permanently to offshore submerged lands, that houses equipment to extract 

hydrocarbons from the ocean or lake floor and that processes and/or transfers 

such hydrocarbons to storage, transport vessels, or onshore. In addition, 

offshore production includes secondary platform structures connected to the 

platform structure via walkways, storage tanks associated with the platform 

structure and floating production and storage offloading equipment (FPSO). 

This source category does not include emissions from offshore drilling and 

exploration that is not conducted on production platforms. 

(2) Onshore petroleum and natural gas production. Onshore petroleum and 

natural gas production means all equipment on a well-pad or associated with a 

well pad (including compressors, generators, dehydrators, storage vessels, 

and portable non-self-propelled equipment which includes well drilling and 

completion equipment, workover equipment, gravity separation equipment, 

auxiliary non-transportation-related equipment, and leased, rented or 

contracted equipment) used in the production, extraction, recovery, lifting, 

stabilization, separation or treating of petroleum and/or natural gas (including 

condensate). This equipment also includes associated storage or 

measurement vessels and all enhanced oil recovery (EOR) operations (both 

thermal and non-thermal), and all petroleum and natural gas production 

equipment located on islands, artificial islands, or structures connected by a 

causeway to land, an island, or an artificial island. Crude oil and associated 

gas that is piped to an onshore production facility as an emulsion as defined in 

section 95102(a) must follow the requirements of section 95156(a)(7)-(10) and 

meet the metering requirements of section 95103(k) by measuring the 

emulsion before the first separation tank at the onshore production facility and 

not at the platform. 

(3) Onshore natural gas processing. Natural gas processing means the 

separation of natural gas liquids (NGLs) or non-methane gases from produced 

natural gas, or the separation of NGLs into one or more component mixtures. 

Separation includes one or more of the following: forced extraction of natural 

gas liquids, sulfur and carbon dioxide removal, fractionation of NGLs, or the 

capture of CO2 separated from natural gas streams. This segment also 

includes all residue gas compression equipment owned or operated by the 

natural gas processing plant. This industry segment includes processing 

plants that fractionate gas liquids, and processing plants that do not fractionate 

gas liquids but have an annual average throughput of 25 MMscf per day or 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 203 February 2015 

greater. This industry segment also includes all booster stations owned and/or 

operated by the facility owner/operator. 

(4) Onshore natural gas transmission compression. Onshore natural gas 

transmission compression means any stationary combination of compressors 

that move natural gas from production fields, natural gas processing plants, or 

other transmission compressors through transmission pipelines to natural gas 

distribution pipelines, LNG storage facilities, or into underground storage. In 

addition, a transmission compressor station includes equipment for liquids 

separation, and tanks for the storage of water and hydrocarbon liquids. 

Residue (sales) gas compression that is part of onshore natural gas 

processing plants are included in the onshore natural gas processing segment 

and are excluded from this segment. This industry segment also includes all 

booster stations owned and/or operated by the facility owner/operator. 

(5) Underground natural gas storage. Underground natural gas storage means 

subsurface storage, including depleted gas or oil reservoirs and salt dome 

caverns that store natural gas that has been transferred from its original 

location for the primary purpose of load balancing (the process or equalizing 

the receipt and delivery of natural gas); natural gas underground storage 

processes and operations (including compression, dehydration and flow 

measurement, and excluding transmission pipelines); and all the wellheads 

connected to the compression units located at the facility that inject and 

recover natural gas into and from the underground reservoirs. 

(6) Liquefied natural gas (LNG) storage. LNG storage means onshore LNG 

storage vessels located above ground, equipment for liquefying natural gas, 

compressors to capture and re-liquefy boil-off-gas, re-condensers, and 

vaporization units for regasification of the liquefied natural gas. 

(7) LNG import and export equipment. LNG import equipment means all onshore 

or offshore equipment that receives imported LNG via ocean transport, stores 

LNG, re-gasifies LNG, and delivers re-gasified natural gas to a natural gas 

transmission or distribution system in California. LNG export equipment 

means all onshore or offshore equipment that receives natural gas, liquefies 

natural gas, stores LNG, and transfers the LNG via ocean transportation to 

California. 

(8) Natural gas distribution. Natural gas distribution means the distribution 

pipelines and metering and regulating equipment at metering-regulating 

stations that are operated by a Local Distribution Company (LDC) within 

California that is regulated by a public utility commission or that is operated as 

an independent municipally-owned distribution system. This segment also 

excludes customer meters and regulators, infrastructure, and pipelines (both 

interstate and intrastate) delivering natural gas directly to major industrial 

users and farm taps upstream of the local distribution company inlet. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 204 February 2015 

NOTE: Authority cited: Sections 38510, 38530, 39600, 39601, 39607, 39607.4 and 

41511, Health and Safety Code. Reference: Sections 38530, 39600 and 41511, Health 

and Safety Code. 

§95151. Reporting Threshold. 

(a) The operator of a facility must report GHG emissions under this subarticle if the 

facility contains petroleum and natural gas systems and the facility meets the 

requirements of sections 95101(b) and the reporting thresholds outlined in section 

95101(e). 

(b) For applying the threshold defined in section 95101(b), natural gas processing 

facilities must also include owned or operated residue gas compression equipment. 

NOTE: Authority cited: Sections 38510, 38530, 39600, 39601, 39607, 39607.4 and 

41511, Health and Safety Code. Reference: Sections 38530, 39600 and 41511, Health 

and Safety Code. 

§95152. Greenhouse Gases to Report. 

(a) The operator of a facility must report CO2, CH4, and N2O emissions from each 

industry segment specified in paragraphs (b) through (i) of this section, CO2, CH4, 

and N2O emissions from each flare as specified in paragraphs (b) through (i) of this 

section, and stationary and portable combustion emissions as applicable and as 

specified in paragraph (j) of this section. 

(b) For offshore petroleum and natural gas production, the operator must report CO2, 

CH4, and N2O emissions from equipment leaks, vented emissions, and flare 

emission source types as identified in the data collection and emissions estimation 

study (Year 2008 Gulfwide Emission Inventory Study (GOADS) (December 2010)) 

conducted by the Bureau of Ocean Energy Management, Regulation and 

Enforcement (BOEMRE) in compliance with 30 CFR §§250.302 through 304 

(July 1, 2011), which is hereby incorporated by reference. Offshore platforms do 

not need to report portable emissions. In addition, offshore production facilities 

must report combustion emissions from supply and transportation vessels (e.g., 

ships and helicopters) used to transport personnel, equipment and products to and 

from the production facility using methods found in subpart C of 40 CFR Part 98. 

(c) For an onshore petroleum and natural gas production facility, the operator must 

report CO2, CH4, and N2O emissions from the following source types on a well-pad, 

associated with a well-pad or associated with equipment to which an emulsion is 

transferred: 

(1) Metered natural gas pneumatic device and pump venting; 

(2) Non-metered natural gas pneumatic device venting; 

(3) Acid gas removal vents; 

(4) Dehydrator vents; 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 205 February 2015 

(5) Well venting for liquids unloading; 

(6) Gas well venting during well completions and workovers; 

(7) Equipment and pipeline blowdowns; 

(8) Dump valves; 

(9) Well testing venting and flaring; 

(10) Associated gas venting and flaring; 

(11) Flare stack or other destruction device emissions; 

(12) Centrifugal compressor venting; 

(13) Reciprocating compressor venting; 

(14) EOR injection pump blowdown; 

(15) Crude oil, condensate and produced water CO2 and CH4; 

(16) Equipment leaks from valves, connectors, open ended lines, pressure relief 

valves, pumps, flanges, and other equipment leak sources (such as 

instruments, loading arms, stuffing boxes, compressor seals, dump lever 

arms, and breather caps); and 

(17) The operator must use the methods in section 95153(y) and report under this 

subarticle the emissions of CO2, CH4, and N2O from stationary or portable fuel 

combustion equipment that cannot move on roadways under its own power 

and drive train, and that is located at an onshore petroleum and natural gas 

production facility as defined in section 95150. Stationary or portable 

equipment includes equipment which is integral to the extraction, processing, 

and movement of oil and/or natural gas; such as well pad construction 

equipment, well drilling and completion equipment, equipment used for 

abandoned well plugging and site reclamation, workover equipment, natural 

gas dehydrators, natural gas compressors, electrical generators, steam 

boilers, and process heaters. 

(d) For onshore natural gas processing, the operator must report CO2, CH4, and N2O 

emissions from the following sources: 

(1) Acid gas removal vents; 

(2) Dehydrator vents; 

(3) Equipment and pipeline blowdowns; 

(4) Flare stack or other destruction device emissions; 

(5) Centrifugal compressor venting; 

(6) Reciprocating compressor venting; and 

(7) Equipment leaks from valves, connectors, open ended lines, pressure relief 

valves, and meters. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 206 February 2015 

(e) For onshore natural gas transmission compression, the operator must report CO2, 

CH4, and N2O emissions from the following sources: 

(1) Metered natural gas pneumatic device and pump venting; 

(2) Non-metered natural gas pneumatic device venting; 

(3) Equipment and pipeline blowdowns; 

(4) Transmission storage tanks; 

(5) Flare stack or other destruction device emissions; 

(6) Centrifugal compressor venting; 

(7) Reciprocating compressor venting; and 

(8) Equipment leaks from valves, connectors, open ended lines, pressure relief 

valves, and meters. 

(f) For underground natural gas storage, the operator must report CO2, CH4, and N2O 

from the following sources: 

(1) Metered natural gas pneumatic device and pump venting; 

(2) Non-metered natural gas pneumatic device venting; 

(3) Equipment and pipeline blowdowns; 

(4) Flare stack or other destruction device emissions; 

(5) Centrifugal compressor rod packing venting; 

(6) Reciprocating compressor venting; and 

(7) Equipment leaks from valves, connectors, open ended lines, pressure relief 

valves, and meters. 

(g) For LNG storage, the operator must report CO2, CH4, and N2O emissions from the 

following sources: 

(1) Equipment and pipeline blowdowns; 

(2) Flare stack or other destruction device emissions; 

(3) Centrifugal compressor rod packing venting; 

(4) Reciprocating compressor venting; and 

(5) Equipment leaks from valves, pump seals, connectors, vapor recovery 

compressors, and other equipment leak sources. 

(h) For LNG import and export equipment, the operator must report CO2, CH4, and N2O 

emissions from the following sources: 

(1) Equipment and pipeline blowdowns; 

(2) Flare stack or other destruction device emissions; 

(3) Centrifugal compressor rod packing venting; 

(4) Reciprocating compressor venting; and 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 207 February 2015 

(5) Equipment leaks from valves, pump seals, connectors, vapor recovery 

compressors, and other equipment leak sources. 

(i) For natural gas distribution, the operator must report CO2, CH4, and N2O emissions 

from the following sources: 

(1) Equipment leaks from connectors, block valves, control valves, pressure relief 

valves, orifice meters, regulators, and open ended lines at above grade 

transmission-distribution transfer stations; 

(2) Equipment leaks at below grade transmission-distribution transfer stations; 

(3) Equipment leaks at above grade metering-regulating stations that are not 

above grade transmission-distribution transfer stations; 

(4) Equipment leaks at below grade metering-regulating stations. 

(5) Distribution main equipment leaks; 

(6) Distribution services equipment leaks; 

(7) Report under section 95150 of this article the emissions of CO2, CH4, and N2O 

from stationary fuel combustion sources following the methods in 95153(y); 

(8) Flare stack emissions; 

(9) Equipment and pipeline blowdowns; 

(10) CO2 and CH4 emissions from customer meters (N2O emissions excluded); and 

(11) CO2 and CH4 emissions from pipeline dig-ins (N2O emissions excluded). 

(j) Except for facilities under onshore petroleum and natural gas production and 

natural gas distribution, the operator of a facility must report emissions of CO2, CH4, 

and N2O for each stationary fuel combustion unit by following the requirements of 

section 95115 of this article. Operators of onshore petroleum and natural gas 

production facilities must report stationary and portable combustion emissions as 

specified in paragraph (c) of this section. Natural gas distribution facilities must 

report stationary combustion emissions as specified in paragraph (i) of this section. 

(k) Operators of facilities must report CO2 emissions captured and transferred off site 

by following the requirements of section 95123 of this article (suppliers of carbon 

dioxide). 

NOTE: Authority cited: Sections 38510, 38530, 39600, 39601, 39607, 39607.4 and 

41511, Health and Safety Code. Reference: Sections 38530, 39600 and 41511, Health 

and Safety Code. 

 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 208 February 2015 

§ 95153. Calculating GHG Emissions. 

The operator of a facility must calculate and report annual GHG emissions as 

prescribed in this section. The facility operator who is a local distribution company 

reporting under section 95122 of this article must comply with section 95153 for 

reporting emissions from the applicable source types in section 95152(i) of this article. 

(a) Metered Natural Gas Pneumatic Device and Pneumatic Pump Venting. The 

operator of a facility who is subject to the requirements of sections 95153(a) and (b) 

must calculate emissions from a natural gas powered continuous high bleed control 

device and pneumatic pump venting using the method specified in paragraph (a)(1) 

below when the natural gas flow to the device is metered. By January 1, 2015, 

natural gas consumption must be metered for all of the operator’s pneumatic 

continuous high bleed devices and pneumatic pumps. The operator may choose to 

also meter flow to any or all low bleed and intermittent bleed natural gas powered 

devices. For unmetered devices the operator must use the method specified in 

section 95153(b). Vented emissions from natural gas driven pneumatic pumps 

covered in paragraph (d) of this section do not have to be reported under paragraph 

(a) of this section. 

(1) The operator must calculate vented emissions for all metered natural gas 

powered pneumatic devices and pumps using the following equation: 

de = ∑ 



<

 (Eq. 1) 

 Where: 

Em = Annual natural gas emissions at standard conditions, in cubic feet, for all 

metered natural gas powered pneumatic devices. 

n = Total number of meters. 

Bn = Natural gas consumption for meter n. 

(2) For both metered and unmetered natural gas powered devices, CH4 and CO2

volumetric and mass emissions must be calculated from volumetric natural 

gas emissions using methods in paragraphs (s) and (t) of this section. 

(b) Non-metered Natural Gas Pneumatic Device Venting. The operator must calculate 

CH4 and CO2 emissions from all un-metered natural gas powered pneumatic 

intermittent bleed and continuous low and high bleed devices using the following 

method: 

de,,g = ∑ ∑ dh

g

<



< ∗ _,g (Eq. 2) 

Where: 

Enm,i,x = Annual natural gas emissions at standard conditions for all unmetered 

natural gas powered devices and pumps (in scf). 

i = Total number of unmetered component types. 

x = Total number of component type i. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 209 February 2015 

EFi = Population emission factor for natural gas pneumatic device type i 

(scf/hour/component) listed in Tables 1A, 3, and 4 of Appendix A for onshore 

petroleum and natural gas production, onshore natural gas transmissions 

compression, and underground natural gas facilities, respectively. 

Ti,x = Total number of hours type i component x was in service. Default is 

8760 hours. 

(1) GHG (CO2 and CH4) volumetric and mass emissions must be calculated from 

volumetric natural gas emissions using methods in paragraphs (s) and (t) of 

this section. 

(c) Acid gas removal (AGR) vents. For AGR vents (including processes such as 

amine, membrane, molecular sieve or other absorbents and adsorbents), the 

operator must calculate emissions for CO2 only (not CH4) vented directly to the 

atmosphere or emitted through a flare, engine (e.g. permeate from a membrane or 

de-adsorbed gas from a pressure swing adsorber used as fuel supplement), or 

sulfur recovery plant using the applicable calculation methodologies described in 

paragraphs (c)(1)-(c)(10) below. 

(1) Calculation Methodology 1. If the operator operates and maintains a CEMS 

that has both a CO2 concentration monitor and volumetric flow rate meter, they 

must calculate CO2 emissions under this subarticle by following the Tier 4 

Calculation Methodology and all associated calculation, quality assurance, 

reporting, and recordkeeping requirements for Tier 4 in section 95115 

(stationary fuel combustion sources). Alternatively, the operator may follow 

the manufacturer’s instructions or industry standard practice. If a CO2

concentration monitor and volumetric flow rate monitor are not available, the 

operator may elect to install a CO2 concentration monitor and a volumetric flow 

rate monitor that comply with all the requirements specified for the Tier 4 

Calculation Methodology in section 95115 (stationary fuel combustion 

sources). The calculation and reporting of CH4 and N2O emissions is not 

required as part of the Tier 4 requirements for AGRs. 

(2) Calculation Methodology 2. If CEMS is not available but a vent meter is 

installed, the operator must use the CO2 composition and annual volume of 

vent gas to calculate emissions using Equation 3 of this section. 

d,j = k ∗ kR`j (Eq. 3) 

Where: 

Ea,CO2 = Annual volumetric CO2 emissions at actual conditions, in cubic feet 

per year. 

Vs = Total annual volume of vent gas flowing out of the AGR unit in cubic 

feet per year at actual conditions as determined by flow meter using 

methods set forth in section 95154(b). Alternatively, the facility operator 

may follow the manufacturer’s instructions for calibration of the vent meter. 

VolCO2 = Annual average volumetric fraction of CO2 content in the vent gas 

out of the AGR unit as determined in (c)(5) of this section. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 210 February 2015 

(3) Calculation Methodology 3. If CEMS or a vent meter is not installed, the 

operator may use the inlet or outlet gas flow rate of the acid gas removal unit 

to calculate emissions for CO2 using Equations 4A or 4B of this section. If inlet

gas flow rate is known, use Equation 4A. If outlet gas flow rate is known, use 

Equation 4B. 

 Eα,CO2 = Vin * [(VolI - VolO)/(1-VolO)] (Eq. 4A) 

 Eα,CO2 = Vout * [(VolI – VolO)/(1-VolI)] (Eq. 4B)

Where: 

Eα, CO2= Annual volumetric CO2 emissions at actual conditions, in cubic feet 

per year. 

Vin= Total annual volume of natural gas flow into the AGR unit in cubic feet 

per year at actual condition as determined using methods specified in 

paragraph (c)(4) of this section. 

Vout= Total annual volume of natural gas flow out of the AGR unit in cubic feet 

per year at actual condition as determined using methods specified in 

paragraph (c)(4) of this section. 

VolI= Volume fraction of CO2 content in natural gas into the AGR unit as 

determined in paragraph (c)(6) of this section. 

Volo= Volume fraction of CO2 content in natural gas out of the AGR unit as 

determined in paragraph (c)(7) of this section. 

(4) Record the gas flow rate of the inlet and outlet natural gas stream of an AGR 

unit using a meter according to methods set forth in section 95154(b). If the 

operator does not have a continuous flow meter, either install a continuous 

flow meter or use an engineering calculation to determine the flow rate. 

(5) If continuous gas analyzer is not available on the vent stack, either install a 

continuous gas analyzer or take quarterly gas samples from the vent gas 

stream to determine VolCO2 according to methods set forth in section 95154(b).

(6) If a continuous gas analyzer is installed on the inlet gas stream, then the 

continuous gas analyzer results must be used. If continuous gas analyzer is 

not available, either install a continuous gas analyzer or take quarterly gas 

samples from the inlet gas stream to determine VolI according to methods set 

forth in section 95154(b). 

(7) Determine volume fraction of CO2 content in natural gas out of the AGR unit 

using one of the methods specified in paragraph (c)(7) of this section. 

(A) If a continuous gas analyzer is installed on the outlet gas stream, then the 

continuous gas analyzer results must be used. If a continuous gas 

analyzer is not available, the operator may install a continuous gas 

analyzer. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 211 February 2015 

(B) If a continuous gas analyzer is not available or installed, quarterly gas 

samples may be taken from the outlet gas stream to determine VolO 

according to methods set forth in section 95154(b).

(C) Use sales line quality specification for CO2 in natural gas. 

(8) Calculate CO2 volumetric emissions at standard conditions using calculations 

in paragraph (r) of this section. 

(9) Mass CO2 emissions shall be calculated from volumetric CO2emissions using 

calculations in paragraph (t) of this section. 

(10) Determine if emissions from the AGR unit are recovered and transferred 

outside the facility. Adjust the emission estimated in paragraphs (c)(1) through 

(c)(10) of this section downward by the magnitude of emission recovered and 

transferred outside the facility. 

(d) Dehydrator vents. For dehydrator vents, calculate annual CH4, CO2, and N2O 

emissions using any of the calculation methodologies described in paragraph (d) of 

this section. 

(1) Calculate annual mass emissions from dehydrator vents using a software 

program which applies the Peng-Robinson equation of state (Equation 38 of 

section 95154) to calculate the equilibrium coefficient, speciates CH4 and CO2

emissions from dehydrators, and has provisions to include regenerator control 

devices, a separator flash tank, stripping gas and a gas injection pump or gas 

assist pump. A minimum of the following parameters determined by 

engineering estimate based on best available data must be used to 

characterize emissions from dehydrators. 

(A) Feed natural gas flow rate. 

(B) Feed natural gas water content. 

(C) Outlet natural gas water content. 

(D) Absorbent circulation pump type (natural gas pneumatic/air 

pneumatic/electric). 

(E) Absorbent circulation rate. 

(F) Absorbent type: including triethylene glycol (TEG), diethylene glycol 

(DEG) or ethylene glycol (EG). 

(G) Use of stripping gas. 

(H) Use of flash tank separator (and disposition of recovered gas). 

(I) Hours operated. 

(J) Wet natural gas temperature and pressure. 

(K) Wet natural gas composition. Determine this parameter by selecting one 

of the methods described in subparagraphs (1) – (4) below. 

1. Use the wet natural gas composition as defined in section 

95153(s)(2). 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 212 February 2015 

2. If wet natural gas composition cannot be determined using paragraph 

95153(s)(2) of this section, select a representative analysis. 

3. The facility operator may use an appropriate standard method 

published by a consensus-based standards organization or the 

facility operator may use an industry standard practice as specified in 

section 95154(b) to sample and analyze wet natural gas composition. 

4. If only composition data for dry natural gas is available, assume the 

wet natural gas is saturated. 

(2) Determine if the dehydrator unit has vapor recovery. Adjust the emissions 

estimated in paragraphs (d)(1) or (d)(4) of this section downward by the 

magnitude of emissions captured. 

(3) Calculate annual emissions from dehydrator vents to flares or regenerator firebox/fire tubes as follows: 

(A) Use the dehydrator vent volume and gas composition as determined in 

paragraph (d)(1) of this section. 

(B) Use the calculation methodology of flare stacks in paragraph (l) of this 

section to determine dehydrator vent emissions from the flare or 

regenerator combustion gas vent. 

(4) In the case of dehydrators that use desiccant, operators must calculate 

emissions from the amount of gas vented from the vessel when it is 

depressurized for the desiccant refilling process using Equation 5 of this 

section. 

d, = P l ∗ Wj∗ m ∗ %n ∗ Lj/ 4 ∗ L<

$$ (Eq. 5) 

Where: 

ES,n = Annual natural gas emissions at standard conditions in cubic feet. 

n = number of fillings in reporting period. 

H = Height of the dehydrator vessel (ft). 

D = Inside diameter of the vessel (ft). 

π = pi (3.1416) 

%G = Percent of packed vessel volume that is gas (expressed as a decimal, 

e.g.,15% = 0.15). 

P1 = Atmospheric pressure (psia). 

P2 = Pressure of the gas (psia). 

(5) For glycol dehydrators, both CH4 and CO2 mass emissions must be calculated 

from volumetric GHGi emissions using calculations in paragraph (t) of this 

section. For dehydrators that use desiccant, both CH4 and CO2 volumetric 

and mass emissions must be calculated from volumetric natural gas emissions 

using calculations in paragraphs (s) and (t) of this section. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 213 February 2015 

(e) Well venting for liquids unloadings. Calculate CO2 and CH4 emissions from well 

venting for liquids unloading using one of the calculation methodologies described 

in paragraphs (e)(1), (e)(2) or (e)(3) of this section. 

(1) Calculation Methodology 1. Calculate the total emissions for well venting for 

liquids unloading without plunger lift assist using Equation 6 of this section. 

d, = ∑ qkr ∗ s 0.37 ∗ 10v$ ∗ Wr

j

∗ Wr ∗ wLrx + ∑ ywhzr ∗ ylzr,{ − 1.0| ∗ }r,{|

~

r;< Ä

Å

r;< 

 (Eq. 6) 

Where: 

ES,n = Annual natural gas emissions at standard conditions, in cubic feet/year. 

W = Total number of well venting events for liquids unloading for each basin. 

0.37x10-3 = {3.14(pi)/4}/{14.7x144}(psia converted to pounds per square feet). 

p = wells 1 through W with well venting for liquids unloading in the basin. 

CDp = Casing diameter for each well, p, in inches. 

WDp = Well depth from either the top of the well or the lowest packer to the 

bottom of the well, for each well, p, in feet. 

SPp = For each well, p, shut-in pressure or surface pressure for wells with 

tubing production and no packers or casing pressure for each well, p, in 

pounds per square inch absolute (psia). 

Vp = Number of unloading events per year per well, p.

SFRp = Average flow-line rate of gas for well p, at standard conditions in cubic 

feet per hour. Use Equation 29 to calculate the average flow-rate at standard 

conditions. 

HRp,q = Hours that each well, p, was left open to the atmosphere during each 

unloading event, q. 

1.0 = Hours for average well to blowdown casing volume at shut-in pressure. 

Zp,q = If HRp,q is less than 1.0 then Zp,q is equal to 0. If HRp,q is greater than or 

equal to 1.0 then Zp,q is equal to 1. 

(A) Both CH4 and CO2 volumetric and mass emissions shall be calculated 

from volumetric natural gas emissions using calculations in paragraphs 

(s) and (t) of this section. 

(2) Calculation Methodology 2. Calculate emissions from each well venting to the 

atmosphere for liquids unloading with plunger lift assist using Equation 7 of 

this section. 

d, = ∑ qkr ∗ s 0.37 ∗ 10v$ ∗ _Wr

j

∗ Wr ∗ wLrx + ∑ ywhzr ∗ ylzr,{ − 0.5| ∗ }r,{|

~

{;< Ä

Å

r;<

 (Eq. 7) 

Where: 

ES,n = Annual natural gas emissions at standard conditions, in cubic feet/year. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 214 February 2015 

W = Total number of well venting liquid unloading events at wells using 

plunger lift assist technology for each basin. 

0.37 x 10-3 = {3.14(pi)/4}/{14.7 x 144} (psia converted to pounds per square 

feet). 

TDp = Tubing internal diameter for each well, p, in inches. 

WDp = Tubing depth to plunger bumper for each well, p, in feet. 

SPp = Flow-line pressure for each well, p, in pounds per square inch absolute 

(psia). 

Vp = Number of unloading events per year for each well, p. 

SFRp = Average flow-line rate of gas for well, p, at standard conditions in 

cubic feet per hour. Use Equation 29 to calculate the average flow-line rate at 

standard conditions. 

HRp,q = Hours that each well, p, was left open to the atmosphere during each 

unloading, q. 

0.5 = Hours for average well to blowdown tubing volume at flow-line pressure. 

Zp,q = If HRp,q is less than 0.5, then Zp,q is equal to 0. If HRp,q is greater than or 

equal to 0.5, then Zp,q is equal to 1. 

(3) Both CH4 and CO2 volumetric and mass emissions shall be calculated from 

volumetric natural gas emissions using calculations in paragraphs (s) and (t) of 

this section. 

(f) Gas well venting during well completions and well workovers. Using one of the 

calculation methodologies in this paragraph (f)(1) through (f)(5) below, operators 

must calculate CH4, CO2 and N2O (when flared) annual emissions from gas well 

venting during both conventional completions and completions involving hydraulic 

fracturing in wells and during both conventional well workovers and well workovers 

involving hydraulic fracturing. 

(1) Calculation Methodology 1. Measure total gas flow with a recording flow 

meter (analog or digital) installed in the vent line ahead of a flare or vent id 

used. The facility operator must correct total gas volume vented for the 

volume of CO2 or N2: 

d = 	 kÉ − 	kÑÖÜ	áà	âÜ	 (Eq. 8) 

Where: 

Ea = Gas emissions during the well completion or workover at actual 

conditions (m3). 

VM= Volume of vented gas measured during well completion or workover 

(m3). 

V CO2 or N2 = Volume of CO2 or N2 injected during well completion or workover 

(m3). 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 215 February 2015 

(A) All gas volumes must be corrected to standard temperature and pressure 

using methods in section(r). 

(B) Calculate CO2 and CH4 volumetric and mass emissions using the 

methodologies in sections (s) and (t). 

(2) Calculation Methodology 2. 

(A) Record the well flowing pressure upstream (P1) and downstream (P2) of a 

well choke, upstream temperature and elapsed time of venting according 

to methods set forth in section 95154(b) to calculate the well backflow 

during well completions and workovers. 

(B) The operator must record this data at a time interval (e.g., every five 

minutes) suitable to accurately describe both sonic and subsonic flow 

regimes. 

(C) Sonic flow is defined as the flow regime where P2/P1 ≤ 0.542. 

(D) Calculate the average flow rate during sonic conditions using Equation 9 

of this section: 

hz = 1.27 ∗ 10ã∗ ! ∗ å187.08 ∗ _ (Eq. 9) 

Where: 

FRa = Average flow rate in cubic feet per hour, under actual sonic flow 

conditions. 

A = Cross sectional open area of the restriction orifice (m2). 

Tu = Upstream temperature (degrees Kelvin). 

187.08 = Constant with units of m2/(sec2x K). 

1.27 x 105 = Conversion from m3/second to ft3/hour. 

(E) Calculate total gas volume vented during sonic flow conditions as follows: 

k = hz ∗ _ (Eq. 10) 

Where: 

 Vs = Volume of gas vented during sonic flow conditions (scf). 

 TS = Length of time that the well vented under sonic conditions (hours). 

(F) For each of the sets of data points (Tu, P1, P2, and elapsed time under 

subsonic flow conditions) recorded as the well vented under subsonic 

flow conditions, calculate the instantaneous gas flow rate as follows: 

hz = 1.27 ∗ 10ã∗ ! ∗ å3430 ∗ _ ∗ V Lj/L<

$

<.ã<ã − Lj/L<

$

<.éãè\ (Eq. 11) 

Where: 

FRa = Instantaneous flow rate in cubic feet per hour, under actual 

subsonic flow conditions. 

A = Cross sectional open area of the restriction orifice (m2). 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 216 February 2015 

P1 = Upstream pressure (psia). 

Tu = Upstream temperature (degrees Kelvin). 

P2 = Downstream pressure (psia). 

3430 = Constant with units of m2/(sec2xK). 

1.27 x 105 = Conversion from m3/second to ft3/hour. 

(G) Calculate the total gas volume vented during subsonic flow conditions, 

VSS, as the total volume under the curve of a plot of FRa and elapsed time 

under subsonic flow conditions. 

(H) Correct VSS to standard conditions using the methodology found in 

paragraph (r) of this section. 

(I) Sum the vented volumes during subsonic and sonic flow and adjust 

vented emissions for the volume of CO2 and N2 injected and the volume 

of gas recovered to a sales line as follows: 

d = k + k − kêëÜ

íÜ

− kì (Eq. 12) 

Where: 

Es = Total volume of gas vented during the well completion or workover 

(scf). 

Vs = Volume of gas vented during sonic flow conditions for the well 

completion or workover (scf) (see Eq. 10). 

Vss = Volume of gas vented during subsonic flow conditions for the well 

completion or workover (scf) (see 95153(f)(2)(G) above). 

VCO2/N2 = Volume of CO2 or N2 injected during the well completion or 

workover (scf). 

VSG = Volume of gas recovered to a sales line during the well completion 

or workover (scf). 

(3) The volume of CO2 or N2 injected into the well reservoir during energized 

hydraulic fractures must be measured using an appropriate meter as 

described in section 95154(b) or using receipts of gas purchases that are used 

for the energized fracture job. 

(A) Calculate gas volume at standard conditions using calculations in 

paragraph (r) of this section. 

(4) Determine if the backflow gas from the well completion or workover is 

recovered with purpose designed equipment that separates natural gas from 

the backflow, and sends this natural gas to a flow-line (e.g., reduced 

emissions completion or workover). 

(A) Use the factor VSG in Equation 8 of this section to adjust the emissions 

estimated in paragraphs (f)(1) through (f)(4) of this section by the 

magnitude of emissions captured using purpose designed equipment that 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 217 February 2015 

separates saleable gas from the backflow as determined by engineering 

estimate based on best available data. 

(B) Calculate gas volume at standard conditions using calculations in 

paragraph (r) of this section. 

(5) Both CH4 and CO2 volumetric and mass emissions must be calculated from 

volumetric total emissions using calculations in paragraphs (s) and (t) of this 

section. 

(g) Equipment and pipeline blowdowns. Calculate CO2 and CH4 blowdown emissions 

from depressurizing equipment and natural gas pipelines to reduce system 

pressure for planned or emergency shutdowns resulting from human intervention or 

to take equipment out of service for maintenance (excluding depressurizing to a 

flare, over-pressure relief, operating pressure control venting and blowdown of nonGHG gases; desiccant dehydrator blowdown venting before reloading is covered in 

paragraphs (d)(4) of this section) as follows: 

(1) Calculate the unique physical volume (including pipelines, compressor case or 

cylinders, manifolds, suction bottles, discharge bottles, and vessels) between 

isolation valves determined by engineering estimates based on best available 

data. Engineering estimates based on best available data may also be used 

to determine the temperature and pressure variables used in the Equations 13 

and 14 if monitoring data is unavailable. Equipment blowdowns with a unique 

physical volume (including pipelines, compressor case or cylinder manifolds, 

suction bottles, discharge bottles and vessels) of less than 50 cubic feet (cf) 

between isolation valves are not subject to the requirements of 95153(g). 

(2) Calculate the total annual venting emissions for unique volumes using either 

Equation 13 or 14 of this section. 

d, = î ∗ sk s ïãñ.óéòô

$ö

 ïãñ.óéòö$ô

x − k ∗ x (Eq. 13) 

Where: 

Es,n = Annual natural gas venting emissions at standard conditions from 

blowdowns in cubic feet. 

N = Number of occurrences of blowdowns for each unique physical volume in 

the calendar year. 

V = Unique physical volume (including pipelines, compressors and vessels) 

between isolation valves in cubic feet. 

C = Purge factor that is 1 if the unique physical volume is not purged or zero if 

the unique physical volume is purged using non-GHG gases. 

Ts = Temperature at standard conditions (60 ̊F). 

Ta = Temperature at actual conditions in the unique physical volume ( ̊F). 

Ps = Absolute pressure at standard conditions (14.7 psia). 

Pa = Absolute pressure at actual conditions in the unique physical volume 

(psia). 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 218 February 2015 

d, = ∑ ∑ Vk 459.67 + _	$ L ,,r$ − L ,,r$	$/ 459.67 + _,r	$	L	$\ 

<

~

<

 (Eq. 14) 

Where: 

Es,n = Annual natural gas venting emissions at standard conditions from 

blowdowns in cubic feet. 

PV = Number of unique physical volumes blowndown. 

N = Number of occurrences of blowdowns for each unique physical volume. 

V = Total physical volume (including pipelines, compressors and vessels) 

between isolation valves in cubic feet for each blowdown “p”. 

Ts = Temperature at standard conditions (60 ̊F). 

Ta,p = Temperature at actual conditions in the unique physical volume ( ̊F). 

Ps = Absolute pressure at standard conditions (14.7 psia). 

Pa,b,p = Absolute pressure at actual conditions in the unique physical volume 

(psia) at the beginning of the blowdown “p”. 

Pa,e,p = Absolute pressure at actual conditions in the unique physical volume 

(psia) at the end of the blowdown “p”; 0 if blowdown volume is purged using 

non-GHG gases. 

(3) Calculate both CH4 and CO2 volumetric and mass emissions using 

calculations in paragraph (s) and (t) of this section. 

(4) Calculate total annual venting emissions for all blowdown vent stacks by 

adding all standard volumetric and mass emissions determined by Equation 

13 or 14 and paragraph (g)(3) of this section. 

(h) Dump Valves. Calculate emissions from occurrences of gas-liquid separator liquid 

dump valves not closing during the calendar year by using the method found in 

95153(i). 

(i) Transmission storage tanks. For vent stacks connected to one or more 

transmission condensate storage tanks, either water or hydrocarbon, without vapor 

recovery, in onshore natural gas transmission compression and onshore petroleum 

and natural gas production, the operator of a facility must calculate CH4, CO2 and 

N2O annual emissions from condensate scrubber dump valve leakage as follows: 

(1) Monitor the tank vapor vent stack annually for emissions using an optical gas 

imaging instrument according to methods set forth in section 95154(a)(1) or by 

directly measuring the tank vent using a flow meter or high volume sampler 

according to methods in section 95154(b) through (d) for a duration of five 

minutes, or a calibrated bag according to methods in section 95154(b). Or the 

facility operator may annually monitor leakage through compressor scrubber 

dump valve(s) into the tank using an acoustic leak detection device according 

to methods in paragraph 95154(a)(5). 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 219 February 2015 

(2) If the tank vapors from the vent stack are continuous for five minutes, or the 

acoustic leak detection device detects a leak, then use one of the following 

two methods in paragraph (i)(2) of this section to quantify annual emissions: 

(A) Use a meter, such as a turbine meter, calibrated bag, or high flow 

sampler to estimate tank vapor volumes from the vent stack according to 

methods set forth in section 95154(b) through (d). If a continuous flow 

measurement device is not installed, the facility operator may install a 

flow measuring device on the tank vapor vent stack. If the vent is directly 

measured for five minutes under paragraph (i)(1) of this section to detect 

continuous leakage, this serves as the measurement.

(B) Use an acoustic leak detection device on each scrubber dump valve 

connected to the tank according to the method set forth in section 

95154(a)(5). 

(C) Use the appropriate gas composition in paragraph (s)(2)(C) of this 

section. 

(D) Calculate GHG volumetric and mass emissions at standard conditions 

using calculations in paragraphs (r), (s), and (t) of this section, as 

applicable to the monitoring equipment used. 

(3) If a leaking dump valve is identified, the leak must be counted as having 

occurred since the beginning of the calendar year, or from the previous test 

that did not detect leaking in the same calendar year. If the leaking dump 

valve is fixed following leak detection, the leak duration will end upon being 

repaired. If the leaking dump valve is identified and not repaired, the leak 

must be counted as having occurred through the rest of the calendar year. 

(4) Calculate annual emissions from storage tanks to flares as follows: 

(A) Use the storage tank emissions volume and gas composition as 

determined in paragraphs (i)(1) through (i)(3) of this section. 

(B) Use the calculation methodology of flare stacks in paragraph (l) of this 

section to determine storage tank emissions sent to a flare. 

(j) Well testing venting and flaring. Calculate CH4, CO2 and N2O (when flared) gas 

and oil well testing venting and flaring emissions as follows: 

(1) Determine the gas-to-oil ratio (GOR) of the hydrocarbon production from all oil 

well(s) tested. Determine the production rate from all gas well(s) tested. 

(2) If GOR cannot be determined from available data, then the facility operator 

must measure quantities reported in this section according to one of the two 

procedures in paragraph (j)(2) of this section to determine GOR. 

(A) The facility operator may use an appropriate standard method published 

by a consensus-based standards organization if such a method exists; or 

(B) The facility operator may use an industry standard practice as described 

in section 95154(b). 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 220 February 2015 

(3) Estimate venting emissions using Equation 15 (for oil wells) or Equation 16 

(for gas wells) of this section. 

d, = n#z ∗ hz ∗ W (Eq. 15) 

d, = Lz ∗ W (Eq. 16) 

Where: 

ES,n = Annual volume of gas emissions from well(s) testing in cubic feet under 

actual conditions. 

Ea,n = Annual volumetric natural gas emissions from well(s) testing in cubic 

feet under actual conditions. 

GOR = Gas-to-oil ratio, for well p in basin q, in cubic feet of gas per barrel of 

oil; oil here refers to hydrocarbon liquids produced of all API gravities. 

FR = Annual average flow rate in barrels of oil per day for the oil well(s) being 

tested. 

PR = Average annual production rate in actual cubic feet per day for the gas 

well(s) being tested. 

D = Number of days during the year the well(s) is tested. 

(4) For equation 16 calculate natural gas volumetric emissions at standard 

conditions using calculations in paragraph (r) of this section. 

(5) Calculate both CH4 and CO2 volumetric and mass emissions from volumetric 

natural gas emissions using the calculations in paragraphs (s) and (t) of this 

section. 

(6) Calculate emissions from well testing to flares as follows: 

(A) Use the well testing emissions volume and gas composition as 

determined in paragraphs (j)(1) through (3) of this section. 

(B) Use the calculation methodology of flare stacks in paragraph (l) of this 

section to determine well testing emissions from the flare. 

(k) Associated gas venting and flaring. Calculate CH4, CO2 and N2O (when flared) 

associated gas venting and flaring emissions not in conjunction with well testing as 

follows: 

(1) Determine the GOR of the hydrocarbon production from each well whose 

associated natural gas is vented or flared. If GOR from each well is not 

available, the GOR from a cluster of wells in the same basin shall be used. 

(2) If GOR cannot be determined from available data, then use one of the two 

procedures in paragraph (k)(2) of this section to determine GOR. 

(A) Use an appropriate standard method published by a consensus-based 

standards organization if such a method exists, including ARB’s sampling 

methodology and flash liberation test procedure in Appendix B of this 

regulation; or 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 221 February 2015 

(B) The facility operator may use an industry standard practice as described 

in section 95154(b). 

(3) Estimate venting emissions using Equation 17 of this section. 

d, = ∑ n#zr,{

g

r;< ∗ kr,{ (Eq.17) 

Where: 

Ea,n = Annual volumetric natural gas emissions, at the facility level, from 

associated gas venting under actual conditions, in cubic feet. 

GORp,q = Gas-to-oil ratio, for well p in basin q, in cubic feet of gas per barrel of 

oil; oil here refers to hydrocarbon liquids produced of all API gravities. 

Vp,q = Volume of oil produced, for well p in basin q, in barrels in the calendar 

year during which associated gas was vented or flared. 

x = Total number of wells in the basin that vent or flare associated gas. 

(4) Calculate natural gas volumetric emissions at standard conditions using 

calculations in paragraph (r) of this section. 

(5) Calculate both CH4 and CO2 volumetric and mass emissions from volumetric 

natural gas emissions using calculations in paragraphs (s) and (t) of this 

section. 

(6) Calculate emissions from associated gas to flares as follows: 

(A) Use the associated natural gas volume and composition as determined in 

paragraph (k)(1) through (k)(4) of this section. 

(B) Use the calculation methodology of flare stacks in paragraph (l) of this 

section to determine associated gas emissions from the flare. 

(l) Flare stack or other destruction device emissions. Calculate CO2, CH4 and N2O 

emissions from a flare stack or other destruction device as follows: 

(1) For the purposes of this reporting requirement, the facility operator must 

calculate emission from all flares, incinerators, oxidizers and vapor combustion 

units. 

(2) If a continuous flow measurement device is installed on the flare or destruction 

device, the measured flow volumes must be used to calculate the flare gas 

emissions. If all of the gas or liquid sent to the flare or destruction device is 

not measured by the existing flow measurement device, then the flow not 

measured can be estimated using engineering calculations based on best 

available data or company records. If a continuous flow measurement device 

is not installed on the flare or destruction device, a flow measuring device can 

be installed on the flare or destruction device or engineering calculations 

based on process knowledge, company records, or best available data. 

(3) If a continuous gas composition analyzer is not installed on gas or liquid 

supply to the flare or destruction device, use the appropriate gas composition 

for each stream of hydrocarbons going to the flare as follows: 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 222 February 2015 

(A) For onshore natural gas processing, when the stream going to the flare is 

natural gas, use the GHG mole percent in feed natural gas for all streams 

upstream of the de-methanizer or dew point control, and GHG mole 

percent in facility specific residue gas to transmissions pipeline systems 

for all emissions sources downstream of the de-methanizer overhead or 

dew point control for onshore natural gas processing facilities. For 

onshore natural gas processing plants that solely fractionate a liquid 

stream, use the GHG mole percent in feed natural gas liquid for all 

streams. 

(B) For any applicable industry segment, when the stream going to the flare 

is a hydrocarbon product stream, such as methane, ethane, propane, 

butane, pentane-plus and mixed light hydrocarbons, then the facility 

operator may use a representative composition from the source for the 

stream determined by engineering calculation based on process 

knowledge and best available data. 

(4) Determine flare combustion efficiency from manufacturer specifications. If not 

available, assume that flare combustion efficiency is 98 percent. 

(5) Calculate GHG volumetric emissions at actual conditions using Equations 18 

and 19 of this section. 

d,ï = k ∗ ùï ∗ V 1 − ƞ$ ∗ }ü + }†\ (Eq. 18) 

d,j = k ∗ ùj + ∑ yƞ ∗ k ∗ °¢ ∗ z¢ ∗ }ü|

ã

¢;< (Eq. 19) 

Where: 

Ea,CH4 = Annual CH4 emissions from flare stack in cubic feet, under actual 

conditions. 

Ea,CO2 = Annual CO2 emissions from flare stack in cubic feet, under actual 

conditions. 

Va = Volume of gas sent to flare in cubic feet, during the year. 

Ƞ = Fraction of gas combusted by a burning flare (default is 0.98). For gas 

sent to an unlit flare, ƞ is zero. 

XCH4 = Mole fraction of CH4 in gas to the flare. 

ZL = Fraction of the feed gas sent to a burning flare (equal to 1 – ZU). 

ZU = Fraction of the feed gas sent to an unlit flare determined by engineering 

estimate and process knowledge based on best available data and operating 

records. 

XCO2 = Mole fraction of CO2 in gas to the flare. 

Yj = Mole fraction of gas hydrocarbon constituents j (such as methane, 

ethane, propane, and pentanes-plus). 

Rj = Number of carbon atoms in the gas hydrocarbon constituent j: 1 for 

methane, 2 for ethane, 3 for propane, 4 for butane, and 5 for pentanes-plus. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 223 February 2015 

(6) Calculate GHG volumetric emissions at standard conditions using calculations 

in paragraph (r) of this section. 

(7) Calculate both CH4 and CO2 mass emissions from volumetric CH4 and CO2 

emissions using calculation in paragraph (t) of this section. 

(8) Calculate N2O emissions from flare stacks using Equation 37 in paragraph (y) 

of this section. 

(9) If the facility operator operates and maintains a CEMS that has both a CO2

concentration monitor and volumetric flow rate monitor, calculate only CO2

emissions for the flare. The facility operator must follow the Tier 4 Calculation 

Methodology and all associated calculation, quality assurance, reporting, and 

record keeping requirements for Tier 4 in section 95115. If a CEMS is used to 

calculate flare stack emissions, the requirements specified in paragraphs (l)(1) 

through (l)(8) are not required. If a CO2 concentration monitor and volumetric 

flow rate monitor are not available, the facility operator may elect to install a 

CO2 concentration monitor and a volumetric flow rate monitor that comply with 

all of the requirements specified for the Tier 4 Calculation Methodology in 

section 95115 of this article (stationary fuel combustion sources). 

(10) The flare emissions determined under paragraph (l) of this section must be 

corrected for flare emissions calculated and reported under other paragraphs 

of this section to avoid double counting of these emissions. 

(11) If source types in section 95153 use Equations 18 and 19 of this section, use 

volume under actual conditions for the parameter, Va, in these equations. 

(m) Centrifugal compressor venting. Calculate CH4, CO2 and N2O (when flared) 

emissions from both wet seal and dry seal centrifugal compressor vents as follows: 

(1) For each centrifugal compressor with a rated horsepower of 250hp or greater 

covered by sections 95152(c)(12), (d)(5), (e)(6), (f)(5), (g)(3), and (h)(3) the 

operator must conduct an annual measurement in each operating mode in 

which it is found for more than 200 hours in a calendar year. Measure 

emissions from all vents (including emissions manifolded to common vents) 

including wet seal oil degassing vents, unit isolation valve vents, and 

blowdown valve vents. Record emissions from the following vent types in the 

specified compressor modes during the annual measurement: 

(A) Operating mode, blowdown valve leakage through the blowdown vent, 

wet seal and dry seal compressors. For all centrifugal compressor 

start-ups where natural gas is used as spin-up or starting gas (i.e. not 

combusted in the compressor), venting of this gas must be quantified and 

reported as follows: 

dì = ∑ k£ 1 − h$°



<

 (Eq. 20) 

Where: 

ESGi = Annual GHGi (CO2 and CH4) vented emissions at standard 

conditions in cubic feet. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 224 February 2015 

n = number of compressor start-ups using spin gas. 

Vsg = Volume of spin-up gas in standard cubic feet determined by 

metering or engineering estimates based on best available data. 

CF = Fraction of spin-up gas that is sent to vapor recovery or fuel 

gas as determined by keeping logs of the number of operating 

hours for the vapor recovery system and the amount of gas that is 

directed to the fuel gas or vapor recovery system. 

Yi = Mole fraction of GHGi in the vent gas. 

Calculate both CH4 and CO2 mass emissions from volumetric 

emissions using calculations in paragraph (t) of this section. 

(B) Operating mode, wets seal oil degassing vents. 

(C) Not operating depressurized mode, unit isolation valve leakage through 

open blowdown vent, without blind flanges, wet seal and dry seal 

compressors. 

1. For the not operating depressurized mode, each compressor must be 

measured at least once in any three consecutive calendar years. If a 

compressor is not operated and has blind flanges in place throughout 

the three year period, measurement is not required in this mode. If 

the compressor is in standby depressurized mode without blind 

flanges in place and is not operated throughout the three year period, 

it must be measured in the standby depressurized mode. 

2. An engineering estimate approach based on similar equipment 

specifications and operating conditions may be used to determine the 

MTm variable in place of actual measured values for centrifugal 

compressors that are operated for no more than 200 hours in a 

calendar year and used for peaking purposes in place of metered 

gas emissions if an applicable meter is not present on the 

compressor. 

(2) For wet seal oil degassing vents, determine vapor volumes sent to an 

atmospheric vent or flare, using a temporary meter such as a vane 

anemometer or permanent flow meter according to section 95154(b) of this 

section. If a permanent flow meter is not installed, the operator may install a 

permanent flow meter on the wet seal oil degassing tank vent. 

(3) For blowdown valve leakage and isolation valve leakage to open ended vents, 

use one of the following methods: Calibrated bagging or high volume sampler 

according to methods set forth in sections 95154(c) and 95154(d), 

respectively. For through valve leakage, such as isolation valves, the facility 

operator may install a port for insertion of a temporary meter, or a permanent 

flow meter, on the vents. 

(4) To determine Yi, use gas composition data from a continuous gas analyzer if a 

continuous gas analyzer is installed, or quarterly measurements of gas 

composition where a continuous gas analyzer is not installed. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 225 February 2015 

(5) Estimate annual emissions using the flow measurement and Equation 21 of 

this section. 

d,,e = ∑e Z_e ∗ _e ∗ ° ∗ 1 − h$ (Eq. 21) 

Where: 

Es,i,m = Annual GHG (either CH4 or CO2) volumetric emissions at standard 

conditions, in cubic feet. 

MTm = Measured gas emissions in standard cubic feet per hour during 

operating mode m as described in sections (m)(1)(A) through (m)(1)(C). 

Tm = Total time the compressor is in the mode for which Es,i is being 

calculated, in the calendar year in hours. 

Yi = Mole fraction of GHGi in the vent gas. 

CF = Fraction of centrifugal compressor vent gas that is sent to vapor 

recovery or fuel gas as determined by keeping logs of the number of 

operating hours for the vapor recovery system and the amount of gas that is 

directed to the fuel gas or vapor recovery system. 

(6) For each centrifugal compressor with a rated horsepower of less than 250hp 

covered by sections 95152(c)(12), (d)(5), (e)(6), (f)(5), (g)(3), and (h)(3), the 

operator must calculate annual emissions from both wet seal and dry seal 

centrifugal compressor vents using Equation 22 of this section. 

d, = RcPQ ∗ dh (Eq. 22) 

Where: 

Es,i = Annual total volumetric GHG emissions at standard conditions from 

centrifugal compressors (<250hp) in cubic feet. 

Count = Total number of centrifugal compressors less than 250hp. 

EFi = Emission factor for GHGi. Use 1.2 x 107

 standard cubic feet per year per 

compressor for CH4 and 5.30 x 105 standard cubic feet per year per 

compressor for CO2 at 60 ̊F and 14.7 psia. 

(7) Calculate both CH4 and CO2 mass emissions from volumetric emissions using 

calculations in paragraph (t) of this section. 

(8) Calculate emissions from seal oil degassing vent vapors to flares as follows: 

(A) Use the seal oil degassing vent vapor volume and gas composition as 

determined in paragraphs (m)(2) through (m)(4) of this section. 

(B) Use the calculation methodology of flare stacks in paragraph (l) of this 

section to determine degassing vent vapor emissions from the flare. 

(n) Reciprocating compressor venting. Calculate CH4 and CO2, and N2O (when flared) 

emissions from all reciprocating compressor vents as follows: 

(1) For each reciprocating compressor with a rated horsepower of 250hp or 

greater covered in sections 95152(c)(13), (d)(6), (e)(7), (f)(6), (g)(4), and (h)(4) 

the facility operator must conduct an annual measurement for each 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 226 February 2015 

compressor in each operating mode in which it is found for more than 200 

hours in a calendar year. Measure emissions from (including emissions 

manifolded to common vents) reciprocating rod packing vents, unit isolation 

valve vents, and blowdown valve vents. Record emissions from the following 

vent types in the specified compressor modes during the annual measurement 

as follows: 

(A) Operating or standby pressurized mode, blowdown vent leakage through 

the blowdown vent stack. 

(B) Operating mode, reciprocating rod packing emissions. 

(C) Not operating depressurized mode, unit isolation valve leakage through 

the blowdown vent stack, without blind flanges. 

1. For the not operating, depressurized mode, each compressor must 

be measured at least once in any three consecutive calendar years if 

this mode is not found in the annual measurement. If a compressor 

is not operated and has blind flanges in place throughout the three 

year period, measurement is not required in this mode. If the 

compressor is in standby depressurized mode without blind flanges 

in place and is not operated throughout the three year period, it must 

be measured in the standby depressurized mode. 

2. An engineering estimate approach based on similar equipment 

specifications and operating conditions may be used to determine the 

MTm variable in place of actual measured values for reciprocating 

compressors that are operated for no more than 200 hours in a 

calendar year and used for peaking purposes in place of metered 

gas emissions if an applicable meter is not present on the 

compressor. 

(2) If reciprocating rod packing and blowdown vent are connected to an openended vent line, use one of the following two methods to calculate emissions: 

(A) Measure emissions from all vents (including emissions manifolded to 

common vents) including rod packing, unit isolation valves, and 

blowdown vents using either calibrated bagging or high volume sampler 

according to methods set forth in sections 95154(c) and 95154(d), 

respectively. 

(B) Use a temporary meter such as a vane anemometer or a permanent 

meter such as an orifice meter to measure emissions from all vents 

(including emissions manifolded to a common vent) including rod packing 

vents and unit isolation valve leakage through blowdown vents according 

to methods set forth in section 95154(b). If a permanent flow meter is not 

installed, the facility operator may install a port for insertion of a 

temporary meter or a permanent flow meter on the vents. For throughvalve leakage to open ended vents such as unit isolation valves on not 

operating, depressurized compressors, use an acoustic detection device 

according to methods set forth in section 95154(a).
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 227 February 2015 

(3) If reciprocating rod packing is not equipped with a vent line use the following 

method to calculate emissions: 

(A) The facility operator must use the methods described in section 95154(a) 

to conduct annual leak detection of equipment leaks from the packing 

case into an open distance piece, or from the compressor crank case 

breather cap or other vent with a closed distance piece. 

(B) Measure emissions found in paragraph (n)(2)(A) of this section using an 

appropriate meter, or calibrated bag, or high volume sampler according to 

the methods set forth in sections 95154(b), (c), and (d) respectively. 

(4) To determine Yi, use gas composition data from a continuous gas analyzer if a 

continuous gas analyzer is installed, or quarterly measurements of gas 

composition where a continuous gas analyzer is not installed. 

(5) Estimate annual emissions using the flow measurement and Equation 23 of 

this section. 

d,,e = ∑e Z_e ∗ _e ∗ Y ∗ 1 − h$ (Eq. 23) 

Where: 

Es,i,m = Annual GHGi (either CH4 or CO2) volumetric emissions at standard 

conditions, in cubic feet. 

MTm = Measured gas emissions in standard cubic feet. 

Tm = Total time the compressor is in the mode for which Es,i,m is being 

calculated, in the calendar year in hours. 

Yi = Mole fraction of GHGi in the vent gas. 

CF = Fraction of reciprocal compressor vent gas that is sent to vapor recovery 

or fuel gas as determined by keeping logs of the number of operating hours 

for the vapor recovery system and the amount of gas that is directed to the 

fuel gas or vapor recovery system. 

(6) For each reciprocating compressors with a rated horsepower of less than 

250hp, the operator must calculate annual emissions using Equation 24 of this 

section. 

d, = RcPQ ∗ dh (Eq. 24) 

Where: 

Es,i = Annual total volumetric GHG emissions at standard conditions from 

reciprocating compressors in cubic feet. 

Count = Total number of reciprocating compressors for the facility operator. 

EFi = Emission factor for GHGi. Use 9.48 x 103 standard cubic feet per year 

per compressor for CH4 and 5.27 x 102 standard cubic feet per year per 

compressor for CO2 at 60 ̊F and 14.7 psia. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 228 February 2015 

(7) Estimate CH4 and CO2 volumetric and mass emissions from volumetric natural 

gas emissions using the calculations in paragraphs (s) and (t) of this section. 

(o) Leak detection and leaker emission factors. The operator must use the methods 

described in section 95154(a) to conduct leak detection(s) of equipment leaks from 

all components types listed in sections 95152(c)(16), (d)(7), (e)(8), (f)(7), (g)(5), 

(h)(5), and (i)(1). This paragraph (o) applies to component types in streams with 

gas content greater than 10 percent CH4 plus CO2 by weight. Component types in 

streams with gas content less than 10 percent CH4 plus CO2 by weight do not need 

to be reported. Tubing systems equal to or less than one half inch diameter are 

exempt from the requirements of this paragraph (o) and do not need to be reported. 

If equipment leaks are detected for sources listed in this paragraph (o), calculate 

equipment leak emissions per component type per reporting facility using Equations 

25 or 26 of this section for each component type. Use Equation 25 for industry 

segments listed in section 95150(a)(1) – (a)(7). Use Equation 26 for natural gas 

distribution facilities as defined in section 95150(a)(8). Use methods found in 

section 95153(t) to convert GHGi volume emissions to GHGi mass emissions. 

d, = nln ∗ ∑ ydh ∗ _r|

g

r;< (Eq. 25) 

d, = nln ∗ ∑ ∑ ydh ∗ _r,{|

g

r;<



{;ò< (Eq. 26) 

Where: 

Es,i = Annual total volumetric GHG emissions at standard conditions from each 

component type in cubic feet, as specified in (o)(1) through (o)(8) of this section. 

X = Total number of each component type. 

EF = Leaker emission factor for specific component types listed in Table 1A and 

2 through 7 of Appendix A. 

GHGi = For onshore petroleum and natural gas production facilities, 

concentration of GHGi, CH4 or CO2, in produced natural gas as defined in 

paragraph (s)(2)(A) of this section; For onshore natural gas processing facilities, 

concentration of GHGi, CH4 or CO2, in the total hydrocarbon of the feed natural 

gas; for onshore natural gas transmission compression and underground natural 

gas storage, GHGi equals 0.975 for CH4 and 1.1 x 10-2 for CO2; for LNG storage 

and LNG import and export equipment, GHGi equals 1 for CH4 and 0 for CO2; 

and for natural gas distribution, GHGi equals 1 for CH4 and 1.1 x 10-2 for CO2 or 

use the experimentally determined gas composition for CO2 and CH4. 

Tp = The total time the component, p, was found leaking and operational, in 

hours. If one leak detection survey is conducted, assume the component was 

leaking for the entire calendar year. If multiple leak detection surveys are 

conducted, assume that the component found to be leaking has been leaking 

since the previous survey (if not found leaking in the previous survey) or the 

beginning of the calendar year (if it was found leaking in the previous survey) or 

the beginning of the calendar year (if it was found leaking in the previous 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 229 February 2015 

survey). For the last leak detection survey in the calendar year, assume that all 

leaking components continue to leak until the end of the calendar year. 

t = Calendar year of reporting. 

n = The number of years over which one complete cycle of leak detection is 

conducted over all the Transmission – Distribution (T-D) transfer stations in a 

natural gas distribution facility; 0 < n ≤ 5. For the first (n-1) calendar years of 

reporting the summation in Equation 26 should be for years that the data is 

available. 

Tp,q = The total time the component, p, was found leaking and operational, in 

hours, in year q. If one leak detection survey is conducted, assume the 

component was leaking for the entire period n. If multiple leak detection surveys 

are conducted, assume the component found to be leaking has been leaking 

since the previous survey) or the beginning of the calendar year (if it was found 

to be leaking in the previous survey). For the last leak detection survey in the 

cycle, assume that all leaking components continue to leak until the end of the 

cycle. 

(1) The operator must select to conduct either one leak detection survey in a 

calendar year or multiple complete leak detection surveys in a calendar year. 

The number of leak detection surveys selected must be conducted during the 

calendar year. 

(2) Onshore petroleum and natural gas production facilities must use the 

appropriate default leaker emissions factors listed in Table 1A of Appendix A 

for all leaks from equipment types in the table. 

(3) Onshore natural gas processing facilities must use the appropriate default 

leaker emission factors listed in Table 2 of Appendix A for equipment leaks 

detected from valves, connectors, open ended lines, pressure relief valves, 

and meters. 

(4) Onshore natural gas transmission facilities shall use the appropriate default 

leaker emission factors listed in Table 3 of Appendix A for equipment leaks 

detected from valves, connectors, open ended lines, pressure relief valves, 

and meters. 

(5) Underground natural gas storage facilities for storage stations shall use the 

appropriate default leaker emission factors listed in Table 4 of Appendix A for 

equipment leaks detected from valves, connectors, open ended lines, 

pressure relief valves, and meters. 

(6) LNG storage facilities shall use the appropriate default leaker emission factors 

listed in Table 5 of Appendix A for equipment leaks detected from valves, 

pump seals, connectors, and other equipment. 

(7) LNG import and export facilities shall use the appropriate default leaker 

emission factors listed in Table 6 of Appendix A for equipment leaks detected 

from valves, pump seals, connectors, and other equipment. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 230 February 2015 

(8) Natural gas distribution facilities for above ground transmission-distribution 

transfer stations, shall use the appropriate default leak emission factors listed 

in Table 7 of Appendix A for equipment leaks detected from connectors, block 

valves, control valves, pressure relief valves, orifice meters, regulators, and 

open ended lines. Leak detection at natural gas distribution facilities is only 

required at above grade stations that qualify as transmission-distribution 

transfer stations. Below grade transmission-distribution transfer stations and 

all metering-regulating stations that do meet the definition of transmissiondistribution transfer stations are not required to perform component leak 

detection under this section. 

(A) Natural gas distribution facilities may choose to conduct leak detection at 

the T-D transfer stations over multiple years, not exceeding a five year 

period to cover all T-D transfer stations. If the facility operator chooses to 

use the multiple year option then the number of T-D transfer stations that 

are monitored in each year should be approximately equal across all 

years in the cycle without monitoring the same station twice during the 

multiple year survey. 

(p) Population count and emission factors. This paragraph applies to emissions 

sources listed in sections 95152(c)(16), (f)(7), (g)(5), (h)(5), (i)(2), (i)(3), (i)(4), (i)(5), 

(i)(6), and (i)(10) on streams with gas content greater than 10 percent CH4 plus CO2

by weight. Emissions sources in streams with gas content less than 10 percent 

CH4 plus CO2 by weight do not need to be reported. Tubing systems equal to or 

less than one half inch diameter are exempt from the requirements of paragraph (p) 

of this section and do not need to be reported. Calculate emissions from all 

sources listed in this paragraph using Equation 27 of this section. 

d, = RcPQ ∗ dh ∗ nln ∗ _ (Eq. 27) 

Where: 

Es,i = Annual volumetric GHG emissions at standard conditions from each 

component type in cubic feet. 

Counts = Total number of this type of emission source at the facility. 

Underground natural gas storage shall count the components listed for 

population emission factors in Table 4. LNG storage shall count the number 

of vapor recovery compressors. LNG import and export shall count the 

number of vapor recovery compressors. Natural gas distribution shall count 

the meter/regulator runs and the number of customer meters as described in 

paragraph (p)(6) of this section. 

EFs = Population emission factor for the specific component type, as listed in 

Table 1A and Tables 3 through Table 7 of Appendix A. Use appropriate 

emission factor for operations in Western U.S., according to Table 1(A) – 1(C) 

of Appendix A. EF for meter/regulator runs at above grade metering-regulator 

stations is determined in Equation 28 of this section. 

GHGi = For onshore petroleum and natural gas production facilities, 

concentration of GHGi, CH4 or CO2, in produced natural gas as defined in 

paragraph (s)(2) of this section; for onshore natural gas transmission 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 231 February 2015 

compression and underground natural gas storage, GHGi equals 0.975 for 

CH4 and 1.1 x 10-2 for CO2; for LNG storage and LNG import and export 

equipment, GHGi equals 1 for CH4 and 0 for CO2; for natural gas distribution, 

GHGi equals 1 for CH4 and 1.1 x 10-2 for CO2 or use the experimentally 

determined gas composition for CO2 and CH4. 

Ts = Total time that each component type associated with the equipment leak 

emission was operational in the calendar year, in hours, using engineering 

estimate based on best available data, assume Ts = 8760 hours for section 

95152(i)(10). 

(1) Calculate both CH4 and CO2 mass emissions from volumetric emissions using 

calculations in paragraph (t) of this section. 

(2) Onshore petroleum and natural gas production facilities must use the 

appropriate default population emission factors listed in Table 1A of 

Appendix A for equipment leaks from valves, connectors, open ended lines, 

pressure relief valves, pump, flanges, and other. Major equipment and 

components associated with gas wells are considered gas service 

components in reference to Table 1A of Appendix A and major natural gas 

equipment in reference to Table 1B of Appendix A. Major equipment and 

components associated with crude oil wells are considered crude service 

components in reference to Table 1A of Appendix A and major crude oil 

equipment in reference to Table 1C of Appendix A. Where facilities conduct 

EOR operations the emissions factor listed in Table 1A of Appendix A shall be 

used to estimate all streams of gases, including recycle CO2 stream. The 

component count can be determined using either of the methodologies 

described in this paragraph (p)(2). The same methodology must be used for 

the entire calendar year. 

(A) Component Count Methodology 1. For all onshore petroleum and natural 

gas production operations in the facility perform the following activities: 

1. Count all major equipment listed in Table 1B and Table 1C of 

Appendix A. For meters/piping, use one meters/piping per well-pad. 

2. Multiply major equipment counts by the average component counts 

listed in Table 1B and 1C of Appendix A for onshore natural gas 

production and onshore oil production, respectively. Use the 

appropriate factor in Table 1A of Appendix A for operations in 

Eastern and Western U.S. according to the mapping in Table 1B of 

Appendix A. 

(B) Component Count Methodology 2. Count each component individually 

for the facility. Use the appropriate factor in Table 1A of Appendix A for 

operations in the Western U.S. 

(3) Underground natural gas storage facilities for storage wellheads must use the 

appropriate default population emission factors listed in Table 4 of Appendix A 

for equipment leak from connectors, valves, pressure relief valves and open 

ended lines. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 232 February 2015 

(4) LNG storage facilities must use the appropriate default population emission 

factors listed in Table 5 of Appendix A for equipment leak from vapor recovery 

compressors. 

(5) LNG import and export facilities must use the appropriate emission factor 

listed in Table 6 of Appendix A for equipment leak from vapor recovery 

compressors. 

(6) Natural gas distribution facilities must use the appropriate emission factors as 

described in paragraph (p)(6) of this section. 

(A) Below grade metering-regulating stations; distribution mains; distribution 

services; and customer meters must use the appropriate default 

population emission factors listed in Table 7 of Appendix A. Below grade 

T-D transfer stations must use the emission factor for below grade 

metering-regulating stations. 

(B) Emissions from all above grade metering-regulating stations (including 

above grade T-D transfer stations) must be calculated by applying the 

emission factor calculated in Equation 28 and the total count of 

metering/regulator runs at all above grade metering-regulating stations 

(inclusive of T-D transfer stations) to Equation 27. The facility wide 

emission factor in Equation 28 will be calculated by using the total 

volumetric GHG emissions at standard conditions for all equipment leak 

sources calculated in Equation 26 and the count of meter/regulator runs 

located at above grade transmission-distribution transfer stations that 

were monitored over the years that constitute one complete cycle as per 

(p)(1) of this section. A meter on a regulator run is considered one meter 

regulator run. Facility operators that do not have above grade T-D 

transfer stations shall report a count of above grade metering-regulating 

stations only and do not have to comply with section 95157(c)(16)(T). 

dh = d,/ 8760 ∗ RcPQ$ (Eq. 28) 

Where: 

EF = Facility emission factor for a meter/regulator run per component type at 

above grade meter/regulator run for GHGi in cubic feet per meter/regulator 

run per hour. 

Es,i = Annual volumetric GHGi emissions, CO2 or CH4, at standard condition 

from each component type at all above grade T-D transfer stations, from 

Equation 26. 

Count = Total number of meter/regulator runs at all T-D transfer stations that 

were monitored over the years that constitute one complete cycle as per 

paragraph (o)(8)(A) of this section. 

8760 = Conversion to hourly emissions. 

(q) Offshore petroleum and natural gas production facilities. Operators must report 

CO2, CH4, and N2O emissions for offshore petroleum and natural gas production 

from all equipment leaks, vented emission, and flare emission source types as 

identified in the data collection and emissions estimate study (Year 2008 Gulfwide 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 233 February 2015 

Emission Inventory Study (GOADS) (December 2010)) conducted by BOEMRE in 

compliance with 30 CFR §§250.302 through 304 (July 1, 2011), which is hereby 

incorporated by reference. 

(1) Offshore production facilities under BOEMRE jurisdiction must report the same 

annual emissions as calculated and reported by BOEMRE in data collection 

and emissions estimate study published by BOEMRE and referenced in 30 

CFR §§250.302 through 304 (July 1, 2011) Gulfwide Offshore Activities Data 

System (GOADS). 

(A) The BOEMRE data is collected and reported every other year. In years 

where the BOEMRE data is not available, use the previous year’s 

BOEMRE data and adjust the emissions based on the operating time for 

the facility relative to the operating time in the previous year’s BOEMRE 

data. 

(2) Offshore production facilities that are not under BOEMRE jurisdiction must use 

monitoring methods and calculation methodologies published by BOEMRE 

and referenced in 30 CFR §§250.302 through 304 (July 1, 2011) to calculate 

and report emissions (GOADS). 

(A) The BOEMRE data is collected and reported every other year. In years 

where the BOEMRE data is not available, use the previous year’s 

BOEMRE data and adjust the emissions based on the operating time for 

the facility relative to the operating time in the previous year’s BOEMRE 

data. 

(3) If BOEMRE discontinues or delays their data collection effort by more than 4 

years, then offshore operators must once in every 4 years use the most recent 

BOEMRE data collection and emissions estimation methods to report 

emission from the facility sources. 

(4) For either the first or subsequent year of reporting, offshore facilities either 

within or outside of BOEMRE jurisdiction that were not covered in the previous 

BOEMRE data collection cycle must use the BOEMRE data collection and 

emissions estimation methods published by BOEMRE and referenced in 

30 CFR §§250.302 through 304 (July 1, 2011) (GOADS) to calculate and 

report. 

(r) Volumetric emissions. If equation parameters in section 95153 are already at 

standard conditions, which results in volumetric emissions at standard conditions, 

then this paragraph does not apply. Calculate volumetric emissions at standard 

conditions as specified in paragraphs (r)(1) or (2) of this section, with actual 

pressure and temperature determined by engineering estimates based on best 

available data unless otherwise specified. 

(1) Calculate natural gas volumetric emissions at standard conditions using actual 

natural gas emission temperature and pressure, and Equation 29 of this 

section. 

d, = d, ∗ 459.67 + _

$ ∗ L/ 459.67 + _$ ∗ L$ (Eq. 29) 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 234 February 2015 

Where: 

Es,n = Natural gas volumetric emissions at standard temperature and pressure 

(STP) conditions in cubic feet except Es,n equals (FRs,p) for each well p, when 

calculating either subsonic or sonic flow rates under section 95153(f). 

Ea,n = Natural gas volumetric emissions at actual conditions in cubic feet. 

Ts = Temperature at standard conditions (60 ̊F). 

Ta = Temperature at actual conditions ( ̊F). 

Ps = Absolute pressure at standard conditions (14.7 psia). 

Pa = Absolute pressure at actual conditions (psia). 

(2) Calculate GHG volumetric emissions at standard conditions using actual GHG 

emissions temperature and pressure, and Equation 30 of this section. 

d, = d, ∗ 459.67 + _

$ ∗ L/ 459.67 + _$ ∗ L$ (Eq. 30) 

Where: 

Es,i = GHG i volumetric emissions at standard conditions in 

cubic feet. 

Ea,i = GHG i volumetric emissions at actual conditions in cubic feet. 

Ts = Temperature at standard conditions (60 ̊F). 

Ps = Absolute pressure at standard conditions (14.7 psia). 

Pa = Absolute pressure at actual conditions (Psia).

(3) Facility operators using 68 ̊F for standard temperature may use the ratio 

519.67/527.67 to convert volumetric emissions from 68 ̊F to 60 ̊F. 

(s) GHG volumetric emissions. Calculate GHG volumetric emissions at standard 

conditions as specified in paragraphs (s)(1) and (s)(2) of this section, with mole 

fraction of GHGs in the natural gas determined by engineering estimate based on 

best available data unless otherwise specified. 

(1) Estimate CH4 and CO2 emissions from natural gas emissions using 

Equation 31 of this section. 

d, = d, ∗ Z (Eq. 31) 

Where: 

Es,i = GHG i (either CH4 or CO2) volumetric emissions at standard conditions 

in cubic feet. 

Es,n = Natural gas volumetric emissions at standard conditions in cubic feet. 

Mi = Mole fraction of GHG i in the natural gas. 

(2) For Equation 31 of this section, the mole fraction, Mi, must be the annual 

average mole fraction for each basin or facility, as specified in paragraphs 

(s)(2)(A) through (s)(2)(G) of this section. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 235 February 2015 

(A) GHG mole fraction in produced pipeline quality natural gas for onshore 

petroleum and natural gas production facilities. If the facility has a 

continuous gas composition analyzer for produced natural gas, the facility 

operator must use an annual average of these values for determining the 

mole fraction. If the facility does not have a continuous gas composition 

analyzer, then it must use an annual average gas composition based on 

the most recent available analysis of the facility.

(B) GHG mole fraction in feed natural gas for all emissions sources upstream 

of the de-methanizer or dew point control and GHG mole fraction in 

facility specific residue gas to transmission pipeline system for all 

emissions sources downstream of the de-methanizer overhead or dew 

point control for onshore natural gas processing facilities. For onshore 

natural gas processing plants that solely fractionate a liquid stream, use 

the GHG mole percent in feed natural gas liquid for all streams. If the 

facility has a continuous gas composition analyzer on feed natural gas, 

the facility operator must use these values for determining the mole 

fraction. If the facility does not have a continuous gas composition 

analyzer, then annual samples must be taken according to methods set 

forth in section 95154(b). 

(C) GHG mole fraction in transmission pipeline natural gas that passes 

through the facility for the onshore natural gas transmission compression 

industry segment. If the facility has a continuous gas composition 

analyzer, the facility operator must use these values for determining the 

mole fraction. If the facility does not have a continuous gas composition 

analyzer, then annual samples must be taken according to methods set 

forth in section 95154(b). 

(D) GHG mole fraction in natural gas stored in the underground natural gas 

storage industry segment. If the facility has a continuous gas composition 

analyzer, the facility operator must use these values for determining the 

mole fraction. If the facility does not have a continuous gas composition 

analyzer, then annual samples must be taken according to methods set 

forth in section 95154(b). 

(E) GHG mole fraction in natural gas stored in the LNG storage industry 

segment. If the facility has a continuous gas composition analyzer, the 

facility operator must use these values for determining the mole fraction. 

If the facility does not have a continuous gas composition analyzer, then 

annual samples must be taken according to methods set forth in section 

95154(b). 

(F) GHG mole fraction in natural gas stored in the LNG import and export 

industry segment. If the facility has a continuous gas composition 

analyzer, the facility operator must use these values for determining the 

mole fraction. If the facility does not have a continuous gas composition 

analyzer, then annual samples must be taken according to methods set 

forth in section 95154(b). 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 236 February 2015 

(G) GHG mole fraction in local distribution pipeline natural gas that passes 

through the facility for natural gas distribution facilities. If the facility has a 

continuous gas composition analyzer, the facility operator must use these 

values for determining the mole fraction. If the facility does not have a 

continuous gas composition analyzer, then annual samples must be 

taken according to methods set forth in section 95154(b). 

(t) GHG mass emissions. Calculate GHG mass emissions by converting the GHG 

volumetric emissions at standard conditions into mass emissions using Equation 32 

of this section. 

ZYUU = d, ∗ • ∗ 10v (Eq. 32) 

Where: 

Massi = GHGi (either CH4, CO2, or N2O) mass emissions in metric tons GHGi. 

Es,i = GHGi (either CH4, CO2, or N2O) volumetric emissions at standard 

conditions, in cubic feet. 

Ρi = Density of GHGi. Use 0.0526 kg/ft3 for CO2 and N2O, and 0.0192 kg/ft3

for CH4 at 60 ̊F and 14.7 psia. 

(u) EOR injection pump blowdown. Calculate CO2 pump blowdown emissions from 

EOR operations using critical CO2 injection as follows: 

ZYUUj = î ∗ k¶ ∗ z
 ∗ nln ∗ 10v (Eq. 33) 

Where: 

MassCO2 = Annual EOR injection gas venting emissions in metric tons from 

blowdowns. 

N = Number of blowdowns for the equipment in the calendar year. 

Rc = Density of critical phase EOR injection gas in kg/ft3

. The facility operator 

may use an appropriate standard method published by a consensus based 

organization if such a method exists or the facility operator may use an 

industry standard practice to determine density of super-critical emissions. 

Vv = Total volume in cubic feet of blowdown equipment chambers (including 

pipelines, manifolds and vessels) between isolation valves. 

GHGi = Mass fraction of GHGi in critical phase injection gas. 

1x 10-3 = Conversion factor from kilograms to metric tons.

(v) Crude Oil, Condensate, and Produced Water Dissolved CO2 and CH4. The 

operator must calculate dissolved CO2 and CH4 in crude oil, condensate, and 

produced water. This reporting requirement includes emissions from hydrocarbon 

liquids and water produced using EOR operations. Emissions must be reported for 

crude oil, condensate, and produced water sent to storage tanks, ponds, and 

holding facilities. The facility operator must also report the volume of produced 

water in barrels per year. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 237 February 2015 

(1) Calculate CO2 and CH4 emissions from crude oil, condensate, and produced

water using Equation 33A: 

dj/ï = w ∗ k$y1 − kz ∗ d$| (Eq. 33A) 

Where: 

ECO2/CH4 = Annual CO2 or CH4 emissions in metric tons. 

S = Mass of CO2 or CH4 liberated in a flash liberation test per barrel of

crude oil, condensate, and produced water (as determined in paragraph 

(v)(1)(A)1. or mass of CO2 or CH4 recovered in a vapor recovery system 

per barrel of crude oil, condensate, or produced water (as determined in 

paragraph (v)(1)(A)2. 

V = Barrels of crude oil, condensate, or produced water sent to tanks, 

ponds, or holding facilities annually. 

VR = Percentage of time the vapor recovery unit was operational 

(expressed as a decimal). 

CE = Collection efficiency of the vapor recovery system (expressed as 

a decimal). 

(A) S (the mass of CO2 or CH4 per barrel of crude oil, condensate, or 

produced water) shall be determined using one of the following methods: 

1. Flash liberation test. Measure the amount of CO2 and CH4 liberated 

from crude oil, condensate, or produced water when the crude oil, 

condensate, or produced water changes temperature and pressure 

from well stream to standard atmospheric conditions, using ARB’s 

sampling methodology and flash liberation test procedure entitled 

“Flash Emissions of Greenhouse Gases and Other Compounds from 

Crude Oil and Natural Gas Separator and Tank Systems,” which is 

included as Appendix B of this article. The flash liberation test 

results must provide the metric tons of CO2 and CH4 liberated per 

barrel of crude oil, condensate, or produced water. The test results 

from the flash liberation test must be submitted to ARB as part of the 

emissions data report. 

2. Vapor recovery system method. For storage tank systems 

connected to a vapor recovery system, calculate the mass of CO2

and CH4 liberated from crude oil, condensate, or produced water as 

follows: 

a. Measure the annual gas stream volume captured by the vapor 

recovery system. 

b. Calculate the annual mass of CO2 and CH4 in the gas stream 

using the gas stream volume and mole percentage of CO2 and 

CH4 as determined by a laboratory analysis of an annual gas 

stream sample. 

c. Calculate S by dividing the total mass of CO2 and CH4 in the gas 

stream by the total volume, in barrels, of the crude oil, 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 238 February 2015 

condensate, or produced water throughput of the storage tank 

system. 

d. Vapor recovery system measurements and analyses may include 

gases from crude oil, condensate, and produced water. 

e. The vapor recovery system method is included in Appendix B. 

(B) Emissions resulting from the destruction of the vapor recovery system 

gas stream shall be reported using the Flare Stack reporting provisions in 

paragraph (l) of this section. 

(2) EOR operations that route produced water from separation directly to reinjection into the hydrocarbon reservoir are exempt from paragraph (v) of this 

section. 

(w) Pipeline dig-ins. For reporting pipeline dig-in emissions as specified in section 

95152(i)(11), operators may either use measured data or use engineering 

estimation based on best available data to quantify the volume of natural gas 

released from pipeline dig-in events. Volumetric emissions must be converted into 

mass emissions of CO2 and CH4 using the applicable methods in paragraphs (r), 

(s), and (t) of this section. 

(x) Reserved.

(y) Onshore petroleum and natural gas production and natural gas distribution 

combustion emissions. Calculate CO2, CH4, and N2O combustion-related 

emissions from stationary or portable equipment, except as specified in paragraph 

(y)(3) and (y)(4) of this section as follows: 

(1) If a fuel combusted in the stationary or portable equipment is listed in Table 

C-1 of Subpart C of 40 CFR Part 98, or is a blend completely consisting of one 

or more fuels listed in Table C-1, calculate emissions according to paragraph 

(y)(1)(A). If the fuel combusted is natural gas and is of pipeline quality 

specification, use the calculation methodology described in paragraph 

(y)(1)(A) and the facility operator may use the emission factor provided for 

natural gas as listed in Subpart C, Table C-1. If the fuel is natural gas, and is 

not pipeline quality calculate emissions according to paragraph (y)(2). The 

operator must use the appropriate gas composition for each stream of 

hydrocarbon going to the combustion unit as specified in paragraph (s)(2) of 

this section. If the fuel is field gas, process vent gas, or a blend containing 

field gas or process vent gas, calculate emissions according to paragraph 

(y)(2). 

(A) For fuels listed in Table C-1 or a blend completely consisting of one or 

more fuels listed in Table C-1 of Subpart C, calculate CO2, CH4, and N2O 

emissions according to any Tier listed in section 95115. 

(2) For fuel combustion units that combust field gas, process vent gas, a blend 

containing field gas or process vent gas, or natural gas that is not of pipeline 

quality, calculate combustion emissions as specified below: 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 239 February 2015 

(A) The operator may use company records, which includes the common 

pipe method, to determine the volume of fuel combusted in the unit 

during the reporting year. 

(B) If a continuous gas composition analyzer is installed and operational on 

fuel supply to the combustion unit, the operator must use these 

compositions for determining the concentration of gas hydrocarbon 

constituent in the flow of gas to the unit. If a continuous gas composition 

analyzer is not installed on gas to the combustion unit, the facility 

operator must use the appropriate gas compositions for each stream of 

hydrocarbons going to the combustion unit. 

(C) Calculate GHG volumetric emissions at actual conditions using Equations 

35 and 36 of this section: 

d,j = ∑ ß k ∗ °j$ + ƞ ∑ k ∗ °¢ ∗ z¢

ã

¢;< ®

<j

;< (Eq. 35) 

d,ï = ∑ Vk ∗ 1 − ƞ$ ∗ °ï\

<j

;< (Eq. 36) 

Where: 

Ea,CO2 = Contribution of annual CO2 emissions from portable or 

stationary fuel combustion sources in cubic feet, under actual 

conditions. 

Va = Volume of fuel gas sent to combustion unit in cubic feet, during 

the month. 

YCO2 = Monthly concentration of CO2 constituent in gas sent to 

combustion unit. 

Ea,CH4 = Contribution of annual CH4 emissions from portable or 

stationary fuel combustion sources in cubic feet, under actual 

conditions. 

Ƞ = Fraction of gas combusted for portable and stationary equipment 

determined using an engineering estimation. For internal combustion 

devices, a default of 0.995 can be used. 

Yj = Monthly concentration of gas hydrocarbon constituent j (such as 

methane, ethane, propane, butane and pentanes plus) in gas sent to 

combustion unit. 

Rj = Number of carbon atoms in the gas hydrocarbon constituent j; 1 

for methane, 2 for ethane, 3 for propane, 4 for butane, and 5 for 

pentanes plus, in gas sent to combustion unit. 

YCH4 = Monthly concentration of methane constituent in gas sent to 

combustion unit. 

n = Month of the year 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 240 February 2015 

Calculate CO2 and CH4, volumetric emissions at standard conditions using

the provisions of section 95153(r). Use the provisions in sections 

95153(s) and (t) to convert volumetric gas emissions to GHG volumetric 

and GHG mass emissions respectively. 

(D) Calculate N2O mass emissions using Equation 37 of this section.

ZYUUj = 1	]	10v$ ∗ hcM` ∗ llk ∗ dh (Eq. 37) 

Where: 

MassN2O = Annual N2O emissions from the combustion of a particular type 

of fuel (metric tons N2O). 

Fuel = Mass or volume of the fuel combusted (mass or volume per year, 

choose appropriately to be consistent with the units of HHV). 

HHV = For the higher heating value for field gas or process vent gas, use 

either a weighted average of quarterly measurements of HHV or a default 

value of 1.235 x 10-3 MMBtu/scf for HHV. 

EF = Use 1.0 x 10-4 kg N2O/MMBtu. 

1 x 10-3 = Conversion factor from kilograms to metric tons.

(3) External fuel combustion sources with a rated heat capacity equal to or less 

than 5 MMBtu/hr do not need to report combustion emissions or include these 

emissions for threshold determination in section 95101(e). The operator must 

report the type and number of each external fuel combustion unit. 

(4) Internal fuel combustion sources, not compressor-drivers, with a rated heat 

capacity equal to or less than 1 MMBtu/hr (or equivalent of 130 horsepower), 

do not need to report combustion emissions or include these emissions for 

threshold determination in section 95101(e). The operator must report the 

type and number of each internal fuel combustion unit. 

(5) Calculate sorbent CO2 emissions from fluidized bed boilers with flue gas

desulfurization using methods found in §98.33(d). 

NOTE: Authority cited: Sections 38510, 38530, 39600, 39601, 39607, 39607.4 and 

41511, Health and Safety Code. Reference: Sections 38530, 39600 and 41511, Health 

and Safety Code. 

§ 95154. Monitoring and QA/QC Requirements. 

The GHG emissions data for petroleum and natural gas emissions sources must be 

quality assured as applicable and as specified in this section. Offshore petroleum and 

natural gas production facilities must adhere to the monitoring and QA/QC requirements 

as set forth in 30 CFR §250 (July 1, 2011), which is hereby incorporated by reference. 

(a) Facility operators must use any of the methods described as follows in this 

paragraph to conduct leak detection(s) of equipment leaks and through-valve 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 241 February 2015 

leakage from all source types listed in sections 95153(i), (m), (n) and (o) that occur 

during a calendar year, except as provided in paragraph (a)(4) of this section. 

(1) Optical gas imaging instrument. Use an optical gas imaging instrument for 

equipment leak detection in accordance with 40 CFR Part 60, subarticle A, 

§60.18 of the Alternative work practice for monitoring equipment leaks, 

§60.18(i)(1)(i); §60.18(i)(2)(i) except that the monitoring frequency shall be 

annual using the detection sensitivity level of 60 grams per hour as stated in 

40 CFR Part 60, subarticle A, Table 1: Detection Sensitivity Levels; 

§60.18(i)(2)(ii) and (iii) except the gas chosen shall be methane, and 

§60.18(i)(2)(iv) and (v); §60.18(i)(3); §60.18(i)(4)(i) and (v); including the 

requirements for daily instrument checks and distances, and excluding 

requirements for video records (July 1, 2011, which is hereby incorporated by 

reference). Any emissions detected by the optical gas imaging instrument is a 

leak unless screened with Method 21 (40 CFR Part 60, appendix A-7 (July 1, 

2011), which is hereby incorporated by reference) monitoring, in which case 

10,000 ppm or greater is designated a leak. In addition, facility operators must 

operate the optical gas imaging instrument to image the source types required 

by this subarticle in accordance with the instrument manufacturer’s operating 

parameters. Unless using methods in paragraph (a)(2) of this section, an 

optical gas imaging instrument must be used for all source types that are 

inaccessible and cannot be monitored without elevating the monitoring 

personnel more than two meters above a support surface. 

(2) Method 21. Use the equipment leak detection methods in 40 CFR Part 60, 

appendix A-7, Method 21 (July 1, 2011). If using Method 21 monitoring, if an 

instrument reading of 10,000 ppm or greater is measured, a leak is detected. 

Inaccessible emissions sources, as defined in 40 CFR Part 60, are not exempt 

from this subarticle. Owners or operators must use alternative leak detection 

devices as described in paragraph (a)(1) or (a)(2) of this section to monitor 

inaccessible equipment leaks or vented emissions. 

(3) Infrared laser beam illuminated instrument. Use an infrared laser beam 

illuminated instrument for equipment leak detection. Any emissions detected 

by the infrared laser beam illuminated instrument is a leak unless screened 

with Method 21 monitoring, in which case 10,000 ppm or greater is designated 

a leak. In addition, the facility operator must operate the infrared laser beam 

illuminated instrument to detect the source types required by this subarticle in 

accordance with the instrument manufacturer’s operating instructions. 

(4) Optical gas imaging instrument. An optical gas imaging instrument must be 

used for all source types that are inaccessible and cannot be monitored 

without elevating the monitoring personnel more than 2 meters above a 

support surface. 

(5) Acoustic leak detection device. Use the acoustic leak detection device to 

detect through-valve leakage. When using the acoustic leak detection device 

to quantify the through-valve leakage, use the instrument manufacturer’s 

calculation methods to quantify the through-valve leak. When using the 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 242 February 2015 

acoustic leak detection device, if a leak of 3.1 scf per hour or greater is 

calculated, a leak is detected. In addition, the facility operator must operate 

the acoustic leak detection device to monitor the source valves required by 

this subarticle in accordance with the instrument manufacturer’s operating 

parameters. Acoustic stethoscope type devices designed to detect through 

valve leakage when put in contact with the valve body and that provide an 

audible leak signal but do not calculate a leak rate can be used to identify nonleakers with subsequent measurement required to calculate the rate if 

through-valve leakage is identified. Leaks are reported if a leak rate of 3.1 scf 

per hour or greater is measured. In addition, the facility operator must operate 

the acoustic leak detection device to monitor the source valves required by 

this subarticle in accordance with the instrument manufacturer’s operating 

parameters. 

(b) The operator must operate and calibrate all flow meters, composition analyzers and 

pressure gauges used to measure quantities reported in section 95153 according to 

the procedures in section 95103(k) and the procedures in paragraph (b) of this 

section. Pursuant to section 95109 of this article, the facility operator may use an 

appropriate standard method published by a consensus-based standards 

organization if such a method exists or use an industry standard practice. 

(c) Use calibrated bags (also known as vent bags) only where the emissions are at 

near-atmospheric pressures and below the maximum temperature specified by the 

vent bag manufacturer such that the vent bag is safe to handle. The bag opening 

must be of sufficient size that the entire emission can be tightly encompassed for 

measurement till the bag is completely filled. 

(1) Hold the bag in place enclosing the emissions source to capture the entire 

emissions and record the time required for completely filling the bag. If the 

bag inflates in less than one second, assume one second inflation time. 

(2) Perform three measurements of the time required to fill the bag, report the 

emissions as the average of the three readings. 

(3) Estimate natural gas volumetric emissions at standard conditions using 

calculations in section 95153(r). 

(4) Estimate CH4 and CO2 volumetric and mass emissions from volumetric natural 

gas emissions using the calculations in sections 95153(s) and (t). 

(d) Use a high volume sampler to measure emissions within the capacity of the 

instrument. 

(1) A technician following manufacturer instructions shall conduct measurements, 

including equipment manufacturer’s operating procedures and measurement 

methodologies relevant to using a high volume sampler, including positioning 

the instrument for complete capture of the equipment leak without creating 

backpressure on the source. 

(2) If the high volume sampler, along with all attachments available from the 

manufacturer, is not able to capture all the emissions from the source then use 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 243 February 2015 

anti-static wraps or other aids to capture all emissions without violating 

operating requirements as provided in the instrument manufacturer’s manual. 

(3) Estimate natural gas volumetric emissions at standard conditions using 

calculations in section 95153(r). Estimate CH4 and CO2 volumetric and mass 

emissions from volumetric natural gas emissions using the calculations in 

sections 95153(s) and (t). 

(4) Calibrate the instrument at 2.5 percent methane with 97.5 percent air and 100 

percent CH4 by using calibrated gas samples by following manufacturer’s 

instructions for calibration. 

(e) Peng-Robinson Equation of State means the equation of state defined by 

Equation 38 of this section. 

X =

©

 ~TM$

− Y ́/ ke

j + 2 ̈ke −  ̈j

$ (Eq. 38) 

Where: 

p = Absolute pressure. 

R = Universal gas constant 

T = Absolute temperature. 

Vm = Molar volume. 

Y = 0.45724zj_


j

/X


 ̈ = 0.7780z_
/X


 ́ = s1 + 0.37464 + 1.54226­ − 0.26992­j

$y1 − å_/_
|xj

Where: 

ω = Acentric factor of the species. 

Tc = Critical temperature. 

Pc = Critical pressure. 

NOTE: Authority cited: Sections 38510, 38530, 39600, 39601, 39607, 39607.4 and 

41511, Health and Safety Code. Reference: Sections 38530, 39600 and 41511, Health 

and Safety Code. 

§ 95155. Procedures for Estimating Missing Data. 

(a) A complete record of all estimated and/or measured parameters used in the GHG 

emissions calculations is required. If data are lost or an error occurs during annual 

emissions estimation or measurements, the operator must repeat the estimation or 

measurement activity for those sources within the measurement period. In cases 

where repeat sampling and/or analysis cannot be completed, the operator must 

follow the missing data substitution procedures outlined below: 

(1) To substitute for missing data for emissions reported under section 95115 of 

this article (stationary combustion units and units using continuous emissions 

monitoring systems), the operator must follow the requirements of section 

95129 of this article. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 244 February 2015 

(2) If data required by this subarticle is missing and additional sampling and/or 

analysis is not possible, the operator must generate a substitute value as 

follows: 

(A) If the analytical data capture rate is at least 90 percent for the data year, 

the operator must substitute for each missing value using available 

process data. 

(B) If the analytical data capture rate is at least 80 percent but not at least 90 

percent for the data year, the operator must substitute for each missing 

value with the highest quality assured value recorded for the parameter 

during the given data year, as well as the two previous data years. 

(C) If the analytical data capture rate is less than 80 percent for the data 

year, the operator must substitute for each missing value with the highest 

quality assured value recorded for the parameter in all records kept 

according to section 95105(a). 

NOTE: Authority cited: Sections 38510, 38530, 39600, 39601, 39607, 39607.4 and 

41511, Health and Safety Code. Reference: Sections 38530, 39600 and 41511, Health 

and Safety Code. 

§ 95156. Additional Data Reporting Requirements. 

Operators must conform to the data reporting requirements in section 95157 in addition 

to the data reporting requirements specified below. Sales records or sales records with 

an inventory adjustment are allowable methods to quantify the covered product data 

required by paragraphs (a)(7)-(10), (b), (c) and (d) of this section, for products that are 

sold or produced during the data year, if the measurement system meets the criteria in 

section 95103(k). Any changes in the covered product data reporting method must 

conform to the requirements in 95103(m). Reporting entities must exclude inaccurate 

product data pursuant to section 95103(l). 

(a) In addition to the data required by section 95157, the operator of an onshore or 

offshore petroleum and natural gas production facility must report the following data 

for the facility, disaggregated within the basin by sub-facility : 

(1) CO2e emissions, including CO2, CH4, and N2O as applicable for the source 

types specified in section 95152(c); 

(2) For combustion sources for which emissions are reported, fuel use by fuel 

type; 

(3) For cogeneration sources: 

(A) Total thermal output (MMBtu); 

(B) Net electricity generation (MWh); 

(C) Amount of electricity generation (MWh) not consumed within the facility 

(i.e., exported offsite or to another facility owner/operator); 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 245 February 2015 

(4) For steam generator sources: 

(A) Total thermal energy generated (MMBtu) and the CO2e emissions 

associated with this output; 

(B) Thermal energy (MMBtu) not utilized within the facility (i.e., exported 

offsite or to another facility owner/operator) and the CO2e emissions 

associated with this output; 

(5) For electricity generation sources not included in section 95156(a)(3): 

(A) Net electricity generation (MWh) and the CO2e emissions associated with 

this generation; 

(B) Amount of electricity generation (MWh) not consumed within the facility 

(i.e., exported offsite or to another facility owner/operator) and the portion 

of CO2e emissions associated with this generation; 

(6) Total steam (MMBtu) utilized but not generated at the facility and the CO2e 

emissions associated with this output, if known; 

(7) Barrels of crude oil produced using thermal enhanced oil recovery. This 

means the volume of crude oil produced within the facility boundary during the 

data year, a volume which may include the crude oil fraction piped as an 

emulsion as defined in section 95102(a); 

(8) Barrels of crude oil produced using non-thermal enhanced oil recovery. This 

means the volume of crude oil produced within the facility boundary during the 

data year, a volume which may include the crude oil fraction piped as an 

emulsion as defined in section 95102(a); 

(9) Heat energy (MMBtu) of associated gas produced using thermal enhanced oil 

recovery. This includes the associated gas fraction piped as an emulsion as 

defined in section 95102(a). Associated gas may be quantified using 

production or sales meters as appropriate. Associated gas may also be 

quantified by multiplying the barrels of crude oil produced during the data year 

by a representative GOR measurement plus the representative GWR 

measurement multiplied by the produced water volume. When GOR and 

GWR measurements are used for quantifying associated gas, these 

measurements must be the most disaggregated data available (e.g., field or 

tank farm level). The average HHV of the produced gas must be multiplied by 

the data year volume to determine the annual heat content in MMBtu. HHV 

measurements must be collected and averaged consistent with the frequency 

requirements in 95153(y)(2)(D); 

(10) Heat energy (MMBtu) of associated gas produced using non-thermal 

enhanced oil recovery. This includes the associated gas fraction piped as an 

emulsion as defined in section 95102(a). Associated gas may be quantified 

using production or sales meters as appropriate. Associated gas may also be 

quantified by multiplying the barrels of crude oil produced during the data year 

by a representative GOR measurement plus the representative GWR 

measurement multiplied by the annual produced water volume. When GOR 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 246 February 2015 

and GWR measurements are used for quantifying associated gas, these 

measurements must be the most disaggregated data available (e.g., field or 

tank farm level). The average HHV of the produced gas must be multiplied by 

the data year volume to determine the annual heat content in MMBtu. HHV 

measurements must be collected and averaged consistent with the frequency 

requirements in 95153(y)(2)(D). 

(b) For dry gas production, the operator of an onshore petroleum and natural gas 

production facility must report its annual heat energy of dry gas produced (MMBtu). 

The average HHV of the produced gas must be multiplied by the data year volume 

to determine the heat energy in MMBtu. HHV measurements must be collected and 

averaged consistent with the frequency requirements in 95153(y)(2)(D); 

(c) The operator of a natural gas liquid fractionating facility, a natural gas processing 

facility, or an onshore petroleum and natural gas production facility with a natural 

gas processing plant that processes less than 25 MMscf per day must report the 

annual production of the following natural gas liquids in barrels corrected to 60 

degrees Fahrenheit: 

(1) Ethane 

(2) Ethylene 

(3) Propane 

(4) Propylene 

(5) Butane 

(6) Butylene 

(7) Isobutane 

(8) Isobutylene 

(9) Pentanes plus 

(10) Natural gasoline 

(11) Liquefied petroleum gas 

(12) Bulk natural gas liquids not included in 95156(d)(1)-(11) 

If a facility extracts natural gas liquids from produced gas, associated gas, or waste 

gas, and re-injects these natural gas liquids into barrels of crude oil produced at the 

same facility, the operator of such a facility shall report the amount of any 

re-injected natural gas liquids as covered product data pursuant to section 

95156(a)(7) or (8). All other natural gas liquids produced at the facility should be 

reported as covered product data pursuant to section 95156(c). 

(d) Onshore natural gas processing facilities that have an annual average throughput of 

25 MMscf per day or greater must also report the heat energy of associated gas, 

waste gas, and natural gas processed (MMBtu). The average HHV of the produced 

gas must be multiplied by the data year volume to determine the heat energy in 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 247 February 2015 

MMBtu. HHV measurements must be collected and averaged consistent with the 

frequency requirements in 95153(y)(2)(D). 

NOTE: Authority cited: Sections 38510, 38530, 39600, 39601, 39607, 39607.4 and 

41511, Health and Safety Code. Reference: Sections 38530, 39600 and 41511, Health 

and Safety Code. 

§95157. Activity Data Reporting Requirements. 

In addition to the information required by section 95103, each annual report must 

contain reported emissions and related information as specified in this section. 

(a) Report annual emissions in metric tons per year for each GHG separately for each 

of the industry segments listed in paragraphs (a)(1) through (8) of this section: 

(1) Onshore petroleum and natural gas production. 

(2) Offshore petroleum and natural gas production 

(3) Onshore natural gas processing. 

(4) Onshore natural gas transmission compression. 

(5) Underground natural gas storage. 

(6) LNG storage. 

(7) LNG import and export. 

(8) Natural gas distribution. 

(b) For offshore petroleum and natural gas production, report emissions of CH4, CO2, 

and N2O as applicable to the source type (in metric tons per year at standard 

conditions) individually for all of the emissions source types listed in the most recent 

BOEMRE study. 

(c) Report the information listed in this paragraph for each applicable source type in 

metric tons for each GHG type. If a facility operates under more than one industry 

segment, each piece of equipment should be reported under the unit’s respective 

majority use segment. When a source type listed under this paragraph routes gas 

to flare, separately report the emissions that were vented directly to the atmosphere 

without flaring, and the emissions that resulted from flaring of the gas. Both the 

vented and flared emissions will be reported under respective source types and not 

under flare source type. 

(1) For natural gas pneumatic devices (refer to Equations 1 and 2 of section 

95153), report the following: 

(A) Actual count and estimated count separately of natural gas pneumatic 

high bleed devices, as applicable. 

(B) Actual count and estimated count separately of natural gas low bleed 

devices, as applicable. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 248 February 2015 

(C) Actual count and estimated count separately of natural gas pneumatic 

intermittent bleed devices, as applicable. 

(D) Report annual CO2 and CH4 emissions at the facility level, expressed in 

metric tons for each gas, for each of the following pieces of equipment: 

high bleed pneumatic devices; intermittent bleed pneumatic devices; low 

bleed pneumatic devices. 

(2) For natural gas driven pneumatic pumps (refer to Equation 1 and 2 of section 

95153), report the following: 

(A) Count of natural gas driven pneumatic pumps. 

(B) Report annual CO2 and CH4 emissions at the facility level, expressed in 

metric tons for each gas, for all natural gas driven pneumatic pumps 

combined. 

(3) For each acid gas removal unit (refer to Equation 3 and Equations 4A-B of 

section 95153), report the following: 

(A) Total throughput of the acid gas removal unit using a meter or 

engineering estimate based on process knowledge or best available data 

in million cubic feet per year. 

(B) For Calculation Methodology 1 and Calculation Methodology 2 of section 

95153(c), annual fraction of CO2 content in the vent from acid gas 

removal unit (refer to section 95153(c)(6)). 

(C) For Calculation Methodology 3 of section 95153(c), annual average 

volume fraction of CO2 content of natural gas into and out of the acid gas 

removal unit (refer to section 95153(c)(6)). 

(D) Report the annual quantity of CO2, expressed in metric tons that was 

recovered from the AGR unit and transferred outside the facility, under 

section 95153. 

(E) Report annual CO2 emissions for the AGR unit, expressed in metric tons. 

(F) For the onshore natural gas processing industry segment only, report a 

unique name or ID number for the AGR unit. 

(G) An indication of which methodology was used for the AGR unit. 

(4) For dehydrators, report the following: 

(A) For each Glycol dehydrator (refer to section 95153(d)(1)), report the 

following: 

1. Glycol dehydrator feed natural gas flow rate in MMscfd, determined 

by engineering estimate based on best available data. 

2. Glycol dehydrator absorbent circulation pump type. 

3. Whether stripper gas is used in glycol dehydrator. 

4. Whether a flash tank separator is used in glycol dehydrator. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 249 February 2015 

5. Type of absorbent. 

6. Total time the glycol dehydrator is operating in hours. 

7. Temperature, in degrees Fahrenheit and pressure, in psig, of the wet 

natural gas. 

8. Concentration of CH4 and CO2 in wet natural gas. 

9. What vent gas controls are used (refer to sections 95153(d)(3) and 

(d)(4)). 

10. For each glycol dehydrator, report annual CO2 and CH4 emissions 

that resulted from venting gas directly to the atmosphere, expressed 

in metric tons for each gas. 

11. For each glycol dehydrator, report annual CO2, CH4, and N2O 

emissions that resulted from flaring process gas from the dehydrator, 

expressed in metric tons for each gas. 

12. For the onshore natural gas processing industry segment only, report 

a unique name or ID number for (each) glycol dehydrator. 

(B) For absorbent desiccant dehydrators (refer to Equation 5 of section 

95153), report the following: 

1. Count of desiccant dehydrators. 

2. Report annual CO2 and CH4 emissions at the facility level, expressed 

in metric tons for each gas, for all absorbent desiccant dehydrators 

combined. 

(5) For well venting for liquids unloading, report the following: 

(A) For Calculation Methodology 1 (refer to Equation 6 of section 95153(e)), 

report the following: 

1. Count of wells vented to the atmosphere for liquids unloading. 

2. Count of plunger lifts. Whether the well had a plunger lift (yes/no). 

3. Cumulative number of unloadings vented to the atmosphere. 

4. Internal casing diameter or internal tubing diameter in inches, where 

applicable, and well depth of each well, in feet. 

5. Casing pressure, in psia, of each well that does not have a plunger 

lift. 

6. Tubing pressure, in psia, of each well that has a plunger lift. 

7. Report annual CO2 and CH4 emissions, expressed in metric tons for 

each gas. 

(B) For Calculation Methodologies 2 (refer to Equation 7 of section 

95153(e)), report the following for each basin: 

1. Count of wells vented to the atmosphere for liquids unloading. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 250 February 2015 

2. Count of plunger lifts. 

3. Cumulative number of unloadings vented to the atmosphere. 

4. Average internal casing diameter, in inches, of each well, where 

applicable. 

5. Report annual CO2 and CH4 emissions, expressed in metric tons for 

each GHG gas. 

(6) For well completions and workovers, report the following for each basin 

category: 

(A) Total field count of gas well completions and total field count of oil well 

completions by average depth (in thousands of feet) in calendar year. 

1. Total number of gas well completions by average depth (in 

thousands of feet) using hydraulic fracturing; 

2. Total number of oil well completions by average depth (in thousands 

of feet) using hydraulic fracturing; 

(B) Total field count of gas well workovers and total field count of oil well 

workovers by average depth (in thousands of feet) in calendar year. 

1. Total number of gas well workovers by average depth (in thousands 

of feet) using hydraulic fracturing; 

2. Total number of oil well workovers by average depth (in thousands of 

feet) using hydraulic fracturing; 

(C) Report number of completions employing purposely designed equipment 

that separates natural gas from the backflow and the amount of natural 

gas, in standard cubic feet, recovered using engineering estimate based 

on best available data. 

(D) Report number of workovers employing purposely designed equipment 

that’s separates natural gas from the backflow and the amount of natural 

gas recovered using engineering estimate based on best available data. 

(E) Annual CO2 and CH4 emissions that resulted from venting gas directly to 

the atmosphere, expressed in metric tons for each gas. 

(F) Annual CO2, CH4, and N2O emissions that resulted from flares, 

expressed in metric tons for each gas. 

(G) The following field average activity data for oil wells: 

1. Casing diameter; 

2. Tubing diameter; 

3. Typical pressure inside the well at the wellhead, immediately prior to 

removing the wellhead for well work activities; 

4. Typical producing temperature inside the well; 

5. Time, in hours, to complete well work (workover or completion). 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 251 February 2015 

(7) For each equipment and pipeline blowdown event (refer to Equation 13 and 

Equation 14 of section 95153(g)), report the following: 

(A) For each unique physical volume that is blowdown more than once during 

the calendar year, report the following: 

1. Total number of blowdowns for each unique physical volume, 

expressed in metric tons for each gas. 

2. Annual CO2 and CH4 emissions for each unique physical blowdown 

volume, expressed in metric tons for each gas. 

3. A unique name or ID number for the unique physical volume. 

(B) For all unique volumes that are blow down once during the calendar year, 

report the following: 

1. Total number of blowdowns for all unique physical volumes in the 

calendar year. 

2. Annual CO2 and CH4 emissions from all unique physical volumes as 

an aggregate per facility, expressed in metric tons for each gas. 

(8) For gas emitted from produced oil sent to atmospheric tanks: 

(A) If a wellhead separator dump valve is functioning improperly during the 

calendar year (refer to section 95153 (i)), report the following: 

1. Count of wellhead separators that dump valve factor is applied. 

2. Annual CO2 and CH4 emissions that resulted from venting gas to the 

atmosphere, expressed in metric tons for each gas, at the basin level 

for improperly functioning dump valves. 

(9) For transmission tank emissions identified using optical gas imaging 

instrument pursuant to section 95154(a) (refer to section 95153(i)), or acoustic 

leak detection of scrubber dump valves, report the following: 

(A) For each vent stack, report annual CO2 and CH4 emissions that resulted 

from venting gas directly to the atmosphere, expressed in metric tons for 

each gas. 

(B) For each transmission storage tank, report annual CO2, CH4 and N2O 

emissions that resulted from flaring process gas from the transmission 

storage tank, expressed in metric tons for each gas. 

(C) A unique name or ID number for the vent stack monitored according to 

section 95153(i). 

(10) For well testing venting and flaring (refer to Equation 15 or 16 of section 

95153(j)), report the following: 

(A) Number of wells tested per basin in calendar year. 

(B) Average gas-to-oil ratio for each basin. 

(C) Average number of days the well is tested in a basin. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 252 February 2015 

(D) Report annual CO2 and CH4 emissions at the facility level, expressed in 

metric tons for each gas, emissions from well testing venting. 

(E) Report annual CO2, CH4 and N2O emissions at the facility level, 

expressed in metric tons for each gas, emissions from well testing flaring. 

(11) For associated natural gas venting and flaring (refer to Equation 17 of section 

95153), report the following for each basin: 

(A) Number of wells venting or flaring associated natural gas in a calendar 

year. 

(B) Average gas-to-oil ratio for each basin. 

(C) Report annual CO2 and CH4 emissions at the facility level, expressed in 

metric tons for each gas, emission s from associated natural gas venting. 

(D) Report annual CO2, CH4 and N2O emissions at the facility level, 

expressed in metric tons for each gas, emissions from associated natural 

gas flaring. 

(12) For flare stacks (refer to Equation 18, 19, and 20 of section 95153(l)), report 

the following for each flare: 

(A) Whether flare has a continuous flow monitor. 

(B) Volume of gas sent to flare in cubic feet per year. 

(C) Percent of gas sent to un-lit flare determined by engineering estimate and 

process knowledge based on best available data and operating records. 

(D) Whether flare has a continuous gas analyzer. 

(E) Flare combustion efficiency. 

(F) Report CH4 emissions, in metric tons (refer to Equation 18 of section 

95153). 

(G) Report CO2 emissions, in metric tons (refer to Equation 19 of section 

95153). 

(H) Report N2O emissions, in metric tons. 

(I) For the natural gas processing industry segment, a unique name or ID 

number for the flare stack. 

(J) In the case that a CEMS is used to measure CO2 emissions for the flare 

stack, indicate that a CEMS was used in the annual report and report the 

combusted CO2 and uncombusted CO2 as a combined number. 

(13) For each centrifugal compressor: 

(A) For compressors with wet seals in operational mode (refer to Equation 21 

and 22 of section 95153(m)), report the following for each degassing 

vent: 

1. Number of wets seals connected to the degassing vent. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 253 February 2015 

2. Fraction of vent gas recovered for fuel or sales or flared. 

3. Annual throughput in million scf, use an engineering calculation 

based on best available data. 

4. Type of meters used for making measurements. 

5. Total time the compressor is operating in hours.

6. Report seal oil degassing vent emissions for compressors measured 

(refer to Equation 21 of section 95153) and for compressors not 

measured (refer to Equation 22 of section 95153). 

(B) For wet and dry seal centrifugal compressors in operating mode, (refer to 

Equation 21 and 22 of section 95153(m)), report the following: 

1. Total time in hours the compressor is in operating mode. 

2. Report blowdown vent emissions when in operating mode (refer to 

Equation 21 and 22 of section 95153). 

(C) For wet and dry seal centrifugal compressors in not operating, 

depressurized mode (refer to Equations 21 and 22 of section 95153(m)), 

report the following: 

1. Total time in hours the compressor is in shutdown, depressurized 

mode. 

2. Report the isolation valve leakage emissions in not operating, 

depressurized mode in cubic feet per hour (refer to Equations 21 and 

22 of section 95153). 

(D) Report total annual compressor emissions from all modes of operation. 

(14) For reciprocating compressors: 

(A) For reciprocating compressors rod packing emissions with or without a 

vent in operating mode, report the following: 

1. Annual throughput in million scf, use an engineering calculation 

based on best available data. 

2. Total time in hours the reciprocating compressor is in operating 

mode. 

3. Report rod packing emissions for compressors measured (refer to 

Equation 23 of section 95153). 

(B) For reciprocating compressors blowdown vents not manifold to rod 

packing vents, in operating and standby pressurized mode, report the 

following: 

1. Total time in hours the compressor is in standby, pressurized mode. 

2. Report blowdown vent emissions when in operating and standby 

modes. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 254 February 2015 

(C) For reciprocating compressors in not operating, depressurized mode 

report the following: 

1. Total time the compressor is in not operating depressurized mode. 

2. Facility operator emission factor for isolation valve emissions in not 

operating mode, depressurized mode in cubic feet per hour. 

3. Report the isolation valve leakage emissions in not operating, 

depressurized mode. 

(D) Report total annual compressor emissions from all modes of operation. 

(E) For reciprocating compressors in onshore petroleum and natural gas 

production report the following: 

1. Count of compressors. 

2. Report emissions collectively. 

(15) For each component type (major equipment type for onshore production) that 

uses emission factors for estimating emissions (refer to sections 95153(o) 

and (p). 

(A) For equipment leaks found in each leak survey (refer to section 

95153(o)), report the following: 

1. Total count of leaks found in each complete survey listed by date of 

survey and each component type for which there is a leak emission 

factor in Tables 2, 3, 4, 5, 6, and 7 of Appendix A. 

2. For onshore natural gas processing, range of concentrations of CH4

and CO2. 

3. Annual CO2 and CH4 emissions, in metric tons for each gas by 

component type. 

(B) For equipment leaks calculated using population counts and factors (refer 

to section 95153(p)), report the following: 

1. For source categories listed in sections 95150(a)(4), (a)(5), (a)(6), 

and (a)(7), total count for each component type in Tables 2, 3, 4, 5, 

and 6 of Appendix A for which there is a population emission factor, 

listed by major heading and component type. 

2. For onshore production (refer to section 95150 (a)(2)), total count for 

each type of major equipment in Table 1B and Table 1C of 

Appendix A, by facility. 

3. Annual CO2 and CH4 emissions, in metric tons for each gas by 

component type. 

(16) For local distribution companies, report the following: 

(A) Total number of above grade T-D transfer stations in the facility. 

(B) Number of years over which all T-D transfer stations will be monitored at 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 255 February 2015 

least once. 

(C) Number of T-D stations monitored in calendar year. 

(D) Total number of below grade T-D transfer stations in the facility. 

(E) Total number of above grade metering-regulating stations (this count will 

include above grade T-D transfer stations) in the facility. 

(F) Total number of below grade metering-regulating stations (this count will 

include below grade T-D transfer stations) in the facility. 

(G) Leak factor for meter/regulator run developed in Equation 28 of section 

95153. 

(H) Number of miles of unprotected steel distribution mains. 

(I) Number of miles of protected steel distribution mains. 

(J) Number of miles of plastic distribution mains. 

(K) Number of miles of cast iron distribution mains. 

(L) Number of unprotected steel distribution services. 

(M) Number of protected steel distribution services. 

(N) Number of plastic distribution services. 

(O) Number of copper distribution services. 

(P) Annual CO2 and CH4 emissions, in metric tons for each gas, from all 

below grade T-D transfer stations combined. 

(Q) Annual CO2 and CH4 emissions, in metric tons for each gas, from all 

above grade metering-regulating stations (including T-D transfer stations) 

combined. 

(R) Annual CO2 and CH4 emissions, in metric tons for each gas, from all 

below grade metering-regulating stations (including T-D transfer stations) 

combined. 

(S) Annual CO2 and CH4 emissions, in metric tons for each gas, from all 

distribution mains combined. 

(T) Annual CO2 and CH4 emissions, in metric tons for each gas, from all 

distribution services combined. 

(U) Annual CO2 and CH4 emissions, in metric tons for each gas, from 

customer meters serving residential, commercial, and industrial 

customers, respectively. 

(V) Annual CO2 and CH4 emissions, in metric tons for each gas, from 

pipeline dig-ins. 

(W) Number of customer meters at residential, commercial, and industrial 

premises, respectively. 

(X) Number of pipeline dig-ins. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 256 February 2015 

(17) For each EOR injection pump blowdown (refer to Equation 33 of section 

95153), report the following: 

(A) Pump capacity, in barrels per day. 

(B) Volume of critical phase gas between isolation valves. 

(C) Number of blowdowns per year. 

(D) Critical phase EOR injection gas density. 

(E) For each EOR pump, report annual CO2 and CH4 emissions, expressed 

in metric tons for each gas. 

(18) For crude oil, condensate, and produced water dissolved CO2 and CH4 (refer 

to section 95153(v)), report the following: 

(A) Volume of crude oil produced in barrels per year. 

(B) Report annual CO2 and CH4 emissions at the basin level. 

(19) For onshore petroleum and natural gas production and natural gas distribution 

combustion emissions, report the following: 

(A) Cumulative number of external fuel combustion units with a rated heat 

capacity equal to or less than 5 MMBtu/hr, by type of unit. 

(B) Cumulative number of external fuel combustion units with a rated heat 

capacity larger than 5 MMBtu/hr, by type of unit. 

(C) Report annual CO2, CH4, and N2O emissions from external fuel 

combustion units with a rated heat capacity larger than 5 MMBtu/hr, 

expressed in metric tons for each gas, by type of unit. 

(D) Cumulative volume of fuel combusted in external fuel combustion units 

with a rated heat capacity larger than 5 MMBtu/hr, by type of unit. 

(E) Cumulative number of internal fuel combustion units, not compressordrivers, with a rated heat capacity equal to or less than 1 MMBtu/hr or 

130 horsepower, by type of unit. 

(F) Report annual CO2, CH4 and N2O emissions from internal fuel 

combustion units with a rated heat capacity larger than 5 MMBtu/hr, 

expressed in metric tons for each gas, by type of unit. 

(G) Cumulative volume of fuel combusted in internal combustion units with a 

rated heat capacity larger than 1 MMBtu/hr or 130 horsepower, by fuel 

type. 

(H) Annual volume of associated gas produced MMBtu) using thermal 

enhanced oil recovery and non-thermal enhanced oil recovery. 

(I) Onshore petroleum and natural gas production facilities may voluntarily 

report total thermal input (MMBtu) to EOR wells generated using 

renewable energy source(s) as defined in section 95102(a). 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 257 February 2015 

(d) Report annual throughput as determined by engineering estimate based on best 

available data for each industry segment listed in paragraphs (a)(1) through (a)(8) 

of this section. 

(e) For onshore petroleum and natural gas production, report the best available 

estimate of API gravity, best available estimate of gas-to-oil ratio, and best available 

estimate of average low pressure separator pressure for each oil basin category. 

NOTE: Authority cited: Sections 38510, 38530, 39600, 39601, 39607, 39607.4 and 

41511, Health and Safety Code. Reference: Sections 38530, 39600 and 41511, Health 

and Safety Code. 

§95158. Records That Must Be Retained. 

The operator shall follow the document retention requirements of section 95105 of this 

article. 

NOTE: Authority cited: Sections 38510, 38530, 39600, 39601, 39607, 39607.4 and 

41511, Health and Safety Code. Reference: Sections 38530, 39600 and 41511, Health 

and Safety Code. 

 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board 258 February 2015 

Page Intentionally Blank 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board A-1 February 2015

Appendix A 

to the Regulation for the Mandatory Reporting 

of Greenhouse Gas Emissions 

Emission Factors and Calculation Data 

for Petroleum and Natural Gas Systems Reporting 

 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board A-2 February 2015

Table 1A 

Default Whole Gas Emission Factors for Onshore Petroleum and Natural Gas 

Production 

Onshore petroleum and natural gas production Emission factor 

(scf/hour/ component) 

Western U.S.

Population Emission Factors All components, Gas Service:1

 Valve 0.121 

 Connector 0.017 

 Open-ended line 0.031 

 Pressure relief valve 0.193 

 Low Continuous Bleed Pneumatic Device Vents2 1.39 

 High Continuous Bleed Pneumatic Device Vents2 37.3 

 Intermittent Bleed Pneumatic Device Vents2 13.5 

 Pneumatic Pumps3 13.3 

Population Emission Factors – All Components, Light Crude 

Service:4

 Valve 0.05 

 Flange 0.003 

 Connector 0.007 

 Open-ended Line 0.05 

 Pump 0.01 

 Other5 0.30 

Population Emission Factors – All Components, Heavy Crude 

Service:6

 Valve 0.0005 

 Flange 0.0009 

 Connector (other) 0.0003 

 Open-ended Line 0.006 

 Other5 0.003 

1

 For multi-phase flow that includes gas, use the gas service emissions factors. 

2 Emissions factor is in units of “scf/hour/device.” 

3

 Emission Factor is in units of “scf/hour/pump.” 

4

 Hydrocarbon liquids greater than or equal to 20 ̊API are considered “light crude.” 

5

 “Other” category includes instruments, loading arms, pressure relief valves, stuffing boxes, 

compressor seals, dump lever arms, and vents. 

6

 Hydrocarbon liquids less than 20 ̊API are considered “heavy crude.” 

 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board A-3 February 2015

Table 1B 

Default Average Component Counts for Major Onshore Natural Gas Production 

Equipment 

Major 

equipment 

Valves Connectors Open-ended 

lines 

Pressure relief 

valves 

Western U.S.

Wellheads 11 36 1 0

Separators 34 106 6 2

Meters/piping 14 51 1 1

Compressors 73 179 3 4

In-line heaters 14 65 2 1

Dehydrators 24 90 2 2

Table 1C 

Default Average Component Counts for Major Crude Oil Production Equipment 

Major 

equipment 

Valves Flanges Connectors Open-ended 

lines 

Other 

components 

Western U.S.

Wellhead 5 10 4 0 1 

Separator 6 12 10 0 0 

Heatertreater 8 12 20 0 0 

Header 5 10 4 0 0 

 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board A-4 February 2015

Table 2 

Default Total Hydrocarbon Emission Factors for Onshore Natural Gas Processing 

Onshore natural gas processing Emission Factor 

(scf/hour/component) 

Leaker Emission Factors – Compressor Components, Gas Service

 Valve114.84

 Connector 5.59

 Open-Ended Line 17.27

 Pressure Relief Valve 39.66

 Meter 19.33

Leaker Emission Factors – Non-Compressor Components, Gas Service

 Valve16.42

 Connector 5.71

 Open-Ended Line 11.27

 Pressure Relief Valve 2.01

 Meter 2.93

1 Valves include control valves, block valves and regulator valves.

Table 3 

Default Total Hydrocarbon Emission factors for Onshore Natural Gas Transmission 

Compression 

Onshore Natural Gas Transmission compression Emission Factor 

(scf/hour/component) 

Leaker Emission Factors – Compressor Components, Gas Service

 Valve114.84

 Connector 5.59

 Open-Ended Line 17.27

 Pressure Relief Valve 39.66

 Meter 19.33

Leaker Emission Factors – Non-Compressor Components, Gas Service

 Valve16.42

 Connector 5.71

 Open-Ended Line 11.27

 Pressure Relief Valve 2.01

 Meter 2.93

Population Emission Factors – Gas Service

 Low Continuous Bleed Pneumatic Device Vents21.37

 High Continuous Bleed Pneumatic Device Vents218.20

 Intermittent Bleed Pneumatic Device Vents22.35

1

 Valves include control valves, block valves, and regulator valves. 

2

 Emission Factor is in units of “scf/hour/component.” 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board A-5 February 2015

Table 4 

Default Total Hydrocarbon Emission Factors for Underground Natural Gas Storage 

Underground natural gas storage Emission Factor 

(scf/hour/component) 

Leaker Emission Factors – Storage Station, Gas Service

 Valve114.84

 Connector 5.659

 Open-Ended Line 17.27

 Pressure Relief valve 39.66

 Meter 19.33

Population Emission Factors – Storage Wellheads, Gas Service

 Connector 0.01

 Valve10.1

 Pressure Relief Valve 0.17

 Open Ended Line 0.03

Population Emission Factor – Other Components, Gas Service

 Low Continuous Bleed Pneumatic Device Vents21.37

 High Continuous Bleed Pneumatic Device Vents218.20

 Intermittent Bleed Pneumatic Device Vents22.35

1

 Valves include control valves, block valves and regulator valves. 

2

 Emission Factor is in units of “scf/hour/device. 

Table 5 

Default Methane Emission Factors for Liquefied Natural Gas (LNG) Storage 

LNG Storage Emission Factor 

(scf/hour/component)

Leaker Emission Factors – LNG storage Components, Gas and Liquids Service

 Valve 1.19

 Pump Seal 4.00

 Connector 0.34

 Other11.77

Population Emission Factors – LNG Storage Compressor, Gas Service

 Vapor Recovery Compressor24.17

1

 “other” equipment type should be applied for any equipment type other than connectors, 

pumps, or valves. 

2

 Emission Factor is in units of “scf/hour/compressor.” 

 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board A-6 February 2015

Table 6 

Default Methane Emission Factors for LNG Import and Export Equipment 

LNG import and export equipment Emission Factor 

(scf/hour/component)

Leaker Emission Factors – LNG Terminals Components, Gas and Liquid Service

 Valve 1.19

 Pump Seal 4.00

 Connector 0.34

 Other11.77

Population Emission Factors – LNG Terminal Compressor, Gas Service

 Vapor Recovery Compressor24.17

1

 “other” equipment type should be applied for any equipment type other than connectors, 

pumps, or valves. 

2

 Emission Factor is in units of “scf/hour/compressor.” 

 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board A-7 February 2015

Table 7 

Default Methane Emission Factors for Natural Gas Distribution 

Natural gas distribution Emission Factor 

(scf/hour/component)

Leaker Emission Factors – Above Grade M&R at City Gate Stations1 Components

 Connector 1.69

 Block Valve 0.557

 Control Valve 9.34

 Pressure Relief Valve 0.27

 Orifice Meter 0.212

 Regulator 0.772

 Open-ended Line 26.131

Population Emission Factors – Below Grade M&R 2 Components, Gas Service

 Below Grade M&R Station, Inlet Pressure >300 psig 1.30

 Below Grade M&R Station, Inlet Pressure 100 to 300 psig 0.20

 Below Grade M&R Station, Inlet Pressure <100 psig 0.10

Population emission Factors – Distribution Mains, Gas Service4

 Unprotected steel 12.58

 Protected Steel 0.35

 Plastic 1.13

 Cast Iron 27.25

Population Emission Factors – Distribution Services, Gas Service5

 Unprotected Steel 0.19

 Protected Steel 0.02

 Plastic 0.001

 Copper 0.03

Population Emission Factors – Customer Meters Emission Factor 

(scf/meter-hour) 

 Residential 0.01582

 Commercial 0.00547

 Industrial 0.00547

1 City gate stations at custody transfer and excluding customer meters. 

2

 Excluding customer meters. 

3

 Emission Factor is in units of “scf/hour/station.”

4

 Emission Factor is in units of “scf/hour/mile.” 

5

 Emission factor is in units of “scf/hour/number of services.” 

 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

California Air Resources Board A-8 February 2015

Page Intentionally Blank 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

Air Resources Board B-1 February 2015 

Appendix B 

to the Regulation for the Mandatory Reporting 

of Greenhouse Gas Emissions 

TEST PROCEDURE 

Flash Emissions of Greenhouse Gases and 

Other Compounds from Crude Oil and Natural Gas 

Separator and Tank Systems 

 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

Air Resources Board B-2 February 2015 

Test Procedure 

Flash Emissions of Greenhouse Gases and Other Compounds from Crude Oil and 

Natural Gas Separator and Tank Systems 

1. PURPOSE AND APPLICABILITY 

This procedure is used to determine annual emission rates of Greenhouse 

Gases and other compounds from crude oil and natural gas separator and tank 

systems. This procedure is conducted by gathering one sample of crude oil or 

condensate and one sample of produced water from a pressurized vessel and 

having the liquids analyzed by a laboratory to determine the composition and 

volume of gas released from the liquids while they change from reservoir to 

standard atmospheric conditions. The laboratory results are used in conjunction 

with throughput to calculate the emission rates per year. The sampling and lab 

analyses may also be conducted to evaluate emissions from Flowback Fluids 

used to stimulate or hydraulically fracture a crude oil or natural gas well if they 

are handled by a separation and tank system. An alternative methodology is 

included for determining the specified emissions rates using measured vapor 

recovery system parameters provided the system meets the requirements 

specified in Section 9. 

2. PRINCIPLE AND SUMMARY OF TEST PROCEDURE 

The sampling and laboratory methods specified in this procedure are used to 

take samples of liquids and conduct a Flash Analysis on crude oil or natural gas 

separator and tank systems and are based on American Standards and Testing 

Materials (ASTM), US Environmental Protection Agency (EPA), and Gas 

Processor Association (GPA) methods and standards. The alternative vapor 

recovery system methodology described in Sections 9 and 10.2 is based on 

common industry practices. 

Samples must be taken from a primary vessel located in a separator and tank 

system using the sampling methods specified in this procedure. Non-pressurized 

tanks or secondary vessels may not be used for sampling. Typical sampling 

points are from pressurized Two-Phase or Three-Phase Separators or vessels 

used to measure Percent Water Cut (e.g., Automatic Well Tester). The liquids 

found in these vessels contain gases that will flash from the liquids as vapor 

when the liquids flow into lower pressure secondary vessels. This procedure is 

used to measure both the volume and composition of this flashed gas vapor. 

Liquid samples of a crude oil-produced water emulsion do not contain enough 

crude oil to be evaluated by a laboratory and are not applicable to this procedure. 

Two sampling methods are specified: The first is a displacement method used 

for gathering crude oil or condensate. The second is for gathering produced 

water. Both methods are specified due to the nature of the laboratory analyses 

and the design of the sampling cylinders. Produced water cannot be displaced 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

Air Resources Board B-3 February 2015 

from a Double-Valve Cylinder using laboratory grade water and heavy crude oil 

may solidify and cause problems with a Floating-Piston Cylinder. 

The laboratory methods are used to measure the composition and volume of gas 

that flash from liquids while they cool or depressurize to standard atmospheric 

conditions. This includes the molecular weight and weight percent of the 

gaseous compounds and a Gas-to-Oil Ratio or Gas-to-Water Ratio. The 

laboratory results are applied to the annual liquid production rates to calculate 

Greenhouse Gas and other compound emission rates per year. 

3. DEFINITIONS 

For the purposes of this procedure, all definitions are found in section 95102(a) 

of the Regulation for the Mandatory Reporting of Greenhouse Gas Emissions 

(title 17, California Code of Regulations, section 95100 et seq.). 

4. BIASES AND INTERFERENCES 

4.1 The sampling methods specified in this procedure have an impact on the 

laboratory methods and the final results reported. All samples must be 

gathered in adherence with the minimum procedures and specifications 

identified in this procedure. 

4.2 A representative sampling point must be selected to ensure that 

pressurized gases remain suspended in liquid during sampling. Obtaining 

samples from a non-pressurized vessel or a vessel connected to a vapor 

recovery system will produce non-representative results. 

4.3 All pressure and temperature measurements must be acquired using 

calibrated instruments as described in Section 5. Un-calibrated equipment, 

including pressure or temperature gauges installed on vessels, may 

produce non-representative results. This may result in data errors when 

analyzing samples in a laboratory. 

4.4 The analytical portion of this procedure must be conducted by laboratories 

experienced with laboratory instrumentation, analytical methods, and the 

laboratory methods specified in this procedure. 

5. EQUIPMENT SPECIFICATIONS 

5.1 A pressure gauge capable of measuring liquid pressure less than 200 

pounds per square inch pressure within +/-10% accuracy. 

5.2 A pressure gauge capable of measuring liquid pressure greater than 200 

pounds per square inch pressure within +/- 5% accuracy. 

5.3 A temperature gauge capable of reading liquid temperature to within +/- 

2

o

F. The range of the gauge must be at least 32 to 200oF. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

Air Resources Board B-4 February 2015 

5.4 A volume meter with a minimum of +/- 5% accuracy over the entire range 

of flow rates for which the meter is used. Volume meters must be 

calibrated annually against a NIST traceable standard. 

6. TEST EQUIPMENT 

6.1 A Double-Valve Cylinder filled with laboratory grade water for crude oil or 

condensate or a Floating-Piston Cylinder for produced water. 

6.2 A Graduated Cylinder to measure displaced laboratory grade water from a 

Double-Valve Cylinder. 

6.3 A waste container suitable for capturing and disposing sample liquid. 

6.4 High-pressure rated components and control valves that can withstand 

pressure under the same operating conditions as the vessel sampled. 

6.5 A low-pressure and a high-pressure measuring device with minimum 

specifications listed in Section 5. 

6.6 A temperature measuring device with minimum specifications listed in 

Section 5. 

6.7 A calibrated volume meter with temperature and pressure gauges each 

with minimum specifications listed in Section 5 for measuring collected 

vapor recovery gas volume as described in Section 9. 

6.8 A stainless steel hand pump equipped with one-way check valves suitable 

for pumping low API gravity crude oil into a Double-Valve Cylinder per 

Section 7.3. Stainless steel is required to prevent sample contamination. 

7. SAMPLING METHODS 

Pre-Sampling Requirements 

Prior to gathering liquid samples, the sampling technician must be provided with 

the vessel description, Throughput, Percent Water Cut, Days of Operation, and a 

description of the vapor recovery system on downstream vessels by the facility 

operator as indicated in Table 1 and on Form 1. If required, the Percent Water 

Cut may be measured using ASTM D-4007-08. For sampling liquids that may 

contain proprietary compounds, such as those used in hydraulic fracturing 

liquids, a Tentatively Identified Compound List must also be provided prior to 

gathering liquid samples. All of this information specified is required to calculate 

and report the results of this test procedure. The results of this test procedure 

may be nullified without the specified information.

Background 

The sampling method used for this procedure depends on the type of liquid to be 

sampled. Crude oil or condensate is collected using the Crude Oil or 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

Air Resources Board B-5 February 2015 

Condensate Sampling Method specified in Section 7.1. Produced water is 

collected using the Produced Water Sampling Method specified in Section 7.2. 

Low API gravity crude oil that will not flow into a sampling cylinder may be 

collected using the method specified in Section 7.3. 

Liquid samples must only be taken from separated liquids. This is accomplished 

by taking samples from different levels in a pressurized separator, which may be 

a permanent or temporarily installed vessel. Liquid samples of emulsions cannot 

be evaluated by a laboratory and are therefore not applicable to this procedure. 

To gather a liquid sample, the sample vessel must be pressurized. Samples 

must not be taken from tanks or separators open to atmosphere. 

When a liquid sample is gathered, the technician measures the pressure and 

temperature of the liquid using the calibrated gauges specified and records the 

vessel and liquid characteristics as reported by the facility operator. The cylinder 

is then identified with a Cylinder Identification Tag (See Section 8) and sent to a 

laboratory for analysis. The laboratory heats and pressurizes the liquid to the 

same conditions recorded at the time of sampling and performs a Flash Analysis 

which measures the rate and composition of gas evolved from the liquid while it 

cools and depressurizes to specified atmospheric conditions. 

7.1 CRUDE OIL OR CONDENSATE SAMPLING METHOD 

The Crude Oil or Condensate Sampling Method is conducted by displacing 

laboratory grade water with pH between 5 and 7 from a Double-Valve Sampling 

Cylinder. Figure 1 illustrates a Double-Valve Cylinder sampling train. The 

configuration shows a cylinder outfitted with high-pressure rated components that 

can be used for controlling the flow of liquid. Calibrated temperature (Gauge L) 

and pressure (Gauge M) gauges are included for conducting field 

measurements. Sample liquid enters the cylinder when water is displaced into a 

graduated cylinder. The amount of sample liquid contained in the cylinder is 

equal to the amount of laboratory grade water measured in the graduated 

cylinder. 

 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

Air Resources Board B-6 February 2015 

Figure 1 

Double-Valve Cylinder Sampling Train 

(a) If samples are to be shipped to a laboratory, calculate 90% of the cylinder 

volume, which will be the volume of sample to gather. As an example, 

90% of a 500ml cylinder is 0.9 x 500 ml = 450 ml. This also represents 

the amount of water to displace with sample liquid. The cylinder must 

retain 10% of the laboratory grade water to allow for flashing during 

shipping and to prevent an explosive situation from occurring. If samples 

are not going to be shipped to a laboratory, this step does not need to be 

performed. Instead, fill the entire cylinder with sample liquid after purging 

with three cylinder volumes of liquid as described in (f). 

(b) Connect the sampling train to a sampling point on the pressurized vessel. 

Bushings or reducers may be required. 

(c) Purge the sample line: with Valves C and D closed, route the outlet of 

Valve B into a suitable waste container to purge sample liquid. Slowly 

open Valve B. Slowly open Valve A and allow air and liquid to purge. 

Continue purging until a consistent, steady stream of liquid is observed 

and gas pockets subside. Close Valve B. 

(d) With Valve C and D closed, slowly open Valve A to the full-open position 

and then slowly open Valve C to the full-open position. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

Air Resources Board B-7 February 2015 

(e) Slowly open Valve D to allow a slow discharge of water into the graduated 

cylinder at a rate of approximately 60 milliliters per minute (1 drip per 

second). 

(f) Record the temperature from Gauge L and pressure from Gauge M while 

the liquid is filling the cylinder. Do not take temperature or pressure 

measurements on stagnant liquid. If the sample is to be shipped as 

described in (a), continue displacing the laboratory grade water from the 

cylinder until 90% of the water is displaced. If the cylinder is not going to 

be shipped, continue filling the cylinder with sample liquid until three 

cylinder volumes of liquid have passed through the sampling cylinder. 

(g) Close Valves D, C, and A in that order. 

(h) Purge the line pressure: slowly open Valve B and allow pressurized liquid 

to drain into the waste container. 

(i) Disconnect the Double-Valve Cylinder from the sampling train and 

disconnect the sampling train from the pressurized vessel. 

(j) Check Valves C and D for leaks. If either Valve C or D is leaking, drain 

the cylinder into a suitable waste container and use a different cylinder to 

obtain a new sample. 

(k) Wrap the threaded connections of the cylinder with Teflon tape and cap 

using threaded metal caps to protect the threads and ensure the cylinder 

is securely sealed for shipping. 

(l) Identify the sample cylinder as specified in Section 8. 

7.2 PRODUCED WATER SAMPLING METHOD 

The Produced Water Sampling Method is conducted using a Floating-Piston 

Cylinder. This allows the sample liquid to be extracted from the cylinder without 

using laboratory water. The cylinder is provided by a laboratory with the piston 

pressurized with inert gas to approximately 1,000 psig or greater. Note: produced 

water may be gathered using a Double-Valve Cylinder as described in Section 

7.1 provided that the laboratory can displace the produced water from the 

cylinder without commingling the sample liquid with laboratory grade water. 

Prior to gathering a sample, the technician first measures the vessel pressure 

and temperature using the calibrated gauges specified. The technician then 

bleeds off excess pressure from the piston to at least 10 psig greater than the 

vessel to be sampled. Sample liquid is gathered by slowly bleeding off additional 

pressure from the piston. The rate at which liquid is gathered must not exceed 

60 milliliters per minute in order to prevent the liquid from flashing gases within 

the sample cylinder. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

Air Resources Board B-8 February 2015 

Figure 2 shows a Floating-Piston Cylinder sample train outfitted with 

high-pressure rated components. Calibrated temperature (Gauge L) and 

pressure (Gauge M and N) gauges are included for conducting the required 

vessel measurements. 

Figure 2 

Floating-Piston Cylinder Sampling Train 

(a) Connect the sampling train to a sampling point on the pressurized vessel. 

Bushings or reducers may be required. 

(b) Purge the sample line: with Valves C and D closed, route the outlet of 

Valve B into a suitable waste container to purge sample liquid. Slowly 

open Valve A to the full-open position. Slowly open Valve B and allow 

liquid to purge. Continue purging until a consistent, steady stream of 

liquid is observed and gas pockets subside. Close Valve B. 

(c) Slowly open Valve C to the full-open position. 

(d) Slowly open Valve D to release inert gas pressure until the pressure 

indicated on Gauge N is equal to Gauge M. When both gauges read 

equal pressure, close Valve D and prepare to gather sample liquid. 

(e) Slowly open Valve D and allow liquid to enter the cylinder at a slow rate of 

approximately 60 ml per minute to prevent liquid from flashing within the 

sampling cylinder. Use the measurement scale located on the sampling 

cylinder and a stopwatch to measure the rate at which liquid is gathered. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

Air Resources Board B-9 February 2015 

(f) Record the temperature from Gauge L and pressure from Gauge M while 

liquid is gathered. Do not take measurements on stagnant liquid. 

(g) Continue gathering liquid until the cylinder is 80% full as indicated on the 

cylinder scale. The rate at which liquid enters the cylinder, and the 

volume of liquid in the cylinder, are indicated on the sample cylinder. No 

outage is required when using a Floating-Piston Cylinder. 

(h) Close valves D, C, and A in that order. 

(i) Purge the line pressure: slowly open Valve B and allow pressurized liquid 

to drain into the waste container. 

(j) Disconnect the Floating-Piston Cylinder from the sampling train and 

disconnect the sampling train from the pressurized vessel. 

(k) Check Valves C and D for leaks. If either Valve C or D is leaking, drain 

the cylinder into a suitable waste container and use a different cylinder to 

obtain a new sample. 

(l) Wrap the threaded connections of the cylinder with Teflon tape and cap 

using threaded metal caps to protect the threads and ensure the cylinder 

is securely sealed for shipping. 

(m) Identify the sample cylinder as specified in Section 8. 

7.3 LOW API GRAVITY CRUDE OIL SAMPLING METHOD 

In some cases, low API gravity crude oil may not flow into a sampling cylinder. 

This could be due to the viscosity, temperature, or pressure of the oil. In these 

cases, a stainless steel hand pump is used to assist with the collection of liquid. 

The pump must be outfitted with one-way check valves to ensure that liquid flows 

in only one direction. The difference between the Displacement Method and this 

method is that the hand pump is used in place of system pressure. 

(a) Install the stainless steel hand pump equipped with one-way check valves 

as described in Section 6 at the inlet of the Double-Valve Cylinder 

Sampling Train. 

(b) Using the hand pump to slowly force the flow of liquid, collect a liquid 

sample following the sample procedures described in Section 7.1. 

8. CYLINDER IDENTIFICATION TAG 

8.1 Identify the cylinder with a Cylinder Identification Tag. Both the tag and a 

copy of Form 1 must be completed prior to sampling using information 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

Air Resources Board B-10 February 2015 

provided by the facility operator and must include the following minimum 

information: 

(a) Date and time; 

(b) Unique sample ID number or cylinder number; 

(c) Sample type (crude oil, condensate, or produced water); 

(d) Sample pressure and temperature during sampling; 

(e) Vessel description; 

(f) Vessel throughput of emulsion or liquid in barrels per day; 

(g) Percent Water Cut; 

(h) Days of Operation per Year; 

(i) Facility name and location of where sample was gathered; and, 

(j) Attach a completed copy of Form 1. 

8.2 Package the cylinder with the information tag and a copy of Form 1. 

9. ALTERNATIVE METHODOLOGY FOR CALCULATING EMISSION RATES 

USING MEASURED VAPOR RECOVERY SYSTEM PARAMETERS IN LIEU 

OF GATHERING AND EVALUATING LIQUID SAMPLES 

This methodology is used to measure the specified emission rates using a vapor 

recovery system in lieu of gathering and evaluating liquid samples. This 

methodology requires that all gases flashed from liquid are collected and 

measured, and that a vapor recovery system is installed on a minimum of the 

primary and secondary vessels, and that intermediate vessels be covered and 

controlled using a pressure/vacuum valve, at minimum, so that the vessels are 

not open to atmospheric pressure. This methodology is an alternative to 

gathering and evaluating liquid samples and may be used for systems that 

handle emulsions or single liquids. 

The Greenhouse Gas and other compound emission rates are calculated using 

the measured annual vapor recovery gas volume metered by the system and an 

annual gas composition analysis. The annual measured gas volume is adjusted 

to account for capture efficiency of the vapor recovery system. 

(a) Measure the annual gas volume recovered by the vapor recovery system 

using the calibrated meter outfitted with temperature and pressure gauges 

as described in Section 6. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

Air Resources Board B-11 February 2015 

(b) Obtain an annual gas sample of the vapor recovery gas and evaluate it for 

all gaseous compounds, the molecular weight, and the weight percent of 

Greenhouse Gases and other compounds. 

(c) Calculate the annual emission rates as described in Section 10.2. 

10. CALCULATING RESULTS 

10.1 Flash Emission Calculation Methodology for Liquid Samples 

The following is used in conjunction with vessel information and a laboratory 

analysis to calculate metric tons of Greenhouse Gases (CO2 and CH4) or short 

tons of other compounds (VOCC3-C9 or BTEX). The same formulas may be 

applied to crude oil, condensate, and produced water. 

(a) If required, calculate the barrels per day of crude oil or condensate in 

emulsion using the Percent Water Cut: 

Barrels / Day = (1− Percent Water Cut)(Throughput) Equation 1A

Where: 

 Barrels/Day = barrels per day crude oil or condensate 

Percent Water Cut = percentage of produced water in emulsion 

Throughput = barrels per day of emulsion 

(b) If required, calculate the barrels per day of produced water in emulsion 

using the Percent Water Cut: 

Barrels / Day = (Percent Water Cut)(Throughput) Equation 1B

Where: 

 Barrels/Day = barrels per day produced water 

Percent Water Cut = percentage of produced water in emulsion 

Throughput = barrels per day of emulsion 

(c) Calculate the total volume of gas produced per year: 

( ) 



























=

Year

Days

Day

Barrels Ft /Year G

3

 Equation 2
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

Air Resources Board B-12 February 2015 

 Where: 

 Ft3

/Year = standard cubic feet of gas produced per year 

 G = Gas-to-Oil Ratio or Gas-to-Water Ratio (from lab analysis) 

 Barrels/Day = barrels per day crude oil, condensate, or produced water 

(Eq. 1A/1B) 

 Days/Year = days of operation per year 

(d) Convert the total gas volume to pounds: 

 Equation 3 











































 −

















−

















=

grams

lb

Ft

l

l

gram mole

gram mole

gram

Year

Ft Mass Year Gas 454

.28 317

.23 690

/

3

3

 Where: 

Mass Gas /Year = pounds of gas per year 

Ft3

/Year = cubic feet of gas produced per year (Eq. 2)

Gram/Gram-Mole = Molecular Weight of gas sample (from lab analysis) 

23.690 l/gr-mole = molar volume of ideal gas at 14.696 psi and 600F 

(e) Calculate the mass of GHG or other compound: 













































=

lb

metric ton

Year

WT GHG Mass

Mass Year Gas

GHG 100 2205

%

/ Equation 4 









































=

lb

ton

Year

WT Compound Mass

Mass Year Gas

Compound 100 2000

%

/ Equation 5

Where: 

Mass GHG /Year = metric tons of CO2 or CH4 (Eq. 4) 

Mass Compound /Year = tons of other compound (Eq. 5) 

Mass Gas /Year = pounds of gas per year (Eq. 3) 

WT% GHG = Weight % of CO2 or CH4 (from lab analysis) 

WT% Compound = Weight % of VOCC3-C9 or BTEX (from lab analysis) 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

Air Resources Board B-13 February 2015 

(f) If a vapor recovery system is installed on the separator and tank system, 

adjust the annual emission rate as follows: 

( / ) 1( ) Emissions GHG /Compound = Mass GHG /Compound Year −CE Equation 6 

Where: 

Emissions GHG/Compound = controlled GHG or other compound emissions 

Mass GHG/Compound /Year = uncontrolled GHG or other compound emissions 

per year (Eq. 4 or 5) 

CE = capture and control efficiency of vapor recovery system 

10.2 Emission Calculation Methodology Using Measured Vapor Recovery 

System Parameters

(a) Convert the total volume of vapor measured using the calibrated meter 

and average annual vapor temperature and pressure to standard 

conditions: 











 +













=

696.14

519 67. 696.14

/

3 P

T

Ft Year V Equation 7 

 Where: 

Ft3/Year = annual cubic feet of gas corrected to standard conditions (scf) 

V = annual volume of gas going to the vapor recovery system, measured 

by the calibrated meter (cubic feet) 

T = average annual vapor temperature measured at the meter (degrees R) 

P = average annual gauge pressure measured at the meter (psig) 

(b) Convert the total gas volume to pounds: 

 Equation 8 











































 −

















−

















=

grams

lb

Ft

l

l

gram mole

gram mole

gram

Year

Ft Mass Year Gas 454

.28 317

.23 690

/

3

3

 Where: 

Mass Gas /Year = pounds of gas per year 

Ft3

/Year = cubic feet of gas produced per year (Eq. 6)

Gram/Gram-Mole = Molecular Weight of gas sample (from lab analysis) 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

Air Resources Board B-14 February 2015 

23.690 l/gr-mole = molar volume of ideal gas at 14.696 psi and 600F 

(c) Calculate the mass of GHG or other compound: 













































=

lb

metric ton

Year

WT GHG Mass

Mass Year Gas

GHG 100 2205

%

/ Equation 9 









































=

lb

ton

Year

WT Compound Mass

Mass Year Gas

Compound 100 2000

%

/ Equation 10

Where: 

Mass GHG /Year = metric tons of CO2 or CH4 (Eq. 9) 

Mass Compound /Year = tons of other compound (Eq. 10) 

Mass Gas /Year = pounds of gas per year (Eq. 8) 

WT% GHG = Weight % of CO2 or CH4 (from lab analysis) 

WT% Compound = Weight % of VOCC3-C9 or BTEX (from lab analysis) 

(d) Adjust the annual emission rate as follows: 

Equation 11 

( ) 









 −

=

CE

CE Emissions Mass Year GHG Compound GHG Compound

1

/

/ /

 Where: 

Emissions GHG/Compound = uncaptured GHG or other compound emissions 

Mass GHG/Compound /Year = captured GHG or other compound emissions 

per year (Eq. 9 or 10) 

CE = capture efficiency of vapor recovery system. 

11. REPORTING RESULTS 

The results of this procedure are used to estimate or report emission rates of 

Greenhouse Gases or other compounds from separator and tank systems used 

in onshore crude oil or natural gas production, processing, or storage. All results 

shall be reported to at least three significant figures. All supporting information 

used to derive the emission estimates, including sample information, laboratory 

results, and calculations must be maintained by the reporting entity for a 

minimum of three years in order to reproduce the estimated or reported results. 

The following information must be maintained by the reporting entity: 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

Air Resources Board B-15 February 2015 

11.1 Crude Oil, Condensate, or Produced Water (Section 10.1)

(a) Laboratory results specified in Section 12; 

(b) All calculations and calculated results; 

(c) A completed copy of Form 1; 

(d) Annual emission rates of Greenhouse Gases and other compounds; 

(e) Annual production of crude oil, condensate, and produced water; and 

(f) API Gravity of crude oil or condensate. 

 11.2 Emulsion or Liquids under Vapor Recovery (Section 10.2) 

(a) Laboratory results of an annual gas composition analysis or an average of 

multiple, more frequent samples within the year; 

(b) Measured annual vapor recovery system gas throughput; 

(c) All calculations and calculated results; 

(d) Annual emission rates of Greenhouse Gases and other compounds; and, 

(e) API Gravity of crude oil or condensate. 

12. ANALYTICAL LABORATORY METHODS 

12.1 Sample Preparation 

(a) Prior to extracting liquid from a sample cylinder, the cylinder must be 

heated to the same temperature as measured at the time of sampling. 

The laboratory apparatus must be temperature and pressure controlled by 

a means that allows cooling and depressurizing liquid from sampling 

conditions to the standard temperature and pressure while precisely 

measuring liquid and gas volumes.

(b) Sample gases shall be collected in a closed system with a means of 

precisely measuring liquid and gas volume. Sample preparation guidance 

can be found in GPA 2174-93, GPA 2261-00 and GPA 2177-03. 

12.2 Laboratory Methods 

The following methods are required to evaluate and report flash emission rates 

from crude oil, condensate, and produced water. All methods and quality control 

requirements shall be conducted as specified in each method. 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

Air Resources Board B-16 February 2015 

(a) Hydrogen Sulfide (Low-Level): Evaluate using EPA Method 15 and EPA 

Method 16 or use ASTM D-1945-03 (Thermal Conductivity Detector), 

ASTM D-5504-08 (sulfur chemiluminescence detector), and ASTM D6228-10 (flame photometric detector) as alternate methods. 

(b) Oxygen, Nitrogen, Carbon Dioxide, Hydrogen Sulfide (High-Level), 

Methane, Ethane, Propane, i-Butane, n-Butane, i-Pentane, n-Pentane, 

Hexanes, Heptanes, Octanes, Nonanes, and Decanes+: Evaluate per 

ASTM D-1945-03, ASTM D-3588-98(2003), and ASTM D-2597-

94(2004)(GC/TCD). Note: This analysis requires all three methods 

specified. The base method is ASTM D-1945-03, which is modified to 

extend the hydrocarbon analysis range based on information from the 

other two methods. 

(c) BTEX: Evaluate per EPA 8021 B (GC/FID) or use ASTM D-3170, GPA 

2286, EPA 8260B, EPA TO-14, and EPA TO-15 as alternate methods. 

(d) API Gravity of liquid phase crude oil or condensate at 60 degrees 

Fahrenheit (60o

F): Evaluate per ASTM D-287-92-(2006) using measured 

result of Specific Gravity. Note: If water is entrained in the sample, 

measure the API Gravity using ASTM D-287-92 (2006)(API Hydrometer) 

and calculate the Specific Gravity using the measured API Gravity. 

(e) Specific Gravity of pre-flash liquid phase crude oil or condensate: 

Evaluate per ASTM D-4052-09, ASTM D-70-09, or ASTM D-5002-

99(2010) or calculate using results from ASTM D-287-92(2006). 

(f) Molecular Weight of gaseous phase by calculation per ASTM D-3588-

98(2003). 

(g) Percent Water Cut: evaluate per ASTM D-4007-08 (Basic Sediment and 

Water). 

12.3 Laboratory Reports

Any chromatograph system that allows for the collection, storage, interpretation, 

adjustment, or quantification of chromatograph detector output signals 

representing relative component concentrations may be used to conduct this 

procedure. The laboratory results must be reported as specified in Section 11. A 

laboratory report that provides the following minimum information described 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

Air Resources Board B-17 February 2015 

below and in Table 1 must be provided to the facility operator so they can 

calculate and report the results specified in Sections 10 and 11: 

(a) The gaseous phase WT% of CO2, CH4, the gaseous phase WT% of C2 

through C9 and C10+, the gaseous phase WT% of BTEX, and the 

gaseous phase WT% of O2, N2, and H2S; 

(b) The gaseous phase Gram Molecular Weight of the total gas sample; 

(c) The liquid phase API Gravity of crude oil or condensate at 60oF; 

(d) Volumetric Gas-to-Water Ratio (GWR) for produced water; and, 

(e) Volumetric Gas-to-Oil Ratio (GOR) for crude oil or condensate. 

 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

Air Resources Board B-18 February 2015 

Table 1 

Flash Analysis Sampling and Laboratory Requirements

Sampling Technician Needs to Obtain from Operator 

Before Sampling Can Occur: 

Vessel Description 

Vessel Throughput (Barrels/Day) 

Percent Water Cut 

Number of Days in Operation 

Vapor Recovery System Information (downstream vessels) 

• Presence of VR System 

• Vapor Processing & Type 

• Vapor End Use(s) 

Tentatively Identified Compound List (if sampling proprietary 

compounds) 

Gas Evolved from Crude Oil, 

Condensate, or Produced Water 

WT% CO2, CH4 

WT% C2-C9, C10+ 

WT% BTEX 

WT% O2 

WT% N2 

WT% H2S 

Molecular Weight Total Gaseous Sample

Gas-to-Oil Ratio 

Gas-to-Water Ratio 

Pre-Flash Liquid Crude Oil 

or Condensate 

API Gravity 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

Air Resources Board B-19 February 2015 

13. REFERENCES 

ASTM D-70-09 Standard Test Method for Density of Semi-Solid 

Bituminous Materials (Pycnometer Method) 

ASTM D-287-92(2006) Standard Test Method for API Gravity of Crude 

Petroleum and Petroleum Products (Hydrometer Method) 

ASTM D-1945-03 Standard Test Method for Analysis of Natural Gas by Gas 

Chromatography 

ASTM D-2597-94(2004) Standard Test Method for Analysis of Demethanized 

Hydrocarbon Liquid Mixtures Containing Nitrogen and

Carbon Dioxide by Gas Chromatography 

ASTM D-3710-95(1999) Standard Test Method for Boiling Range Distribution of 

Gasoline and Gasoline Fractions by Gas Chromatography

ASTM D-3588-98(2003) Standard Practice for Calculating Heat Value, 

Compressibility Factor, and Relative Density of Gaseous 

Fuels 

ASTM D-4007-08 Standard Test Method for Water and Sediment in Crude 

Oil by the Centrifuge Method

ASTM D-4052-09 Standard Test Method for Density, Relative Density, and 

API Gravity of Liquids by Digital Density Meter 

ASTM D-5002-99(2010) Standard Test Method for Density and Relative Density 

of Crude Oils by Digital Density Analyzer 

ASTM D-5504-08 Standard Test Method for Determination of Sulfur 

Compounds in Natural Gas and Gaseous Fuels by Gas 

Chromatography and Chemiluminescence 

ASTM D-6228-10 Standard Test Method for Determination of Sulfur 

Compounds in Natural Gas and Gaseous Fuels by Gas 

Chromatography and Flame Photometric Detection 

EPA Method 15 (1996) Determination of Hydrogen Sulfide, Carbonyl Sulfide, and 

Carbon Disulfide Emissions from Stationary Sources

EPA Method 16 (1996) Semicontinuous Determination of Sulfur Emissions from 

Stationary Sources 

EPA Method 8021B (1996) Aromatic and Halogenated Volatiles By Gas 

Chromatography Using Photoionization And/Or Electrolytic 

Conductivity Detectors
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

Air Resources Board B-20 February 2015 

EPA Method 8260B(1996) Volatile Organic Compounds By Gas 

Chromatography/Mass Spectrometry (GC/MS)

EPA Method TO-14(1999) Determination Of Volatile Organic Compounds 

(VOCs) In Ambient Air Using Specially Prepared Canisters 

With Subsequent Analysis By Gas Chromatography 

EPA Method TO-15(1999) Determination Of Volatile Organic Compounds 

(VOCs) In Air Collected In Specially-Prepared Canisters 

And Analyzed By Gas Chromatography/Mass 

Spectrometry (GC/MS) 

GPA 2174-93 Analysis Obtaining Liquid Hydrocarbon Samples For 

Analysis by Gas Chromatography

GPA 2177-03 Analysis of Natural Gas Liquid Mixtures Containing 

Nitrogen and Carbon Dioxide by Gas Chromatography

GPA 2261-00 Analysis for Natural Gas and Similar Gaseous Mixtures by 

Gas Chromatography

 GPA 2286-95 Extended Gas Analysis Utilizing a Flame Ionization 

Detector

 
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

Air Resources Board B-21 February 2015 

Facility Contact Information:

Facility Name:

Address:

City: State:

Zip: Phone:

Facility Contact:

Sampling Company:

Company Name:

Address:

City: State:

Zip: Phone:

Sampling Technician:

Sample Information:

Sample Type: (crude oil, condensate, produced water)

Date:

Time: Sample Temperature: Deg. F

Cylinder Number: Sample Pressure: PSI

Field Name: (field from where sample was taken)

Separator Information:

Separator Type: (e.g., heater/treater)

Separator Throughput: (barrels/day)

Percentage Water Cut % Days in Operation/Year:

Vapor Recovery (VR) System (downstream of sample vessel):

VR System Installed: Yes No

Vapor Processing & Type: Yes No List Type(s):

(Sulfa Treat, Amine, etc.)

Vapor End Use(s) (list):

(sales gas, flare, engine, boiler, etc.)

Shipping Information:

Shipping Company:

Tracking Number:

Crude Oil, Condensate, and Produced Water Sampling Field Data Sheet

Form 1

(report measured results to at least three significant figures)
Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Greenhouse Gas 

Emissions. The official legal edition is available at the OAL website: http://www.oal.ca.gov/CCR.htm 

Air Resources Board B-22 February 2015