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o r u s e w i t h a l l r e p o r t i n g e n t i t i e s e x c e p t p e t r o l e u m r e f i n e r i e s ) P e t r o l e u m R e f i n e r y V e r i f i c a t i o n S t a t e m e n t F o r m ( f o r u s e w i t h p e t r o l e u m r e f i n e r i e s o n l y )



## I n f o r m a t i o n f o r R e p o r t i n g E n t i t i e s

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. A l i n k t o t h e p r

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e

.Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house 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 Regulatio n for the Mandatory Reporting of Greenhouse Gas Emissions following this Disclaimer was produced by California Air Resources Board (ARB) staff for the reader’s conven ience. 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 fo llowing 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 unoff icial version accurate, the officially published CCR takes precedence if there are any dis crepancies.

Official Legal Edition

The official legal edition of title 17, CCR, sectio ns 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=CC R1000&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 sec tion, 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 Green house Gas

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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 G as 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 Definition s .................... 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 ................................. ................................................. 9 3 95108 Severability ................................

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

Subarticle 2. Requirements for the Mandatory Report ing 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 ............................. .............................................. 158Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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California Air Resources Board ii February 2015 Subarticle 3. Additional Requirements for Reported Data ................................ 160 95129 Substitution for Missing Data Used to Calcula te Emissions

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

Subarticle 4. Requirements for Verification of Gree nhouse Gas Emissions Data

Reports; Requirements Applicable to Emissions Data Verifiers; Requirements for Accreditation of Emissions Data an d Offset Project Data Report Verifiers .............. ............................... 171 95130 Requirements for Verification of Emissions Da ta Reports ........... 171 95131 Requirements for Verification Services ..... .................................. 172 95132 Accreditation Requirements for Verification B odies,

Lead Verifiers, and Verifiers of Emissions Data Rep orts and Offset Project Data Reports ................... ............................... 189 95133 Conflict of Interest Requirements for Verific ation Bodies ............ 194

Subarticle 5. Reporting Requirements and Calculatio n 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 fo r Petroleum

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

Appendix B TEST PROCEDURE: Flash Emissions of Green house Gases

and Other Compounds from Crude Oil and Natural Gas Separator and Tank Systems ........................ .............................. B-1Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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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, 95 121, 95122, 95124, 95130, 95131, 95132, 95133, 95152, 95153, 95156, 95157, an d Appendix A, title 17 California Code of Regulations to read as follows:

Article 2: Mandatory Greenhouse Gas Emissions Repo rting

Subarticle 1. General Requirements for Greenhouse Gas Reporting

§ 95100. Purpose and Scope.

(a) The purpose of this article is to establish man datory 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 a nd offset project data reports submitted pursuant to the cap-and-trade regulation, and verification bodies. This article is designed to meet the requirements of sec tion 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 spe cifies general requirements for the reporting of GHG emissions that apply to all report ing entities listed in section 95101. Subarticle 2 specifies reporting requiremen ts and calculation methods for specific types of facilities and entities. Subarti cle 3 specifies additional requirements for reported data, including procedure s for the substitution for missing data. Subarticle 4 specifies verification requirem ents for GHG emissions data reports, requirements for those who provide verific ation services for GHG reporting entities, and accreditation requirements for verifi ers of emissions data reports and offset project data reports. Subarticle 5 specifie s reporting requirements and calculation methods for petroleum and natural gas p roduction, processing, and storage facilities. (c) U.S. EPA GHG Reporting Rule. This article inco rporates various provisions of title 40, Code of Federal Regulations (CFR), Part 98. Th ese provisions are a portion of the U.S. Environmental Protection Agency (U.S. EPA) Final Rule on Mandatory Reporting of Greenhouse Gases. Unless otherwise sp ecified, 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, 20 09, July 12, 2010, September 22, 2010, October 28, 2010, November 30, 2010, Dece mber 17, 2010, and April 25, 2011. (d) Except as otherwise specifically provided: (1) Wherever the term “Administrator” is used in th e federal rules referred to in this article, the term “Executive Officer of the Ca lifornia Air Resources Board” or “Executive Officer” shall be substituted.Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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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 faci lity or a supplier are not the same party, the operator is responsible for complia nce with this article. (4) For purposes of reporting GHG emissions in Cali fornia, reporting entities must follow the requirements of this article where any i ncorporated provisions of 40 CFR Part 98 or Part 75 appear in conflict with it. NOTE: Authority cited: Sections 38510, 38530, 3960 0, 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 w ith source categories listed below are subject to this article regardless of emi ssions level: 1. Electricity generation units that report CO 2 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 w ith source categories listed below, are subject to this article when stationary combustion and process emissions of CO 2 , CH 4 , and N 2 O equal or exceed 10,000 metric tons CO 2 e for a calendar year: 1. Stationary fuel combustion, which includes elect ricity 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 Green house Gas

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California Air Resources Board 3 February 2015

(C) Suppliers of fuels provided for consumption wit hin California that are specified below in paragraph (c); (D) Carbon dioxide suppliers as specified below in paragraph (c), including CO 2 producers regardless of quantity produced, and CO 2 importers and exporters when bulk imports or exports equal or exc eed 10,000 metric tons for 2011 or a later calendar year; (E) Electric power entities as specified below in p aragraph (d); and, (F) Operators of petroleum and natural gas systems as specified below in paragraph (e). (G) Any California reporting entity subject to subp arts 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 CO 2 e resulting from CO 2 , N 2 O, or CH 4 emissions. If a reporting entity utilizes the abo ve industrial processes and emits over 10,000 metric tons of CO 2 e resulting from CO 2 , N 2 O, or CH 4 emissions, they must notify the Executive Officer within 90 days of the effective date of this regulation or wi thin 90 days of commencing the industrial process. This notificati on requirement also applies to facility operators subject to section 95 103(a), for abbreviated reporting. (2) Any reporting entity in one or more of the cate gories 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 GH Gs 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 reporti ng applicability and responsibility on the basis of common ownership, the basis of repo rting applicability and responsibility can only be changed to common contro l at the beginning of a compliance period. If a facility operator determin es their reporting applicability and responsibility on the basis of common control, the basis of reporting applicability and responsibility can only be change d to common ownership at the beginning of a compliance period. These provis ions 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 r equirements for entities acting as verification bodies and individuals acting as th ird party verifiers of emissions data reports and offset project data repo rts. These requirements are specified in sections 95130 through 95133 of th is article. (b) Calculating GHG Emissions Relative to Thresholds. For facilities for which an emissions-based applicability threshold is specifie d in section 95101(a)(1), theLegal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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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 CO 2 e threshold specified in section 95812 of the cap-and -trade regulation, operators must include all covered emissions of CO 2 , CH 4 , and N 2 O. (2) For the purpose of computing emissions relative to the 10,000 metric ton CO 2 e threshold for reporting applicability specified in section 95101(a), operators must include emissions of CO 2 , CH 4 and N 2 O from stationary combustion sources and process emissions, but may exclude any vented and fugitive emissions from the estimate. However, if all the CO 2 , CH 4 , and N 2 O emissions captured within the reporting entity’s facility bou ndary, including vented and fugitive emissions, exceed the 25,000 metric ton CO 2 e threshold specified in sections 95103(a) and 95103(f), the reporting entit y is not eligible for the abbreviated reporting option provided in section 95 103(a) and must submit an emissions data report pursuant to the full requirem ents of this Article, including obtaining verification services pursuant to section 95103(f). (3) Facilities with only stationary combustion emis sions 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 m etric tons of CO 2 e and an aggregate maximum heat input capacity of 12 MMBtu/h r or greater. (4) Notwithstanding 40 CFR §98.2(b)(2), operators o f facilities and suppliers must include emissions of CO 2 from the combustion of biomass and other biofuels when determining applicability relative to threshol ds for emissions reporting and cessation of reporting. (5) Operators of geothermal generating units must r eport when total facility emissions of CO 2 and CH 4 equal or exceed 10,000 metric tons of CO 2 e. (6) Operators of a hydrogen fuel cell unit must in clude emissions from the hydrogen fuel cell unit in calculating emissions fo r 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 releas e of greater than or equal to 10,000 metric tons of CO 2 e in California, unless otherwise specified in this article: (1) Position holders at terminals and refiners deli vering petroleum fuels and/or biomass-derived fuels, as described in section 9512 1; (2) Enterers that import transportation fuels outsi de the bulk transfer/terminal system, as described in section 95121, and biofuel production facilities that produce and deliver transportation fuels outside th e bulk/terminal system, as described in section 95121; (3) All refiners that produce liquefied petroleum g as, without regard to quantities, as described in section 95121;Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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California Air Resources Board 5 February 2015 (4) Operators of interstate pipelines delivering na tural gas, as described in section 95122; (5) California consignees of imported liquefied pet roleum gas, compressed natural gas, or liquefied natural gas, as described in sect ion 95122; (6) Local distribution companies who are public uti lity gas corporations or publiclyowned natural gas utilities delivering natural gas, as described in section 95122; (7) Operators of intrastate pipelines delivering na tural gas as described in section 95122; (8) All natural gas liquid fractionators, without r egard 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 annu al bulk imports into or exports from California of 10,000 metric tons or mo re, 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-jurisdictiona l 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 o r exceed 10,000 metric tons of CO 2 e, or their stationary combustion, process, fugitiv e, and vented emissions equal or exceed 25,000 metric tons of CO 2 e. (1) Offshore petroleum and natural gas production f acilities; (2) Onshore petroleum and natural gas production fa cilities; (3) Onshore natural gas processing plants; (4) Onshore natural gas transmission compression fa cilities; (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 Green house Gas

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California Air Resources Board 6 February 2015 (7) Liquefied natural gas import and export facilit ies; (8) Natural gas distribution facilities. (f) Exclusions . This article does not apply to, and greenhouse g as emissions reporting is not required for: (1) Electricity generating facilities that are sole ly powered by nuclear, hydroelectric, wind, or solar energy, unless on-sit e stationary combustion emissions equal or exceed 10,000 metric tons of CO 2 e; (2) Generating units designated as backup or emerge ncy 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 r equired 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 emi ssions from livestock manure management systems described in 40 CFR Part 98, Sub part 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 entit y that the operator, supplier, or entity does not meet one or more of the applicabili ty criteria specified in this article. Such demonstration must be provided to the Executiv e Officer within 20 days of receipt of a written request. (h) Cessation of Reporting . A facility operator or supplier who is not subje ct to the capand-trade regulation, whose emissions fall below th e 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 req uirements until there is no longer a compliance obligation. If the compliance obligat ion 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 op erator 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 sectio n 95101(a)(1)(A) that are subject to the requirements of this article regardless of e missions 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 ap plied.Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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California Air Resources Board 7 February 2015 If reported emissions are less than 10,000 metric tons of CO 2 e 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 ce ssation of reporting and explains the reasons for the reduction in emissions . The notification must be submitted no later than March 31 of the year immedi ately following the third consecutive year in which emissions are less than 1 0,000 metric tons of CO 2 e per year. The owner, operator, or supplier must ma intain the corresponding records required under section 95103 for each of th e three consecutive years and retain such records for five years following th e year that reporting was discontinued. The owner, operator, or supplier mus t resume reporting if annual emissions in any future calendar year increa se to 10,000 metric tons of CO 2 e 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 par agraph (a)(1) of this section cease to operate or are permanently shut do wn, the owner, operator, or supplier must submit an emissions data report fo r 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 follo ws. The owner, operator, or supplier must submit a notification to ARB that ann ounces the cessation of reporting and certifies to the closure of all GHG-e mitting processes and operations no later than March 31 of the year follo wing such changes. Paragraph 95101(h)(2) does not apply to seasonal or other temporary cessation of operations. The owner, operator, or s upplier must resume reporting for any future calendar year during which any of the GHG-emitting processes or operations resume operation and are su bject to reporting pursuant to section 95101(a)(1). (3) Electric power entities must comply with the fo llowing requirements for cessation of reporting: (A) Electric power entities that import or export e lectricity in 2011 or 2012 must continue to submit and certify an emissions da ta report through the 2014 data year. If an electric power entity has ze ro imports or exports, it must indicate as such in its emissions data report. (B) Electric power entities that import or export e lectricity in any year of a subsequent compliance period must continue to submi t and certify an emissions data report through the end of the same c ompliance period. If an electric power entity has zero imports or export s, 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 mu st notify the Executive Officer in writing of the reason(s) for cessation o f reporting. The notification must be submitted no later than March 31 of the yearLegal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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California Air Resources Board 8 February 2015

following the last year that the electric power ent ity 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 wit h the requirements specified in section 95101(i) and notify ARB by the applicable r eporting deadline if the reporting entity has met the cessation criteria and intends t o no longer obtain verification services. A reporting entity that is subject to th e cap-and-trade regulation must follow the requirements in section 95812 and contin ue 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 verifica tion 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 par agraph 95101(a)(1) of this section cease to operate or are permanently shut do wn, 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 o perations 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 a re changed such that the entity ceases to import and export electricity, the electr ic power entity must continue to obtain the services of an accredited verification b ody 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 CO 2 e, including CO 2 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 25,0 00 metric tons of CO 2 e. 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 Green house Gas

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California Air Resources Board 9 February 2015 § 95102. Definitions.

(a) For the purposes of this article, the definitio ns 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 rela ted processes. (1) “Absorbent circulation pump” means a pump commo nly powered by natural gas pressure that circulates the absorbent liquid b etween 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 qu antity (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 (H 2 S) and/or carbon dioxide (CO 2 ) contaminants that are separated from sour natural g as by an acid gas removal. (4) “Acid gas removal unit (AGR)” means a process u nit 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 th e acid gas separated from the acid gas absorbing medium (e.g., an amine solut ion) and released with methane and other light hydrocarbons to the atmosph ere 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 submi tted emissions data report is free of material misstatement, or that th e emissions data submitted in the emissions data report contains correctable erro rs as defined pursuant to this section and thus is not in conformance with th e requirement to fix such errors pursuant to section 95131(b)(9), or both. (7) “Adverse product data verification statement” m eans a verification statement rendered by a verification body attesting that the verification body cannot say with reasonable assurance that the submitted emissi ons data report is free of material misstatement, or that the covered product data submitted in the emissions data report contains correctable errors a s defined pursuant to this section and thus is not in conformance with the req uirements to fix such errors pursuant to section 95131(b)(9), or both. (8) “Adverse verification statement” means a verifi cation statement rendered by a verification body attesting that the verification b ody cannot say with reasonable assurance that the submitted emissions d ata report is free of material misstatement, or that the emissions or cov ered product data submitted in the emissions data report contains cor rectable errors as defined pursuant to this section and thus is not in conform ance with the requirements to fix such errors pursuant to section 95131(b)(9), or both. This definitionLegal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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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 la nd used for horticulture, fruit growing, seed growing, dairy farming, livestock bre eding and keeping, or grazing land, meadow land, osier land (growing will ow ), market gardens and nursery grounds as a result of agricultural activit y. (10) “Air injected flare” means a flare in which ai r 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 b e based on the calendar year. (12) “API” means the American Petroleum Institute. (13) "API Gravity" means a scale used to reflect th e 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 grav ity of the fluid at 60°F, and where API refers to the American Petroleum Institut e. (14) “AQMD/APCD” or “air district” or “air quality management district” or “air pollution control district” means any district crea ted or continued in existence pursuant to the provisions of Part 3 (commencing wi th 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 artic le, the unique identification number assigned to each facility, supplier, and ele ctric power entity that reports GHG emissions to the ARB. (17) “ARB offset credit” is as defined in the cap-a nd-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 p roduction. (19) “Asphalt” means a dark brown-to-black cement-l ike material obtained by petroleum processing and containing bitumens as the predominant component. It includes crude asphalt as well as th e following finished products: cements, fluxes, the asphalt content of e mulsions (exclusive of water), and petroleum distillates blended with asph alt to make cutback asphalts. (20) “Asset-controlling supplier” means any entity that owns or operates interconnected electricity generating facilities or serv es as an exclusive marketer for these facilities even though it does not own th em, 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 consid ered specified sources.Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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California Air Resources Board 11 February 2015 (21) "Assigned emissions level” means an amount of emissions, in CO 2 e, assigned to the reporting entity by the Executive O fficer under the requirements of section 95103(g). (22) “Associated gas” or “produced gas” means a nat ural gas that is produced in association with the production of crude oil. (23) “ASTM” means the American Society of Testing a nd Materials. (24) “Authorized project designee” means an entity authorized by an Offset Project Operator to act on behalf of the Offset Project Ope rator. (25) “Aviation gasoline” means a complex mixture of volatile hydrocarbons, with or without additives, suitably blended to be used in a viation reciprocating engines. Specifications can be found in ASTM Speci fication D910–07a,

“ Standard Specification for Aviation Gasolines ” (2007). (26) “Balancing authority” means the responsible en tity that integrates resource plans ahead of time, maintains load-interchange-gen eration balance within a balancing authority area, and supports interconnect ion frequency in real time. (27) “Balancing authority area” means the collectio n of generation, transmission, and loads within the metered boundaries of a balanc ing authority. A balancing authority maintains load-resource balance within this area. (28) “Barrel” means a volume equal to 42 U.S. gallo ns. (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 Rich ard F. Meyer, Laurie G. Wallace, and Fred J. Wagner, Jr., Volume 75, Num ber 10 (October 1991), which is hereby incorporated by reference. (30) "Best available data and methods" means ARB me thods for emissions calculations set forth in this article where reason ably feasible, or facility fuel use and other facility process data used in conjunc tion 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 me asurements that will be either consistently low or high relative to the reference value. (32) “Bigeneration unit” means a unit that simultan eously generates electricity and useful thermal energy from the same fuel source but without waste heat recovery. An example of bigeneration includes a bo iler 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 oth er industrial, commercial, heating and cooling purposes that are not in suppor t of or a part of the electricity generation system. (33) “Biodiesel” means a diesel fuel substitute pro duced from nonpetroleum renewable resources that meet the registration requ irements for fuels and fuel additives established by the U.S. Environmental Pro tection Agency underLegal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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California Air Resources Board 12 February 2015

section 211 of the Clean Air Act. It includes biod iesel that is all of the following: (A) Registered as a motor vehicle fuel or fuel addi tive 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 Blendstoc k (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 product ion facility that produces one or more of the following biomass-derived transportatio n fuels: ethanol, biodiesel, renewable diesel, rendered animal fat, or vegetable oil. (35) “Biogas” means gas that is produced from the b reakdown of organic material in the absence of oxygen. Biogas is produced in pr ocesses including anaerobic digestion, anaerobic decomposition, and t hermochemical decomposition. These processes are applied to biod egradable biomass materials, such as manure, sewage, municipal solid waste, green waste, and waste from energy crops, to produce landfill gas, d igester gas, and other forms of biogas. (36) “Biogenic portions of CO 2 emissions” means carbon dioxide emissions generated as the result of biomass combustion from combustion units. (37) “Biomass” means non-fossilized and biodegradab le organic material originating from plants, animals and micro-organism s, including products, byproducts, residues and waste from agriculture, fo restry and related industries as well as the non-fossilized and biodeg radable organic fractions of industrial and municipal wastes, including gases an d liquids recovered from the decomposition of non-fossilized and biodegradab le 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 (refor mulated blendstock for oxygenate blending) and CBOB (conventional blendsto ck for oxygenate blending), but exclude oxygenates, butane, and pent anes plus.Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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California Air Resources Board 13 February 2015 (41) “Blowdown” means the act of emptying or depres surizing a vessel. This may also refer to the discarded material such as blowdo wn water from a boiler or cooling tower. (42) “Blowdown vent stack emissions” mean natural g as and/or CO 2 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 materi al that weighs 2,000 pounds at zero percent moisture content. (45) “Bottom ash” means ash that collects at the bo ttom 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 th ermal energy application or process, and at least some of the reject heat emerg ing from the application or process is then used for electricity production. (47) “British thermal unit” or “Btu” means the quan tity of heat required to raise the temperature of one pound of water by one degree Fah renheit at about 39.2 degrees Fahrenheit. (48) “BTEX” means gaseous compounds of benzene, tol uene, ethyl benzene, and xylenes. (49) “Bulk transfer/terminal system” means a fuel d istribution system consisting of refineries, pipelines, vessels, and terminals. Fue l storage and blending facilities that are not fed by pipeline or vessel a re considered outside the bulk transfer system. (50) “Busbar” means a power conduit of a facility w ith electricity generating units that serves as the starting point for the electrici ty transmission system. (51) “Business-as-usual scenario” means the set of conditions reasonably expected to occur within the offset project boundar y in the absence of the financial incentives provided by offset credits, ta king into account all current laws and regulations, as well as current economic a nd technological trends. (52) “Butane” or “n-Butane” is a paraffinic straigh t-chain hydrocarbon with molecular formula C 4 H 10

. (53) “Butylene” or “n-Butylene” means an olefinic s traight-chain hydrocarbon with molecular formula C 4 H 8

. (54) “Bypass dust” means discarded dust from the by pass system dedusting unit of suspension preheater, precalciner and grate preh eater kilns, consisting of fully calcined kiln feed material.Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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California Air Resources Board 14 February 2015 (55) “Calcination” means the thermal decomposition of carbonate minerals, such as calcium carbonate (the principal mineral in lime stone) 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 Jan uary 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 su ch that the emissions inflate the bag to its calibrated volume. (59) “California balancing authority” means a balan cing authority with control over a balancing authority area primarily located in the State of California. A California balancing authority is responsible for t he operation of the transmission grid within its metered boundaries whi ch 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 4 2800 et seq. (61) “California consignee” means the person or ent ity 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 f or Oxygenate Blending” or “CARBOB” has the same meaning as defined in title 1 3 of the California Code of Regulations, section 2260(a). (64) “Cap-and-trade regulation” or “cap-and-trade p rogram” means ARB’s regulation establishing the California Cap on Green house Gas Emissions and Market-Based Compliance Mechanisms set forth in tit le 17, California Code of Regulations, Chapter 1, Subchapter 10, article 5 (c ommencing with section 95800). (65) “Carbon dioxide” or “CO 2 ” means the most common of the six primary greenhouse gases, consisting on a molecular level o f a single carbon atom and two oxygen atoms. (66) “Carbon dioxide equivalent” or “CO 2 equivalent” or “CO 2 e” means the number of metric tons of CO 2 emissions with the same global warming potential a s 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 CO 2 equivalent of emissions. (67) “Carbon dioxide supplier” means: (a) facilitie s with production process units located in the State of California that capture a C O 2 stream for purposes of supplying CO 2 for commercial applications or that capture the CO 2 stream in order to utilize it for geologic sequestration wher e capture refers to the initial separation and removal of CO 2 from a manufacturing process or any other process, (b) facilities with CO 2 production wells located in the State ofLegal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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California that extract or produce a CO 2 stream for purposes of supplying CO 2 for commercial applications or that extract a CO 2 stream in order to utilize it for geologic sequestration, (c) exporters (out of t he State of California) of bulk CO 2 that export CO 2 for the purpose of geologic sequestration, (d) exp orters (out of the State of California) of bulk CO 2 that export for purposes other than geologic sequestration, and (e) importers (into the State of California) of bulk CO 2 . This source category is focused on upstream supp ly and is not intended to place duplicative compliance obligation s on CO 2 already covered upstream. The source category does not include tra nsportation or distribution of CO 2 , purification, compression or processing of CO 2 , or on-site use of CO 2 captured on-site. (68) “Carbonate” means compounds containing the rad ical CO 3 −2 . Upon calcination, the carbonate radical decomposes to ev olve carbon dioxide (CO 2 ). Common carbonates consumed in the mineral indus try include calcium carbonate (CaCO 3 ) or calcite; magnesium carbonate (MgCO 3 ) or magnesite; and calcium-magnesium carbonate (CaMg(CO 3 ) 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 stronti um carbonate. (70) “Catalyst” means a substance added to a chemic al 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 blend ed with a specified type and percentage of oxygenate, meets the definit ion 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 co nventional-winter. (73) “Cement” means a building material that is pro duced by heating mixtures of limestone and other minerals or additives at high t emperatures in a rotary kiln to form clinker, followed by cooling and grinding w ith blended additives. Finished cement is a powder used with water, sand a nd gravel to make concrete and mortar. (74) “Cement kiln dust” or “CKD” means the fine-gra ined, solid, highly alkaline waste removed from cement kiln exhaust gas by air p ollution control devices. CKD consists of partly calcined kiln feed material and includes all dust from cement kilns and bypass systems including bottom as h and bypass dust. (75) “Centrifugal compressor” means any equipment t hat increases the pressure of a process natural gas or CO 2 by centrifugal action, employing rotating movement of the driven shaft. (76) “Centrifugal compressor dry seals” mean a seri es of rings around the compressor shaft where it exits the compressor case that operateLegal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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California Air Resources Board 16 February 2015

mechanically under the opposing forces to prevent n atural gas or CO 2 from escaping to the atmosphere. (77) “Centrifugal compressor wet seal degassing ven t emissions” means emissions that occur when the high-pressure oil bar riers for centrifugal compressors are depressurized to release absorbed n atural gas or CO 2

. High-pressure oil is used as a barrier against esca ping gas in centrifugal compressor seals. (78) “Certification” or “certify” refers to the pro cedure in 40 CFR §98.4(e), as required for reports submitted to ARB under this ar ticle. (79) “Chain of title” means the sequence of histori cal 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 lo cal distribution company system and typically are used to measure local dist ribution company system sendout to customers. (81) “Coal” means all solid fuels classified as ant hracite, bituminous, subbituminous, or lignite by the American Society for Testing and Materials Designation ASTM D388–05 “Standard Classification o f Coals by Rank” (2005), which is hereby incorporated by reference. (82) “Coal coke” means a solid residue high in carb on content produced by the destructive distillation of coal at high temperatur es 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, commercia l, or heating and cooling purposes, through the sequential or simultaneous us e of the original fuel energy. Cogeneration must involve generation of el ectricity and useful thermal energy and some form of waste heat recovery . Some examples of cogeneration include: (a) a gas turbine or reciproc ating engine generating electricity by combusting fuel, which then uses a h eat recovery unit to capture useful heat from the exhaust stream of the turbine or engine; (b) Steam turbines generating electricity as a byproduct of s team 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 so me 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, wh ere 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 generati on system), is not considered a cogeneration unit.Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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California Air Resources Board 17 February 2015 (84) “Cogeneration system” means individual cogener ation components including the prime mover (heat engine), generator, heat reco very, and electrical interconnection, configured into an integrated syst em that provides sequential or simultaneous generation of multiple forms of use ful energy (usually mechanical and thermal), at least one form of which the facility consumes onsite or makes available to other users for an end-u se other than electricity generation. (85) “Cogeneration unit” means a unit that produces electric energy and useful thermal energy for industrial, commercial, or heati ng and cooling purposes, through the sequential or simultaneous use of the o riginal fuel energy and waste heat recovery. (86) “Coke (petroleum)” means a solid residue consi sting mainly of carbon which results from the cracking of petroleum hydrocarbons in processes such as coking and fluid coking. This includes catalyst co ke deposited on a catalyst during the refining process which must be burned of f in order to regenerate the catalyst. (87) “Combustion emissions” means greenhouse gas em issions occurring during the exothermic reaction of a fuel with oxygen. (88) “Combustion source” means a source of emission s 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 “operatio nal control” as defined herein. (91) “Compliance instrument” is as defined in the c ap-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 p rotocol 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-weld ed connection separated by a compression gasket, screwed thread (with or wi thout thread sealing compound), metal to metal compression, or fluid bar rier through which natural gas or liquid can escape to the atmosphere. (96) “Compressed natural gas” or “CNG” means natura l gas in high-pressure containers that is highly compressed (though not to the point of liquefaction), typically to pressures ranging from 2900 to 3600 ps i.Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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California Air Resources Board 18 February 2015 (97) “Compressor” means any machine for raising the pressure of a natural gas or CO 2 by drawing in low pressure natural gas and dischar ging significantly higher pressure natural gas or CO 2

. (98) “Condensate” means hydrocarbon and other liqui d, including both water and hydrocarbon liquids, separated from natural gas tha t condenses due to changes in the temperature, pressure, or both, and remains liquid at storage conditions. (99) “Conflict of interest” means a situation in wh ich, because of financial or other activities or relationships with other persons or o rganizations, a person or body is unable or potentially unable to render an i mpartial verification statement of a potential client’s greenhouse gas em issions data report, or the person or body’s objectivity in performing verifica tion services is or might be otherwise compromised. (100) “Consignee” means the same as “California con signee.” (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 w here the signal is compared with the process set-point to adjust gas pressure i n the valve actuator. (102) “Continuous emissions monitoring system” or “ CEMS” means the total equipment required to obtain a continuous measureme nt of a gas concentration or emission rate from combustion or i ndustrial 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 fin al 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 d o not meet the requirements of the reformulated gasoline regulatio ns 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 o r as specified by the state. Note: This category excludes conventional g asoline for oxygenate blending (CBOB) as well as other blendstock. (105) “Conventional wells” mean crude oil or gas we lls in producing fields that do not employ hydraulic fracturing to produce commerci ally 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 d o not meet the requirements of the reformulated gasoline regulatio ns 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 sp ecified by the state. Note: This category excludes conventional blendstoc k for oxygenate blending (CBOB) as well as other blendstock.Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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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 re sult from a nonconformance with this article. Differences that, i n the professional judgment of the verification team, are the result of differi ng but reasonable methods of truncation or rounding or averaging, where a specif ic procedure is not prescribed by this article, are not considered erro rs and therefore do not require correction. (108) “Covered emissions” mean all emissions includ ed 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 o f 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 temp eratures and pressures. (111) "Crude oil" means a mixture of hydrocarbons t hat exists in the liquid phase in natural underground reservoirs and remains liquid a t atmospheric pressure after passing through surface separating facilities . Depending upon the characteristics of the crude stream, it may also in clude any of the following: (A) Small amounts of hydrocarbons that exist in gas eous phase in natural underground reservoirs but are liquid at atmospheri c conditions (temperature and pressure) after being recovered fr om 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 w ells in lease or field separation facilities and later mixed into the crud e stream is also included. (B) Small amounts of non-hydrocarbons, such as sulf ur and various metals. (C) Drip gases, and liquid hydrocarbons produced fr om tar sands, oil sands, gilsonite, and oil shale. (D) Petroleum products that are received or produce d at a refinery and subsequently injected into a crude supply or reserv oir by the same refinery owner or operator. Liquids produced at natural gas processing plants a nd natural gas fractionating facilities are excluded, unless the p roduced 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 w ide 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 Green house Gas

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California Air Resources Board 20 February 2015

lubricants; asphalt; ethane, propane, and butane; a nd many other products used for their energy or chemical content. (112) “Customer” means a purchaser of electricity n ot for the purposes of retransmission or resale. (113) “Customer meter” means natural gas meter, ris er, 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 f or a source or sources that are calculated using alternative methods selected b y 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 CO 2 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 pu mps. (118) “Delayed coking” means a process by which hea vier crude oil fractions are thermally decomposed under conditions of elevated t emperature and pressure to produce a mixture of lighter oils and p etroleum coke. (119) “Delivered electricity” means electricity tha t was distributed from a PSE and received by a PSE or electricity that was generated , transmitted, and consumed. (120) “Demethanizer” means the natural gas processi ng unit that separates methane rich residue gas from the heavier hydrocarb ons (e.g., ethane, propane, butane, pentane-plus) in the feed natural gas stream. (121) “Desiccant” means a material used in solid-be d dehydrators to remove water from raw natural gas by adsorption or absorption. Desiccants include activated alumina, palletized calcium chloride, lit hium chloride and granular silica gel material. Wet natural gas is passed thr ough a bed of the granular or pelletized solid adsorbent or absorbent in these de hydrators. As the wet gas contacts the surface of the particles of desiccant material, water is adsorbed on the surface or absorbed and dissolves the surfac e of these desiccant particles. Passing through the entire desiccant be d, almost all of the water is adsorbed onto or absorbed into the desiccant materi al, leaving the dry gas to exit the contactor. (122) “Designated representative” means the person responsible for certifying, signing, and submitting the GHG emissions data repo rt. (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 Green house Gas

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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 interconnecti on with a California balancing authority; (B) The facility has a first point of interconnecti on with distribution facilities used to serve end users within a California balanci ng authority area; (C) The electricity is scheduled for delivery from the specified source into a California balancing authority via a continuous phy sical transmission path from interconnection of the facility in the ba lancing 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 e lectricity 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 an d from crackers and hydrotreating process units. The generic term disti llate 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 (Fu el Oils No. 1, No. 2, and No. 4; EIA product codes 508, 509, and 510). (126) “Distillate Fuel No. 1” has a maximum distill ation 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 cat egories of sulfur content: High Sulfur (greater than 500 ppm), Low Sulfur (les s 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 max imum 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 conten t: 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 1 5 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 o f 131°F. (129) “Distribution pipeline” means a pipeline that is designated as such by the Pipeline and Hazardous Material Safety Administrati on (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 distribut ed 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 Green house Gas

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California Air Resources Board 22 February 2015 (131) “Double-Valve Cylinder,” for purposes of Appe ndix 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 produce d from gas wells not associated with the production of crude oil. (133) “E&P Tank” means E&P Tank Version 2.0 for Win dows software, copyright 1996-1999 by the American Petroleum Institute and t he Gas Research Institute (published 2000). (134) “EIA” means the Energy Information Administra tion. 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 a n 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 C ooperative (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 furna ce that produces molten steel and heats the charge materials with electric arcs f rom carbon electrodes. Furnaces that continuously feed direct-reduced iron ore pellets as the primary source of iron are not affected facilities within t he scope of this definition. (137) “Electric Power Entity” or “EPE” means those entities specified in section 95101(d) of this article, including electricity imp orters and exporters; retail providers, including multi-jurisdictional retail pr oviders; the California Department of Water Resources (DWR); the Western Ar ea Power Administration (WAPA); and the Bonneville Power Adm inistration (BPA). (138)“Electricity exporter” means electric power en tities that deliver exported electricity. The entity that exports electricity i s 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 in side the state of California and the point of delivery located outside the state of California. Electricity exporters include Energy Imbalance Market (EIM) Ent ity Scheduling Coordinators serving the EIM market that can result in exports from California. (139) “Electricity generating facility” means a fac ility that generates electricity and includes one or more generating units at the same l ocation. (140) “Electricity generating unit” or “EGU” means any combination of physically connected generator(s), reactor(s), boiler(s), comb ustion turbine(s), or other prime mover(s) operated together to produce electri c 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 Green house Gas

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California Air Resources Board 23 February 2015 (141) “Electricity importers” deliver imported elec tricity. For electricity that is scheduled with a NERC e-Tag to a final point of del ivery 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. F or facilities physically located outside the state of California with the first poin t of interconnection to a California balancing authority’s transmission and d istribution system when the electricity is not scheduled on a NERC e-Tag, the i mporter is the facility operator or scheduling coordinator. Federal and st ate agencies are subject to the regulatory authority of ARB under this article and include Western Area Power Administration (WAPA), Bonneville Power Admin istration (BPA), and California Department of Water Resources (DWR). El ectricity Importers include EIM Participating Resource Scheduling Coord inators serving the EIM market whose transactions result in electricity imp orts into California. (142) “Electricity sold into the CAISO markets” mea ns electricity sold into California Independent System Operator (CAISO) markets, includ ing 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 Replace ment 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 Calif ornia, an intermediate point of delivery located inside the state of California, an d the final point of delivery located outside the state of California. (145) “Eligible renewable energy resource” is as de fined in section 95802(a) of the cap-and-trade regulation. (146) “Emission factor” means a unique value for de termining an amount of a greenhouse gas emitted for a given quantity of acti vity (e.g., metric tons of carbon dioxide emitted per barrel of fossil fuel bu rned.) (147) “Emissions” means the release of greenhouse g ases 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 emi ssions data report” or “report” means the report prepared by an operator or supplie r 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 requiredLegal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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California Air Resources Board 24 February 2015

data for the calendar year prior to the year in whi ch the report is due. For example, a 2013 emissions data report would cover e missions and product data for the 2013 calendar year and would be report ed in 2014. (149) “Emissions data verification statement” means the final statement rendered by a verification body attesting whether a reportin g entity’s covered emissions data in their emissions data report is free of mate rial misstatement, and whether the emissions data conforms to the requirem ents of this article. (150) “Emulsion” means a mixture of water, crude oi l, associated gas, and other components from the oil extraction process that is transferred from an existing platform that is permanently affixed to the ocean f loor and that is located outside the distance specified in the “offshore” de finition of this article, to an onshore petroleum and natural gas production facili ty. 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 energ y 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 Resou rce Scheduling Coordinator” or “EIM” Participating Resource Scheduling Coordina tor means the participating resource owner or operator, or a thir d-party designated by the resource owner or operator that is certified by the CAISO and enters into the pro forma EIM Participating Resource Scheduling Coo rdinator Agreement, under which it is responsible for meeting the requi rements specified in the CAISO Tariff on behalf of the resource owner or ope rator. (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 en gineering principles applied to measured and/or approximated physical pa rameters such as dimensions of containment, actual pressures, actual temperatures, and compositions. (156) “Enhanced oil recovery” or “EOR” means the us e of certain methods such as steam (thermal EOR), water flooding or gas injectio n 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 car bon dioxide into a crude oil reservoir to enhance the recovery of oil. (157) “Enterer” means an entity that imports into C alifornia motor vehicle fuel, diesel fuel, fuel ethanol, biodiesel, non-exempt biomass-d erived fuel or renewableLegal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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California Air Resources Board 25 February 2015

fuel and who is the importer of record under federa l 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 report ing under the regulation. (158) “Entity” means a person, firm, association, o rganization, partnership, business trust, corporation, limited liability company, comp any, or government agency. (159) “Equipment” means any stationary article, mac hine, or other contrivance, or combination thereof, which may cause the issuance o r control the issuance of air contaminants; equipment shall not mean portable equipment, tactical support equipment, or electricity generators design ated as backup generators in a permit issued by an air pollution control dist rict or air quality management district. (160) “Equipment leak” means those emissions which could not reasonably pass through a stack, chimney, vent, or other functional ly-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 mol ecular formula C 2 H 6

. (163) “Ethanol” is an anhydrous alcohol with molecu lar formula C 2 H 5 OH. (164) “Ethylene” is an olefinic hydrocarbon with mo lecular formula C 2 H 4

. (165) “Exchange agreement” means a commitment betwe en electricity market participants to swap energy for energy. Exchange t ransactions do not involve transfers of payment or receipts of money for the f ull market value of the energy being exchanged, but may include payment for net differences due to market price differences between the two parts of t he transaction or to settle minor imbalances. (166) “Exclusive marketer” means a marketer that ha s exclusive rights to market electricity for a generating facility or group of g enerating facilities. (167) “Executive Officer” means the Executive Offic er of the California Air Resources Board, or his or her delegate. (168) “Exported electricity” means electricity gene rated inside the state of California and delivered to serve load located outside the sta te of California. This includes electricity delivered from a first point o f receipt inside California, to the first point of delivery outside California, wit h a final point of delivery outside the state of California. Exported electric ity delivered across balancing authority areas is documented on NERC e-Tags with t he first point of receipt located inside the state of California and the fina l point of delivery located outside the state of California. Exported electric ity does not include electricity generated inside the state of California then trans mitted 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 cu stomers of a multi-jurisdictional retail provider, consistent with a cost allocation methodology approved by theLegal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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California Air Resources Board 26 February 2015

California Public Utilities Commission and the util ity regulatory commission of at least one additional state in which the multi-ju risdictional retail provider provides retail electric service. (169) “External combustion” means fired combustion in which the flame and products are separated from contact with the proces s fluid to which the energy is delivered. Process fluids may be air, ho t water, or hydrocarbons. External combustion equipment may include fired hea ters, industrial boilers, and commercial and domestic combustion units. (170) “Facility,” unless otherwise specified in rel ation to natural gas distribution facilities and onshore petroleum and natural gas pr oduction facilities as defined in section 95102(a), means any physical pro perty, plant, building, structure, source, or stationary equipment located on one or more contiguous or adjacent properties in actual physical contact o r separated solely by a public roadway or other public right-of-way and und er common ownership or common control, that emits or may emit any greenhou se gas. Operators of military installations may classify such installati ons as more than a single facility based on distinct and independent function al groupings within contiguous military properties. (171) “Facility,” with respect to natural gas distr ibution for the purposes of sections 95150 to 95158 of this article, means the collectio n of all distribution pipelines and metering-regulating stations that are operated by a local distribution company (LDC) within the State of California that i s 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 art icle, means all petroleum and natural gas equipment on a well-pad, associated with a well pad or to which emulsion is transferred and CO 2 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 o nshore petroleum and natural gas production facility if the onshore petr oleum 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 on shore petroleum and natural gas production equipment associated with al l wells that the person or entity owns or operates in the basin would be consi dered 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 t o a process.Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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California Air Resources Board 27 February 2015 (175) “Field,” in the context of oil and gas system s, means oil and gas fields identified in the United States as defined by the E nergy Information Administration Oil and Gas Field Code Master List 2 008, DOE/EIA 0370(08), January 2009, which is hereby incorporated by refer ence. (176) “Field accuracy assessment” means a test, che ck, or engineering analysis intended to confirm that a flow meter or other mass or volume measurement device is operating within an acceptable accuracy r ange. A field accuracy assessment should be conducted in a manner that doe s not interrupt operations or require removal of the meter or requi re primary element inspection. The selected method for field accuracy assessment will vary based on meter type and piping system design, and m ay be performed by the facility operator, a third party meter servicing fi rm, or the original equipment manufacturer. (177) “Final point of delivery” means the sink spec ified on the NERC e-Tag, where defined points have been established through the NE RC Registry. When NERC e-Tags are not used to document electricity de liveries, 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 de liverer” 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 wh ich imported electricity and electricity wheeled through California may be measu red, consistent with defined points that have been established through t he NERC Registry. (180) “First point of receipt” means the generation source specified on the NERC eTag, where defined points have been established thr ough the NERC Registry. When NERC e-Tags are not used to document electrici ty deliveries, as may be the case within a balancing authority, the first point of receipt is the location of the individual generating facility or u nit, or group of generating facilities or units. Imported electricity and whee led 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 c ombustion air provided by uncontrolled ambient air around the flame. (182) “Flare combustion” means unburned hydrocarbon s including CH 4 , CO 2 , and N 2 O emissions resulting from the incomplete combustio n of gas in flares. (183) “Flare combustion efficiency” means the fract ion of liquid and gases sent to the flare, on a volume or mole basis, that is combu sted at the flare burner tip. (184) “Flare stack emissions” means CO 2 and N 2 O from partial combustion of hydrocarbon gas sent to a flare plus CH 4 emissions resulting from the incomplete combustion of hydrocarbon gas in the fla re.Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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California Air Resources Board 28 February 2015 (185) “Flash Analysis,” for purposes of Appendix B, means laboratory methodologies for measuring the volume and composit ion of gases released from liquids, including the molecular weight of the total gaseous sample, the weight percent of individual compounds, and a Gas-O il 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 low est 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 w hen the liquid changes temperature and pressure, also known as phase chang e. (188) “Floating-Piston Cylinder,” for purposes of A ppendix B, means a cylinder used for gathering produced water. The cylinder contain s an internal piston controlled by gas pressure. The piston prevents sa mple liquid from flashing within the sampling cylinder and provides a means o f extracting the sample liquid. (189) “Flow meter” means a measurement device consi sting of one or more individual components that is designed to measure t he bulk fluid movement of liquid or gas through a piped system at a designate d 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 conti nuous 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 reservo ir and that flows back to the surface as a fluid after injection is completed. (192) “Fluid catalytic cracking unit” or “FCCU” mea ns 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 c oke and other deposits. The unit includes, but is not limited to, the riser , reactor, regenerator, air blowers, spent catalyst, and all equipment for cont rolling air pollutant emissions and recovering heat. (193) “Fluid coking” means a thermal cracking proce ss utilizing the fluidized-solids technique to remove carbon (coke) for continuous co nversion of heavy, lowgrade oils into lighter products. (194) “Fluorinated greenhouse gas” means sulfur hex afluoride (SF 6 ), nitrogen trifluoride (NF 3 ), and any fluorocarbon except for controlled subst ances as defined at 40 CFR Part 82, subpart A, (May 1995), w hich is hereby incorporated by reference, and substances with vapo r 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 Green house Gas

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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” me ans removal of ethane or higher carbon number hydrocarbons existing in the vapor ph ase in natural gas, by removing ethane or heavier hydrocarbons derived fro m natural gas into natural gas liquids by means of a forced extraction process. Forced extraction processes include refrigeration, absorpt ion (lean oil), cryogenic expander, and combinations of these processes. For ced extraction does not include in and of itself, natural gas dehydration, or the collection or gravity separation of water or hydrocarbon liquids from nat ural gas at ambient temperatures, or the condensation of water or hydro carbon liquids through passive reduction in pressure or temperature, or po rtable dewpoint suppression skids. (196) “Forest-derived wood and wood waste” means wo od harvested pursuant to the California Forest Practice Rule, Title 14, Cali fornia Code of Regulations, Chapters 4, 4.5, and 10 or pursuant to the National Environmental Policy Act. (197) “Fossil fuel” means natural gas, petroleum, c oal, or any form of solid, liquid, or gaseous fuel derived from such material. (198) “Fractionates” means the process of separatin g natural gas liquids into their constituent liquid products. (199) “Fractionator” means plants that produce frac tionated natural gas liquids (NGLs) extracted from produced natural gas and sepa rate the NGLs individual component products: ethane, propane, but anes 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 in stead fractionate bulk NGLs received from natural gas processors. Some fr actionators both process natural gas and fractionate bulk NGLs recei ved from other plants. (200) “Fuel” means solid, liquid or gaseous combust ible material. Volatile organic compounds burned in destruction devices are not fue ls 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 a bout fuel usage (including mass, volume, and flow rate) and fuel characteristics (in cluding heating value, carbon content, and molecular weight) to support em issions calculation. (202) “Fuel characteristic data” means, for the pur pose of this article, properties of a fuel used for calculating GHG emissions including c arbon content, high heat value, and molecular weight. (203) “Fuel combusting electricity generating or co generation unit” means an electricity generating unit, which may include a co generation or bigeneration unit, that produces electricity from fuel combustio n.Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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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 Blendi ng 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 sy stem which provides a continuous record of the flow rate of fuel oil or g aseous fuel. A fuel flowmeter system consists of one or more fuel flowmeter compo nents, all necessary auxiliary components (e.g., transmitters, transduce rs, 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 speci fied in this article. (208) “Fuel transaction” means the record of the ex change of fuel possession, ownership, or title from one entity to another. (209) “Fugitive emissions” means those emissions wh ich are unintentional and could not reasonably pass through a stack, chimney, vent, or other functionally-equivalent opening. (210) “Fugitive emissions detection” means the proc ess of identifying emissions from equipment, components, and other point sources

. (211) “Fugitive equipment leak” means the unintende d or incidental emissions of greenhouse gases from the production, transmission, processing, storage, use or transportation of fossil fuels, greenhouse g ases, or other equipment. (212) "Fugitive source" means a source of fugitive emissions. (213) “Full verification” means all verification se rvices 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; relativel y great expansion and contraction with changes in pressure and temperatur e; the ability to diffuse readily; and the spontaneous tendency to become dis tributed uniformly throughout any container. (215) “Gas conditions” means the actual temperature , volume, and pressure of a gas sample. (216) “Gas gathering/booster stations” means centra lized stations where produced natural gas from individual wells is co-mingled, co mpressed for transport to processing plants, transmission and distribution sy stems, and other gathering/booster stations which co-mingle gas from multiple production gathering/booster stations. Such stations may inclu de gas dehydration,Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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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 o f gas produced from a barrel of crude oil or condensate when cooling and depressuri zing 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 rati o of gas produced from a barrel of produced water when cooling and depressurizing p roduced 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 product ion of natural gas from one or more gas zones or reservoirs. Such wells contain n o completions for the production of crude oil. (220) “Generated electricity” means electricity gen erated by an electricity generating unit at the reporting facility. Generat ed electricity does not include any electricity that is generated outside the facil ity and delivered into the facility with final destination outside of the faci lity. (221) “Generated energy” means electricity or therm al energy generated by the electricity generating, cogeneration, or bigenerati on units included in the reporting facility. (222) “Generating unit” means any combination of ph ysically connected generator(s), reactor(s), boiler(s), combustion tur bine(s), or other prime mover(s) operated together to produce electric powe r. (223) “Generation providing entity” or “GPE” means a facility or generating unit operator, full or partial owner, party to a contrac t for a fixed percentage of net generation from the facility or generating unit, pa rty to a tolling agreement with the owner, or exclusive marketer recognized by ARB that is either the electricity importer or exporter with prevailing ri ghts to claim electricity from the specified source. (224) “Geothermal” means heat or other associated e nergy 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 ref erence gas, i.e., CO 2

. (226) “Graduated Cylinder,” for purposes of Appendi x B, means a measuring instrument for measuring fluid volume, such as a gl ass container (cup or cylinder or flask) which has sides marked with or d ivided into amounts. (227) “Greenhouse gas” or “GHG” means carbon dioxid e (CO 2 ), methane (CH 4 ), nitrous oxide (N 2 O), sulfur hexafluoride (SF 6 ), hydrofluorocarbons (HFCs), perfluorocarbons (PFCs), and other fluorinated gree nhouse gases as defined in this section.Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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California Air Resources Board 32 February 2015 (228) “Greenhouse gas emission reduction” or “GHG e mission reduction” or “greenhouse gas reduction” or “GHG reduction” means a calculated decrease in GHG emissions relative to a project baseline ove r 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 hydrospher e 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 sour ce. (231) “Greenhouse gas sink” or “GHG sink” means a p hysical unit or process that removes a GHG from the atmosphere. (232) “Grid” or “electric power grid” means a syste m of synchronized power providers and consumers connected by transmission a nd distribution lines and operated by one or more control centers. (233) “Grid-dedicated facility” means an electricit y generating facility in which all net power generated is destined for distribution on the grid through retail providers or electricity marketers, ultimately serv ing 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, expresse d in megawatt hours (MWh) per year. (235) “HD-5” or “special duty propane” means a cons umer grade of liquefied petroleum gas containing a minimum of 90% propane, a maximum of 5% propylene, and a maximum of 2.5% butane as specifie d in ASTM D1835-05. (236) “HD-10” means the fuel that meets the specifi cations for propane used in transportation fuel found in Title 13, California C ode of Regulations, section 2292.6. (237) “Heat input rate” means the product (expresse d in MMBtu/hr) of the gross calorific value of the fuel (expressed in MMBtu/mas s 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 ca tegory of crude oil characterized by relatively high viscosity, a highe r carbon-to-hydrogen ratio, and a relatively higher density having an API gravi ty of less than 20. (239) “High-bleed pneumatic devices” means automati c, continuous or intermittent bleed flow control devices powered by pressurized n atural gas and used for maintaining a process condition such as liquid leve l, pressure, delta-pressure and temperature. Part of the gas power stream that is regulated by the process condition flows to a valve actuator control ler where it ventsLegal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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California Air Resources Board 33 February 2015

continuously or intermittently (bleeds) to the atmo sphere 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 inclinat ion or declination tracking in parallel with and through the target formation. (242) “Hydrocarbons” means chemical compounds conta ining 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, o ccurring chiefly in combination with oxygen in water; exists also in acids, bases, alcohols, petroleum, and other hydrocarbons. (245) “Hydrogen plant” means a facility that produc es hydrogen with steam hydrocarbon reforming, partial oxidation of hydroca rbons, or other processes. (246) “Imported electricity” means electricity gene rated outside the state of California and delivered to serve load located insi de 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 in cludes electricity imported into California over a multi-jurisdictional retail provi der’s transmission and distribution system, or electricity imported into t he state of California from a facility or unit physically located outside the sta te 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 Californi a. Imported electricity does not include electricity wheeled through California, defined pursuant to this section. Imported electricity does not include elec tricity imported into the California Independent System Operator (CAISO) bala ncing authority area to serve retail customers that are located within the CAISO balancing authority area, but outside the state of California. Importe d Electricity does not include electricity imported into California by an Independ ent System Operator to obtain or provide emergency assistance under applic able emergency preparedness and operations reliability standards o f the North American Electric Reliability Corporation or Western Electri city Coordinating Council. Imported electricity shall include Energy Imbalance Market dispatches designated by the CAISO’s optimization model and re ported 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 Green house Gas

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California Air Resources Board 34 February 2015 (247) “Importer of record” means the owner or purch aser of the goods that are imported into California. (248) “Independently operated and sited cogeneratio n/bigeneration facility” means a cogeneration or bigeneration facility that is not located on the same facility footprint as its thermal host and has different ope rational control and different ownership than the thermal host. (249)“Independently operated cogeneration/bigenerat ion 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 ho st. (250) “Independent reviewer” has the same meaning a s “lead verifier independent reviewer.” (251) “Industrial/institutional/commercial facility with electricity generation capacity” means a facility whose primary business is not elec tricity generation and includes one or more electricity generating, cogene ration, or bigeneration units. (252) “Intermittent bleed pneumatic devices” means automated flow control devices powered by pressurized natural gas and used for aut omatically maintaining a process condition such as liquid level, pressure, d elta-pressure and temperature. These are snap-acting or throttling d evices that discharge all or a portion of the full volume of the actuator interm ittently when control action is necessary, but do not bleed continuously. Intermit tent 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 t his 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 hi gh-pressure gases produced by combustion, applies direct force to a c omponent of the engine, such as pistons, turbine blades, or a nozzle. This force moves the component over a distance, generating useful mechan ical energy. Internal combustion equipment may include gasoline and diese l industrial engines, natural gas-fired reciprocating engines, and gas tu rbines. (254) “Interstate pipeline” means any entity that o wns 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 Commiss ion. (255) “Intrastate pipeline” means any pipeline or p iping 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 th e 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, intrasta te pipeline operators that physically deliver gas to end users in California a re considered to be Local Distribution Companies. Facilities that receive ga s from an upstream LDCLegal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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California Air Resources Board 35 February 2015

and redeliver a portion of the gas to one or more a djacent facilities are not considered intrastate pipelines. (256) “Inventory position” means a contractual agre ement with the terminal operator for the use of the storage facilities and terminali ng services for the fuel. (257) "ISO" means the International Organization fo r Standardization. (258) “Isobutane” is a paraffinic branch chain hydr ocarbon with molecular formula C 4 H 10

. (259) “Isobutylene” is an olefinic branch chain hyd rocarbon with molecular formula C 4 H 8

. (260) “Isopentane” is the methylbutane or 2-methylb utane, branched chain, isomer of C 5 H 12 under the International Union of Pure and Applied Chemistry (IUPAC) nomenclature. (261) “Jurisdiction” means U.S. state or Canadian p rovince. For purposes of this article, “U.S. state” means U.S. State, the Distric t of Columbia, the Commonwealth of Puerto Rico, the Virgin Islands, Gu am, 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 wi th 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 to tal mass, respectively), as well as all other grades of kerosene called rang e or stove oil. “Kerosene” does not include kerosene-type jet fuel. (263) “Kerosene-type jet fuel” means a kerosene-bas ed product used in commercial and military turbojet and turboprop aircraft. The p roduct 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 encl osure 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 f rom, an electric circuit steadily for one hour. (A watt is a unit of electr ical power equal to one ampere under pressure of one volt, or 1/746 horsepo wer.) (266) “Last point of delivery in California” means the last defined point on the transmission system located inside California at wh ich exported electricity may be measured, consistent with defined points tha t have been established through the NERC Registry.Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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California Air Resources Board 36 February 2015 (267) “Lead verifier” means a person that has met a ll 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 verifi er providing an independent review of verification services rendered. (268) “Lead verifier independent reviewer” or “inde pendent reviewer” means a lead verifier within a verification body who has not par ticipated in conducting verification services for a reporting entity, offse t project developer, or authorized project designee for the current reporti ng year who provides an independent review of verification services rendere d to the reporting entity as required in section 95131. The independent reviewe r is not required to meet the requirements for a sector specific verifier. (269) “Legacy contract” shall have the meaning def ined 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 verif ication services provided in interim years between full verifications; less intensive ve rification of a reporting entity’s emissions data report only requires data c hecks and document reviews of a reporting entity’s emissions data repo rt based on the analysis and risk assessment in the most current sampling pl an 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 o il 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 2 0. (273) “Liquefied natural gas” or “LNG” means natura l 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 natu ral gas liquid (NGL) that is primarily a mixture of propane and butane, with small amounts of propene (propylene) and ethane. The most common specificat ion categories are propane grades HD-5, HD-10, and commercial grade pr opane, and propane/butane mix. LPG also includes both odorize d and non-odorized liquid petroleum gas, and is also referred to as pr opane. (275) “Linkage” is as defined in section 95802(a) o f the cap-and-trade regulation. (276) “Linked jurisdiction” means a jurisdiction wh ich 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 Green house Gas

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California Air Resources Board 37 February 2015 (277) “LNG boiloff gas” means natural gas in the ga seous phase that vents from LNG storage tanks due to ambient heat leakage throu gh the tank insulation and heat energy dissipated in the LNG by internal p umps. (278) “Local distribution company” or “LDC,” for pu rposes of this article, means a company that owns or operates distribution pipeline s, not interstate pipelines, that physically deliver natural gas to end users an d 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 pe riod 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 mai ntaining a process condition such as liquid level, pressure, delta-pre ssure and temperature. Part of the gas power stream that is regulated by the pr ocess condition flows to a valve actuator controller where it vents continuous ly 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 casi ng vents, vapor recovery systems, crude oil and petroleum product storage ta nks and other parts of the crude oil refining and natural gas production proce ss. (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 CO 2 e) or total reported covered product data contains errors greater than 5%, as applicable, in an emissions dat a report. Material misstatement is calculated separately for covered e missions and covered product data, as specified in section 95131(b)(12)( A). (285) “Maximum potential fuel flow rate” or “maximu m fuel consumption rate” means the maximum fuel use rate the source is capab le of combusting, measured in physical unit of the fuel (e.g. million standard cubic feet for gases, gallons for liquids, short tons for non-biom ass solids, and bone dry short tons for biomass-derived solids). When the s ource consists of multiple units, the maximum potential fuel use rate is the s um of the maximum potential fuel use rates of all the units aggregate d 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 Green house Gas

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California Air Resources Board 38 February 2015 (287) “Meter/regulator run” means a series of compo nents 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, c ustomer regulators, or farm taps. (289) “Methane” or “CH 4 ” 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 internati onal measurement for mass, equivalent to 2204.6 pounds or 1.1 short tons. (291) “Midgrade gasoline” means gasoline that has a n octane rating greater than or equal to 88 and less than or equal to 90. This def inition applies to the midgrade categories of conventional-summer, convent ional-winter, reformulated-summer, and reformulated-winter. For midgrade categories of RBOB-summer, RBOB-winter, CBOB-summer, and CBOB-win ter, 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 th e measurement device is not in compliance with the applicable quality-assurance re quirements. In the context of periodic fuel sampling, missing data per iod is the entire sampling period (e.g. week, month, or quarter) for which cor responding fuel characteristic data are not obtained. In the conte xt of periodic fuel consumption monitoring and recording, a missing dat a 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 m ixture of volatile hydrocarbons, with or without additives, suitably blended to be u sed in spark ignition engines. Motor gasoline includes conventional gaso line, reformulated gasoline, and all types of oxygenated gasoline. Ga soline also has seasonal variations in an effort to control ozone levels. T his is achieved by lowering the Reid Vapor Pressure (RVP) of gasoline during th e 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 ga s, 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 o r 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 Green house Gas

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California Air Resources Board 39 February 2015 (298) “Municipal solid waste” or “MSW” means solid phase household, commercial/retail, and/or institutional waste. Hous ehold waste includes material discarded by single and multiple residenti al dwellings, hotels, motels, and other similar permanent or temporary housing es tablishments or facilities. Commercial/retail waste includes material discarded by stores, offices, restaurants, warehouses, non-manufacturing activiti es at industrial facilities, and other similar establishments or facilities. Ins titutional waste includes material discarded by schools, nonmedical waste dis carded 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 was tes include yard waste, refuse-derived fuel, and motor vehicle maintenance materials. Insofar as there is separate collection, processing and dispos al of industrial source waste streams consisting of used oil, wood pallets, construction, renovation, and demolition wastes (which includes, but is not l imited to, railroad ties and telephone poles), paper, clean wood, plastics, indu strial process or manufacturing wastes, medical waste, motor vehicle parts or vehicle fluff, or used tires that do not contain hazardous waste iden tified or listed under 42 U.S.C. §6921, such wastes are not municipal solid w aste. However, such wastes qualify as municipal solid waste where they are collected with other municipal solid waste or are otherwise combined wit h other municipal solid waste for processing and/or disposal. (299) “NAICS” means North American Industry Classif ication System. (300) “Nameplate generating capacity” means the max imum rated output of a generator under specific conditions designated by t he manufacturer. Generator nameplate capacity is usually indicated i n units of kilovolt-amperes (kVA) and in Kilowatts (kW) on a nameplate physical ly 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 i s composed largely of paraffinic hydrocarbons. (302) “Natural gas” means a naturally occurring mix ture or process derivative of hydrocarbon and non-hydrocarbon gases found in geol ogic formations beneath the earth’s surface, of which its constitue nts include, methane, heavier hydrocarbons and carbon dioxide. Natural g as may be field quality (which varies widely) or pipeline quality. For the purposes of this article, the definition of natural gas includes similarly consti tuted 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 statio ns 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 Green house Gas

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California Air Resources Board 40 February 2015 (304) “Natural gas driven pneumatic pump” means a p ump that uses pressurized natural gas to move a piston or diaphragm, which pu mps liquids on the opposite side of the piston or diaphragm. (305) “Natural gas liquids” or “NGLs” means those h ydrocarbons in natural gas that are separated from the gas as liquids through the p rocess of absorption, condensation, adsorption, or other methods. Natura l gas liquids can be classified according to their vapor pressures as lo w (condensate), intermediate (natural gasoline), and high (liquefie d petroleum gas) vapor pressure. Generally, such liquids consist of ethan e, propane, butanes, pentanes, and higher molecular weight hydrocarbons. Bulk NGLs refers to mixtures of NGLs that are sold or delivered as undi fferentiated product from natural gas processing plants. (306) “Natural gas liquid fractionator” means an in stallation that fractionates natural gas liquids (NGLs) into their constituent liquid pr oducts (ethane, propane, normal butane, isobutene or pentanes plus) for supp ly to downstream facilities. (307) “Natural gas supplier” means, for the purpose s of this article, the local distribution company or interstate pipeline that ow ns or operates the distribution pipelines that physically deliver natu ral gas to end users. (308) “Natural gasoline” means a mixture of liquid hydrocarbons (mostly pentanes and heavier hydrocarbons) extracted from natural ga s. It includes isopentane. Natural gasoline is a natural gas liqu id of intermediate vapor pressure. (309) “NERC e-Tag” means North American Electric Re liability Corporation (NERC) energy tag representing transactions on the North A merican bulk electricity market scheduled to flow between or across balancin g authority areas. (310) “Net generation” or “net power generated” mea ns 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 “N 2 O” 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, o r the failure to meet any other requirements of the regulation. (313) “Non-exempt biomass-derived CO 2 ” means CO 2 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 Green house Gas

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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 generat ing unit” means a unit that generates electricity not from fuel sources, but fr om renewable energy sources, such as solar, wind, or hydropower. For t he purpose of this article, a non-fuel based renewable electricity generating uni t does not include other types of generation explicitly listed in section 95 112(a)-(f). (316) "Non-submitted/non-verified emissions data re port" means an emissions data report that is not submitted to ARB by the applicab le reporting deadline, or for which a verification statement has not been issued by the applicable verification deadline. (317) “North American Industry Classification Syste m (NAICS) code(s)” means the six-digit code(s) that represent the product(s)/act ivity(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, materia ls, items, or actions that are directly related to or have an impact upon GHG redu ctions, project emissions or GHG removal enhancements within the offset proje ct boundary. (319) “Offset project boundary” is defined by and i ncludes all GHG emission sources, GHG sinks or GHG reservoirs that are affec ted 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 Authorize d 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 t hat provides the information and documentation required by this arti cle or a compliance offset protocol. (321) “Offset project operator” means the entity(ie s) with legal authority to implement the offset project. (322) “Offset project specific verifier” means an i ndividual who has been accredited by ARB to verify offset projects of a specific offs et project type. (323) “Offset protocol” means a documented set of p rocedures and requirements to quantify ongoing GHG reductions or GHG removal enha ncements achieved by an offset project and calculate the project base line. Offset protocols specify relevant data collection and monitoring pro cedures, emission factors and conservatively account for uncertainty and acti vity-shifting and marketshifting leakage risks associated with an offset pr oject. (324) “Offshore,” for purposes of this article, mea ns all waters within three nautical miles of the California baseline, starting at the C alifornia-Oregon border andLegal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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California Air Resources Board 42 February 2015

ending at the California-Mexico border at the Pacif ic 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 pro duction of crude oil from at least one oil zone or reservoir. (326) “Oil and gas systems specialist” means a veri fier accredited to meet the requirements of section 95131(a)(2) for providing v erification 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 associat ed with a well pad or to which emulsion is transferred and CO 2 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 defi ned in 40 CFR §98.238. When a commonly owned cogeneration plant is within the basin, the cogeneration plant is only considered part of the o nshore petroleum and natural gas production facility if the onshore petr oleum 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 bas in, then all onshore petroleum and natural gas production equipment asso ciated 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 pe troleum 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 permi t, 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 r eporting means within the facility boundary. (330) “Operating pressure” means the containment pr essure that characterizes the normal state of gas or liquid inside a particular p rocess, pipeline, vessel or tank. (331) “Operational control” for a facility subject to this article means the authority to introduce and implement operating, environmental, h ealth and safety policies. In any circumstance where this authority is shared among multiple entities, the entity holding the permit to operate from the l ocal air pollution control district or air quality management district is cons idered to have operational control for purposes of this article.Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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California Air Resources Board 43 February 2015 (332) “Operator” means the entity, including an own er, having operational control of a facility. For onshore petroleum and natural gas production, the operator is the operating entity listed on the state well drill ing permit, or a state operating permit for wells where no drilling permit is issued by the state. (333) “Operating Pressure,” for purposes of Appendi x B means the working pressure that characterizes the conditions of crude oil, condensate, or produced water inside a particular process, pipelin e, vessel or tank. In general, low pressure liquid is under less than app roximately 200 psig of pressure. (334) “Outside of the facility boundary” means not within the physical boundary of the facility (regardless of ownership or operationa l control), or not in the same operational control of the reporting entity if with in the same physical boundary of the facility. For example, an entity outside of the facility boundary may include another facility not in the reporting entit y’s operational control, another facility under the same operational control but con sidered a separate facility according to the definition of “facility” in this s ection, or an on-site industrial operation (e.g. a cogeneration system) within the f acility fence line but that is operated by another operator and for which the on-s ite industrial operation has not been included in the reporting entity’s GHG report. (335) “Parasitic load” means the amount of electric ity 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 equi pment. (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 retra nsmission or resale. (337) “Pentane” is the n-pentane, straight chain, i somer of C 5 H 12 under the International Union of Pure and Applied Chemistry ( IUPAC) nomenclature. (338) “Pentanes plus” or “C5+” means a mixture of h ydrocarbons that is a liquid at ambient temperature and pressure, and consists most ly 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 a s measured using ASTM D-4007-08. The percent water cut is expressed as a percentage. (341) “Performance review” means an assessment cond ucted by ARB of an applicant seeking to become accredited as a verific ation body, verifier, lead verifier, offset project specific verifier, or sect or specific verifier pursuant to section 95132 of this article. Such an assessment may include a review of applicable past sampling plans, verification report s, verification statements,Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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California Air Resources Board 44 February 2015

conflict of interest submittals, and additional inf ormation 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, va cuum bottoms, tar and pitches in processes such as delayed coking or flui d coking. It consists mainly of carbon (90 to 95 percent), has low ash co ntent, and may be used as a feedstock in coke ovens. This product is also kn own as marketable coke. (344) “Petroleum refinery” or “refinery” means any facility engaged in producing gasoline, gasoline blending stocks, naphtha, kerose ne, distillate fuel oils, residual fuel oils, lubricants, or asphalt (bitumen ) through distillation of petroleum or through redistillation, cracking, or r eforming of unfinished petroleum derivatives. Facilities that distill onl y pipeline transmix (off-spec material created when different specification produ cts mix during pipeline transportation) are not petroleum refineries, regar dless 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 punctur e or rupture to a buried natural gas transmission and distribution pipeline during e xcavation 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, an d which is at least ninety percent methane by volume, and which is less than f ive 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 electri city available to a receiver, or available to serve load. This point can be an i nterconnection with another system or a substation where the transmission provi der’s transmission and distribution systems are connected to another syste m, or a distribution substation where electricity is imported into Calif ornia over a multijurisdictional retail provider’s distribution syste m. (349) “Point of receipt” or “POR” means the point o n an electricity transmission or distribution system where an electricity receiver r eceives electricity from a deliverer. This point can be an interconnection wi th another system or a substation where the transmission provider’s transm ission and distribution systems are connected to another system. (350) “Point source” means any separately identifia ble stationary point from which greenhouse gases are emitted.Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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California Air Resources Board 45 February 2015 (351) “Portable” means designed and capable of bein g carried or moved from one location to another. Indications of portability in clude 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 s ame 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 facili ty, remains at the facility for at least two years, and operates at that facili ty for at least three months each year. (D) The equipment is moved from one location to ano ther in an attempt to circumvent the portable residence time requirements of this definition. (352) “Portland cement” means hydraulic cement (cem ent that not only hardens by reacting with water but also forms a water-resistan t product) produced by pulverizing clinkers consisting essentially of hydr aulic calcium silicates, usually containing one or more of the forms of calc ium 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 termin al operator that owns motor vehicle fuel or diesel fuel in its terminal. “Posi tion 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 stateme nt” 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 misstatem ent and that the product data conforms to the requirements of this article. (356) “Positive verification statement” means a ver ification statement rendered by a verification body attesting that the verification b ody can say with reasonable assurance that the submitted emissions data report is free of material misstatement and that the emissions data report con forms to the requirements of this article. This definition appli es to the emissions data verification statement and the product data verific ation statement.Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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California Air Resources Board 46 February 2015 (357) “Power” means electricity, except where the c ontext 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 as sociated verbal or electronic records if included as part of the writt en power contract, arranging for the procurement of electricity. Power contract s 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 transacti on is executed. (359) “Premium grade gasoline” is gasoline having a n antiknock index, i.e., octane rating, greater than 90. This definition applies t o the premium grade categories of conventional-summer, conventional-win ter, 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 finishe d gasoline after oxygenate has been added to the RBOB or CBOB. (360) “Primary fuel” means the fuel that provides t he greatest percentage of the annual heat input to a stationary fuel combustion u nit. (361) “Primary Vessel,” for purposes of Appendix B means a separator or tank that receives crude oil, condensate, produced water, nat ural gas, or emulsion from one or more crude oil, condensate, or natural gas w ells or field gathering systems. (362) “Prime mover” means the type of equipment suc h as an engine or water wheel that drives an electric generator. “Prime mo vers” include, but are not limited to, reciprocating engines, combustion or ga s turbines, steam turbines, microturbines, and fuel cells. (363) “Process” means the intentional or unintentio nal reactions between substances or their transformation, including, but not limited to, the chemical or electrolytic reduction of metal ores, the therma l 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 ch emical or physical transformations other than fuel combustion. For ex ample, the calcination of carbonates in a kiln during cement production or th e oxidation of methane in an ammonia process results in the release of proces s CO 2 emissions to the atmosphere. Emissions from fuel combustion to prov ide process heat are not part of process emissions, whether the combustion i s internal or external to the process equipment.Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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California Air Resources Board 47 February 2015 (365) “Process emissions specialist” means a verifi er accredited to meet the requirements of section 95131(a)(2) for providing v erification services to operators of facilities engaged in cement productio n, glass production, lime manufacturing, pulp and paper manufacturing, iron a nd steel production, nitric acid production, and lead production. (366) “Process gas” means any gas generated by an i ndustrial process such as petroleum refining. (367) “Process Heater” means equipment for the heat ing of process streams (gases, liquids, or solids) other than water throug h 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 e ither a final or an intermediate product used in the onsite production of other products. The process unit also includes the purification of reco vered byproducts. (369) “Process vent” means an opening where a gas s tream is continuously or periodically discharged during normal operation. (370) “Produced water” means the resulting water th at is produced as a byproduct of crude oil or natural gas production. (371) “Producer” means a person who owns, leases, o perates, 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 P art 98. (373) “Product data verification statement” means t he final statement rendered by a verification body attesting whether a reporting ent ity’s covered product data in their emissions data report is free of material mis statement, and whether the product data conforms to the requirements of this a rticle. (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 emis sion reductions or GHG removal enhancements for the offset project’s G HG emission sources, GHG sinks, or GHG reservoirs within the offset proj ect boundary. (376) “Propane” is a paraffinic hydrocarbon with mo lecular formula C 3 H 8

. (377) “Propylene” is an olefinic hydrocarbon with m olecular formula C 3 H 6

. (378) “Public utility gas corporation” is a gas cor poration defined in California Public Utilities Code section 222 that is also a public ut ility 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 powersLegal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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California Air Resources Board 48 February 2015

authority that includes one or more of these agenci es 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 r eleased from the seal face between the pump internal chamber and the atmospher e. (382) “Pump seals” means any seal on a pump drive s haft 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 th e entity that is identified on a NERC e-Tag for each physical path segment. (384) “Pure” means consisting of at least 97 percen t by mass of a specified substance. For facilities burning biomass fuels, t his 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 §29 2.207 under the Public Utility Regulatory Policies Act of 1978 (PURPA). (386) “QA/QC” means quality assurance and quality c ontrol. (387) “Qualified exports” is as defined in section 95802(a) of the cap-and-trade regulation. (388) “Qualified positive emissions data verificati on statement” means a statement rendered by a verification body attesting that the verification body can say with reasonable assurance that the covered emission s data in the submitted emissions data report is free of material misstatem ent and is in conformance with section 95131(b)(9), but the emissions data ma y 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 misstatem ent 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 art icle which do not result in a material misstatement. (390) “Qualified positive verification statement” m eans a statement rendered by a verification body attesting that the verification b ody can say with reasonable assurance that the submitted emissions data report is free of material misstatement and is in conformance with section 951 31(b)(9), but the emissions data report may include one or more other nonconformance(s) with the requirements of this article which do not resul t in a material misstatement.Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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This definition applies to the qualified positive e missions data verification statement and the qualified positive product data v erification 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 t he 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 bef ore 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 integr al part of the cogeneration unit. (392) “Quality-assured data” or “quality-assured va lue” means the data are obtained from a monitoring system that is operating within t he performance specifications and the quality assurance/quality co ntrol procedures set forth in the applicable rules, for example 40 CFR Part 60 (J uly 1, 2009) or Part 75, (July 1, 2009), which is hereby incorporated by ref erence, 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, railroa d car, or other means of nonbulk transfer. (394) “RBOB-summer” or “reformulated blendstock foroxygenate blendingsummer” means a petroleum product which, when blend ed with a specified type and percentage of oxygenate, meets the definit ion 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 re formulated-winter. (396) “Reasonable assurance” means a high degree of confidence that submitted data and statements are valid. (397) “Reciprocating compressor” means a piece of e quipment that increases the pressure of a process natural gas or CO 2 by positive displacement, employing linear movement of a shaft driving a piston in a cy linder. (398) “Reciprocating compressor rod packing” means a series of flexible rings in machined metal cups that fit around the reciprocati ng compressor piston rod to create a seal limiting the amount of compressed natural gas or CO 2 that escapes to the atmosphere. (399) “Reciprocating internal combustion engine” or “RICE” or “piston engine” means an engine that uses heat from the internal co mbustion of fuel to create pressure that drives one or more reciprocating pist ons, creating mechanical energy.Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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California Air Resources Board 50 February 2015 (400) “Re-condenser” means heat exchangers that coo l compressed boil-off gas to a temperature that will condense natural gas to a l iquid. (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 refineri es 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, an d that is combusted separately or in any combination with any type of g as or used as a chemical feedstock. (403) “Reformulated Gasoline Blendstock for Oxygena te Blending” or “RBOB” has the same meaning as defined in title 13 of the Cali fornia Code of Regulations, section 2260(a). (404) “Reformulated-summer” means finished gasoline formulated for use in motor vehicles, the composition and properties of which m eet the requirements of the reformulated gasoline regulations promulgated b y the U.S. Environmental Protection Agency under 40 CFR §80.40 and 40 CFR §8 0.41, and summer RVP standards required under 40 CFR §80.27 or as sp ecified by the state. Reformulated gasoline excludes RBOB as well as othe r blendstock. (405) “Reformulated-winter” means finished gasoline formulated for use in motor vehicles, the composition and properties of which m eet the requirements of the reformulated gasoline regulations promulgated b y the U.S. Environmental Protection Agency under 40 CFR §80.40 and 40 CFR §8 0.41, but which do not meet summer RVP standards required under 40 CFR §80.27 or as specified by the state. Note: This category includ es Oxygenated Fuels Program Reformulated Gasoline (OPRG). Reformulated gasoline excludes RBOB as well as other blendstock. (406) “Regular grade gasoline” is gasoline having a n antiknock index, i.e., octane rating, greater than or equal to 85 and less than 8 8. 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 s imultaneously 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 Green house Gas

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(A) Registered as a motor vehicle fuel or fuel addi tive under 40 CFR Part 79; (B) Not a mono-alkyl ester; (C) Intended for use in engines that are designed t o 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 inex haustible. Renewable energy includes energy derived from solar, wind, ge othermal, hydroelectric, wood, biomass, tidal power, sea currents, and ocean thermal gradients. (411) “Renewable Energy Credit” or “REC” has the sa me meaning defined in the California Energy Commission’s “Renewable Portfolio Standard Eligibility,” 7 th edition, Commission Guidebook, April, 2013; CEC-300

‐ 2013

‐ 005

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‐ 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 wh ich 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 unde rground natural formation containing oil or gas. A reservoir is characterize d by a single natural pressure. (417) “Residual fuel oil” means a general classific ation 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 operati ons. (418) “Residue gas and residue gas compression” mea ns, respectively, production lease natural gas from which gas liquid products an d, in some cases, nonhydrocarbon components have been extracted such tha t it meets the specifications set by a pipeline transmission compa ny, and/or a distribution company; and the compressors operated by the proces sing facility, whether inside the processing facility boundary fence or ou tside the fence-line, that deliver the residue gas from the processing facilit y to a transmission pipeline. (419) “Retail end-use customer” or “retail end user ” means a residential, commercial, agricultural, or industrial electric cu stomer who buys electricity to be consumed as a final product and not for resale. (420) “Retail provider” means an entity that provid es electricity to retail end users in California and is an electric corporation as define d in Public Utilities Code section 218, electric service provider as defined i n Public Utilities Code section 218.3, local publicly owned electric utilit y as defined in Public Utilities Code section 224.3, a community choice aggregator a s defined in PublicLegal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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Utilities Code section 331.1, or the Western Area P ower 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 reta il end users. (422) “Sales oil” means produced crude oil or conde nsate 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 categorizat ion such as specified in section 95101. (425) “Sector specific verifier” means a verifier a ccredited pursuant to section 95132(b)(5)(A) as one or more of the following type s 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 se parate crude oil, condensate, natural gas, produced water, emulsion or solids. (427) “Short ton” means a common international meas urement for mass, equivalent to 2,000 pounds. (428) “Shutdown” means the cessation of operation o f an emission source for any purpose. (429) “Simplified block diagram” means a diagram co nsisting of boxes, shapes, lines, arrows, and labels that meets the requiremen ts 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 obj ects 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 energ y 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 disaggr egated 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 con tains significant concentrations of hydrogen sulfide (H 2 S) 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 Green house Gas

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California Air Resources Board 53 February 2015 (433) “Source” means greenhouse gas source; any phy sical unit, process, or other use or activity that releases a greenhouse gas into the atmosphere. (434) “Source category” means categories of emissio n 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, whe re defined points have been established through the NERC Registry. Import ed 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 “specifi ed source” means a facility or unit which is permitted to be claimed as the source of e lectricity delivered. The reporting entity must have either full or partial o wnership in the facility/unit or a written power contract to procure electricity gen erated by that facility/unit. Specified facilities/units include cogeneration sys tems. Specified source also means electricity procured from an asset-controllin g 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 bigenerati on facility. (439) “Standard conditions” or “standard temperatur e 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 o f 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 pressur e. (441) “Steam generator” means equipment that produc es 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 containe r, or reservoir used for the storage of organic liquids, excluding tanks that ar e 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, with in a single township or within a group of contiguous or adjacent townships identified in the Public Land Survey System of the United States, where oper ations and equipment are located. The operator may disaggregate sub-fac ilities based on contiguous township areas to smaller sub-facilities according to similar operational, geological, or geographical characteri stics. Sub-facility disaggregation may be retained from year to year, o r may be updated when some of the operations cease or equipment is reconf igured within theLegal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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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 bound aries. 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 operat ional, 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 electr icity. (446) “Sulfur hexafluoride” or “SF 6 ” 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 li ned or unlined surface impoundment or depression in the ground that, durin g normal operations, is used for separating crude oil, condensate, produced water, emulsion, or solids. (448) “Supplemental firing” means an energy input t o the cogeneration facility used only in the thermal process of a topping cycle plan t, or in the electricity generating or manufacturing process of a bottoming cycle cogeneration facility. (449) “Supplier” means a producer, importer, export er, 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 concen trations of hydrogen sulfide (H 2 S) and/or carbon dioxide (CO 2 ) that does not require (or has already had) acid gas treatment to meet pipeline corrosion-preve ntion 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 holdin g or storing crude oil, condensate, produced water, or emulsion. (453) “Tentatively Identified Compound List,” for p urposes of Appendix B means a list of target compounds that laboratories can use to evaluate uncommon gaseous compounds when performing a Gas Chromatogra ph/ Mass Spectrometry analysis. (454) “Terminal” means a motor vehicle fuel or dies el fuel storage and distribution facility that is supplied by pipeline or vessel, an d from which fuel may be removed at a rack. “Terminal” includes a fuel produ ction facility where motor vehicle or diesel fuel is produced and stored and f rom which fuel may be removed at a rack.Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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California Air Resources Board 55 February 2015 (455) “Terminal operator” means any entity that own s, 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 pro duced by a combustion source used directly as part of a manufacturing pro cess, industrial/commercial process, or heating/cooling a pplication, 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 Appe ndix B, means a pressurized vessel sealed from the atmosphere used to gravimetr ically 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 thes e 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 sect ion 95115 of this article. (461) “Tier 1” means a stationary combustion calcul ation method that applies default values for emission factors and high heat v alue to generate an emissions estimate, as specified in 40 CFR §98.33. (462) “Tier 2” means a stationary combustion calcul ation method that applies a default value for an emission factor and a fuel’s m easured high heat value (or a boiler efficiency for steam-generating solid fuel s) to generate an emissions estimate, as specified in 40 CFR §98.33. (463) “Tier 3” means a stationary combustion calcul ation method that utilizes a fuel’s measured carbon content to generate an emiss ions estimate, as specified in 40 CFR §98.33. (464) “Tier 4” means a stationary combustion calcul ation method that utilizes quality-assured data from a continuous emission mon itoring system to generate an emissions estimate, as specified in 40 CFR §98.33. This method may also capture process emissions from a common st ack. (465) “Tolling agreement” means an agreement whereb y 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, gener ally 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 electri city, 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 Green house Gas

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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 th at can potentially be made available for use in any industrial or commercial p rocesses, heating or cooling applications, or delivered to other end users. Thi s quantity excludes the heat content of returned condensate and makeup water, bu t includes the thermal energy used for supporting (but not directly used f or) power generation, thermal energy used in other on-site processes or a pplications that are not in support of or a part of the electricity generation system, thermal energy provided or sold to particular end-user, and therma l energy that is otherwise not utilized. Thermal energy directly used for pow er generation (e.g., steam used to drive a steam turbine generator for electri city generation) is not included in total thermal output. (468) “Transactions specialist” means a verifier ac credited to meet the requirements of section 95131(a)(2) for providing verification s ervices to electric power entities; suppliers of petroleum products and biofu els; suppliers of natural gas, natural gas liquids, and liquefied petroleum g as; and suppliers of carbon dioxide. (469) “Transmission-distribution (T-D) transfer sta tion” means a metering-regulating station where a local distribution company takes pa rt or all of the natural gas from a transmission pipeline and puts it into a dis tribution pipeline. (470) “Transmission pipeline” means a high pressure cross country pipeline transporting saleable quality natural gas from prod uction or natural gas from processing to natural gas distribution pressure let -down, metering, regulating stations, where the natural gas is typically odoriz ed before delivery to customers. (471) “Traceable” means that a standard used to cal ibrate a device has an unbroken chain of comparisons to a stated reference (such as a standard set by the National Institute of Standards and Technolo gy), with each comparison having a stated uncertainty (472) “Turbine” means any of various types of machi nes in which the kinetic energy of a moving fluid is converted into mechanical ener gy 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 Append ix B, means a pressurized vessel sealed from the atmosphere used to gravimetr ically separate crude oil and produced water that still contain entrained gas es. (475) “Type of thermal energy product” means the fo rm in which energy is transferred from a facility producing thermal energ y 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, a nd distilled water.Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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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 f or 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 hi ghest-level United States company(s) with an ownership interest in the report ing entity as of December 31 of the reporting year. (480) “Unspecified source of electricity” or “unspe cified source” means a source of electricity that is not a specified source at the t ime of entry into the transaction to procure the electricity. (481) “Upstream entity” means the last entity in th e chain of title prior to the fuel being received by the reporting entity. (482) “Urban waste” means waste pallets, crates, du nnage, manufacturing and construction wood waste, tree trimmings, mill resid ues and range land maintenance residues. (483) “U.S. EPA” means the United States Environmen tal Protection Agency. (484) “Used oil” means a petroleum-derived or synth etically-derived oil whose physical properties have changed as a result of han dling 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 l ocated at the source of potential gas emissions to the atmosphere or to a f lare, that is composed of piping, connections, and, if necessary, flow-induci ng devices, and that is used for routing the gas back into the process as a prod uct and/or fuel. (486) “Vegetable oil” means oils extracted from veg etation that are generally used as a feedstock in making biodiesel. (487) “Vented emissions” means intentional or desig ned releases of CH 4 or CO 2 containing natural gas or hydrocarbon gas (not incl uding stationary combustion flue gas), including process designed fl ow to the atmosphere through seals or vent pipes, equipment blowdown for maintenance, and direct venting of gas used to power equipment (such as pne umatic devices). (488) “Verification” means a systematic, independen t and documented process for evaluation of a reporting entity’s emissions data r eport against ARB’s reporting procedures and methods for calculation an d reporting GHG emissions and product data.Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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California Air Resources Board 58 February 2015 (489) “Verification body” means a firm accredited b y ARB that is able to render a verification statement and provide verification ser vices for reporting entities subject to reporting under this article. (490) “Verification services” means services provid ed during verification as specified in section 95131 beginning with the devel opment of the verification plan or first site visit, including but not limited to reviewing a reporting entity’s emissions data report, ensuring its accuracy accor ding 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 stat ement rendered by a verification body attesting whether a reporting entity’s emissio ns data report is free of material misstatement, and whether it conforms to t he requirements of this article. This definition applies to the emissions d ata verification statement and the product data verification statement. (492) “Verification team” means all of those workin g for a verification body, including all subcontractors, to provide verificati on services for a reporting entity. (493) “Verified emissions data report” means an emi ssions data report that has been reviewed by a third-party verifier and has a v erification 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 a ll 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 conf ormance with the requirements of this article. (496) “Vertical well” means a well bore that is pri marily vertical but has some unintentional deviation to enter one or more subsur face targets that are offset horizontally from the surface location, interce pting the targets either vertically or at an angle. (497) “Vessel,” for the purposes of Appendix B, mea ns any container, constructed primarily of non-earthen materials, used to separat e or store crude oil, condensate, natural gas, produced water, or emulsio n. (498) “Volatile organic compound” or “VOC” means an y volatile compound of carbon, excluding carbon monoxide, carbon dioxide, carbonic acid, metallic carbides or carbonates, and ammonium carbonate, whi ch participates in atmospheric photochemical reactions. (499) “VOC C3-C9, ” for purposes of Appendix B, means Volatile Organi c Compounds with three to nine carbon atoms.Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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California Air Resources Board 59 February 2015 (500) “VOC C10+, ” for purposes of Appendix B, means Volatile Organi c 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 t he 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 all ows for the flow of petroleum or natural gas from newly drilled wells to expel drill ing and reservoir fluids and test the reservoir flow characteristics, steps whic h may vent produced gas to the atmosphere via an open pit or tank. Well compl etion also involves connecting the well bore to the reservoir, which ma y include treating the formation or installing tubing, packer(s), or lifti ng 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 la rge quantities of produced gas to the atmosphere. (503) “Well testing venting and flaring” means vent ing and/or flaring of natural gas at the time the production rate of a well is determ ined for regulatory, commercial, or technical purposes. If well testing is conducted immediately after a well completion or workover, then it is con sidered part of well completion or workover. (504) “Well workover” means the process(es) of perf orming one or more of a variety of remedial operations on producing petroleum and n atural gas wells to try to increase production. This process also includes hi gh-rate flowback of injected gas, water, oil, and proppant used to re-f racture and prop-open new fractures in existing low permeability gas reservoi rs, steps that may vent large quantities of produced gas to the atmosphere. (505) “Wellhead” means the piping, casing, tubing a nd 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 val ve. Wellhead equipment includes all equipment, permanent and portable, loc ated on the improved land area (i.e. well pad) surrounding one or multiple we llheads. (506) “Wet natural gas” means natural gas in which water vapor exceeds the concentration specified for commercially saleable n atural gas delivered from transmission and distribution pipelines. This inpu t 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 Green house Gas

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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 per cent 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, magn esium, manganese, zinc, or other elemental additives or any combination of elements added.(4) (4) “Aluminum and aluminum alloy billet” means a so lid 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 pr oduct is sterilized before filling into pre-sterilized packs under sterile conditions. (6) “Aseptic tomato paste” means tomato paste packa ged using aseptic preparation. Aseptic paste is normalized to 31 per cent tomato soluble solids. Aseptic paste normalized to 31% TSS = (%TSS - raw T SS)/(31 - raw TSS) (7) “Aseptic whole and diced tomato” means the sum of whole and diced tomatoes packaged using aseptic preparation. Sum o f aseptic whole and diced tomatoes = whole tomatoes + (diced tomatoes x 1.05)) (8) “Baked potato chip” means a potato chip made fr om potato dough that is rolled to a specified thickness, cut into a chip sh ape and then toasted in an

oven. (9) "Barrel of oil equivalent," with respect to rep orting of oil and gas production, means barrels of crude oil produced, plus associate d gas and dry gas produced, converted to barrels at 5.8 MMBtu per bar rel. (10) “Bathroom tissue” means a thin, soft, lightwei ght, sanitized paper used in bathrooms for personal cleanliness. Bathroom tissu e is usually sold as a long strip of perforated paper wrapped around a paperboa rd core. (11) “Blending component” means a material blended into a primary refinery product, such as n-butane (EIA product codes 249 an d 643), isobutane (EIA product codes 247 and 644), butylene (EIA product c ode 633), isobutylene (EIA product code 634), pentanes plus (EIA product code 220), ethyl tertiary butyl ether (ETBE) (EIA product code 142), methyl t ertiary butyl ether (MTBE) (EIA product code 144), other oxygenates (EIA produ ct code 445), and fuel ethanol (EIA product code 141). (12) "Butter" means the product made by gathering t he fat of fresh or ripened milk or cream into a mass that also contains a small por tion 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 Green house Gas

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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 pa steurized prior to condensing. Buttermilk powder has a protein conten t of no less than 30%. It may not contain, or be derived from, nonfat dry mil k, dry whey, or products other than buttermilk, and contains no added preser vatives, 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 applic ations. (17) "Calcium ammonium nitrate solution" means calc ium nitrate that contains ammonium nitrate and water. Calcium ammonium nitra te solution is generally used as agricultural fertilizer. (18) “Casein” means a group of proteins found in mi lk which is coagulated by enzymes and acid to form cheese. (19) "Cheese" means a food product derived from mil k that is produced in a wide range of flavors, textures, and forms by coagulatio n of the milk protein casein. (20) “Clinker” means the mass of fused material pro duced in a cement kiln from which finished cement is manufactured by milling an d grinding. (21) "Cold rolled and annealed steel sheet" means s teel that is cold rolled and then annealed. Cold rolling means the changes in t he 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 s ufficient amount of time and then cooled. (22) "Cold rolling of steel" means the changes in t he structure and shape of steel through rolling, hammering or stretching the steel at a low temperature. (23) "Concentrated milk" means the liquid food obta ined 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 i s pasteurized, but is not processed by heat so as to prevent spoilage. It ma y be homogenized. (24) "Condensed milk" means the food obtained by pa rtial removal of water only from a mixture of milk and nutritive carbohydrate s weeteners. 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 qua ntity of nutritive carbohydrate sweetener used is sufficient to preven t 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 manufacturin g process where "container glass" is defined as glass products inte nded for packaging.Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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California Air Resources Board 62 February 2015 (26) “Corn” means the kernels of the dent corn plan t ( 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 sha pe, 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 sep arate the kernel’s various components into starch, germ, fiber and protein (gl uten) and then process the components into useful products such as starch, syr up, high fructose corn syrup, animal feed, and by-products such as gluten meal and germ. (30) “Cream” means that portion of milk, rich in mi lk 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 m odified dairy by-products derived from the fluid milk production process that are purposely processed for animal consumption obtained by the removal of w ater, protein and/or lactose, and/or minerals. (32) “Dehydrated chili pepper” means chili pepper t hat has been dehydrated to no more than 12 percent water by volume in order to ex tend 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 pl ant (Allium sativum) having a bulb that breaks up into separable cloves with a st rong distinctive odor and flavor. (34) “Dehydrated onion” mean onion that has been de hydrated 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 be en dehydrated to no more than 5 percent water by volume in order to extend t he 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 be en dehydrated to no more than 7 percent water by volume in order to extend t he shelf life and to concentrate the flavor. Spinach ( Spinacia oleracea ) is an edible flowering plant in the family of Amaranthaceae

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California Air Resources Board 63 February 2015 (37) “Delicate task wiper” means tissue-based wiper s used for the delicate cleaning of lenses, surfaces, and equipment in labs , research facilities, hospitals, and manufacturing settings. (38) "Deproteinized whey" means products manufactur ed through the cold ultrafiltration of sweet dairy whey, removing a por tion of the protein from sweet whey to result in a non-hygroscopic, free-flo wing and clean flavored powder containing greater than 80% carbohydrate (la ctose) 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 peel ed and diced, and shall have had the stems and calicies removed and shall h ave been cored, except where the internal core is insignificant to texture and appearance. (40) “Distilled spirit” means a spirit made from th e separation of alcohol and a fermented product. (41) “Dolime" is calcined dolomite. (42) “Dry color concentrate” means precipitated sol ids 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 fe rrous 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 s ubstances which can flow. (44) “EIA product code” means the code used to repo rt a specific product to the U.S. Energy Information Administration (EIA) throug h EIA reporting forms. (45) “Facial Tissue” means a class of soft, absorbe nt, disposable tissue papers that is suitable for use on the face. (46) "Fiberglass pulled" means the quantity of glas s removed from the melting furnace in the fiberglass manufacturing process whe re "fiberglass" is defined as insulation products for thermal, acoustic, and f ire applications manufactured using glass. (47) "Flat glass pulled" means the quantity of glas s removed from the melting furnace in the flat glass manufacturing process whe re "flat glass" is defined as glass initially manufactured in a sheet form. (48) “Freshwater diatomite filter aids” means inorg anic 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 pota to that is deep fried until crunchy. (50) "Galvanized steel sheet" means steel coated wi th a thin layer of zinc to provide corrosion resistance for such products as g arbage cans, storage tanks, or framing for buildings. Sheet steel norma lly must be cold-rolled prior to the galvanizing stage.Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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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 i t to prevent clumping. (52) “Grape juice concentrate” means the liquid fro m crushed grapes, from the botanical genus Vitas, processed to remove water. (53) “Grape seed extract” means the extract from gr ape seeds containing concentrations of proanthocyanidin. (54) “Gypsum” means a mineral with the chemical for mula CaSO 4 ·2H 2 O. (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 pr ocessing.
(58) “Intermediate dairy ingredients” means interme diate (non-final) dairy product imported from other dairy facilities that enter the rehydrating process, which uses water and heat to manufacture powdered product s. (59) “Lactose” means a white to creamy white crysta lline product, possessing a mildly sweet taste. It may be anhydrous, contain on e molecule of water of hydration, or be a mixture of both forms. (60) “Lager beer” means beer produced with bottom f ermenting 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 (CaCO 3 ). (63) “Liquid Color Concentrate” means a fluid extra ct from fruits and vegetables reduced by driving off water and the use of which i s for altering the color of materials and/or food. (64) “Liquid Hydrogen" means hydrogen in a liquid s tate. (65) “Milk” means the lacteal secretion, practicall y free from colostrum, obtained by the complete milking of one or more healthy cows. M ilk that is in final package form for beverage use shall have been pasteurized o r 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 m ay be homogenized. (66) “Nitric acid” means HNO 3 of 100% purity.Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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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 mi lk. 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 mi lk. 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 h igher than 70 oC for 2 minutes and includes undenatured whey protein nitro gen content equal to or greater than 6 mg/g powder. (69) “Nonfat dry milk and skimmed milk powder (medi um heat)” means milk powder obtained by removing water from pasteurized skim mi lk. 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” me ans the sum of tomato paste and tomato puree packaged using methods other than aseptic preparation. Non-aseptic paste and puree is normalized to 24 per cent tomato soluble solids. Non-aseptic paste and puree normalized to 2 4% 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 tomat oes + (diced tomatoes x 1.05). (73) “Non-thermal enhanced oil recovery” or “non-th ermal EOR” means the process of using methods other than thermal EOR, wh ich may include water flooding or CO 2 injection, to increase the recovery of crude oil f rom a reservoir. (74) “On-purpose hydrogen gas” means pure molecular hydrogen gas produced by a process or processes dedicated to producing hy drogen (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 s heet 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 a s an intermediate product for further processing. (77) “Pistachio” means the nuts of the pistachio tr ee Pistacia vera

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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 a t the same facility. (79) "Plasterboard" is a panel made of gypsum plast er pressed between two thick sheets of paper. (80) “Poultry deli product” means the products, inc luding corn dogs, sausages, and franks, that contain a significant portion of pre-p rocessed poultry, that are cooked and sold wholesale or retail, or transferred to other facilities. (81) “Pretzel” is a crisp biscuit made from dough f ormed into a knot or stick, flavored with salt, passed through a caustic hot wa ter bath and baked in an

oven. (82) “Primary refinery product” means aviation gaso line (EIA product codes 111 and 112), motor gasoline (finished) (EIA product co des 125, 127, 130, 149, and 166), motor gasoline blendstocks (EIA product c odes 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 9 31). 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 dis tilled spirits that is 50% alcohol at 60 degrees F. (84) “Protein meal and fat” means meal, feather mea l, and fat rendered product from poultry tissues including meat, viscera, bone, blood, and feathers. (85) “Raw TSS” means the average annual percent tom ato soluble solids of raw tomatoes to be processed in a tomato processing fac ility. (86) “Rare earth elements” means a set of seventeen chemical elements in the periodic table, specifically the fifteen lanthanide s (Lanthanum, Cerium, Praseodymium, Neodymium, Promethium, Samarium, Euro pium, Gadolinium, Terbium, Dysprosium, Holmium, Erbium, Thulium, and Lutetium) plus Scandium and Yttrium. (87) “Rare earth oxide equivalent” means the mass o f 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 lanthanide s (Lanthanum, Cerium, Praseodymium, Neodymium, Promethium, Samarium, Euro pium, 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 pro tective paper packaging for dry foods. It also includes folding paper cartons, set-up boxes, and similar boxboard products. Recycled boxboard is made from r ecycled fibers.Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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California Air Resources Board 67 February 2015 (90) "Recycled linerboard" means types of paperboar d made from recycled fibers that meet specific tests adopted by the packaging i ndustry to qualify for use as the outer facing layer for corrugated board, from w hich shipping containers are made. (91) "Recycled medium" means the center segment of corrugated shipping containers, being faced with linerboard on both sid es. Recycled medium is made from recycled fibers. (92) “Salt” means sodium chloride, determined as ch loride and calculated as percent sodium chloride, by the method prescribed i n “Official Methods of Analysis of the Association of Official Analytical Chemists,” 13th Ed., 1980, sections 32.025 to 32.030, under the heading “Metho d III (Potentiometric Method).” (93) “Seamless rolled ring” means a metal product m anufactured by punching a hole in a thick, round piece of metal, and then rol ling and squeezing (or in some cases, pounding) it into a thin ring. Ring dia meters can be anywhere from a few inches to 30 feet. (94) "Skim milk" means the product that results fro m 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, Pot assium 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 f rom carbon electrodes. Furnaces that continuously feed direct-reduced iron ore pellets as the primary source of iron are not affected facilities within t he scope of this definition of EAF. (97) “Stucco” means hemihydrate plaster (CaSO 4 ● 1⁄2H 2 O) produced by heating (“calcining”) raw gypsum, thereby removing three-qu arters of its chemically combined water. (98) “Thermal enhanced oil recovery” or “thermal EO R” means the process of using injected steam to increase the recovery of crude oi l 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 ch aracteristically gauzy in texture and, in some cases, fairly transparent. The y may be glazed, unglazed, or creped, and are used for a variety of purposes. Examples of different types of tissue papers include sanitary g rades such as toilet, facial, napkin, towels, wipes, and special sanitary papers.Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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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 der ived by using the following metric: Tissue produced adjusted by water absorbency capacity = Air dried ton of tissue produced x grams of water a bsorbed by a gram of tissue product. (102) “Tomato juice” is the liquid obtained from ma ture tomatoes conforming to the characteristics of the fruit Lycopersicum esculentum P. Mill, of red or reddish varieties. Tomato juice may contain salt, lemon jui ce, sodium bicarbonate, water, spices and/or flavoring. This food shall co ntain not less than 5.0 percent by weight tomato soluble solids. (103) “Tomato paste” is the food prepared from matu re tomatoes conforming to the characteristics of the fruit Lycopersicum esculentum P. Mill, of red or reddish varieties. Tomato paste is prepared by concentratin g tomato ingredients until the food contains not less than 24.0 percent tomato soluble solids. (104) “Tomato puree” is the semisolid food prepare d 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 sucro se value as determined by the method prescribed in the “Official Methods of A nalysis of the Association of Official Analytical Chemists,” 13th Ed., 1980, s ections 32.014 to 32.016 and 52.012. For instances where no salt has been ad ded, the sucrose value obtained from the referenced tables shall be consid ered the percent of tomato soluble solids. If salt has been added eithe r intentionally or through the application of the acidified break, determine t he percent of such added sodium chloride as specified in the definition of s alt. Subtract the percentage sodium chloride from the percentage of total solubl e solids found (sucrose value from the refractive index tables) and multipl y the difference by 1.016. The resultant value is considered the percent of “t omato 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 vitamin s 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 s pecified by ISO 12625-8:2010 except for the humidity and temperatur e 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 Green house Gas

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California Air Resources Board 69 February 2015 (109) "Whey protein concentrate" means the substanc e obtained by the removal of sufficient nonprotein constituents from pasteurized whey so that the finished dry product contains greater than 25% protein. Whe y protein concentrate is produced by physical separation techniques such as precipitation, filtration, or dialysis. The acidity of whey protein concentra te may be adjusted by the addition of safe and suitable pH adjusting ingredie nts. (110) “Whole chicken and chicken parts” means the w hole 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 ma ture 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 b een 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 whi ch separates air into its components including oxygen utilizing a cryogenic o r other method. (2) “Alkylation/poly/dimersol” means a range of pro cesses transforming C3/C4/C5 molecules into C7/C8/C9 molecules over an acidic catalyst. This can be accomplished by alkylation with sulfuric aci d or hydrofluoric acid, polymerization with a C3 or C3/C4 olefin feed, or d imersol. (3) “Ammonia recovery unit” means a refinery unit i n which ammonia-rich sour water stripper overhead is treated to separate ammo nia 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 s econd stage of a two stage sour water stripping unit. The ammonia recovery un it 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 t he presence of hydrogen. (5) “AROMAX®” means a special application of cataly tic reforming for the specific purpose of producing light aromatics. (6) “Aromatics production” means extraction of ligh t aromatics from reformate and/or hydrotreated pyrolysis gasoline by a solvent

. (7) “Asphalt production” means the processing requi red to produce asphalts and bitumen, including bitumen oxidation (mostly for ro ad paving). This includes polymer-modified asphalt. (8) “Atmospheric Crude Distillation” means primary atmospheric distillation of crude oil and other feedstocks. The atmospheric cr ude distillation unit includes any ancillary equipment such as a crude de salter, naphtha splitting,Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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California Air Resources Board 70 February 2015

gas plant and wet treatment of light streams for me rcaptan removal and may have more than one distillation column. (9) “Benzene saturation” means a selective hydrogen ation of benzene in gasoline streams over a fixed catalyst bed at moderate press ure. (10) “C4 isomer production” means conversion of n-b utane into isobutane over a fixed catalyst bed in the presence of hydrogen at l ow to moderate pressure. (11) “C5/C6 isomer production - including ISOSIV” m eans conversion of normal paraffins into isoparaffins over a fixed catalyst b ed 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 refineri es and related processes. The CWB value for an individual refinery is calcula ted using actual refinery throughput to specified process units and emission factors for these process units. The emission factor is denoted as the CWB f actor and is representative of the greenhouse gas emission inten sity at an average level of energy efficiency, for the same standard fuel ty pe for each process unit for production, and for average process emissions of th e 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 d escribing the mass of carbon residue which an oil deposits when evaporate d, as defined by ASTM D189 - 06(2010)e1 “Standard Test Method for Conrads on Carbon Residue of Petroleum Products” (2010), which is hereby incorpo rated by reference. (14) “Conventional naphtha hydrotreating” means des ulfurization of virgin and cracked naphthas over a fixed catalyst bed at moder ate pressure in the presence of hydrogen. For cracked naphthas this al so involves saturation of olefins. (15) “Cryogenic LPG recovery” means a refinery unit in which liquefied petroleum gas (LPG) is extracted from refinery gas streams th rough cooling and removing the condensate heavy fractions. The proce sses and equipment for this unit may include refrigeration, drier, compres sor, absorber, stripper and fractionation. (16) “Cumene production” means the alkylation of be nzene with propylene. (17) “Cyclohexane production” means hydrogenation o f benzene to cyclohexane over a catalyst at high pressure. (18) “Delayed Coker” means a refinery unit which co nducts 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 reg ular intervals. Coke is cut out of full coke drums as a product. For the p urposes 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 Green house Gas

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California Air Resources Board 71 February 2015 (20) “Desulfurization of C4–C6 Feeds” means desulfu rization 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” me ans selective saturation of diolefins over a fixed catalyst bed, at moderate pr essure in the presence of hydrogen to improve stability of thermally cracked and coker gasolines. (23) “Distillate hydrotreating” means desulfurizati on of distillate blends of components such as diesel and heating oil over a fi xed 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 octan e loss” means selective desulfurization of FCC gasoline cuts with minimum o lefins 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 condu cts a proprietary process incorporating a fluid coker and where coke is gasif ied to produce a low BTU gas which is used to supply the refinery heaters an d surplus coke is drawn off as a product. (28) “Flue gas desulfurizing” means a process in wh ich sulfur dioxide is removed from flue gases with contaminants. This often invo lves an alkaline sorbent which captures sulfur dioxide and transforms it int o a solid product. Flue gas desulfurizing systems can be of the regenerative ty pe 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 c oke is burned off. The hot regenerated catalyst returning to the reactor m ay supply the heat for the endothermic cracking reaction and for most of the d ownstream fractionation of cracked products. (30) “Fluid Coker” means a continuous process where the fluidized powder-like coke is transferred between the cracking reactor an d the coke burning vesselLegal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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California Air Resources Board 72 February 2015

and burned for process heat production. Surplus cok e 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 sil icate type catalyst. The catalyst is not fluidized. (33) “Hydrodealkylation” means dealkylation of tolu ene and xylenes into benzene over a fixed catalyst bed in the presence of hydrog en at low to moderate pressure. (34) “Kerosene hydrotreater” means a refinery proce ss unit which treats and upgrades kerosene and gasoil streams using aromatic saturation of distillates, distillate hydrotreating, middle distillate dewaxin g, the S-ZorbTM process for kerosene and gasoil or selective hydrotreating of C 3-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 remo val 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 ex traction of aromatic compounds from intermediate streams for the manufac ture of base lube oils. This includes solvent regeneration. Different proc esses 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 o f CO 2 and hydrogen to produce methanol. Methanol synthesis is only appli cable when a refinery produces hydrogen via partial oxidation. (41) “Middle distillate dewaxing” means the crackin g of long paraffinic chains in gasoils to improve cold flow properties over a fixe d 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 crac king when the feed has a Conradson carbon level of 2.25% to 3.5% by weight. (43) “Naphtha/Distillate Hydrocracker” means a refi nery process unit which conducts cracking of a hydrocarbon stream typically consisting of gasoils andLegal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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distillates over a fixed catalyst bed, at high pres sure and in the presence of hydrogen. The process combines cracking and hydroge nation reactions. (44) “Naphtha hydrotreater” means a refinery proces s unit that treats and upgrades naphtha/gasoline and lighter streams using any combination of one or more of the following processes: benzene saturat ion, desulfurization of C4–C6 feeds, conventional naphtha hydrotreating, di olefin to olefin saturation of gasoline, FCC gasoline hydrotreating with minimu m octane loss, olefinic alkylation of thio sulfur, desulfurization of pyrol ysis gasoline/naphtha. For naphtha/distillates, selective hydrotreating or the S-ZorbTM process may be used. (45) “Non-Crude Input” means the total volume of ba rrels of raw materials processed in process units at the refinery, excludi ng returns from a lube refiner or a chemical plant within a refining/petro chemical complex and excluding non-processed blendstock. (45) “Olefinic alkylation of thio sulfur” means a g asoline desulfurization process in which thiophenes and mercaptans are catalytically r eacted with olefins to produce higher-boiling sulphur compounds removable by distillation. This process does not utilize hydrogen. (46) “Other FCC” means early catalytic cracking pro cesses on fixed catalyst beds, including Houdry catalytic cracking and Thermofor c atalytic cracking. (47) “Oxygenates” means ethers that are produced by reacting an alcohol with olefins. (48) “Paraxylene production” means the physical sep aration of paraxylene from mixed xylenes. (49) “Process CWB” means the total complexity-weigh ted barrels of a refinery excluding those contributed by the process units ca lled total refinery input and non-crude input. (50) “Propane/Propylene splitter (propylene product ion)” 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 p roduces chemical or polymer grade propylene. (51) “POX syngas for fuel” means the production of synthesis gas by gasification (partial oxidation) of heavy residues. This includ es 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 be d 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 naph thenic rings and paraffin isomerisation over a noble metal catalyst at low pr essure and high temperature. The process also produces hydrogen.Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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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 press ure and in the presence of hydrogen. It results in a limited degree of convers ion of the residue feed into lighter products. (56) “Residual Hydrocracker” means a refinery unit which conducts hydrocracking of residual feedstocks. Different processes involv e continuous or semicontinuous catalyst replenishment. The residual hyd rocracker unit must process residuum with a Conradson carbon level of a t least 3.5% by weight. (57) “S-ZorbTM process for kerosene and gasoil” mean s desulfurization of gasoil using an absorption process. This process does not utilize hydrogen. (58) “S-ZorbTM process for naphtha/distillates” mean s 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 hydrot reatment 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 co mpares actual energy consumption for a refinery with the “standard” ener gy consumption for a refinery of similar size and configuration. The “s tandard” energy consumption is calculated based on an analysis of worldwide ref ining 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 pr ocess uses the refinery energy utilization, throughput and output to determ ine the Solomon EII of the refinery. (63) “Solvent deasphalter” means a refinery unit wh ich uses a solvent such as propane, butane or a heavier solvent to remove asph altines from a residual oil stream and produce asphalt and a deasphalted gasoil

. (64) “Special Fractionation” means fractionation pr ocesses excluding solvents, propylene and aromatics fractionation, which are ac complished by a deethanizer, depropanizer, deisobutanizer, debutani zer, deisopentanizer, depentanizer, deisohexanizer, dehexanizer, deisohep tanizer, deheptanizer, naphtha splitter, alkylate splitter or reformate sp litter. (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 Green house Gas

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California Air Resources Board 75 February 2015 (66) “Sulfur Recovery” means a process where hydrog en 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 equi pment for this process may include the combustor, waste heat boiler, converter , absorber, SO3 recycle, gas cleaning including electrostatic precipitator a nd amine regenerator. (68) “Thermal Cracking” means thermal cracking of d istillate feedstocks. A thermal cracking unit may include a vacuum flasher. Units that combine visbreaking and thermal cracking of distillate generate a contr ibution 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 fe edstock or to pass the feedstock through the catalytic reactor bed. The c atalyst is not fluidized. (70) “Toluene disproportionation/transalkylation me ans a fixed-bed catalytic process for the conversion of toluene to benzene an d 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 pou r point depressants and cetane improvers; antiknock compounds; and other ra w 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 at mospheric residues under vacuum. Some units may have more than one main dis tillation column. (73) “Visbreaker” means a refinery unit which condu cts 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 gene rate a contribution for both processes based on the residue and the distillate t hroughput respectively. (74) “VGO Hydrotreater” means a refinery unit which conducts desulfurization of a hydrocarbon stream typically made up of vacuum gaso ils 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 lighte r 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 Green house Gas

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California Air Resources Board 76 February 2015 § 95103. Greenhouse Gas Reporting Requirements.

The facilities, suppliers, and entities specified i n section 95101 must monitor emissions and submit emissions data reports to the Air Resour ces Board following the requirements specified in 40 CFR §98.3 and §98.4, e xcept as otherwise provided in this part. (a) Abbreviated Reporting for Facilities with Emissions Below 25,000 Metric Tons of CO 2 e. A facility operator may submit an abbreviated emi ssions data report under this article if all of the following conditions hav e 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 ar ticle; and the facility total stationary combustion, process, fugitives and venti ng emissions are below 25,000 metric tons of CO 2 e in 2011 and each subsequent year. This provision does not apply to suppliers or electric power entities. Abb reviated 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 numb er, physical street address including the city, state and zip code, air basin, air district, county, geographic location, natural gas supplier name, natural gas su pplier customer identification number, natural gas supplier service account identification number or other primary account identifier, and ann ual billed MMBtu (10 therms = 1 MMBtu). (2) Facility GHG stationary combustion emissions fo r all stationary fuel combustion units and calculated according to any me thod in 40 CFR §98.33(a), expressed in metric tons of total CO 2 , CO 2 from biomass-derived fuels, CH 4 , and N 2 O. If the facility includes multiple stationary fu el combustion units that belong to more than one unit type catego ry listed in section 95115(h), the operator may report the multiple unit s in aggregate but must indicate the percentage of the aggregated fuel cons umption attributed to each unit type category. In addition, if the facility i ncludes an electricity generating unit, the facility operator must report the electri city generating unit separate from other stationary fuel combustion sources by fo llowing the unit aggregation provisions in sections 95112(b) and 951 03(a)(6). The operator has the option of using engineering estimation or a ny 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 requirement s in the following parts, expressed in metric tons of total CO 2 , CO 2 from biomass-derived fuels, CH 4 , and N 2 O, 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 Green house Gas

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(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 determ ining emissions. (5) Any facility operating data or process informat ion used for the GHG emission calculations, including fuel use by fuel type, repo rted in million standard cubic feet for gaseous fuels, gallons for liquid fuels, s hort 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 calcu late emissions. Missing fuel use or fuel characteristics data must be subst ituted according to the requirements of 40 CFR §98.35. (6) For facilities with on-site electricity generat ion or cogeneration, the applicable information specified in sections 95112(a)-(b) of t his article. Geothermal facilities must also report the information specifi ed in section 95112(e). Operators of hydrogen fuel cells must report the in formation specified in section 95112(f). (7) A signed and dated certification statement prov ided 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 un der this provision must be certified as complete and accurate no later than Ju ne 1 of each calendar year. (9) Subsequent revisions according to the requireme nts of 40 CFR §98.3(h) must be submitted if an error is discovered after the su bmission of the emissions data report. If the error correction would cause t he emissions total to exceed 25,000 metric tons of CO 2 e, a report that meets the full requirements of thi s article must be submitted within ninety days of dis covery. (10) For abbreviated reports submitted under this p rovision, records must be kept according to the requirements of 40 CFR §98.3(g), e xcept that a written GHG Monitoring Plan is not required. (11) An abbreviated emissions data report is not su bject 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 mus t 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 da ta report that indicates emissions equaled or exceeded 25,000 metric tons of CO 2 e, including CO 2 from biomassderived fuels and geothermal sources, or each repor ting entity that has or has had a compliance obligation under the cap-and-trade regul ation in any year of the current compliance period. The requirements of this paragr aph also apply to electric powerLegal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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California Air Resources Board 78 February 2015 entities that are electricity importers or exporter s that have not met the requirements for cessation in section 95101(i)(4). The reportin g entity subject to verification must obtain third-party verification services for that r eport from a verification body that meets the requirements specified in Subarticle 4 of this article. Such services must be completed and separate verification statements f or emissions data and for product data, as applicable, must be submitted by t he verification body to the Executive Officer by September 1 each year. Each r eporting 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 excu se 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-tra de regulation fails to submit an emissions data report or fails to obtain a positive emissions data verification statement or qualified positive emissions data veri fication statement by the applicable deadline, the Executive Officer shall de velop an assigned emissions level for the reporting entity as set forth in section 95 131(c)(5)(A)-(C). (h) Reporting in 2015. All provisions of the regulation are in full effe ct 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 a nd calcined coke pursuant to sections 95113(l)(1) and 95113(l)(2), respective ly. (i) Calculation and Reporting of De Minimis Emissions. A facility operator or supplier may designate as de minimis a portion of GHG emissi ons representing no more than 3 percent of a facility’s total CO 2 equivalent emissions (including emissions from biomass-derived fuels and feedstocks), not to exceed 20,000 metric tons of CO 2 e. The operator or supplier may estimate de minimi s emissions using alternative methods of the operator’s choosing, sub ject to the concurrence of the verification body that the methods used are reasona ble, not biased toward significant underestimation or overestimation of em issions, and unlikely to exceed the de minimis limits. The operator or supplier mu st separately identify and include in the emissions data report the emissions from des ignated de minimis sources. The operator must determine CO 2 equivalence according to the global warming potentials provided in Table A-1 of 40 CFR Part 98. (j) Calculating, Reporting, and Verifying Emissions fr om Biomass-Derived Fuels. The operator or supplier must separately identify and r eport all biomass-derived fuels as described in section 95852.2(a) of the cap-and-trad e 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, calc ulate, and report all direct emissions of CO 2 resulting from the combustion of biomass-derived f uels as specified in sections 95112 and 95115 for facilitie s, and sections 95121 and 95122 for suppliers. A biomass-derived fuel not listed i n section 95852.2(a) of the capand-trade regulation must be identified as non-exem pt biomass-derived fuel. For aLegal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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California Air Resources Board 79 February 2015 fuel listed under section 95852.2 of the cap-and-tr ade regulation, reporting entities must also meet the verification requirements in sec tion 95131(i) of this article and the requirements of section 95852.1.1 of the cap-an d-trade regulation, or the fuel must be identified as non-exempt biomass-derived fu el. Carbon dioxide combustion emissions from non-exempt biomass-derive d fuel will be identified as non-exempt biomass-derived CO 2 . The responsibility for obtaining verification of a biomass-derived fuel falls on the entity that is cl aiming there is not a compliance obligation for the fuel, as indicated in section 95 852.2 of the cap-and-trade regulation. (1) When reporting solid waste, the reporting entit y must separately report the mass, in short tons, of urban waste, agricultural w aste, and municipal solid waste. (2) When reporting the use of forest derived wood a nd wood waste as identified in section 95852.2(a)(4) of the cap-and-trade regulati on and harvested pursuant to any of the California Forest Practice Rules Titl e 14, California Code of Regulations, Chapters 4, 4.5 and 10 of the Federal National Environmental Policy Act, the reporting entity must report: the b one-dry mass received; information about the supplier, including the name, physical address, mailing address, contact person with phone number and e-mai l address; and the corresponding identification number under which the wood was removed. (3) When reporting biomethane, the operator or supp lier 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 vendo r. 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 report s, and contracts must be made available for verifier or ARB review to demons trate the receipt of eligible biomethane. (4) Reporting of fuel consumption from non-exempt b iomass-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 req uirements for data used for calculating non-covered emissions and non-covered p roduct data, except as otherwise specified in this paragraph. In addition , the following accuracy requirements apply to data used for calculating cov ered emissions and covered product data. The operator or supplier with covere d product data or covered emissions equal to or exceeding 25,000 metric tons of CO 2 e or a complianceLegal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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California Air Resources Board 80 February 2015 obligation under the cap-and-trade regulation in an y year of the current compliance period must meet the requirements of paragraphs (k) (1)-(10) below for calibration and measurement device accuracy. Inventory measure ment, stock measurement, or tank drop measurement methods are subject to par agraph (11) below. The requirements of paragraphs (k)(1)-(11) apply to fue l consumption monitoring devices, feedstock consumption monitoring devices, process stream flow monitoring devices, steam flow devices, product dat a measuring devices, mass and fluid flow meters, weigh scales, conveyer scales, g as chromatographs, mass spectrometers, calorimeters, and devices for determ ining density, specific gravity, and molecular weight. The provisions of paragraph (k)(1)-(11) do not apply to: stationary fuel combustion units that use the metho ds in 40 CFR §98.33(a)(4) to calculate CO 2 mass emissions; emissions reported as de minimis under section 95103(i); and devices that are solely used to measu re parameters used to calculate emissions that are not covered emissions or that ar e 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 Par t 75 Appendix G §2.3 to calculate CO 2 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 d evices that were calibrated prior to January 1, 2012 using procedure s specified in previous versions of the Mandatory Reporting Regulation or m ethods specified in 40 CFR Part 98 must be subsequently recalibrated accor ding to the frequency specified in paragraph (4). A flow meter device co nsists of a number of individual components which might include a flow co nstriction 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), howe ver 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 t hat provide data used to calculate GHG emissions or product data must be cal ibrated according to either the manufacturer’s recommended procedures or a method specified in an applicable subpart of 40 CFR 98. The calibratio n method(s) used must be documented in the monitoring plan required under se ction 95105(c), and are subject to verification under this article and revi ew by ARB to ensure that measurements used to calculate GHG emissions or pro duct data have met the accuracy requirements of this section.Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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California Air Resources Board 81 February 2015 (3) For facilities and suppliers that become subjec t 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 measurem ent devices subject to the requirements of this section must be performed no l ess frequently than at one of the following time intervals, whichever is short est: (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 calibr ations not to be less than 30 months or greater than 48 months. (D) Immediately upon replacement of a previously ca librated meter. (E) Immediately upon replacement or repair of a dev ice 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 obtai n Executive Officer approval to relieve the operator from having to com ply with provisions (A) and (C) of this subparagraph. (5) All standards used for calibration must be trac eable 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 require ments specified below, and, if applicable, the field accuracy assessment requireme nts specified below, all flow meter and other measurement devices covered by this part, regardless of type, must be selected, installed, operated, and ma intained 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 s pecified in 40 CFR §98.3(i)(2)-(3), except that a minimum of three cal ibration points must be used spanning the normal operating conditions. Whe n using the three calibration points, one point must be at or near th e 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 docum entation 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 parti cular device, theLegal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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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 I SO 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 pres sure differential device recommends against disassembly and inspectio n of the device, disassembly and inspection requirements in this paragraph do not apply. Documentation of OEM guidance must b e 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 reques t. b. Where inspection requirements apply, the primary element must also be photographed on both sides prior to any tre atment or cleanup of the element to clearly show the conditio n of the element as it existed in the pipe. 2. Devices used to measure total pressure and tempe rature 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 measurement s are not available or are taken at a remote location, the uncertainty caused by this must be factored into the evaluation of the overall meas urement accuracy required under section 95103(k)(6). (B) Operators and suppliers may conduct an annual f ield accuracy assessment of mass and volume measurement devices t o test for field accuracy in years between successive calibrations t o ensure the device is maintaining measurement accuracy within ±5 perce nt. When performing a field accuracy assessment, the as-foun d condition must be recorded to ensure the device is measuring with acc uracy 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 indi cate the assessment procedure and the as-found condition, be preserved pursuant to section 95105, and be made available to verifiers and ARB u pon request. Device accuracy may be assessed using one of the following options: 1. Engineering analysis; 2. OEM calibration guidance or other OEM recommende d methods; 3. Standard industry practices; or

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(C) Pursuant to paragraph (k)(10) of this section, in the event of a failed calibration or recalibration, operators or supplier s who choose not to perform the annual field accuracy assessment specif ied in paragraph (6)(B) of this section for one or more mass or volu me measurement devices must demonstrate data accuracy going back m ultiple years to the most recent successful calibration. Multiple year s of data may be deemed invalid if accuracy cannot be demonstrated b y other means, including strap-on meters or engineering methods. For operators and suppliers who conduct the annual field accuracy ass essment, and a device is found to be out of calibration, accuracy must be demonstrated back to the most recent successful calibration or t he most recent successful field accuracy assessment, whichever is most recent. (7) The requirements of section 95103(k) do not app ly under the following circumstances: (A) Financial transaction meters are exempted from the calibration requirements of section 95103(k) if the supplier an d purchaser do not have any common owners and are not owned by subsidi aries or affiliates of the same company. Financial transaction meters where the supplier and the purchaser do have common owners or are owne d by subsidiaries or affiliates of the same company are exempt from t he calibration requirements of section 95103(k) if one of the foll owing is true: 1. The financial transaction meter is also used by other companies that do not share common ownership with the fuel supplie r; or

2. The financial transaction meter is sealed with a valid seal from the county sealer of weights and measures or from a cou nty certified designee; or 3. The financial transaction meter is operated by a third party. (B) Upstream ethanol and additive meters used to en sure 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 emis sions are exempt from the calibration requirements in sections 95103(k)(1 )-(6) if the supplier can demonstrate that the meters are operated and mainta ined in conformance with a standard that meets the measurem ent accuracy requirements of the California Public Utilities Com mission General Order 58A (1992). (8) For units and processes that operate continuous ly with infrequent outages, it may not be possible to meet deadlines for the initi al or subsequent calibrations of a flow meter or other fuel measurement or sampli ng device, or inspection of orifice plates without disrupting normal process op eration. In such cases, the owner or operator may submit a written request to t he Executive Officer to postpone calibration or inspection until the next s cheduled maintenanceLegal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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outage. Such postponements are subject to the proc edures of section 95103(k)(9) and must be documented in the monitorin g plan that is required under section 95105(c). (9) In cases of continuously operating units and pr ocesses where calibration or inspection is not possible without operational disr uption, the operator must demonstrate by other means to the satisfaction of t he Executive Officer that measurements used to calculate GHG emissions and pr oduct 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 subm itted to the Executive Officer not less than 30 days before the required c alibration, recalibration or inspection date. The Executive Officer may requ est additional documentation to validate the operator’s claim that the device meets the accuracy requirements of this section. The operato r shall provide any additional documentation to ARB within ten (10) wor king days of a request by ARB. (B) The request must include: 1. The date of the required calibration, recalibrat ion, or inspection; 2. The date of the last calibration or inspection; 3. The date of the most recent field accuracy asses sment, if applicable; 4. The results of the most recent field accuracy as sessment, if applicable, clearly indicating a pass/fail status; 5. The proposed date for the next field accuracy as sessment, if applicable; 6. The proposed date for calibration, recalibration , or inspection which must be during the time period of the next schedule d shutdown. If the next shutdown will not occur within three years , this must be noted and a new request must be received every thre e years until the shutdown occurs and the calibration, recalibration or inspection is completed. 7. A description of the meter or other device, incl uding at a minimum:
a. make, b. model, c. install date, d. location, e. annual emissions calculated or annual product da ta reported using data from the device, f. sources for which the device is used to calculat e 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 Green house Gas

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i. proposed method to assure the accuracy requireme nts 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, reca libration, or field accuracy assessment fail to meet the required accuracy specification, a nd the emissions or product data estimated using the data provided by the devic e 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 sat isfaction of the verifier or ARB that measurements used to calculate GHG emissio ns and product data still meet the ± 5% accuracy requirements going bac k to the last instance of successful field accuracy assessment or calibration of the device. Where the results of an initial calibration, recalibration, o r field accuracy assessment fail to meet the accuracy specifications, the verifier s hall note at a minimum a nonconformance as part of the emissions data verifi cation statement. (11) When using an inventory measurement, stock mea surement, or tank drop measurement method to calculate volumes and masses the method must be accurate to ±5 percent for the time periods require d by this article, including annually for covered product data. Techniques used to quantify amounts stored at the beginning and end of these time perio ds are not subject to the calibration requirements of this section. Uncertai nties 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 materi al misstatements. Reported values must be calculated using the follow ing equations:

Fuel consumed (volume or mass) = (inputs during tim e period – outputs during time period) + (amount stored at beginning o f 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. Produc t data will be evaluated for conformance and material misstatement independent o f GHG emissions data. Covered product data is evaluated for material miss tatement and conformance, while the remaining reported product data is evalua ted for conformance only. Reporting entities must exclude inaccurate covered product data, and may elect to exclude accurate covered product data. Reporting e ntities that exclude covered product data must report a description of the exclu ded data and an estimated magnitude using best available methods. The exclud ed covered product data willLegal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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California Air Resources Board 86 February 2015 not be used for the material misstatement assessmen t 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 pe rmits a choice between different methods for the monitoring and calculation of GHGs and product data, the operator or supplier must make th is 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 rep orts, unless the use of an alternative monitoring or calculation method is app roved in advance by the Executive Officer. (1) The operator or supplier is permitted to perman ently 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 syste m. Permanent improvements to emissions monitoring or calculation methods do not require approval in advance by the Executive Officer; howev er, 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 emi ssions monitoring or calculation method, and to all covered product data monitoring or calculation methods, must be approved in advance by the Executi ve Officer per the requirements in parts 95103(m)(2)-(3). (2) When proposing a permanent change in a monitori ng or calculation method to the Executive Officer, an operator or supplier must indicate why the change in method is being proposed, include a detailed descri ption 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 o f the subsequent data year, except in the circumstances described in part (m)(4 ). (4) The operator or supplier is permitted to tempor arily modify the emissions or product data monitoring or calculation method when necessary for the avoidance of missing data or to comply with the mis sing data provisions of this article. In the event of an unforeseen breakd own in fuel analytical data monitoring equipment or CEMS equipment, operators a nd suppliers must use the procedures in section 95129(h) and section 9512 9(i), respectively, for seeking approval of interim data collection procedu res. 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 th e 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 9510 3(m)(2)-(3). Operators and suppliers must be able to demonstrate during ve rification that the temporary method provides data accuracy within ± 5% as specified in sectionLegal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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95103(k)(6). Covered product data that does not me et 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 r eporting 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 fol lowing requirements apply regarding notifications to ARB and reporting respon sibilities. (1) ARB Notifications. Prior to the change of ownership or operational c ontrol, the previous owner or operator of the reporting entity and the new owner or operator of the reporting entity must provide the f ollowing information to ARB. Required information must be submitted to the ARB e mail account: ghgreport@arb.ca.gov (A) The previous owner or operator must notify ARB via email of the ownership or operational control change including t he 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 e mail 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 C alifornia Reporting Greenhouse Gas Reporting Tool (Cal e-GGRT) specifie d in section 95104(e); (2) Reporting Responsibilities. The owner or operator of record at the time of a reporting or verification deadline specified in thi s article has the responsibility for complying with the requirements of this article , including certifying that the emissions data report is accurate and complete, obt aining 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 repor t covering the complete calendar year data. (B) If an ownership change takes place during the c alendar 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 requi red data for the entire, calendar year.Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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(C) Previous owners or operators are required to pr ovide data and records to new owners or operators that is necessary and requi red for preparing annual emissions data reports required by this arti cle. (o) Addresses . The following address shall be substituted for t he addresses provided in 40 CFR §98.9 for both U.S. mail and package deli veries:

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 Mechani sm.

The reporting entities specified in section 95101 m ust develop, submit, and certify greenhouse gas emissions data reports to the Air Re sources 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, Ca lifornia Code of Regulations, section 95200 to 95207), must report the official r esponsible 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 designat ed 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 Co generation, 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 rep orting under this paragraph, the operator may exclude any electricity that is genera ted 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 notLegal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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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 supp ort 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 month s of January and December. (1) Electricity purchases or acquisition from sourc es 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 s ources outside of the facility boundary (MMBtu) and the name and ARB identificatio n number of each energy provider, as applicable. If the operator ac quires thermal energy from a PURPA Qualifying Facility and vents, radiates, wast es, or discharges more than 10% of the acquired thermal energy before util izing the energy in any industrial process, operation, or heating/cooling a pplication, the operator must report the amount of thermal energy actually needed and utilized, in addition to the amount of thermal energy received from the prov ider. (3) Electricity provided or sold, as specified in s ection 95112(a)(4), if applicable. (4) Thermal energy provided or sold to entities out side of the facility boundary: the operator must report the amount of thermal energy p rovided 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 requirem ents of section 95112(a)(5) in reporting the thermal energy generated by cogene ration or bigeneration units, and if applicable, also separately report th e information required in paragraph 95104(d)(4) for the thermal energy provid ed or sold that is not generated by cogeneration or bigeneration units. If the facility boundary includes more than one c ogeneration system, boiler, or steam generator, and each unit/system or each group of units produces thermal energy for different particular end-users o r on-site industrial processes and operations, the operator must report the dispos ition 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 r eports, and any revisions to the reports, through the Californi a Air Resources Board’s (ARB) Greenhouse Gas Reporting Tool, or any other reporti ng tool approved by the Executive Officer that will guarantee transmittal a nd receipt of data required by ARB’s Mandatory Reporting Regulation and Cost of Im plementation 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 th e 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 Green house Gas

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California Air Resources Board 90 February 2015 (1) Whether a change in the facility’s operations o r 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 comp ly 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 iden tified in section 95104(f)(2) caused the increase or decrease in emissions. Incl ude 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 gr eenhouse gases under this article, except as provided in section 95103(a)(9), must kee p 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 p eriod must maintain all records specified in 40 CFR §98.3(g), and records associate d 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 r etained documents, including GHG emissions data and input data, must be sufficient t o 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 yea rs from the date of certification. (b) ARB Requests for Records. Copies of any records or other materials maintain ed under the requirements of 40 CFR Part 98 or this ar ticle must be made available toLegal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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California Air Resources Board 91 February 2015 the Executive Officer upon request, within twenty d ays of receipt of such request by the designated representative of the reporting enti ty. (c) GHG Monitoring Plan for Facilities and Suppliers . Each facility operator or supplier that reports under 40 CFR Part 98, each facility op erator or supplier with emissions equal to or exceeding 25,000 MTCO 2 e (including biomass-derived CO 2 emissions and geothermal emissions), and each facility operat or or supplier with a compliance obligation under the cap-and-trade regulation in an y year of the current compliance period, must complete and retain for review by a ve rifier or ARB a written GHG Monitoring Plan that meets the requirements of 40 C FR §98.3(g)(5). For facilities, the Plan must also include the following elements, as applicable: (1) All fuel use measurement devices used for emiss ions calculations or product data must be clearly identified, and the plan must indicate how data from these devices are incorporated into the emissions data re port. (2) Original equipment manufacturer (OEM) documenta tion, or other documentation that identifies instrument accuracy a nd required maintenance and calibration requirements for all measurement de vices 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 c alculating 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 applicab le. (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 inspec tion performed according to the requirements of ISO 5167-2 (2003), section 5, or AG A Report No 3 (2003) Part 2, which are hereby incorporated by reference. (8) Training practices for personnel involved in GH G monitoring, including documented training procedures, and training materi als. (9) Copies of methodologies used for all fuel-based emissions analyses, including the standardized methods chosen as specified in sec tion 95109. (10) At the operator’s choosing, a fuel monitoring plan to verify on a regular basis the proper functioning of fuel measurement equipmen t that is used to determine facility GHG emissions. The operator wis hing to preserve the option of using the missing data substitution proce dures 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 p roper operation by recording fuel consumption data at least weekly. T he 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 malfuncti oning periods. TheLegal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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records of fuel consumption must be sufficient for the application of the missing data substitution procedure in section 9512 9(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 en tities that import or export electricity must prepare GHG Inventory Program docu mentation that is maintained and available for verifier review and ARB audit pur suant to the recordkeeping requirements of this section. The following inform ation is required: (1) Information to allow the verification team to d evelop a general understanding of entity boundaries, operations, and electricity t ransactions; (2) Reference to management policies or practices a pplicable to reporting pursuant to section 95111; (3) List of key personnel involved in compiling dat a and preparing the emissions data report; (4) Training practices for personnel involved in repor ting 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 th e quantity of electricity (MWh) imported, exported, and wheeled for transacti ons 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 revie w 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 asso ciated verbal or electronic records, full or partial ownership, invoices, and s ettlements data used to document whether reported transactions are specifie d 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 mad e to aggregate data into reporting categories required pursuant to section 9 5111; (8) Records of preventive and corrective actions ta ken to address verifier and ARB findings of past nonconformances and material m isstatements; (9) Log of emissions data report modifications made after initial certification; and (10) A written description of an internal audit pro gram that includes emissions data report review and documents ongoing efforts to impr ove 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 Green house Gas

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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 repo rted 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 Execut ive Officer pursuant to this article may claim such information as “confidential” by cle arly identifying such information as “confidential.” Any claim of confidentiality by an entity submitting information must be based on the entity’s belief that the infor mation 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 vi olation, the size and complexity of the reporting entity’s operations, and the other cr iteria in Health and Safety Code section 42403(b). (b) Each day or portion thereof that any report req uired by this article remains unsubmitted, is submitted late, or contains informa tion that is incomplete or inaccurate is a single, separate violation. For pur poses of this section, “report” means any emissions data report, verification state ment, or other document required to be submitted to the Executive Officer b y this article. (c) Each metric ton of CO 2 e emitted but not reported as required by this arti cle is a separate violation. ARB will not initiate enforceme nt action under this subparagraph until after any applicable verification deadline fo r the pertinent report. (d) Each failure to measure, collect, record or pre serve information in the manner required by this article constitutes a separate vio lation, except where the reporting entity can demonstrate that the failure results sol ely 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 th is 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 p ursuant to Health and Safety Code section 41513.Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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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: Secti ons 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 remainde r 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 mate rials listed in 40 CFR §98.7, or another similar method published by an organizat ion listed in 40 CFR §98.7 that is applicable to the analysis being conducted. For gaseous fuels, fuel characteristics may be determined using chromatogra phic 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 sect ion 95105(c). (b) Alternative test methods that are demonstrated to the satisfaction of the Executive Officer to be equally or more accurate than the met hods in section 95109(a) may be used upon written approval by the Executive Officer

.

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California Air Resources Board 95 February 2015 Subarticle 2. Requirements for the Mandatory Repor ting of Greenhouse Gas Emissions from Specific Types of Facilities, Suppli ers, and Entities

§ 95110. Cement Production.

The operator of a facility who is required to repor t under section 95101 of this article, and who is not eligible for abbreviated reporting u nder 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 fro m cement production to ARB, except as otherwise provided in this section.

(a) CO 2 from Fossil Fuel Combustion. When calculating CO 2 emissions from fuel combustion, the operator must use a method in 40 CF R §98.33(a)(1) to §98.33(a)(4) as specified by fuel type in section 9 5115 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 mod ified 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 a s otherwise provided in paragraphs (1)-(3) below. (1) To substitute for missing data for emissions re ported under section 95115 of this article (stationary combustion units and units using continuous emissions monitoring systems), the operator must follow the r equirements 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 ca nnot 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 usi ng the best available estimate of the parameter, based on all available p rocess 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 y ears. (C) If the data capture rate is less than 80 percen t for the data year, the operator must substitute for each missing value wit h the highest quality assured value recorded for the parameter in all rec ords kept according to section 95105(a).Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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California Air Resources Board 96 February 2015 (3) For each missing value of the monthly raw mater ial consumption or monthly clinker production used to calculate emissions, the operator must apply a substitute value according to paragraphs (A)-(B) be low. (A) If the data capture rate is at least 80 percent for the data year, the operator must substitute for each missing value acc ording to 40 CFR §98.85(c) or 40 CFR §98.85(d), as applicable. (B) If the data capture rate is less than 80 percen t for the data year, the operator must substitute for each missing value wit h the maximum short tons of clinker per day capacity of the system or t he maximum short tons per day raw material throughput of the kiln, as app licable, and the number of days per month. (4) The operator must document and retain records o f the procedure used for all missing data estimates pursuant to the recordkeepin g 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 CO 2 emissions. (1) Annual quantity clinker produced (short tons). (2) Annual quantity clinker consumed (short tons). (3) Annual quantity of limestone and gypsum (includ ing 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 mis statement 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 Green house Gas

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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 CO 2 equivalent (MT of CO 2 e), according to the calculation methods in section 95111(b). (2) Delivered Electricity. The electric power entity must report imported, e xported, and wheeled electricity in MWh disaggregated by fir st point of receipt or final point of delivery, as applicable, and must also sep arately report imported and exported electricity from unspecified sources and f rom 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 informati on: (A) Whether the first point of receipt is located i n a linked jurisdiction published on the ARB Mandatory Reporting website; (B) The amount of electricity from unspecified sour ces 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 U nits. The electric power entity must report all direct delivery of electricity as f rom 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. W hen 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 s ources and the sum of emissions from specified sources explicitly listed as not covered pursuant to section 95852.2 of the cap-and-trade regulation. T he sale or resale of specified source electricity is permitted among ent ities on the e-tag market path insofar as each sale or resale is for specifie d source electricity in which sellers have purchased and sold specified source el ectricity, such that eachLegal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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seller warrants the sale of specified source electr icity from the source through the market path. (A) Claims of specified sources of imported electri city, defined pursuant to section 95102(a), are calculated pursuant to sectio n 95111(b), must meet the requirements in section 95111(g), and must incl ude the following information:

1. Measured at Busbar . The amount of imported electricity from specified facilities or units as measured at the bu sbar; and

2. Not Measured at Busbar . If the amount of imported electricity deliveries from specified facilities or units as me asured at the busbar is not provided, report the amount of imported elec tricity as measured at the first point of delivery in Californ ia, including estimated transmission losses as required in sectio n 95111(b), and the reason why measurement at the busbar is not kno wn. (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 standardi zed PSE acronym or code, full name, and the ARB identification number; (B) Report asset-controlling supplier power that wa s not acquired as specified power, as unspecified power; (C) Report delivered electricity from asset-control ling suppliers as measured at the first point of delivery in the state of Cali fornia; and, (D) Report GHG emissions calculated pursuant to sec tion 95111(b), including transmission losses. (E) Tagging ACS Power . To claim power from an asset-controlling supplie r, the asset-controlling supplier must be identified o n the physical path of the NERC e-Tag as the PSE at the first point of rec eipt, or in the case of asset controlling suppliers that are exclusive mark eters, as the PSE immediately following the associated generation own er. (6) Exported Electricity. The electric power entity must report exported el ectricity in MWh and associated GHG emissions in MT of CO 2 e for unspecified sources disaggregated by each final point of delive ry outside the state of California, and for each specified source disaggreg ated by each final point of delivery outside the state of California, as well a s the following information: (A) Exported electricity as measured at the last po int of delivery located in the state of California, if known. If unknown, rep ort 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 l ocated in a linked jurisdiction published on the ARB Mandatory Reporting website.Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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(D) Report GHG emissions calculated pursuant to sec tion 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 consist ent 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 Califo rnia 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 re ceipt, and must exclude wheeled power transactions from reported imports an d exports. When reporting electricity wheeled through California, t he power entity must include the quantities of electricity wheeled through Calif ornia as measured at the first point of delivery inside the state of California. (9) Verification Documentation. The electric power entity must retain for purpose s of verification NERC e-Tags, written power contract s, settlements data, and all other information required to confirm reported elec tricity procurements and deliveries pursuant to the recordkeeping requiremen ts of section 95105. (10) Electricity Generating Units and Cogeneration Units in California. Electric power entities that also operate electricity genera ting units or cogeneration units located inside the state of California that m eet the applicability requirements of this article must report GHG emissi ons to ARB under section 95112. (11) Electricity Generating Units and Cogeneration Units Outside California. Operators and owners of electricity generating unit s and cogeneration units located outside the state of California who elect t o report to ARB under section 95112 must fully comply with the reporting and veri fication requirements of this article. (12) Electrical Distribution Utility Sales into CAI SO. 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 obl igation, beginning with calendar years 2013 and 2014 reported in 2015. EDU s 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 require ment 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 accou nt pursuant to section 95892(b)(2) of the Cap-and-Trade Regulation. Verifi ers 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 Green house Gas

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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 CO 2 equivalent mass emissions using the following equat ion:

Where: CO 2 e = Annual CO 2 equivalent mass emissions from the unspecified

electricity deliveries at each point of receipt ide ntified (MT of CO 2 e). MWh = Megawatt-hours of unspecified electricity del iveries at each point of

receipt identified. EF unsp = Default emission factor for unspecified electric ity imports. EF unsp = 0.428 MT of CO2e/MWh TL = Transmission loss correction factor. TL = 1.02 to account for transmission losses betwee n the busbar and

measurement at the first point of receipt in Califo rnia. (2) Calculating GHG Emissions from Specified Facilities or Units. For electricity from specified facilities or units, the electric po wer entity must calculate emissions using the following equation:

Where: CO 2 e = Annual CO 2 equivalent mass emissions from the specified

electricity deliveries from each facility or unit c laimed (MT of CO 2 e). MWh = Megawatt-hours of specified electricity deliv eries from each facility

or unit claimed. EF sp = Facility-specific or unit-specific emission fact or published on the

ARB Mandatory Reporting website and calculated usin g total emissions and transactions data as described below. The emission factor is based on data from the year prior to the reporting year. EF sp = 0 MT of CO 2 e 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 associ ated with generation

outside of a California balancing authority. TL = 1.0 if the reporting entity provides documenta tion that demonstrates

to the satisfaction of a verifier and ARB that tran smission losses (1) have been accounted for, (2) are supported by a Cal ifornia balancing authority, or (3) are compensated by usin g electricity sourced from within California.

unsp EF TL MWh e CO ×

× = 2

sp

EF TL MWh e CO ×

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The Executive Officer shall calculate facility-spec ific or unit-specific emission factors and publish them on the ARB Mandatory Repor ting website using the following equation:

EF sp = E sp /EG

Where: E sp = CO 2 e emissions for a specified facility or unit for th e report year

(MT of CO 2 e). EG = Net generation from a specified facility or un it for the report year

shall be based on data reported to the Energy Infor mation 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 A RB unit level GHG emissions consistent with the data source requireme nts 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 e ntity, and proof of direct delivery of the power by the reporting entity as an import to California. (A) For specified facilities or units whose operato rs are subject to this article or whose owners or operators voluntarily report und er this article, E sp shall be equal to the sum of CO 2 e emissions reported pursuant to section 95112. (B) For specified facilities or units whose operato rs are not subject to reporting under this article or whose owners or ope rators do not voluntarily report under this article, but are subj ect to the U.S. EPA GHG Mandatory Reporting Regulation, E sp shall be based on GHG emissions reported to U.S. EPA pursuant to 40 CFR Part 98. E missions from combustion of biomass-derived fuels will be based o n EIA data until such time the emissions are reported to U.S. EPA. (C) For specified facilities or units whose operato rs 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, E sp is calculated using heat of combustion data reported to the Energy Information Administration ( EIA) E sp = 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 generatio n consistent with EIA reporting. For geothermal electricity, Q is the ste am data reported to EIA (MMBtu).Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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EF = O 2 e emission factor for the specified fuel type as re quired by this article (kg CO 2 e /MMBtu). For geothermal electricity, EF is the estimated CO 2 emission factor published by EIA. (D) Facilities or units will be assigned an emission fa ctor 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 repor t is not available, including new facilities and facilities located out side the U.S. (E) Meter Data Requirement. For verification purpo ses, electric power entities shall retain meter generation data to docu ment that the power claimed by the reporting entity was generated by th e facility or unit at the time the power was directly delivered. This provis ion is applicable to imports from specified sources for which ARB has ca lculated an emission factor of zero, and for imports from California Ren ewable Portfolio Standard (RPS) eligible resources, excluding: (1) c ontract or ownership agreements, known as grandfathered contracts that m eet California RPS program requirements in Public Utilities Code Secti on 399.16(d) or California Code of Regulations, Title 20 Section 32 02(a)(2)(A); (2) dynamically tagged power deliveries; (3) untagg ed power deliveries, including EIM imports; (4) nuclear power; (5) asset controlling supplier power; and (6) imports from hydroelectric facilitie s for which an entity’s share of metered output on an hourly basis is not e stablished by power contract. Accordingly, a lesser of analysis is req uired pursuant to the following equation:

Sum of Lesser of MWh = Σ HM sp min(MG sp , TG sp )

Where: Σ HM sp = Sum of the Hourly Minimum of MG sp and TG sp (MWh). MG sp = metered facility or unit net generation (MWh). S sp = entity’s share of metered output. TG sp = tagged or transmitted energy at the transmissio n or subtransmission level imported to California (MWh). (3) Calculating GHG Emissions of Imported Electricity S upplied 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 al l asset-controlling suppliers recognized by the ARB. The reporting entity must c alculate emissions for electricity supplied using the following equation:

Where: CO 2 e = Annual CO 2 equivalent mass emissions from the specified electricity deliveries from ARB-recognized asset-co ntrolling suppliers (MT of CO 2 e). MWh = Megawatt-hours of specified electricity deliv eries. ACS EF TL MWh e CO ×

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EF ACS = Asset-Controlling Supplier system emission facto r published on the ARB Mandatory Reporting website (MTCO 2 e/MWh). ARB will assign the system emission factors for all asset-controlling s uppliers based on a previously verified GHG report submitted to ARB pur suant to section 95111(f). The supplier-specific system emission fa ctor is calculated annually by ARB. The calculation is derived from d ata contained in annual reports submitted pursuant to section 95111( f) that have received a positive or qualified positive verification state ment. The emission factor is based on data from two years prior to the report ing year. TL = Transmission loss correction factor. TL = 1.02 when deliveries are not reported as measu red 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 em ission factor for assetcontrolling suppliers using the following equations : EF ACS = Sum of System Emissions MT of CO 2 e / Sum of System MWh

Sum of System Emissions, MT of CO 2 e = Σ E asp + Σ (PE sp * EF sp ) + Σ (PE unsp * EF unsp ) - Σ (SE sp * EF sp )

Sum of System MWh = Σ EG asp + Σ PE sp + Σ PE unsp – Σ SE sp

Where: Σ E asp = Emissions from Owned Facilities . Sum of CO 2 e emissions from each specified facility/unit in the asset-controlli ng supplier’s fleet, consistent with section 95111(b)(2) (MT of CO 2 e). Σ EG asp = Net Generation from Owned Facilities . Sum of net generation for each specified facility/unit in the asset-contr olling supplier’s fleet for the data year as reported to ARB under this art icle (MWh). PE sp = Electricity Purchased from Specified Sources . Amount of electricity purchased wholesale and taken from spec ified sources by the asset-controlling supplier for the data year as reported to ARB under this article (MWh). PE unsp = Electricity Purchased from Unspecified Sources . Amount of electricity purchased wholesale from unspecified so urces by the asset-controlling supplier for the data year as rep orted to ARB under this article (MWh). SE sp = Electricity Sold from Specified Sources . Amount of wholesale electricity sold from specified sources by the asse t-controlling supplier for the data year as reported to ARB under this article (MWh). EF sp = CO 2 e emission factor as defined for each specified fac ility or unit calculated consistent with section 95111(b)(2) (MTC O 2 e/MWh).Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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EF unsp = Default emission factor for unspecified sources calculated consistent with section 95111(b)(1) (MTCO 2 e/MWh). (4) Calculating GHG Emissions of Imported Electricity f or Multi-jurisdictional Retail Providers. Multi-jurisdictional retail providers must includ e emissions and megawatt-hours in the terms below from facilities o r units that contribute to a common system power pool. Multi-jurisdictional reta il providers do not include emissions or megawatt-hours in the terms below from facilities or units allocated to serve retail loads in designated state s pursuant to a cost allocation methodology approved by the California P ublic Utilities Commission (CPUC) and the utility regulatory commission of at least one additional state in which the multi-jurisdictional retail provider prov ides retail electric service. Multi-jurisdictional retail providers must calculat e emissions that have a compliance obligation using the following equation:

CO 2 e = (MWh R

x TL R - MWh WSP-CA - EG CA ) x EF MJRP + MW WSP-notCA x TL WSP

x EF unsp - CO 2 e linked Where: CO 2 e = Annual CO 2 e mass emissions of imported electricity (MT of CO 2 e). MWh R = Total electricity procured by multi-jurisdiction al retail provider to serve its retail customers in California, reported as retail sales for California service territory, MWh. MWh WSP-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 Calif ornia Public Utilities Commission (CPUC) and the utility regulatory commis sion of at least one additional state in which the multi-jurisdictional retail provider provides retail electric service, MWh. MWh WSP-not CA = Wholesale electricity imported into California b y multijurisdictional retail provider with a final point o f delivery in California and not used to serve its California retail customers, MWh. EF MJRP = Multi-jurisdictional retail provider system emis sion factor calculated by ARB pursuant to subsection 95111(b)(3) and consi stent with a cost allocation methodology approved by the California P ublic Utilities Commission (CPUC) and the utility regulatory commis sion of at least one additional state in which the multi-jurisdictional retail provider provides retail electric service. EF unsp = Default emission factor for unspecified sources calculated consistent with section 95111(b)(1) (MTCO 2 e/MWh). EG CA = Net generation measured at the busbar of facilit ies and units located in California that are allocated to serve i ts retail customers in California pursuant to a cost allocation methodolog y approved by the California Public Utilities Commission (CPUC) and t he utility regulatory commission of at least one additional state in whic h the multijurisdictional retail provider provides retail elec tric service, MWh. TL = Transmission loss correction factor.Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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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. CO 2 e linked = Annual CO 2 e mass emissions recognized by ARB pursuant to linkage under subarticle 12 of the cap-and-trade re gulation (MT of CO 2 e). (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 pursuan t to the equation in 95852(b)(1)(B) of the cap-and-trade regulation and include the following information:

CO 2 e covered = Sum of covered emissions defined pursuant to sec tion 95102(a) and calculated pursuant to the equation in section 95852(b)(1)(B) of the cap-and-trade regulation (MT of CO 2 e).

CO 2 e unsp = Sum of CO 2 equivalent mass emissions from imported electricit y from unspecified sources (MT of CO 2 e).

CO 2 e sp = Sum of CO 2 equivalent mass emissions from imported electricit y that meets the requirements in section 95111(g) for reporting electricity from specified sources (MT of CO 2 e).

CO 2 e sp-not covered = Sum of CO 2 equivalent mass emissions from imported electricity that meets the requirements in section 95111(g) for reporting electricity from specified sources and is explicitl y listed as emissions without a compliance obligation pursuant to section 95852.2 of the capand-trade regulation (MT of CO 2 e).

CO 2 e RPS adjust = Sum of CO 2 equivalent mass emissions adjustment is calculated using the following equation for electr icity generated by each eligible renewable energy resource located outside the state of California and registered with ARB by the reporting entity pur suant to section 95111(g)(1), but not directly delivered as defined pursuant to section 95102(a). Electricity included in the RPS adjustme nt must meet the requirements pursuant to section 95852(b)(4) of the cap-and-trade regulation (MT of CO 2 e).

CO 2 e RPS_adjust

= MWh RPS

x EFunsp (MTCO 2 e/MWh)

Where: MWh RPS = 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 requir ements pursuant to section 95852(b)(4) of the cap-and-trade regulation

. CO 2 e QE adjust = Sum of CO 2 equivalent mass emissions adjustment for qualified exports as defined in section 95102(a) an d that meet the requirements pursuant to section 95852(b)(5) of the cap-and-trade regulation (MT of CO 2 e).Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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CO 2 e linked = Sum of CO 2 e mass emissions recognized by ARB pursuant to linkage under subarticle 12 of the cap-and-trade re gulation (MT of CO 2 e).

(c) Additional Requirements for Retail Providers, exclu ding Multi-jurisdictional Retail Providers. Retail providers must include the following infor mation in the GHG emissions data report for each report year, in addi tion 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 ret ail 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 othe r retail sales. (3) For facilities or units located outside Califor nia 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 greate r 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 o r 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, an d that have emissions greater than the default emission factor for unspec ified electricity based on the most recent GHG emissions data report submit ted to ARB or to U.S.EPA, the retail provider must report the follow ing information: 1. When the product of net generation (MWh) and own ership share is greater than imported electricity (MWh), emissions associated with electricity not imported into California must be re ported as

CO 2 e not imported = (EG sp *OS – I sp )*EF sp.

Where: EG sp = 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, locatio ns, and whetherLegal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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they are new units when I sp < 90% of EG sp *OS and when a facility specified in the previous report year has no import ed electricity in the current report year. (4) Retail providers that report as electricity imp orters or exporters also must separately report electricity imported from specifi ed and unspecified sources by other electric power entities to serve their loa d, designating the electricity importer. In addition, all imported electricity tr ansactions documented by NERC e-Tags where the retail provider is the PSE at the sink must be reported. (d) Additional Requirements for Multi-Jurisdictional Re tail Providers. Multi-jurisdictional retail providers that provide electricity into Cali fornia at the distribution level must include the following information in the GHG emissi ons 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 GH G emissions associated with the common power system or contiguous service territory that includes consumers in California. This includes the requirements in th is section as applicable for each generating facility or unit in the multi-juris dictional retail provider’s fleet; (2) The multi-jurisdictional retail provider must i nclude in its emissions data report wholesale power purchased and taken (MWh) from spec ified and unspecified sources and wholesale power sold from specified sou rces according to the specifications in this section, and as required forARB to calculate a supplierspecific emission factor; (3) Total retail sales (MWh) by the multi-jurisdict ional retail provider in the contiguous service territory or power system that i ncludes consumers in California; (4) Retail sales (MWh) to California customers serv ed in California’s portion of the service territory; (5) GHG emissions associated with the imported elec tricity, including both California retail sales and wholesale power importe d into California from the retail provider’s system, according to the specific ations in this section; (6) Multi-jurisdictional retail providers that serv e California load must claim as specified power all power purchased or taken from f acilities or units in which they have operational control or an ownership share or written power contract; (7) Multi-jurisdictional retail providers that serv e California load may elect to exclude information listed in 95111(g)(1)(E)-(J) wh en registering claims to specified power from facilities located outside Cal ifornia and participating in the Federal Energy Regulatory Commission’s PURPA Qu alifying Facility program. (e) Additional Requirements for WAPA and DWR. (1) In reporting its GHG emissions to ARB, the Cali fornia Department of Water Resources shall include all applicable information identified in this article forLegal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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retail providers, including the amount of electrici ty used for pump loads, to operate the State Water Project. (2) In reporting its GHG emissions to ARB, the West ern Area Power Agency shall include all applicable information identified in th is article for retail providers, including the amount of electricity used for pump l oads, to operate the Central Valley Project. (f) Requirements for Asset-Controlling Suppliers. Owners or operators of electricity generating facilities or exclusive marketers for ce rtain generating facilities may apply for an asset-controlling supplier designation from ARB. Approved assetcontrolling suppliers may request that ARB calculat e a supplier-specific emission factor pursuant to section 95111(b)(3). To apply f or asset-controlling supplier designation, the applicant must:

To apply for asset-controlling supplier designation , the applicant must: (1) Meet the requirements in this article, includin g 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 wh olesale power sold from specified sources according to the specifications i n this section, and as required for ARB to calculate a supplier-specific e mission factor; (3) Retain for verification purposes documentation that the power sold by the supplier originated from the supplier’s fleet of fa cilities 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 identificatio n number to electric power entities who purchase electricity from the supplier ’s system. (5) To apply for and maintain asset-controlling sup plier status, the entity shall submit as part of its emissions data report the fol lowing 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 generatin g facilities for which the reporting entity is a generation providing entity p ursuant to 95102(a); and, (F) An attestation, in writing and signed by an aut horized 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 si gn this attestation on behalf of [name of entity], that [name of entity] m eets the definition of anLegal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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asset-controlling supplier as specified in section 95102(a) of the Regulation for the Mandatory Reporting of Greenhous e Gas Emissions, title 17, California Code of Regulations, section 9 5100 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 re moved 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 u se 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 su bmitted by June 1 of the same year. Each reporting entity claiming specified fac ilities or units for imported or exported electricity must also meet requirements pu rsuant 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), purs uant to section 95852(b)(4) of the cap-and-trade regulation must include registrat ion information for the eligible renewable energy resources pursuant to subsection 9 5111(g)(1) in the emissions data report. Prior registration and subsection 951 11(g)(2)-(5) do not apply to RPS adjustments. Registration information and the amou nt of electricity claimed in the RPS adjustment must be fully reconciled and correct ions 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 th e unit level, the facility and unit names. (B) For sources with a previously assigned ARB iden tification number, the ARB facility or unit identification number or suppl ier number published on ARB’s mandatory reporting program website. For new ly specified sources, ARB will assign a unique identification nu mber. (C) If applicable, the facility and unit identifica tion numbers as used for reporting to the U.S. EPA Acid Rain Program, U.S. E PA pursuant to 40 CFR Part 98, U.S. Energy Information Administration , Federal Energy Regulatory Commission’s PURPA Qualifying Facility p rogram, California Energy Commission, and California Independent Syste m Operator, as applicable.Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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(D) The physical address of each facility, includin g jurisdiction. (E) Provide names of facility owner and operator. (F) The percent ownership share and whether the fac ility 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 ap plicable, date of repowering. (J) GPEs claiming additional capacity at an existin g facility must include the implementation date, the expected increase in net g eneration (MWh), and a description of the actions taken to increase capa city. (K) Designate whether the facility or unit is a new ly specified source, a continuing specified source, or was a specified sou rce in the previous report year that will not be specified in the curre nt report year. (L) Provide the primary technology or fuel type as listed below: 1. Variable renewable resources by type, defined fo r 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 sys tem; 6. Geothermal steam plant or open loop system; 7. Units combusting biomass-derived fuel, by prima ry 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 ser ial numbers of the RECs as specified below: 1. RECs associated with electricity procured from a n eligible renewable energy resource and reported as an RPS adjustment a s well asLegal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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whether the RECs have been placed in a retirement s ubaccount and designated as retired for the purpose of compliance with the California RPS program. 2. RECs associated with electricity procured from a n eligible renewable energy resource and reported as an RPS adjustment i n a previous emissions data report year that were subsequently w ithdrawn from the retirement subaccount, or modified the associat ed emissions data report year the RPS adjustment was claimed, an d the date of REC withdrawal or modification. 3. RECs associated with electricity generated, dire ctly delivered, and reported as specified imported electricity and whet her or not the RECs have been placed in a retirement subaccount. (2) Emission Factors. The emission factor published on the ARB Mandator y Reporting website, calculated by ARB according to t he 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 el ectricity defined in section 95102(a), and one of the following sets of conditio ns: (A) The electricity importer is a GPE; or (B) The electricity importer has a written power co ntract 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 mus t indicate whether one or more of the following descriptions applies: (A) Deliveries from specified sources previously re ported as consumed in California. Specified source of electricity has be en 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 cont ract 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 un it for up to the same share or quantity of net generation within 12 month s following prior expiration; or a specified facility for which impor ted electricity was reported as greater than 80 percent of net generati on in the 2009 or 2010 data years; (B) Deliveries from existing federally owned hydroe lectricity facilities by exclusive marketers. Electricity from specified fe derally owned hydroelectricity facility delivered by exclusive ma rketers; (C) Deliveries from existing federally owned hydroe lectricity facilities allocated by contract. Specified federally owned h ydroelectricity source delivered by electricity importers with a written p ower contract in effectLegal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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within 12 months after changes in rights due to fed eral power allocation or redistribution policies, including acts of Congr ess, and not related to price bidding, that remains in effect or has been r enegotiated 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 sour ce of electricity is first registered pursuant to section 95111(g)(1) and deli vered by an electricity importer within 12 months of the start date of comm ercial operation and the electricity importer making a claim in the curr ent data year is either a GPE or purchaser of electricity under a written pow er contract; (E) Deliveries from existing facilities with additi onal 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 da te 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 speci fied 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 Un its.

The operator of a facility who is required to repor t under section 95101 of this article, and who is not eligible for abbreviated reporting u nder 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 o ther data from electricity generating and cogeneration units to ARB, except as otherwise provided in this section. Notwithstanding the above, the operator of a facili ty 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 t o report disposition of generated energy or energy flow data that are not used direct ly to determine emissions, facility operators must demonstrate accuracy of the chosen e ngineering estimation method. (a) Information About the Electricity Generating Facili ty. Notwithstanding any limitations in 40 CFR Parts 75 or 98, the operator of an electr icity generating facility is required to include in the emissions data report the informa tion listed in this paragraph, unless otherwise specified in paragraphs (e) and (g ) of this section for geothermal facilities and facilities with renewable energy gen eration. Reporting of information specified in section 95112(a)(4)-(6) is optional fo r facilities that do not provide or sell any generated energy outside of the facility bounda ry. However, facility operators that are applying for or receiving the legacy contr act 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 ther mal output under the cap-and-Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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California Air Resources Board 113 February 2015 trade regulation, must report the information in se ctions 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 p rogram, 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 fa cility co-located with the thermal host, an independently operated and sited c ogeneration/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 provid e 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 cat egories, if applicable: (A) Generated Electricity For Grid. Generated electricity provided or sold to a retail provider or electricity marketer who distrib utes the electricity over the electric power grid for wholesale or retail cus tomers of the grid. The operator must report the name of the retail provide r or electricity marketer; (B) Generated Electricity For Other Users. Generated electricity provided or sold directly to particular end-users (as defined i n section 95102). A reportable end-user includes any entity, under the same or different operational control, that is not a part of the faci lity. Report each enduser’s facility name, NAICS code, and ARB ID if app licable; (C) Generated Electricity For On-Site Industrial Applic ations 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 electrici ty that is used to produce cooling energy if: 1. The facility provides cooling energy (e.g., chil led water) to a particular end-user outside of the facility boundary; or 2. The facility includes on-site industrial process es or operations that are neither in support of or a part of the power ge neration system, and a portion of the generated electricity is used to produce cooling energy for such on-site industrial process or opera tions. If the facility includes equipment that utilizes ge nerated electricity to produce cooling (e.g., absorption chiller) for the sole purpose of maintaining temperature in the electricity generati on or cogenerationLegal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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system, account for such electricity as a part of t he difference between gross generation and net generation (parasitic load ) pursuant to section 95112(b)(2). If a facility includes more than one electricity ge nerating unit or cogeneration system, and each unit/system or each g roup of units generate electricity for different particular end-u sers 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 o perator 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 coge neration unit or bigeneration unit (“generated thermal energy”), rep orted at the facility-level, including for each of the following disposition cat egories, 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 dif ferent operational control, that is not a part of the facility. Repor t each end-user’s facility name, NAICS code, ARB ID if applicable, and the typ es of thermal energy product provided. Exclude from this quantit y 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 r eported 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 p ower production, such as the steam used to drive a steam turbine generato r to generate electricity. Activities for supporting power gener ation may include steam used for power augmentation, NO x control, sent to a de-aerator, or sent to a cooling tower. (C) Generated Thermal Energy For On-Site Industrial App lications 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, repo rt the amount of generated thermal energy that is used by those on-s ite industrial processes or operations and heating or cooling appl ications. Exclude from this quantity the amount of thermal energy tha t is vented, radiated, wasted, or discharged before it is utilized at indu strial processes or operations. This quantity does not include the amo unt 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 Green house Gas

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Separately report the amount of generated thermal e nergy that is used to produce cooling energy or distilled water if: 1. The facility provides cooling energy (e.g., chil led water) or distilled water to a particular end-user outside of the facil ity boundary, or 2. The facility includes on-site industrial process es or operations that are neither in support of or a part of the power ge neration system, and a portion of the generated thermal energy is us ed to produce cooling energy or distilled water for such on-site industrial process or operations. If the facility includes equipment that utilizes ge nerated thermal energy to produce cooling (e.g., absorption chiller) for the sole purpose of maintaining temperature in the electricity generati on 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 o r bigeneration unit/system, and each unit/system or each group of units generate thermal energy for different particular end-users o r on-site industrial processes or operations, the operator must report t he disposition of generated thermal energy by unit/system or by group of units with the same dispositions. For the purpose of separate repo rting of disposition, the operator may group similar units together if th e generated thermal energy from the group of units is provided to the s ame destination. (6) For the first year of reporting, operators of c ogeneration or bigeneration units must submit a simplified block diagram depicting th e following, as applicable: individual equipment included in the generation sys tem (e.g. turbine, engine, boiler, heat recovery steam generator); direction o f 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; a nd relative locations of fuel meters and other fuel quantity measurements. If th e cogeneration or bigeneration system is modified after the initial s ubmission 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 electrici ty 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 sect ions 95115(h) and 95112(b). For an electricity generation system (a cogeneration system, a bigeneration system, a combined cycle electricity g eneration system, or a system with boilers and steam turbine generators), the ope rator 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 i n 40 CFR § 98.36(d)(1)(i). If there is more than one system present at the facility, ea ch system must be reported separately. For electricity generating units that a re not part of an integratedLegal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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California Air Resources Board 116 February 2015 generation system, aggregation of electricity gener ating units is limited to units of the same type, as specified in section 95115(h). O perators of geothermal facilities, hydrogen fuel cells, and renewable electricity gene rating units must follow paragraph (e), (f), or (g) of this section, whichev er 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 sec tion 95112(b)(4)-(6) except for any fuels combusted for supplemental firing as specifie d in section 95112(b)(7). (1) Basic information about the generating unit, in cluding: (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 ther mal energy, indicate whether the unit is a cogeneration or a bigeneration unit. If the unit is a cogeneration unit, indicate whether it is topping o r bottoming cycle. (2) Net and gross power generated, in megawatt hour s (MWh). The difference between net generation and gross generation is the parasitic load of electricity generation or cogeneration. The net generation qua ntity represents the amount of generated electricity that can be provide d to the disposition categories in section 95112(a)(4). (3) If the unit is a cogeneration or bigeneration u nit, 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 othe r industrial operations that are not electricity generation. Exclude from this quan tity the heat content of returned condensate and makeup water and steam used to drive a steam turbine generator for electricity generation. The t otal thermal output quantity represents the amount of generated thermal energy t hat can be provided to the thermal energy disposition categories in sectio n 95112(a)(5). (4) Fuel consumption by fuel type, reported in unit s 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 CO 2 , CH 4 , and N 2 O emissions from the unit, expressed in metric tons of each gas

. (6) If used to calculate CO 2 emissions and not already required to be reported under 40 CFR §98.36(e)(2)(ii)(C) and (iv)(C), repor t 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

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consumption (MMBtu) that is used for supplemental f iring, 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 acco unted for in paragraphs 95112(b)(4)-(6) (for example, if steam or heat is a cquired from outside of the electricity generation system boundary or acquired from another facility for the generation of electricity), report the amount of ac quired steam or heat (MMBtu). For bottoming cycle cogeneration units on ly, also report the input steam to the steam turbine (MMBtu) and the output o f the heat recovery steam generator (MMBtu). (c) Emissions from Fuel Combustion and Sorbent . When calculating CO 2 , CH 4 , and N 2 O 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 §98.3 3(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 e lect 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 em issions from fuels combusted within the data year but not reported pursuant to 4 0 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 appl icable, according to the de minimis provisions in section 95103(i) of this article. (2) The operator of a Subpart D unit with contractu al deliveries of biomethane or biogas is subject to the requirements in section 95 131(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 CO 2 emissions using emission calculation methods specified in 40 CFR Part 75, an d who operates a unit with a wet flue gas desulfurization system, must indicat e the portion of the total reported CO 2 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 mod ified in sections 95112, 95115, and 95129 of this article. (e) CO 2 and CH

4 Emissions from Geothermal Facilities. Operators of geothermal generating facilities must report CO 2 and CH 4 emissions from geothermal energy sources, the amount of geothermal steam utilized (M MBtu) if steam quantity is used in calculating emissions, and applicable requiremen ts 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 Green house Gas

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California Air Resources Board 118 February 2015 The operator must calculate annual emissions of CO 2 and CH 4 from geothermal energy sources using source specific emission facto rs 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 firs t test date. The measurement plan must include testing at least annually, and mo re frequently as needed. Upon approval of the measurement plan by the Executive O fficer, the test procedures in that plan must be performed as specified in the pla n. The Executive Officer and the local air pollution control officer must be notifie d at least 20 days in advance of subsequent tests. (f) Hydrogen Fuel Cells. Operators of stationary hydrogen fuel cell units mu st include the following information in the annual GHG emissio ns data report: (1) Basic information about the generating unit spe cified 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) CO 2 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 facilit y operator may use the default carbon content percentage value listed in T able 1 of section 95129(c). (B) For natural gas and biogas, if the fuel heat in put is measured by the facility operator or by the fuel supplier, the oper ator may use the following equation to estimate emissions.

CO 2 (MT/year) = H (MMBtu/year) x EF (kg CO 2 /MMBtu) x 0.001 (MT/kg)

Where CO 2 = Annual CO 2 emissions from fuel and feedstock consumption (met ric tons/year) H = Total fuel heat input for the year (MMBtu/year) EF = Default CO 2 emission factor. Use 53.02 kg CO 2 / MMBtu for natural gas. Use 52.07 kg CO 2 /MMBtu for biogas. 0.001 = Conversion factor from kg to metric tons. (C) For biogas fuels, the facility operator may ele ct to use the best available estimation and engineering estimation approach to c alculate 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 sec tion 95101(f). If such facilityLegal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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California Air Resources Board 119 February 2015 includes non-fuel-based renewable electricity gener ating units with nameplate generating capacity of greater than 0.5 MW, the ope rator must report the nameplate generating capacity (MW), gross power generated (MW h) by the non-fuel-based renewable electricity generating units, and the app licable information in 95112(a). For facility operators that do not operate other el ectricity generating units that are subject to the requirements in paragraphs (a)-(f) o f 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 arti cle (stationary combustion units and units using continuous emissions monitoring sys tems), 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 Contra ct Applicants . The additional requirements in section 95112(i) apply to every fac ility 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 si mplified block diagram in every year that the facility operator applies for legacy contract transition assistance. Legends or attachments may be used when labeling th e 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 diagra m and the summation described in an attachment. (1) The diagram must depict the following elements: (A) For the data year, all of the information descr ibed in sections 95112(a)(4)-(5), as applicable, regardless of wheth er the facility operator, or the equipment, is itself otherwise subject to se ctions 95112(a)(4)-(5). This information reflects electricity and thermal e nergy flows, including information identifying the recipient(s) of the ele ctricity and/or thermal energy. Also report the quantities of any other pr oducts provided or sold under the legacy contract, using the units in which they are reported elsewhere in this regulation, if applicable. The d iagram must indicate where each of these energy flows or products is mea sured. 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 u nder 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 wat er, 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 syst em but produces or consumes energy that is sent to or received from th at system and is owned or operated by the facility operator. Boiler s, individual generatorsLegal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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such as heat recovery steam generators, turbines if separate from generators, ice plants, chillers, purifiers and oth er equipment that meet these criteria must each be shown separately in the diagram. In addition, label each piece of equipment with the amount of fu el consumed (in MMBtu) by that piece of equipment during the data y ear, if any, and the resulting greenhouse gas emissions in CO 2 e as reported elsewhere under this regulation. The diagram must also indic ate the fuel meter where this fuel use was measured, and the amount me asured. (C) An outline showing the boundary of the activiti es 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 repor t under section 95101 of this article, and who is not eligible for abbreviated reporting u nder section 95103(a), must comply with Subpart Y of 40 CFR Part 98 (40 CFR §§98.250 t o 98.258) in reporting emissions and other data from petroleum refineries to ARB, ex cept as otherwise provided in this section. Petroleum refinery operators and refiners are considered separate reporting entities for the purposes of this article. (a) CO 2 from Fossil Fuel Combustion. When calculating CO 2 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. CO 2 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 mod ified 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 cas es 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 imp lement daily sampling and analysis no later than January 1, 2013. (d) Calculating CO 2

from Flares. For periods of normal flare operation, the operat or must use Equation Y-1a, Y-1b, or Y-2 as specified i n 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 parame ters required by Equations Y1a, Y-1b, or Y-2, the operator must determine the q uantity of gas discharged to theLegal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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California Air Resources Board 121 February 2015 flare separately for each SSM, and calculate the CO 2 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 e quation below are defined as they are for Equation Y-3 in 40 CFR §98.253(b)(iii)(C).

(e) Calculating CO 2

from FCCUs and Fluid Coking. The requirements of 40 CFR §98.253(c)(2) apply under this article regardless o f the rated capacity of a fluid catalytic cracking unit or a fluid coking unit. Th e operator may not use Equation Y-8 or the option provided under 40 CFR §98.253(c)(3) f or units with rated capacities of 10,000 barrels per stream day or less. (f) Uncontrolled Blowdown Systems. When calculating CH 4 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 equati on specified in section 95113(d), the operator reporting data under the req uirements 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 Un its. When the operator has calculated CO 2 from fluid catalytic cracking units or fluid cokin g 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 Blowdo wn Systems. When the operator has calculated CH 4 from uncontrolled blowdown systems consistent with section 95113(g), the operator must report the info rmation 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 o f CO 2 , N 2 O and CH 4 are determined to be below the thresholds in 40 CFR §98 .253(j), the operator must maintain records of the method used to determine th e CO 2 , N 2 O, and CH 4 concentrations, and all supporting documentation ne cessary to demonstrate that the thresholds in 40 CFR §98.253(j) are not exceede d during the data year pursuant to the record keeping requirements of sect ion 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 re ported under section 95115 of this article (stationary combustion units and units using continuous emissions



## ( ) 

# [ ]        

× × × × × = 

# ∑

= n

1p p p p SSM 2 CC MVC / MW Flare 12/ 44 001 .0 98.0 COLegal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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monitoring systems), the operator must follow the r equirements of section 95129 of this article. (2) For all other data required for emissions calcu lations 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 a vailable 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 substi tute for each missing value with the highest quality assured value record ed for the parameter during the given data year, as well as the two prev ious data years. (C) If the analytical data capture rate is less tha n 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 componen t that was produced elsewhere and brought on-site. Liquid products mus t 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 du ring the data year. Sales data may be used to report quantities of primary re finery product and blending component produced elsewhere and brought on-site. For each primary refinery product and blending component that was pr oduced 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 b rought on-site may not be included in the reported on-site production quan tity of primary refinery product, unless the reporter has identified that th e quantity of primary refinery product or blending component that is produced else where 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 Ta ble MM-1 of 40 CFR Part 98 (standard cubic feet for gaseous products, barrels for liquid products, shortLegal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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tons for solid products). These products will not be subject to review for material misstatement under the requirements of sec tion 95131(b)(12). Primary products will be evaluated for conformance and assessment of material misstatement through 2014 data year verifi cations. Beginning with 2015 data reported in 2016, primary refinery produc ts will be evaluated for conformance only and will not be evaluated for mate rial misstatement. (4) Energy Intensity Index . For refineries that participate in the Solomon En ergy Reviews, the operator must report its most current Solomon EII values for the applicable data year. Each refinery operator must d emonstrate 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 sec tion using the appropriate units listed in column 3 of Table 1 of this section. Reported throughputs based on feed must include only fresh f eed and exclude recycled streams. The coke-on-catalyst volume perc ent also must be reported for each catalytic cracking unit. Beginni ng 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 calcula ted according to the following formula.

  =  
 +   +  			 Where CWB Total

is the total complexity weighted barrels for a petroleum refinery, and CWB Process , CWB Off-Sites

, and CWB Non-Crude

Sensible Heat

must be calculated as follows:

CWB Process

= ∑ ( CWB Factor

x Throughput

)

CWB Off-Sites = (0.327) x ( Total Refinery Input in thousands of barrels per year) + (0.0085) x ( CWB Process )

CWB Non-Crude Sensible Heat = (0.44) x ( Non-Crude Input in thousands of barrels per year) In these equations, CWB Factor 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 repo rted pursuant to section 95113(l)(3)(A). Total Refinery Input and Non-Crude Input

are the annual volumes of raw materials as defined in secti on 95102(c). Total Refinery Input and Non-Crude Input must each be rep orted in units of thousands of barrels per year and must exclude hydr ogen, natural gas, and any input to a hydrogen production plant. (C) Correction to CWB Factor for Fluid Catalytic Cracking . The following equation must be used to adjust CWB Factor for Fluid Catalytic Cracking (FCC) units and mild residual FCC units that result in coke on theLegal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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catalyst:

 
, =  
 + ! × #$

Where:

CWB Factor, FCC

= The corrected CWB factor used to calculate the contribution to CWB Process for a fluid catalytic cracking unit.

CWB Factor

= The uncorrected CWB factor for a catalytic cracking unit from Table 1 of this section.

A = The coke-on-catalyst factor for a fluid catalyti c 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)/(Volu me of fresh feed to the FCC) (D) Density. In cases where a density measurement is needed fo r purposes of converting a throughput from barrel to mass unit s, the following applies: 1. For a throughput with a known density, utilize t he applicable default value from Section 3-1, Physical Constants of Organ ic Compounds, of the CRC Handbook of Chemistry and Physics, CRC P ress Inc., Boca Raton 83 rd 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 fu nction. For 2014 data reported in 2015, postponement requests for a CWB meter or device pursuant to sections 95103(k)(8)-(9) must be receiv ed by the 2014 reporting deadline in section 95103(e) instead of t he timeframe in section 95103(k)(9)(A). (m) The operator must report the quantity of: (1) CARBOB produced and imported, as defined by “Ca lifornia reformulated gasoline blendstock for oxygenate blending” in sect ion 95202 of the AB 32 Cost of Implementation Fee Regulation, for use in C alifornia and the designated volume of oxygenate associated with the reported CARBOB; (2) Finished California gasoline produced and impor ted, as defined by “California gasoline” in section 95202 of the AB 32 Cost of Imp lementation Fee Regulation, for use in California; and (3) California Diesel produced and imported, as def ined by “California diesel” in section 95202 of the AB 32 Cost of Implementation F ee Regulation, for use inLegal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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California and the volume of biodiesel and/or renew able diesel associated with the reported fuels.

Table 1. CW

B 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, S tandard 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

- on

Catalyst 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

- on

Catalyst 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 Hydrocrack ing (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

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California Air Resources Board 126 February 2015 Conventional Naphtha

Hydrotreating

Diolefin to Olefin Saturation of

Gasoline

FCC gasoline hydrotreating wit h

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

Ultr a

- 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

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California Air Resources Board 127 February 2015 C4 Isomer Production Feed thousands of barrels/year 1.25 615/644 C4 Isomerizatio n

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

Hydrodea lkylation 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 Di stillation

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 Multi

fraction 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

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Hydrofining Feed thousands of barrels/year 1.15 Lube Hydrofinishing with Vacuum
Stripper

Lube Hydrotreating with Multi

Fraction 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 Green house Gas

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California Air Resources Board 129 February 2015 § 95114. Hydrogen Production.

The operator of a facility who is required to repor t under section 95101 of this article, and who is not eligible for abbreviated reporting u nder section 95103(a), must comply with Subpart P of 40 CFR Part 98 (40 CFR §§98.160 t o 98.168) in reporting emissions and other data from molecular hydrogen production t o ARB, except as otherwise provided in this section. GHG emissions and output associated with hydrogen production must be reported separately from other e missions 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 furthe r defined as a hydrogen production source that produces molecular hydrogen whether sold to other entities or consumed on-site. (b) CO 2 from Fossil Fuel Combustion . When calculating CO 2 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 mod ified in sections 95114(h), 95115, and 95129 of this article. (d) CO 2 Process Emissions. When calculating CO 2 under the fuel and feedstock material balance approach specified at 40 CFR §98.1 63(b), the operator must apply the weighted average carbon content values obtaine d (the term CC n in Equations P-1 through P-3) according to the frequencies speci fied 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 wei ghted average carbon content, atomic hydrogen content (excluding hydroge n atoms contained in steam), and molecular hydrogen content from the results of one or more analyses for month n for natural gas or a stan dardized fuel or feedstock specified in Table 1 of section 95115, or from monthly analysis for other gaseous fuels and feedstocks such as refi nery fuel gas; (B) For liquid feedstock the operator must use weig hted average carbon content and atomic hydrogen content from the result s of one or more analyses for month n for a standardized fuel or fee dstock 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 Green house Gas

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(C) For solid feedstock the operator must use weigh ted average carbon content and atomic hydrogen content from the result s 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 CO 2 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 s uch as refinery fuel gas. (B) When reporting CO 2 emissions for liquid fuel and feedstock, the opera tor must use a weighted average carbon content from the results of one or more analyses for month n for a standardized fuel o r feedstock specified in Table 1 of section 95115, or from daily sampling for month n for other liquid fuels or feedstocks. Daily liquid samples ma y be combined to generate a monthly composite sample for carbon anal ysis. (C) When reporting CO 2 emissions for solid fuel and feedstock, the operat or must use the weighted average carbon content from t he results of monthly sampling for month n for a standardized fue l or feedstock specified in Table 1 of section 95115, or from dail y sampling for month n for other solid fuels and feedstock. Daily solid sa mples may be combined to generate a monthly composite sample for carbon a nalysis. (f) Weighted Average Sampling. Where this section requires sampling of a paramet er on a more frequent basis than 40 CFR Part 98, the o perator or supplier must comply with the following: (1) The samples must be spaced apart as evenly as p ossible over time, taking into account the operating schedule of the relevant unit or facility. (2) The operator or supplier must calculate and rep ort a weighted average of the values derived from the samples by using the follow ing formula:

Where: V E = 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

M V

V

1

1 ) (Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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V j = The value of the sample for period j. M j = The mass of the sampled material processed or ot herwise used by the relevant unit or facility in period j. (3) The operator or supplier must keep records of t he date and result for each sample or composite sample and mass measurement use d in the equation above and of the calculation of each weighted avera ge included in the emissions data report, pursuant to the record keepi ng 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 fa cility using other calculation methods provided in this regulation (e.g., carbon i n waste diverted to a fuel system or flare, where the CO 2 and CH 4 emissions are calculated and reported using other methods specified in this regulation). To avoid do uble-counting, these emissions must be subtracted from the total facility emission s. (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 re ported under section 95115 of this article (stationary combustion units and units using continuous emissions monitoring systems); the operator must follow the r equirements of section 95129 of this article. (2) For all other data required for emissions calcu lations 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 a vailable 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 substi tute for each missing value with the highest quality assured value record ed for the parameter during the given data year, as well as the two prev ious data years. (C) If the analytical data capture rate is less tha n 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 CO 2

. The operator must calculate and report the mass of all CO 2 captured, transferred off-site, and reported by the hydrogen production facility as a supplier of CO 2 using reporting provisions found in section 95123. Refineries and hydrogen production facilities must subtract this r eported mass of CO 2 that is captured and sold or transferred off-site from thei r facility emissions report to avoid double counting.Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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California Air Resources Board 132 February 2015 (j) Additional Product Data. Operators must report the annual mass of hydrogen g as produced (metric tons) and liquid hydrogen sold (me tric tons). For hydrogen gas produced, annual masses of on-purpose hydrogen gas and by-product hydrogen gas produced must be reported (metric tons). Opera tors must also specify if the hydrogen plant is an integrated refinery operation. Operators must report all hydrogen sold or otherwise transferred to another f acility and include the purchaser (or receiver) and quantity sold or transferred to e ach 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 re spectively), and CH 4 and N 2 O from fuel stationary combustion sources as set-fort h in 40 CFR §98.33(c). (l) Hydrogen producers shall use the methodology f ound in section 95113(d) to calculate and report CO 2 , CH 4 , and N 2 O 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 repor t under section 95101 of this article, and who is not eligible for abbreviated reporting u nder 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, excep t as otherwise provided in this section. (a) CO 2 from Steam Producing Units. The operator of a steam producing unit combusting municipal solid waste or solid biomass f uels 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 combus ting fossil-based solid fuels must select applicable Tier 3 or Tier 4 methods. (b) CEMS CO 2

Monitoring. Notwithstanding the allowed use of oxygen concent ration monitors in 40 CFR §98.33(a)(4)(iv), an operator in stalling a continuous emissions monitoring system that includes a stack gas volumet ric flow rate monitor after January 1, 2012, and who reports CO 2 emissions using this system, must install and use a CO 2 monitor. An operator without a CO 2 monitor who uses a CEMS and O 2 concentrations to calculate and report a unit’s CO 2 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 CO 2 concentration and flow, and the calculation of CO 2 mass per hour. The operator must retain these res ults pursuant to the recordkeeping requirements of section 95105 and mak e them available to ARB upon request. The requirements of this paragraph d o not apply to facilities for which pipeline natural gas is the only fuel consume d. (c) Choice of Tier for Calculating CO 2 Emissions. Notwithstanding the provisions of 40 CFR §98.33(b), the operator’s selection of a method for calculation of CO 2Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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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 s elect a higher tier than that required for the fuel type or unit size as specifie d below. (1) The operator may select the Tier 1 or Tier 2 ca lculation method specified in 40 CFR §98.33(a) for any fuel listed in Table 1 of thi s 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 th ese emissions are not subject to a compliance obligation under the cap-an d-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 qu ality as defined in section 95102 of this article, and for distillate fuels lis ted in Table 1 of this section. Tier 1 may be selected when the fuel supplier is pr oviding 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 specifi ed 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 pro viding less than 10 percent of the annual heat input to a unit with a maximum rate d 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 oth er fuel, including nonpipeline quality natural gas and fuel with emission s identified as non-exempt biomass-derived CO 2 , subject to the limitations of 40 CFR §98.33(b)(4) -(5) requiring use of the Tier 4 method. The operator u sing Tier 3 must determine annual average carbon content with weighted fuel us e 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 a s the number of lots received in the year. (d) Source Test Option for N 2 O and CH

4

. In lieu of other methods specified in this article, a facility operator may conduct site-speci fic source testing to derive emission factors and determine annual emissions of N 2 O or CH 4 from any combustion source. Alternatively, the operator may use the re sults of an applicable test method specified in title 17, California Code of Regulatio ns, section 95471. For source testing: (1) The facility operator must submit to the Execut ive Officer a test plan at least 45 days prior to the first test date. The test pla n must provide for testing at least annually, and more frequently as needed to ac count for seasonal variations in fuels or processes. (2) The plan must specify conduct of performance an d stack tests consistent with the requirements of approved ARB or U.S. EPA test m ethods. Process ratesLegal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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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 not ified at least ten days in advance of subsequent tests. (e) Procedures for Biomass CO 2 Determination. Reporting entities must use the following procedures when calculating emissions fro m 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 fo llow the procedures specified in 40 CFR §98.33(e)(3) to specify a bioma ss fraction. (2) For the analysis conducted under the requiremen ts of 40 CFR §98.34(e) for partially biogenic fuels other than MSW, the operat or may choose to analyze monthly fuel samples. The operator must collect su ch samples weekly and combine a portion of each weekly sample to form a m onthly composite mixture. The monthly composite mixture must be hom ogenized and well mixed prior to withdrawal of a sample for analysis. (3) When calculating emissions from a biomethane an d natural gas mixture as described in 40 CFR §98.33(a)(2) using the annual M MBtu 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:

E biomass =EF natural	gas ×MMBtu biomethane ×0.001

Where: E biomass = The annual biomass CO 2 , CH 4 or N 2 O emissions from biomethane (metric tons) E natual gas = The annual fossil CO 2 , CH 4 or N 2 O emissions from natural gas (metric tons) EF natural gas = The natural gas emission factor from Tables C-1 a nd C-2 of 40 CFR Part 98 (kg/MMBtu) MMBtu annual = The total delivered MMBtus for the reporting ye ar based on utility bills or meters meeting the accura cy requirements of section 95103(k) MMBtu biomethane = 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 an d 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 calcul ate the biomethaneLegal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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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 na tural gas mixture using 40 CFR §98.33(a)(4) or the carbon content method descr ibed in 40 CFR §98.33(a)(3), or when calculating those emissions a ccording 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 sampl es to conduct the monitoring analyses required under 4 0 CFR §98.34 must sample at the frequencies specified in that section, except i n the following cases. (1) Natural gas that is outside the range of pipeli ne 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 wher e equipment necessary to perform daily sampling and analysis of carbon conte nt and molecular weight for refinery fuel gas is not in place, such equipme nt must be installed and procedures established to implement daily sampling and analysis no later than January 1, 2013. (3) The operator is estimating CO 2 emissions using a CEMS under 40 CFR §98.33(a)(4). (g) Fuel Use for CEMS Units. The operator who estimates and reports CO 2 emissions using a CEMS under 40 CFR §98.33(a)(4) must also re port the quantity of each type of fuel combusted in the unit or group of unit s (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 b iomass-derived solids. Fuel use monitoring devices for units covered under this par agraph are exempt from the provisions of section 95103(k) of this article. (h) Aggregation of Units. Facility operators may elect to aggregate units a ccording to 40 CFR §98.36(c), except as otherwise provided in t his paragraph. Facility operators that are reporting under more than one so urce 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 s ource categories. For the purpose of unit aggregation, units subject to 40 CF R 98 Subpart C that are associated with one source category must not be gro uped with other Subpart C units associated with another source category, exce pt 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: boil er, reciprocating internal combustion engine, turbine, process heater, and oth er (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 a ccording to the common stack provision in 40 CFR §98.36(c)(2) may report emissio ns according to 40 CFR §98.36(c)(2), but they must separately report the f uel use by fuel type as aLegal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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California Air Resources Board 136 February 2015 percentage of the aggregated fuel consumption attri buted 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 elsewher e 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 emis sions from pilot lights in the emissions data report when operated 300 hours or mo re in the data year. The operator may apply appropriate methods from 40 CFR §98.33 or engineering methods to calculate these emissions when pilot lig hts 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 dev ice calibration requirements of section 95103, but pilot light emissions calculatio ns are subject to verification. (j) Electricity Generating and Cogeneration Units. The operator of a facility that includes electricity generating and cogeneration un its meeting the applicability criteria of section 95101 must meet the requirement s 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) o f the supplier(s) of natural gas to the facility, the operator’s natural gas supplie r customer account number(s), natural gas supplier service account identification number(s) or other primary account identifier(s), and the annual MMBtu deliver ed to each account according to billing statements (10 therms = 1 MMBtu), and if th e 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 ac count identification number, but may report the annual MMBtu delivered based on the seller’s billing statement. (l) Information on Natural Gas Supplied to Downstream U sers . 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 rep orted under section 95115 of this article, the operator m ust follow the requirements of section 95129. (n) Additional Product Data. Operators of the following types of facilities mu st also report the production quantities indicated below. (1) The operator of a facility engaged in hot rolli ng and/or cold rolling of steel must report the quantity of hot rolled steel sheet, pick led steel sheet, cold rolled and annealed steel sheet, galvanized steel sheet, and t in plate produced in the data year (short tons). For cold rolled and anneale d steel sheet, the operator must also report a description of the process used to produce the products, such as continuous annealing process or batch annea ling.Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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California Air Resources Board 137 February 2015 (2) The operator of a soda ash manufacturing facili ty must report the quantity of soda ash, biocarb, borax, V-Bor, DECA, PYROBOR, bor ic 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 t he 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 m ust report the quantity of whole chicken and chicken parts, poultry deli products, a nd protein meal and fat produced in the data year (short tons). (6) The operator of a facility that manufactures de hydrated flavors must report the production of dehydrated onion, dehydrated garlic, dehydrated chili peppers, dehydrated parsley, and dehydrated spinach in the d ata 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 faci lity must report the production of fried potato chips, baked potato chips, corn chi ps, 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 to ns) (10) The operator of a tomato processing facility m ust 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 (sh ort 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 processin g of rare earth minerals must report the production of rare earth oxide equivalen ts in the data year (short tons). (14) The operator of a facility mining or processin g 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 to ns). (16) The operator of a dairy product facility must report the production of milk, buttermilk, skim milk, cream, butter, condensed mil k, buttermilk powder,Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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intermediate dairy ingredients, dairy product solid s 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 produc tion. Buttermilk powder and nonfat dry milk and skimmed milk powder that is re-constituted and reintroduced to the manufacturing process may be repo rted as production. The operator must report the production of total WPC an d WPC with high protein concentration using diafiltration process during th e data year (short tons). The operator must also report the amount of imported pr otein. (17) The operator of an almond or pistachio process ing 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 fla vored and dried (short tons) where flavoring and drying is a continuous pr ocess. (18) The operator of a wet corn milling facility mu st report the production of corn entering wet milling process during the data year ( short tons). (19) The operator of a winery must report the produ ction of distilled spirits (proof gallons), dry color concentrate (short tons), grape juice concentrate (gallons), grape seed extract (short tons), and liquid color c oncentrate (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 CO 2 Emission Factor

MMBtu/gallon kg CO 2 /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

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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 repor t under section 95101 of this article, and who is not eligible for abbreviated reporting u nder section 95103(a), must comply with Subpart N of 40 CFR Part 98 (§§98.140 to 98.14 8) in reporting stationary combustion and process emissions and related data f rom glass production to ARB, except as otherwise provided in this section.

(a) CO 2 from Fossil Fuel Combustion. When calculating CO 2 emissions from fuel combustion, the operator must use a method in 40 CF R §98.33(a)(1) to §98.33(a)(4) as specified by fuel type in section 9 5115 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 mod ified 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 oth erwise provided in paragraphs (1)-(3) below. (1) To substitute for missing data for emissions re ported under section 95115 of this article (stationary combustion units and units using continuous emissions monitoring systems), the operator must follow the r equirements of section 95129 of this article. (2) For each missing value of the monthly amounts o f carbonate-based raw materials charged to any continuous glass melting f urnace, the operator must apply a substitute value according to the procedure s 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 acc ording to 40 CFR §98.145(a). (B) If the data capture rate is less than 80 percen t for the data year, the operator must substitute for each missing value wit h the maximum short tons per day raw material capacity of the continuou s glass melting furnace. (3) The operator must document and retain records o f the procedure used for all missing data estimates pursuant to the recordkeepin g 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 Green house Gas

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California Air Resources Board 140 February 2015 below whether or not a CEMS is used to measure CO 2 emissions. (1) The operator of a flat glass manufacturing faci lity 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 faci lity 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 repor t under section 95101 of this article, and who is not eligible for abbreviated reporting u nder section 95103(a), must comply with Subpart S of 40 CFR Part 98 (§§98.190 to 98.19 8) in reporting stationary combustion and process emissions and related data f rom lime manufacturing to ARB, except as otherwise provided in this section. (a) CO 2 from Fossil Fuel Combustion. When calculating CO 2 emissions from fuel combustion, the operator must use a method in 40 CF R §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 mod ified 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 re ported under section 95115 of this article (stationary combustion units and units using continuous emissions monitoring systems), the operator must follow the r equirements 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 operat or 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 usi ng the best available estimate of the parameter, based on all available p rocess data for the reporting year.Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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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 y ears. (C) If the data capture rate is less than 80 percen t for the data year, the operator must substitute for each missing value wit h the highest quality assured value recorded for the parameter in all rec ords 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 acc ording to 40 CFR §98.195(a). (B) If the data capture rate is less than 80 percen t for the data year, the operator must substitute for each missing value wit h the maximum capacity of the system. (4) The operator must document and retain records o f the procedure used for all missing data estimates pursuant to the recordkeepin g 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 (sh ort tons). (e) Produced CO 2

Used On-Site . If a CEMS is not used to measure CO 2 emissions, the facility operator shall report data required by 40 CFR §98.196(b)(17), with the clarification that the referenced annual amount of CO 2 captured for use in the onsite process, reflects CO 2 process emissions generated by the facility that a re not released to the atmosphere. The produced CO 2 emissions must be computed as specified in 40 CFR §98.193(b)(2). The method used to determine the amount of CO 2 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 e valuation of the relative quantities of reactants and products in the lime pr oduction and CO 2 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 Green house Gas

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California Air Resources Board 142 February 2015 § 95118. Nitric Acid Production.

The operator of a facility who is required to repor t under section 95101 of this article, and who is not eligible for abbreviated reporting u nder section 95103(a), must comply with Subpart V of 40 CFR Part 98 (§§98.220 to 98.22 8) in reporting stationary combustion and process emissions and related data f rom nitric acid production to ARB, except as otherwise provided in this section. (a) CO 2 from Fossil Fuel Combustion. When calculating CO 2 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 modifi ed 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 re ported under section 95115 of this article (stationary combustion units and units using continuous emissions monitoring systems), the operator must follow the r equirements of section 95129 of this article. (2) For each missing value of nitric acid productio n used to calculate emissions pursuant to 40 CFR §98.223, the operator must subst itute 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 tha n 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 da ys per month. (3) The operator must document and keep records of the procedures used for estimating missing data pursuant to the recordkeepi ng requirements of section 95105. (d) Additional Product Data. The operator of a nitric acid manufacturing facilit y must report the annual production of nitric acid (HNO 3 ) 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 Green house Gas

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California Air Resources Board 143 February 2015 § 95119. Pulp and Paper Manufacturing.

The operator of a facility who is required to repor t under section 95101 of this article, and who is not eligible for abbreviated reporting u nder 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 f rom pulp and paper manufacturing to ARB, except as otherwise provided in this sectio n. (a) CO 2 from Fossil Fuel Combustion. When calculating CO 2 emissions from fossil fuel combustion in a chemical recovery furnace at a kraf t or soda facility under 40 CFR §98.273(a)(1), a chemical recovery unit at a sulfit e or stand-alone semichemical facility under 40 CFR §98.273(b)(1), a pulp mill li me kiln at a kraft or soda facility under 40 CFR §98.273(c)(1), or other stationary fue l combustion sources, the operator must use a method in 40 CFR §98.33(a)(1) t o §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 sect ions 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 pr ovided in paragraphs (1)-(3) below. (1) To substitute for missing data for emissions re ported under section 95115 of this article (stationary combustion units and units using continuous emissions monitoring systems), the operator must follow the r equirements of section 95129 of this article. (2) For each missing value for the use of makeup ch emicals (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 acc ording to 40 CFR §98.275(c). (B) If the data capture rate is less than 80 percen t for the data year, the operator must substitute for each missing value wit h the maximum metric tons per day capacity of the system. (3) The operator must document and retain records o f the procedure used for all missing data estimates pursuant to the recordkeepin g 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 Green house Gas

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California Air Resources Board 144 February 2015 delicate task wipers, and/or paper towels). The op erator producing tissue products must also report: (1) A description of the process used to produce ti ssue, such as through use of an air dryer. (2) Water absorption capacity of each bathroom tiss ue product with a distinct water absorption capacity manufactured in the data year, measured at least once during the data year using the methodology spe cified by ISO 12625- 8:2010, except the humidity and temperature conditi ons, which shall be 50% relative humidity ±2%, and 23 degrees C ±1 degree C , respectively.

(3) For bathroom tissue, material misstatement shal l be assessed using the following equation:

Material misstatement for bathroom tissue = : #  ! 

;<

Where: Oi = annual product output in air dried saleable ton f or 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 sha ll 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 repor t under section 95101 of this article, and who is not eligible for abbreviated reporting u nder section 95103(a), must comply with Subpart Q of 40 CFR Part 98 (40 CFR §§98.170 t o 98.188) in reporting stationary combustion and process emissions and related data f rom iron and steel production to ARB, except as otherwise provided in this section. (a) CO 2 from Fossil Fuel Combustion. When calculating CO 2 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 areLegal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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California Air Resources Board 145 February 2015 specified in 40 CFR §98.34 to §98.37, except as mod ified 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 re ported under section 95115 of this article (stationary combustion units and units using continuous emissions monitoring systems), the operator must follow the r equirements 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 procedur e in 40 CFR §98.173(b)(1), the operator must apply substitute v alues 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 bas ed on the best available estimate based on information used for ac counting purposes (such as purchase records). (B) If the data capture rate is less than 80 percen t for the data year, the operator must substitute for each missing value wit h the maximum throughput capacity of the system. (3) The operator must document and retain records o f the procedure used for all missing data estimates pursuant to the recordkeepin g requirements of section 95105. (d) Additional Product Data. In addition to the in formation required by 40 CFR §98.176, the operator must report the annual production of i ron and steel products in short tons, a description of the product(s), and, the pro cess 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 Green house Gas

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California Air Resources Board 146 February 2015 § 95121. Suppliers of Transportation Fuels.

Any position holder, refiner, enterer, or biofuel p roduction facility who is required to report under section 95101 of this article must com ply 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 CO 2 emissions specified under 40 CFR §98.392, all refi ners that produce liquefied petroleum gas must report th e CO 2 , CH 4 , N 2 O and CO 2 e emissions that would result from the complete combu stion 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 im port transportation fuels outside the bulk transfer/terminal system, and biof uel production facilities that produce and deliver biomass-derived fuels outside t he bulk transfer/terminal system in California must report the CO 2 , CO 2 from biomass-derived fuels, CH 4 , N 2 O, and CO 2 e emissions that would result from the complete combustion or oxidation of each Blendstock, Distill ate Fuel Oil or biomassderived fuel (Biomass-Based Fuel and Biomass) liste d in Table 2 of this section. However, reporting is not required for fu el in which a final destination outside California or where a use in exclusively av iation or marine applications can be demonstrated. No fuel shall be reported as finished fuel. Fuels must be reported as the individual Blendstock, Distillat e Fuel Oil or biomass-derived fuel listed in Table 2 of this section. For purpos es of this article, CARBOB blendstocks are reported as RBOB blendstocks. (b) Calculating GHG emissions. (1) Refiners, position holders at California termin als, enterers that import fuel outside the bulk transfer system, and biofuel produ ction facilities who produce and deliver fuel outside the bulk transfer/termina l system in California must use Equation MM-1 as specified in 40 CFR §98.393(a) (1) to estimate the CO 2 emissions that would result from the complete combu stion of the fuel. Emissions must be based on the quantity of fuel rem oved from the rack (for refiners and position holders), fuel imported or pr oduced and not delivered to the bulk transfer/terminal system (by enterers and biofuel production facilities), and fuel sold to unlicensed entities as specified i n section 95121(d)(3) (by refiners). For fuels that are blended, emissions m ust be reported for each individual Blendstock, Distillate Fuel Oil or bioma ss-derived fuel listed in Table 2 of this section separately, and not as motor gaso line (finished), biofuel blends, or other similar finished fuel. Emissions from denatured fuel ethanol must be calculated as 100% ethanol only. The volum e of denaturant is assumed to be zero and is not required to be report ed. Emission factors must be taken from column C of 40 CFR 98 Table MM-1 or M M-2 as specified in Calculation Method 1 of 40 CFR §98.393(f)(1), excep t that the emission factorLegal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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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 ho lder is the sole position holder at the terminal, the position holder must ca lculate 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 m ust use Equation MM-1 as specified in 40 CFR §98.393(a)(1) to estimate the C O 2 emissions that would result from the complete combustion of the fuel sup plied. For calculating the emissions from liquefied petroleum gas, the emissio ns from the individual components must be summed. Emission factors must b e taken from column C of 40 CFR Part 98 Table MM-1 as specified in Calc ulation Method 1 of 40 CFR §98.393(f)(1). (3) Refiners, position holders at California termin als, and enterers and biofuel production facilities that deliver fuel outside of the bulk transfer/terminal system must estimate and report CH 4 and N 2 O 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 CH 4 and N 2 O emission factors

Fuel CH 4 (g/bbl) N 2 O (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 estimat e CO 2 e emissions using the following equation:

Where: CO 2 e = Carbon dioxide equivalent, metric tons/year. GHG i = Mass emissions of CO 2 , CH 4 , N 2 O from fuels combusted or

oxidized. GWP i = Global warming potential for each greenhouse ga s 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 me et all the monitoring and i i n

1i 2 GWP

x GHG e CO 

## ∑

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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 951 03 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 receivin g the fuel have common ownership or are owned by subsidiaries or affiliate s of the same company. In such cases the 40 CFR §98.3(i) calibration requirem ents apply, unless: (A) The fuel supplier does not operate the fuel bil ling meter; (B) The fuel billing meter is also used by companie s that do not share common ownership with the fuel supplier; or (C) The fuel billing meter is sealed with a valid s eal 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 f uels that are liquid at 60 degrees Fahrenheit and one standard atmosphere, the volume reported must be temperature- and pressure-adjusted to these conditi ons. For liquefied petroleum gas the volume reported must be temperatu re-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 r eport the information identified below: (1) California position holders must report the ann ual quantity in barrels, as reported by the terminal operator, of each Blendsto ck, Distillate Fuel Oil, or biomass-derived fuel listed in Table 2 of this sect ion, that is delivered across the rack in California, except for fuel for which a final destination outside California can be demonstrated. Denatured fuel eth anol 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 report ed. (2) California position holders that are also termi nal operators and refiners must report the annual quantity in barrels delivered acr oss 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 destinat ion outside California can be demonstrated. Denatured fuel ethanol will be repor ted 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 sin gle position holder at the terminal, and only diesel or biodiesel is being dis pensed 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 inv oices from the entity delivering fuel to the terminal. (3) Refiners that supply fuel within the bulk trans fer system to entities not licensed by the California Board of Equalization as a fuel s upplier must report the annual quantity in barrels delivered of each Blends tock, Distillate Fuel Oil, or biomass-derived fuel listed in Table 2 of this sect ion, except for fuel for which a final destination outside California can be demon strated. Denatured fuelLegal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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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 n ot required to be reported. (4) Enterers and biofuel production facilities deli vering transportation fuels outside the bulk transfer/terminal system must report the a nnual quantity in barrels, as reported on the bill of lading or other shipping do cuments 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 outsi de California can be demonstrated. Denatured fuel ethanol will be repor ted 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 renewabl e 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 C FR §98.396, refiners must also report the volume of liquefied petroleum gas in bar rels 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 m ust also report CO 2 , CO 2 from biomass-derived fuels, CH 4 , N 2 O and CO 2 e emissions in metric tons that would result from the complete combustion or oxidat ion of each petroleum fuel identified in 95121(a)(2), liquefied petroleum gas, or biomass-derived fuel reported in this section, calculated according to s ection 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 bi odiesel and/or renewable diesel that was imported from outside of California for use in California. In addition, for CARBOB imports, the designated percen tage of oxygenate must be reported. (8) Fuel suppliers identified in this section, exce pt 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 u se in California. (e) Procedures for Missing Data. For quantities of fuels that are purchased, sold, or transferred in any manner, fuel suppliers must foll ow the missing data procedures specified in 40 CFR §98.395. The supplier must doc ument and retain records of the procedure used for all missing data estimates p ursuant to the recordkeeping requirements of section 95105.Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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California Air Resources Board 150 February 2015 Table 2 Blendstocks, Distillate Fuel Oils, and Biomass-Deri ved 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%)

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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 Liqu ids, 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 CO 2 emissions specified under 40 CFR §98.402(a), natur al gas liquid fractionators must report the CO 2 , CH 4 , N 2 O and CO 2 e emissions that would result from the complete combustion or o xidation of liquefied petroleum gas sold or delivered to others that was produced on-site, except for products for which a final destination outside Cali fornia can be demonstrated. (2) In addition to the CO 2 emissions specified under 40 CFR §98.402(b), local distribution companies including intrastate pipelin es delivering gas to California end-users must report the CO 2 , CO 2 from biomass-derived fuels, CH 4 , N 2 O, and CO 2 e emissions from the complete combustion or oxidati on of the annual volume of natural gas delivered to all e ntities on their distribution systems in California. (3) The California consignee for imported liquefied petroleum gas, compressed natural gas, or liquefied natural gas must report t he CO 2 , CH 4 , N 2 O and CO 2 e emissions that would result from the complete combu stion or oxidation of the annual quantity of liquefied petroleum gas, compres sed natural gas, and liquefied natural gas imported into the state, exce pt for products for which a final destination outside California can be demonst rated. (4) Operators of liquefied natural gas production f acilities that receive natural gas supply from interstate pipelines must report the CO 2 , CH 4 , N 2 O and CO 2 e emissions that would result from the complete combu stion or oxidation of all liquefied natural gas sold or delivered to others, except for product for which a final destination outside California can be demonst rated. (b) Calculating GHG Emissions. (1) Natural gas liquid fractionators must use calcu lation methodology 2 as specified in 40 CFR §98.403(a)(2) to estimate the C O 2 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 Tab le NN-2. For calculating the emissions from liquefied petroleum gas, the fra ctionators must sum the emissions from the individual constituents of lique fied petroleum gas sold or delivered to others that was produced on-site, exce pt for products for which a final destination outside of California can be demo nstrated.Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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California Air Resources Board 152 February 2015 (2) For the calculation of CO 2i in section 95122(b)(6), local distribution companie s must estimate CO 2 emissions at the state border or city gate for pip eline quality natural gas using calculation methodology 1 as specified in 40 CFR §98.403(a)(1), except that the product of HHV and F uel is replaced by the annual MMBtu of natural gas received. (3) For the calculation of CO 2j in section 95122(b)(6), public utility gas corporations and publicly owned natural gas utiliti es must estimate annual CO 2 emissions from instate receipts of pipeline quality natural gas from other public utility gas corporations, interstate pipelines and intrastate transmission pipelines, and annual CO 2 emissions from all natural gas redelivered to othe r public utility gas corporations or interstate pipel ines. Annual CO 2 emissions from redelivered natural gas to intrastate pipeline s or publicly owned natural gas utilities must be estimated only if emissions f rom the redelivered natural gas equals or exceeds 25,000 MTCO 2 e calculated according to subparagraph (2) above. Emissions are calculated according to E quation NN-3 of 40 CFR §98.403(b)(1) except that CO 2j will be the product of MMBtu Total and the default emission factor from Table NN-1 or the product of M MBtu Total and the reporter specific emission factor. MMBtu Total must be calculated as follows:

MMBtu =>?@A = MMBtu BCDCAEFCBG − MMBtu BCICEJ?K

Where MMBtu Total = Total annual MMBtu used in equation NN-3 MMBtu redelivery = Total annual MMBtu of natural gas delivered to ot her

companies as specified above MMBtu receipts = Total annual MMBtu of natural gas received from other

companies as specified above (4) For the calculation of CO 2l 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 stora ge are estimated according to Equation NN-5 of 40 CFR §98.403(b)(3) except that C O 2l will be calculated as the product of the net annual MMBtu and a default e mission factor from Table NN-1 or the product of the net annual MMBtu and a r eporter specific emission factor. (5) Determination of pipeline quality natural gas i s 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 pi peline, 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 §9 8.404(b)(2) or one determined as follows: (A) For natural gas or biomethane with an annual we ighted HHV below 970 Btu/scf and not exceeding 3% of total emissions est imated under thisLegal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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California Air Resources Board 153 February 2015

section, the local distribution company may use the reporter specific weighted yearly average higher heating value and th e default emission factor or an emission factor as determined in 40 CF R §98.404(c)(3). If emissions exceed 3% of the total, then the Tier 3 m ethod specified in 40 CFR §98.33(a)(3)(iii) must be used with monthly car bon 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 HH V above 1100 Btu/scf and not exceeding 3% of total emissions estimated u nder this section, the local distribution company must use the reporter sp ecific weighted yearly average higher heating value and a default emission factor of 54.67 kg CO 2 /MMBtu or an emission factor as determined in 40 CF R §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 b e used with monthly carbon content samples to calculate the annual emis sions from the portion of natural gas that is above 1100 Btu/scf. (6) When calculating total CO 2 emissions for California, the equation below must be used:

∑

− ∑

− ∑ = 2l 2j 2i 2 CO

CO CO CO

Where: CO 2 = Total emissions. CO 2i = Emissions from natural gas received at the state border or

city gate, calculated pursuant to section 95122 (b)(2). CO 2j = Emissions from natural gas received for redistr ibution to or

received from other natural gas transmission co mpanies, calculated pursuant to section 95122(b)(3). CO 2l = Emissions from storage and direct deliveries fro m producers

calculated pursuant to section 95122(b)(4). (7) Natural gas liquid fractionators and local dist ribution companies must estimate and report CH 4 and N 2 O emissions using equation C-8 and Table C-2 as described in 40 CFR §98.33(c)(1) for all fuels wher e annual CO 2 emissions are required to be reported by 40 CFR §98.406 and t his section. Local distribution companies must use the annual MMBtu de termined in paragraphs (2)-(4) above in place of the product of the Fuel a nd HHV in equation C-8 when calculating emissions. (8) Local distribution companies must separately an d individually calculate enduser emissions of CH 4 , N 2 O, CO 2 from biomass-derived fuels, and CO 2 e by replacing CO 2 in the equation in section 95122(b)(6) with CH 4 , N 2 O, CO 2 from biomass-derived fuels, and CO 2 e. CO 2 emissions from biomass-derived fuel are based on the fuel the LDC has contractually pur chased on behalf of and delivered to end users. Emissions from contractual ly purchased biomethane are calculated using the methods for natural gas re quired by this section, including the use of the emission factor for natura l gas found inLegal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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40 CFR§98.408, table NN-1. Biomass-derived fuels d irectly 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 §98.4 03(a)(2) for calculating CO 2 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 l iquefied petroleum gas, the consignee must sum the emissions from the individua l components of the gas to calculate the total emissions. If the compositi on 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 Calif ornia consignee for compressed natural gas or liquefied natural gas mus t estimate CO 2 using calculation methodology 1 as specified in 40 CFR §9 8.403(a)(1), except that the product of HHV and Fuel is replaced by the annu al MMBtu of the imported compressed natural gas and liquefied natural gas. (10) The California consignee for imported liquefie d petroleum gas, compressed natural gas, or liquefied natural gas must estimate and report CH 4 and N 2 O emissions using equation C-8 and Table C-2 as descr ibed in 40 CFR §98.33(c)(1). (11) Operators of liquefied natural gas production facilities described in section 95122(a)(4) must estimate CO 2 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 so ld or delivered in California. (12) Operators of liquefied natural gas production facilities described in section 95122(a)(4) must estimate and report CH 4 and N 2 O emissions based on the MMBtu of liquefied natural gas sold or delivered us ing 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 e stimate CO 2 e emissions using the following equation:

Where: CO 2 e = Carbon dioxide equivalent, metric tons/year. GHG i = Mass emissions of CO 2 , CH 4 , N 2 O from fuels combusted or

oxidized. GWP i = 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 a ll monitoring and QA/QC requirements specified in 40 CFR §98.404, except as modified in sections 95103, 95115, and below. i GWP x GHG e CO i

n

1i 2 

## ∑

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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 report er specific HHV at least monthly, or if the local distribution company does not make its own measurements according to standard business practic es it must use the delivering pipeline measurement. (3) All natural gas liquid fractionators must sampl e for composition at least monthly. (4) All California consignees of liquefied petroleu m gas must record composition, if provided by the supplier, and quantity in barrel s, corrected to 60 degrees Fahrenheit, for each shipment received. (d) Data Reporting Requirements. (1) For the emissions calculation method selected u nder section 95122(b), natural gas liquid fractionators must report, in addition t o the data required by 40 CFR §98.406(a), the annual volume of liquefied petroleu m gas, corrected to 60 degrees Fahrenheit, that was produced on-site and s old or delivered to others, except for products for which a final destination o utside California can be demonstrated. Natural gas liquid fractionators mus t report the annual quantity of liquefied petroleum gas produced and sold or del ivered to others as the total volume in barrels as well as the volume of the indi vidual components for all components listed in 40 CFR 98 Table MM-1. Fractio nators must also include the annual CO 2 , CH 4 , N 2 O, and CO 2 e mass emissions (metric tons) from the volume of liquefied petroleum gas reported in 40 CF R §98.406(a)(5) as modified by this regulation, calculated in accordan ce with section 95122(b). (2) For the emissions calculation method selected u nder section 95122(b), local distribution companies must report all the data req uired by 40 CFR §98.406(b) subject to the following modifications: (A) Publicly-owned natural gas utilities that repor t 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 M scf 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 o f natural gas in MMBtu associated with the volumes. (C) In addition to the requirements in 40 CFR §98.4 06(b)(8), local distribution companies must also include CO 2 , CO 2 from biomass-derived fuels, CH 4 , N 2 O, and CO 2 e annual mass emissions in metric tons calculated i n accordance with 40 CFR §98.403(a) and (b)(1) throug h (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 l ocal distribution companies, must report the annual volumes in Mscf, annual energy inLegal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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MMBtu, and the information required in 40 CFR §98.4 06(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 p ipelines must report the annual volumes in Mscf, annual energy in MMBtu, cus tomer information required in 40 CFR §98.406(b)(12), and ARB ID numbe r if available for all end-users registering supply equal to or greater th an 188,500 MMBtu during the calendar year. In addition to reporting the information specified in 40 CFR §98.406(b)(13), local distribut ion companies including intrastate pipelines that deliver to end users must report the annual energy in MMBtu delivered to the following e nd-use categories: residential consumers; commercial consumers; indust rial consumers; electricity generating facilities; and other end-us ers not identified as residential, commercial, industrial, or electricity generating facilities. Local distribution companies must also report the t otal 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 CO 2 , CO 2 from biomass-derived fuel, CH 4 , N 2 O, and CO 2 e emissions (metric tons) that would result from th e 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 C FR §98.3(c), the operator of an interstate pipeline, which is not a local distribut ion company, must report the customer name, address, and ARB ID along with annua l 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 C FR §98.3(c), the operator of an intrastate pipeline that delivers natural gas direc tly 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 i ntrastate pipeline operator must report the summed volumes (Mscf) and energy (M MBtu) of natural gas delivered to each entity receiving gas from the int rastate pipeline for purposes of estimating the CO 2i parameter as specified in section 95122(b)(6). Additionally, intrastate pipeline operators are req uired to estimate a value for CO 2j as specified in section 95122(b)(3) for natural ga s delivered to local distribution companies, interstate pipelines, and o ther intrastate pipelines. The CO 2l 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 C FR §98.3(c), the California consignee for liquefied petroleum gas must report t he annual quantity of liquefied petroleum gas imported as the total volum e in barrels as well as the volume of its individual components for all compone nts listed in 40 CFR 98Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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Table MM-1, if supplied by the producer, and report CO 2 , CH 4 , N 2 O, and CO 2 e annual mass emissions in metric tons using the calc ulation 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 impor ted, or delivered and sold, respectively, in MMBtu, and report CO 2 , CH 4 , N 2 O, and CO 2 e annual mass emissions in metric tons separately for compressed natural gas and liquefied natural gas using the calculation methods in sectio n 95122(b). (6) In addition to the information required in 40 C FR §98.3(c), all local distribution companies that report biomass emissions from biomet hane 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 d elivery, 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 operat or 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 r eport 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 t his section. (a) When reporting imported and exported quantities of CO 2 as required in 40 CFR §98.422, the supplier must report quantities of car bon dioxide imported into and exported from the State of California. Exports for purposes of geologic sequestration must be reported separately from expo rts 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 calculation s 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 usi ng the best available estimate of the parameter, based on all available p rocess 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 y ears.Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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(C) If the data capture rate is less than 80 percen t for the data year, the supplier must substitute for each missing value wit h the highest quality assured value recorded for the parameter in all rec ords kept according to section 95105(a). (D) The supplier must document and retain records o f the procedure used for all missing data estimates pursuant to the recordke eping 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 repor t under section 95101(a)(1)(B)(8.) of this article, and who is not eligible for abbreviat ed 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 rel ated data from lead production to ARB, except as otherwise provided in this section. (a) CO 2 from Fossil Fuel Combustion. When calculating CO 2 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 mod ified 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 re ported under section 95115 of this article (stationary combustion units and units using continuous emissions monitoring systems), the operator must follow the r equirements 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 proced ure in 40 CFR §98.183(b)(2), the operator must apply substitute v alues 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 Green house Gas

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(B) If the analytical data capture rate is less tha n 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 da ys per month. (3) The operator must document and keep records of the procedures used for estimating missing data pursuant to the recordkeepi ng requirements of section 95105. (d) Additional Product Data. The operator of a lead production, recycling, recov ery, or manufacturing facility must report production of le ad and lead alloys during the data year (short tons).

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Subarticle 3. Additional Requirements for Reported Data

§ 95129. Substitution for Missing Data Used to Calc ulate 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 reportin g 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 substi tuted 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 s ection for equipment breakdown, the operator may request approval of an interim data co llection procedure as specified in section 95129(h)-(i). For units combusting pure bi omass-derived fuels or for de minimis sources, the operator who is reporting emissions mu st 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 require ments of section 95129 does not relieve the operator from complying with other sect ions of this article. (a) Missing Data Substitution Procedures for Units Repo rting Under 40 CFR Part 75. The operator of a unit that is reporting CO 2 using 40 CFR Part 75 must follow the applicable missing data substitution procedures in Part 75 for CO 2 concentration, stack gas flow rate, fuel flow rate, high heat valu e, 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 CO 2 emissions, but do apply for CH 4 and N 2 O emissions that are not de minimis if data required for calculating CH 4 and N 2 O emissions are missing or invalid. (b) Missing Data Substitution Procedures for Other Unit s Equipped with CEMS. The operator of a stationary combustion unit who monito rs and reports emissions and heat input data for that unit under section 95115 o f this article using Tier 4 of Subpart C (40 CFR §98.33(a)(4)) must follow the app licable 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 qu ality assurance/quality control procedures in 40 CFR Part 60. Paragraphs (c) throu gh (h) of this section do not apply to units using Tier 4 for CO 2 emissions, but do apply for CH 4 and N 2 O emissions that are not de minimis if data required for calculating CH 4 and N 2 O emissions are missing or invalid. (c) Missing Data Substitution Procedures for Fuel Chara cteristic Data. When the applicable emissions estimation methods of this art icle require periodic collection of fuel characteristic data (including carbon content, high heat value, and molecular weight) the operator must demonstrate every reasona ble 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 m issing or invalid, the operator must first attempt to either reanalyze the original sample or perform the fuelLegal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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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 s ample, 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 char acteristic parameter:

Data capture rate = S / T x 100%

Where: S = Number of fuel samples for which valid fuel cha racteristic data were obtained according to the applicable sampling requi rements (including sampling schedule) T = Total number of fuel samples required by the ap plicable 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 a verage of the values of that parameter immediately preceding and immediately fol lowing 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 da ta report is due, the operator must use the “before” value for missing da ta 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 m ust 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 year s. (3) If the operator is unable to obtain fuel charac teristic 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 d ata point as follows: (A) If historical fuel characteristics data are av ailable 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 o f fuel for all records kept under the requirements of section 95105, or 2. The default value in Table 1 of this section (fo r 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 o r Table C-1 of 40 CFR Part 98, the operator must substitute the highe st 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 ch aracteristics data are not available and a default value is not listed in Tabl e 1 of this section, useLegal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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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 Consu mption Data. The operator subject to the requirements of this article must de monstrate every reasonable effort to obtain a total facility fuel consumption data ca pture rate of 100 percent for each year for each type of fuel. The total facility fue l consumption for the data year can be determined using any combination of meters and/o r other fuel measurement devices or methods that individually meet the accur acy 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 faci lity 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 e ach 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 facil ity (e.g., electrical load, steam production, operating hours, production output, or fuel consumption data at other measurement points), or use an applicable missing d ata substitution procedure from section 95129(d)(1)-(3). If during any time p eriods that the facility is in operation, a portion of the total facility fuel con sumption 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 quantit y for the missing data periods is reconstructed. If a source is eligible for more th an one procedure in section 95129(d)(1)-(3), the operator has the option to cho ose one of the applicable procedures in section 95129(d)(1)-(3). The require ments in section 95129(d)(1)-(3) are optional for sources that are not required to m eet 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 p rocedures in paragraph (d)(1): the sources combust gaseous or liquid fuels, produc e electrical or thermal output, use a fuel flowmeter system to continuously measure fuel flow rate; and are equipped with a data acquisition and handli ng system (DAHS) that continuously records fuel flow rates and measured e lectrical or thermal output on an hourly basis, which enables segregation of th e fuel flow rate data into bins. The operator of such sources that applies th e requirements in thisLegal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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paragraph must substitute missing fuel flow rate da ta 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 rat e, the operator must use the following procedures to account for the flow rate o f fuel combusted at the source for each hour during the missing data period . Before using these procedures, operators must establish load ranges fo r the affected sources using the procedures in paragraph (f) of this secti on. When load ranges are used for estimating missing fuel flow rate data, the operator must create and maintain separate fuel-spe cific databases for the source. The database for each type of fuel combust ed 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 m ust 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 t he missing data procedures in this paragraph, measured electrical output or therm al output must be available for the hour(s) in which fuel flow rate data are mi ssing. 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 fu el 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 lo ad range, the operator may combine available data with data from higher lo ad ranges if available until 720 hours are reached. If 720 hours of quali ty-assured fuel flow rate data are not available when combined with higher lo ad 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, th e 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 fu el flow rate(s) measured and recorded by a fuel flowmeter system at the corresponding operating source load range during th e previous 720 operating hours when the fuel for which the flow ra te 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 correspondi ng load range, data from higher load ranges if available may be combine d 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 operatorLegal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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must substitute the maximum potential fuel flow rat e for each hour of the missing data period. 2. If, during an hour in which different types of f uel are co-fired, qualityassured fuel flow rate data are missing for two or more of the fuels being combusted, apply the procedures in subparagra ph (d)(1)(B)1. separately for each type of fuel. 3. If the missing data substitution required in sub paragraphs (d)(1)(B)1-2 causes the reported hourly heat input rate based on the combined fuel usage to exceed the maximum rated hou rly heat input of the unit, adjust the substitute fuel flow rate v alue(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 r ecorded more than three years (26,280 clock hours) prior to the date and time of the missing data period, the operator must substitute the maxim um 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 f or 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 approp riate substitute data values. (2) Fuel Consumption Data Without Load Ranges. The sources that meet the following criteria are eligible to use the procedur es in this paragraph: the facility operator has established and implemented a fuel monitoring plan as a part of the GHG Monitoring Plan specified in sectio n 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 suffi cient for the application of the procedures in this paragraph. For operators tha t apply the requirements in this paragraph, whenever quality-assured fuel consu mption data are missing and there is no backup system available to record t he fuel consumption, the operator must use the procedures in this paragraph to account for the consumption of fuel combusted at the unit during th e missing data period. For fuels that are combusted less than 180 days in a ca lendar 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 r ecord fuel consumption at least weekly. The data capture rate for the data year must be c alculated as follows for each unit with missing fuel consumption data:

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Where: S = Number of fuel monitoring periods (e.g., days o r weeks) in the data

year for which valid measured fuel consumption data are available. Do not include fuel monitoring periods when the fue l 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 t ype 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 equ al to or greater than 95.0 percent during the data year, the operator mus t develop an estimate based on available process data that are r outinely measured and recorded at the unit (e.g., electrical load, steam production, operating hours) or fuel consumption da ta recorded at other upstream or downstream measurement points. 2. If the fuel consumption data capture rate is equ al 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 90 th percentile value of the fuel consumption data recorded for the data yea r 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 op erator must calculate substitute data as the 95 th 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 les s than 80.0 percent during the data year, the operator must apply as su bstitute data the maximum potential fuel consumption rate. (B) Multiple Fuels. For missing data periods that occur when two or mor e different types of fuel are being co-fired, the ope rator must provide substitute fuel flow rate data for each missing dat a period as follows: 1. If the fuel consumption data for a single fuel a re missing, provide substitute fuel consumption data for the missing da ta 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 95 129(d)(2)(A) (as applicable) separately for each type of fuel. 3. If the missing data substitution required in sec tion 95129(d)(2)(A) causes the reported heat input rate based on the co mbined fuel usage to exceed the maximum rated heat input of the source, adjust the substitute fuel consumption value(s) so that th e reported heat input rate equals the source’s maximum rated heat i nput.Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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California Air Resources Board 166 February 2015

(C) Prorating Substitute Value. When applying the procedures in subparagraphs (d)(2)(A)-(B), if an individual missi ng data period is shorter than the fuel consumption data monitoring p eriod, the operator must prorate the specified value for the fuel consu mption data monitoring period by the missing data period. For example, fo r a unit with a missing data period length of one day but weekly fuel consu mption monitoring schedule, the operator may divide the substitute va lue, estimated on a weekly basis, by the number of days the unit operat es in a week to obtain the substitute value for the missing data day. (3) Alternate Missing Data Procedure for Fuel Consumpti on Data. This paragraph applies to fuel combusting units that cannot use th e missing data procedures in paragraphs (d)(1) and (d)(2). If fuel consumpti on 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 arti cle 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 aggregate d-units level are available and meet the accuracy requirements of this article, the operator may estimate the missing unit-level fuel consumption data using avai lable process data that are routinely measured at the facility (e.g., electrica l load, steam production, operating hours) or fuel consumption data recorded at other upstream or downstream measurement points that meet the accurac y requirements of this article. (e) Missing Data Substitution Procedures for Steam Prod uction. The operator of a steam-producing unit who calculates and reports emi ssions using Equation C-2c in 40 CFR §98.33(a)(2) must apply the procedures in th is paragraph to substitute for missing steam production data, unless a backup syst em to record steam production is available. For sources for which steam producti on data are not used to calculate emissions, the operator may develop an estimate usi ng available process data that are routinely measured and recorded at the unit (e. g., electrical load, steam production, product output, operating hours) to est imate missing steam production. If hourly steam production data are not available a t the facility, the operator must record steam production data at least weekly and us e the weekly records for substituting the missing steam production data. Th e 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 cal culated 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, da ily, or weekly) with valid

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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 us ing available process data that are routinely measured and recorded at the uni t (e.g., electrical load, steam production, product output, and operating hou rs). (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 mus t calculate substitute data as the 90 th percentile value of the steam production data reco rded for the data year. (3) If the steam production data capture rate is le ss 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 sec tion 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 i n terms of percent of the maximum hourly average gross load of the unit, in g ross megawatts (MW). (Do not use integrated hourly gross load in MWh.) For a co generating 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 re corded separately, the operator must use the hourly gross steam load of the unit, i n 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 af ter 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 rang e 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. Whe n 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 ope rator 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 secti on. (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 951 29(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 propos ed load metric. At a minimum, the operator will have a system in place that elect ronically measures and records fuel consumption and load at least hourly. The alt ernate 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 y ears of fuel consumption and loadLegal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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California Air Resources Board 168 February 2015 data and may request up to the maximum years of dat a required to be retained under section 95105(a). (h) Procedure for Approval of Interim Fuel Analytic al 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 t o estimate emissions under this article, the Executive Officer may autho rize an operator to use an interim data collection procedure under the circums tances 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 el ement for the data year, and back-up sampling for affected fuel charac teristics is unavailable; (B) The affected monitoring equipment cannot be pro mptly repaired or replaced without shutting down a process unit signi ficantly affecting facility operations, or the monitoring equipment mu st 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 malfunct ioning monitoring equipment. (2) An operator seeking approval of an interim data collection procedure must, within sixty days of the monitoring equipment break down, submit a written request to the Executive Officer that includes all of the following: (A) The proposed start date and end date of the int erim procedure; (B) A detailed description of what data are affecte d by the breakdown; (C) A discussion of the accuracy of data collected during the interim procedure compared with the data collected under th e 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 proce dure, the Executive Officer shall determine whether the accuracy of data collec ted under the procedure is reasonably equivalent to data collected from proper ly functioning monitoring equipment, and if it is not, the relative accuracy to assign for purposes of assessing possible material misstatement under sect ion 95131 of this article. Data collected pursuant to an approved interim data collection procedure shall be considered captured data for purposes of complia nce with the capture rate requirements in this section.Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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California Air Resources Board 169 February 2015 (5) The Executive Officer shall provide written not ification to the operator of approval or disapproval of the interim data collect ion procedure within sixty days of receipt of the request, or within thirty da ys of receipt of any additional information requested by the Executive Officer, whi chever is later. (i) Procedure for Approval of Interim Data Collecti on 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 p ipeline 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 sati sfactorily demonstrate to the Executive Officer that: (A) The breakdown will result in a loss of more tha n 10 percent of the concentration, flow rate, or other information used to calculate and report annual emissions for the data year, and that back-u p monitoring is unavailable; (B) The affected monitoring equipment cannot be pro mptly repaired or replaced without shutting down a process unit signi ficantly affecting facility operations, or the monitoring equipment mu st 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 malfunct ioning monitoring equipment. (2) The operator must collect fuel samples and comp ly with all applicable requirements of the Tier 2 or Tier 3 Calculation Me thodology in 40 CFR §98.33(a)(2) or (3), as modified by section 95115 o f this article, during the equipment breakdown period. Fuel characteristics d ata provided by the fuel suppliers can be used if available. The operator m ust, within sixty days of the monitoring equipment breakdown, submit a written re quest to the Executive Officer that includes all the following information : (A) The proposed start date and end date of the int erim procedure, including a demonstration that the interim procedure will not remain in effect longer than is reasonably necessary for repair or replacem ent of the malfunctioning equipment; (B) A detailed description of what data are affecte d by the breakdown; and, (C) An interim monitoring plan that meets the requi rements of the Tiers 2 and 3 Calculation Methodologies as applicable by fuel t ype 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 Green house Gas

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California Air Resources Board 170 February 2015 (4) The Executive Officer shall provide written not ification to the operator of approval or disapproval of the interim data collect ion procedure within sixty days of receipt of the request, or within thirty da ys of receipt of any additional information requested by the Executive Officer, whi chever 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 Green house Gas

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California Air Resources Board 171 February 2015 Subarticle 4. Requirements for Verification of Gre enhouse Gas Emissions Data Reports and Requirements Applicable to Emissions Da ta Verifiers; Requirements for Accreditation of Emissions Data and Offset Proj ect 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 verify ing each emissions data report submitted under this article, as specified in secti on 95103(f). (a) Annual Verification. (1) Reporting entities required to obtain annual ve rification services as specified in section 95103(f) are subject to full verification r equirements in the first year that verification is required in each compliance pe riod. 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 y ears 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 bod y; (C) An adverse verification statement or qualified positive verification statement was issued for the previous year for eith er emissions data or product data, or both; (D) A change of operational control of the reportin g 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 instanc es where there are changes in sources or emissions. The verification body must provide information on the causes of the emission changes a nd justification in the verification report if a full verification was not conducted in instances where the total reported GHG emissions differ by gr eater than 25 percent relative to the preceding year’s emissions data rep ort. (2) Reporting entities subject to annual verificati on 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 Regis try; The Climate Registry; Climate Action Reserve; or other third-party verifi cations, validations, or audits conducted under impartiality provisions substantive ly equivalent to section 95133, which may include third-party certification of environmental management systems to the ISO 14001 standard or thi rd-party certification of energy management systems to the ISO 50001 standard . This limitation applies only to those third-party verifications, va lidations, or audits that includeLegal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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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 reporti ng entity first contracts for any third-party verifications, validations, or audi ts under any protocols, including ARB verification services, for the scope of activities or operations under the ARB identification number for the emissio ns data report, and ends on the date the final verification statement is sub mitted. Even if these services are provided before the verification body or verifi ers have received ARB accreditation, the six year period still begins whe n these services are contracted for, if accreditation is later received. The six year limit also applies to verification bo dies and verifiers providing ARB or any other third-party verifications, validations , or audits that include the scope of activities or operations under the ARB ide ntification number for the emissions data report and does not reset upon a cha nge 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 contr act 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 follo wing 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 A RB. The verification body may begin verification services for the reporting entit y ten working days after the notice is received by the Executive Officer, or earlier if ap proved by the Executive Officer in writing. In the event that the conflict of interes t statement and the notice of verification services are submitted together, verif ication services cannot begin until ten working days after the Executive Officer has de emed 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 p rovide verification services as a verification team, including the names of each desi gnated staff member, the lead verifier, and all subcontractors, and a descri ption of the roles and responsibilities each member will have during verif ication.Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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California Air Resources Board 173 February 2015 (2) Documentation that the verification team has th e 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 requi red below: (A) For providing verification services to an elect ric power entity, a supplier of petroleum products or biofuels, a supplier of natur al gas, natural gas liquids, or liquefied petroleum gas, or a supplier of carbon dioxide, at least one verification team member must be accredit ed by ARB as a transactions specialist; (B) For providing verification services to the oper ator of a petroleum refinery, hydrogen production unit or facility, or petroleum and natural gas system listed in section 95101(e), at least one verificati on team member must be accredited by ARB as an oil and gas systems special ist; (C) For providing verification services to the oper ator of a facility engaged in cement production, glass production, lime manufactu ring, pulp and paper manufacturing, iron and steel production, nitric ac id production, or lead production, at least one verification team member m ust be accredited by ARB as a process emissions specialist. (3) General information on the reporting entity, in cluding: (A) The name of the reporting entity and the facili ties 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 Indu stry Classification System (NAICS) code for the reporting facility; (C) The date(s) of the on-site visit, if required i n section 95130(a)(1), with facility address and contact information; (D) A brief description of expected verification se rvices 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 verificat ion body must notify ARB by submitting an updated conflict of interest self-eva luation form as soon as the change is made but at least five working days befor e the verification services start date. If any information submitted under sect ion 95131(a)(1) or 95131(a)(3) changes during the verification service s, the verification body must notify ARB . In either instance, the conflict of interest must be reevaluated pursuant to section 95133(f) and ARB mu st approve any changes in writing.Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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California Air Resources Board 174 February 2015 (b) Verification services shall include, but are no t limited to, the following : (1) Verification Plan . The verification team shall develop a verificati on plan based on the following: (A) Information from the reporting entity. Such inf ormation shall include:

1. Information to allow the verification team to de velop a general understanding of facility or entity boundaries, ope rations, emissions sources, product data, and electricity or fuel tran sactions as applicable; 2. Information regarding the training or qualificat ions of personnel involved in developing the emissions data report; 3. Description of the specific methodologies used t o quantify and report greenhouse gas emissions, product data, electricity and fuel transactions, and associated data as needed to deve lop the verification plan; 4. Information about the data management system use d 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 informati on shall include: 1. Dates of proposed meetings and interviews with r eporting facility personnel; 2. Dates of proposed site visits; 3. Types of proposed document and data reviews; 4. Expected date for completing verification servic es. (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 in itial verification services. The verification team shall review the documents su bmitted and plan and conduct a review of original documents and supporti ng data for the emissions data report. (3) Site Visits. At least one accredited verifier in the verificatio n 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 verificati on 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 conduc t the following:Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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(A) The verification team member(s) shall check tha t all sources specified in sections 95110 to 95123, and 95150 to 95157, as app licable to the reporting entity are identified appropriately. (B) The verification team member(s) shall review an d understand the data management systems used by the reporting entity to track, quantify, and report greenhouse gas emissions and, when applicabl e, product data, and electricity and fuel transactions. The verific ation team member(s) shall evaluate the uncertainty and effectiveness of these systems. (C) The verification team shall carry out tasks tha t, in the professional judgment of the team, are needed in the verificatio n process, including the following: 1. Interviews with key personnel, such as process e ngineers and metering experts, as well as staff involved in comp iling 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 confi rming the complete and accurate reporting of required data su ch as facility fuel suppliers, fuel quantities delivered, and if fuel w as received directly from an interstate pipeline. (4) Review of Reporting Entity’s Operations, Product Da ta 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 emissi ons 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 95 157 of this article are included in the emissions data report as required b y this article. The verification team shall also ensure that the report ed 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 documenta tion used to calculate and report emissions, product data, fuels and electrici ty transactions, and other information required under this article, as applica ble. (6) Electricity Importers and Exporters. The verification team shall review the GHG Inventory Program documentation required pursua nt to section 95105(d), electricity transaction records, includin g deliveries and receipts ofLegal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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power via North American Electric Reliability Corpo ration (NERC) e-Tags, written power contracts, settlements data, and any other applicable information required to confirm reported electricit y procurements and deliveries

. (7) Sampling Plan. As part of confirming emissions data, product data, electricity transactions, or fuel transactions, the verificatio n 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 interv iews to assess the likely nature, scale and complexity of the verifica tion services for a reporting entity. The analysis shall review the in puts for the development of the submitted emissions data report, the rigor a nd appropriateness of data management systems, and the coordination withi n the reporting entity’s organization to manage the operation and m aintenance of equipment and systems used to develop emissions dat a reports. (B) The verification team shall include in the samp ling plan a ranking of emissions sources by amount of contribution to tota l CO 2 equivalent emissions for the reporting entity, and a ranking o f emissions sources with the largest calculation uncertainty. The veri fication team shall also include in the sampling plan a ranking of the produ ct data by units specified in the appropriate section of this articl e and a ranking of the product data with the largest uncertainty. As appl icable and deemed appropriate by the verification team, fuel and elec tricity 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 samp ling plan a qualitative narrative of uncertainty risk assessment in the fol lowing areas as applicable under sections 95110 to 95123, 95129, an d 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 e missions data reports. (D) After completing the analyses required by secti ons 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 Green house Gas

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1. Emissions sources, product data, and/or transact ions that will be targeted for document reviews, and data checks as s pecified in 95131(b)(8), and an explanation of why they were ch osen;

2. Methods used to conduct data checks for each sou rce, product data, or transaction; 3. A summary of the information analyzed in the dat a checks and document reviews conducted for each emissions sourc e, product data, or transaction targeted. The sampling plan list must be updated and finalize d prior to the completion of verification services. The final sam pling plan must describe in detail how the identified risks were addressed d uring the verification. (E) The verification team shall revise the sampling plan to describe tasks completed by the verification team as information b ecomes 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 y ears following the submission of each verification statement. The sam pling 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 concl usion in the verification statement. (8) Data Checks. To determine the reliability of the submitted emi ssions data report, the verification team shall use data checks . Such data checks shall focus on the largest and most uncertain estimates o f 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 applie d 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 n onconformance, as indicated in the sampling plan; (D) The verification team shall use professional ju dgment in the number of data checks required for the team to conclude with reasonable assuranceLegal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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whether the total reported covered emissions and co vered product data are free of material misstatement. At a minimum, d ata 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 origin al calculations; 4. Reviewing calculation methodologies used by the reporting entity for conformance with this article; and 5. Reviewing meter and fuel analytical instrumentat ion measurement accuracy and calibration for consistency with the r equirements of section 95103(k). (E) As applicable, the verification team shall revi ew 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 prod uct(s);
5. Product measurement records; and 6. Other information or documentation that provides financial or direct measurement information about total product(s) repo rted. (F) The verification team is responsible for ensuri ng via data checks that there is reasonable assurance that the emissions da ta report conforms to the requirements of this article. In addition, and as applicable, the verifier’s review of conformance must confirm the f ollowing information is correctly reported: 1. For facilities that combust natural gas, natural gas supplier customer account number, service account identification numb er, or other primary account identifier(s) reported pursuant to section 95115(k); 2. For suppliers of natural gas, end-user names, ac count identification numbers, and natural gas deliveries in MMBtu, repor ted pursuant to section 95122(d)(4); 3. Energy generation and disposition information re ported pursuant to section 95112, if any of the following apply: a. The facility belongs to an industry sector liste d in Table 8-1 of section 95870 of the cap-and-trade regulation; b. The facility is applying for legacy contract tra nsition assistance under the cap-and-trade regulation; orLegal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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c. The facility is applying for the limited exempti on of emissions from the production of qualified thermal output pursuant to the capand-trade regulation. (G) The verification team shall compare its own cal culated results with the reported data in order to confirm the extent and im pact of any omissions and errors. Any discrepancies must be investigated . The comparison of data checks must also include a narrative to indica te which sources, product data, and transactions were checked, the ty pes and quantity of data that were evaluated for each source, product d ata, and transaction, the percentage of reported emissions covered by the data checks, the percentage of product data covered by the data chec ks, and any separate discrepancies that were identified in emis sion 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 veri fication statement(s), the reporting entity must fix all correctable errors th at affect covered emissions, non-covered emissions, or covered product data in t he submitted emissions data report, and submit a revised emissions data re port 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-co vered emissions, or covered product data represents a non-conformance w ith this article but does not, absent other errors, result in an adverse veri fication statement. The reporting entity shall maintain documentation to su pport any revisions made to the initial emissions data report. Documentation f or all emissions data report submittals shall be retained by the reporting entit y for ten years pursuant to section 95105. The verification team shall use professional judg ment in the determination of correctable errors as defined in section 95102(a), including whether differences are not errors but result from truncati on or rounding or averaging. If the verification team determines that the repo rted 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 t he current NAICS code(s), the result will be an adverse verification statemen t.

The verification team must document the source of any difference identified, including whether the difference results in a corre ctable 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 tha t the emissions data report does not contain a material misstatement in GHG emissions reported for the reporting entity, on a CO 2 equivalent basis and/or a material misstatement in product data for the reporting enti ty, 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 theLegal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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emissions data report for adherence to the requirem ents 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 issu es identified in the course of verification activities that may a ffect determinations of material misstatement and nonconformance. The issues log mu st identify the regulatory section related to the nonconformance, i f applicable, and indicate if the issues were corrected by the reporting entity p rior to completing the verification. Any other concerns that the verifica tion 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 cover ed emissions and total reported covered product data (units from the appli cable sections of this article). (A) In assessing whether an emissions data report c ontains a material misstatement, the verification team must separately determine whether the total reported covered emissions and total repo rted covered product data contain a material misstatement using the foll owing equation(s):

LMNOMPQ	MNNRN MSTUUTRPU $ = 	: V WTUONMXYPOTMU + #STUUTRPU + ZTUNMXRNQTP[ \ ]	100% _RQY`	NMXRNQMa	ORbMNMa	MSTUUTRPU

or LMNOMPQ	MNNRN	 XNRacOQ	aYQY$

= 	: V WTUONMXYPOTMU + #STUUTRPU + ZTUNMXRNQTP[ \ ]	100%

_RQY`	ORbMNMa	XNRacOQ	aYQY

Where: “Discrepancies” means any differences between the r eported 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 da ta report, but were not included by the reporting entity in the emissions d ata report.

“Misreporting” means duplicate, incomplete or other covered emissions the verifier concludes should, or should not, be pa rt of the emissions data report or duplicate or other product data the verif ier concludes should not be part of the emissions data report.Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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“Total reported covered emissions or covered produc t 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, verifier s must deem correctly substituted missing data to be accurate, regardless of the amount of missing data. (C) The omissions variable described in section 951 31(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 cons idered 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 GH G emissions for the data year: (A) The verification team shall confirm that the re ported 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 elemen ts used to calculate emissions are missing, and emissions are correctly calculated using the missing data requirements in sections 95110 to 9512 3, 95129, and 95150 to 95158 these emissions will be considered accurat e and as meeting the reporting requirements for that source. (C) If greater than 20 percent of any single data e lement used to calculate emissions are missing or any combination of data el ements are missing that would result in more than 5% of a facility’s e missions being calculated using missing data requirements in secti ons 95110 to 95123, 95129, and 95150 to 95158, the verifier must includ e 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 sourc e of any missing data substitutions discovered during the course of verif ication in the verification report. (14) Review of Product Data. The verifier’s review of product data must includ e 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 petro leum refineries subject to section 95113:

1. Verifiers must evaluate conformance and material misstatement for 2013 primary refinery products data reported in 201 4. For the 2014 data year, the total on-site production quantity of primary refineryLegal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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product for a refinery that has not reported a Solo mon EII value pursuant to 95113(l)(4) (“non-EII refinery”) is cov ered product data and verifiers must evaluate conformance and materia l misstatement. For non-EII refineries in the 2014 data year, the q uantity of each primary refinery product and blending component pro duced elsewhere and brought on-site and that is used for a purpose other than blending into a primary refinery product is no t covered product data and is not subject to material misstatement. For the 2014 data year and subsequent years, the total on-site produc tion quantity of primary refinery product for a refinery that has re ported a Solomon EII value pursuant to 95113(l)(4) (“EII refinery”), and the quantities of primary refinery product and blending component pro duced elsewhere and brought on-site by an EII refinery, a re not covered product data and verifiers only evaluate for confor mance. For the 2015 data year and subsequent years, primary refine ry product data are not covered product data for any refinery and v erifiers 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 a nd separately assess material misstatement for the total facility complexity weighted barrel beginning with 2013 data reported i n 2014 4. Verifiers must submit two product data verificat ion statements for 2013 and 2014 data reports:

a. A verification statement that includes the evalu ation of primary refinery products and the Solomon EII, as applicabl e, as well as non-covered product data; b. A verification statement for the evaluation of c omplexity weighted barrel. 5. Beginning with 2015 data reported in 2016, only the verification statement for the complexity weighted barrel is sub mitted. Evaluation of other product data conformance is inc luded in the verification statement for complexity weighted barr el. (c) Completion of verification services must includ e: (1) Verification Statement. Upon completion of the verification services specif ied in section 95131(b), the verification body shall co mplete an emissions data verification statement and product data verificatio n 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 servi ces and findings of the verification team independently reviewed within the verification body by anLegal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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independent reviewer who is a lead verifier not inv olved in services for that reporting entity during that year. (2) Independent Review. The independent reviewer shall serve as a final che ck on the verification team’s work to identify any sig nificant concerns, including: (A) Errors in planning, (B) Errors in data sampling, and (C) Errors in judgment by the verification team tha t are related to the draft verification statement. The independent reviewer must maintain independence from the verification services by not making specific recommendations abo ut how the verification services should be conducted. The independent revie wer will review documents applicable to the verification services p rovided, and identify any failure to comply with requirements of this article or with the verification body’s internal policies and procedures for providing veri fication services. The independent reviewer must concur with the verificat ion 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, trac king and emission calculation/product data systems; 3. The verification plan; 4. The detailed comparison of the data checks condu cted during verification services for emissions and product dat a sources; 5. The log of issues identified in the course of ve rification activities and their resolution; 6. Any qualifying comments on findings during verif ication 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 r eporting entity at the same time as or before the final emissions data ver ification statement and product data verification statement(s) are subm itted to ARB. The detailed verification report shall be made availabl e to ARB upon request. (B) The verification team shall have a final discus sion with the reporting entity explaining its findings, and notify the reporting e ntity of any unresolved issues noted in the issues log before the verificat ion statement(s) are finalized.Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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(C) The verification body shall provide the verific ation statement(s) to the reporting entity and the ARB, attesting whether the verification body has found the submitted emissions data report to be fre e of material misstatements, and whether the emissions data repor t is in conformance with the requirements of this article. For every q ualified positive verification statement, the verification body shall explain the nonconformances contained within the emissions data re port 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 materia l misstatement. For every adverse verification statement, the verificat ion body must explain all non-conformances and material misstatements lea ding 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 shal l attest that the verification team has carried out all verification services as r equired by this article, and the lead verifier who has conducted the indepen dent review of verification services and findings shall attest to his or her independent review on behalf of the verification body and his o r her concurrence with the verification findings.

1. The lead verifier must attest in the verificatio n 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 o ut all verification services as required by this article.” 2. The lead verifier independent reviewer who has c onducted the independent review of verification services and fin dings must attest in the verification statement, in writing, to ARB as f ollows: “I certify under penalty of perjury under the laws of the State of California that I have conducted an independent rev iew 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 fo r 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 misst atements 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 repor ting entity. The modified report and verification statement(s) must be submit ted to ARB before the verification deadline, even if the reporting entity makes a request to the Executive Officer as provided below in section 9513 1(c)(4)(A).Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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(A) If the reporting entity and the verification bo dy cannot reach agreement on modifications to the emissions data report that result in a positive verification statement or qualified positive verifi cation 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 repor t. The reporting entity may petition either emissions or product data, or b oth. At the same time that the reporting entity petitions the Executive O fficer, the reporting entity must submit all information it believes is necessar y for the ARB Executive Officer to make a final decision. (B) The Executive Officer shall make a final decisi on 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 v erification body or the reporting entity, the information must be submitted to ARB within five working days. ARB will notify both the reporting e ntity and the verification body of its determination, which may also include a n assigned emissions level calculated pursuant to section 95131(c)(5), i f applicable. (5) Assigned Emissions Level. When a reporting entity fails to receive a verification statement for a data year by the appli cable deadline or receives an adverse emissions data verification statement, the Executive Officer shall develop an assigned emissions level for the data ye ar for the reporting entity. Within five working days of a written request by th e Executive Officer, the verification body (if applicable) shall provide any available verification services information or correspondence related to the emissi ons 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 bo dy (if applicable), and other information requested by the Executive Officer, inc luding the operating days and hours of the reporting entity during the data y ear. The reporting entity shall also make available personnel who can assist the Executive Officer’s determination of an assigned emissions level for th e data year. (A) In preparing the assigned emissions level for t he reporting entity, the Executive Officer shall consider at a minimum the f ollowing information: 1. The number, types and days and hours of operatio n 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 repo rts; 3. The potential maximum fuel and process material input and output capacities for the reporting entity’s emissions sou rces during operating hours;Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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4. For electric power entities, wholesale and retai l transactions that would affect an assigned emissions level, for the a pplicable data year and for previous years; 5. Emissions, electricity transactions, fuel use, o r product output information reported to ARB or other State, federal , or local agencies. (B) In preparing the assigned emissions level for t he 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 Offi cer 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 emission s level for the reporting entity using the best information available, includ ing 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 9513 1(c)(4)(B), if applicable. (d) Upon provision of the verification statement, o r 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 se ction 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 positi ve verification statement fails an ARB audit, the Executive Officer may set aside the positive or qualified positive verification statement issued by the verification b ody, and require the reporting entity to have the emissions data report re-verifie d by a different verification body within 90 days. This paragraph applies to verifica tion statements for emissions and product data. In instances where an error to an emi ssions data report is identified and determined by ARB to not affect the emissions o r covered product data, the change may be made without a set aside of the posit ive or qualified positive verification statement. (f) Upon request by the Executive Officer, the repo rting entity shall provide the data used to generate an emissions data report, includin g all data available to a verifier in the conduct of verification services, within 20 working days. (g) Upon request of the Executive Officer, the veri fication body shall provide ARB the full verification report given to the reporting ent ity, 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 Offi cer, the verification body shall makeLegal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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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 t his article as modified below when verifying biomass-derived fuel: (1) General biomass-derived fuel verification requireme nts. The following requirements apply to the biomass-derived fuel veri fication: (A) Annual Verification. Biomass-derived fuel is subject to annual verifica tion 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 bi omass-derived fuels must be considered when providing all verification services required under section 95131(b) of this article. The verifi cation team must: 1. Review the reporting entity’s reported biomass-d erived fuel emissions to ensure the biomass-derived fuels are p roperly listed in the emissions data report as required in section 95 103(j) of this article and sections 95852.1.1 and 95852.2 of the c ap-and-trade regulation. 2. Conduct separate data checks that are consisten t with the requirements in 95131(i)(2)(D) for the fuel type be ing verified using the following documentation, as appropriate: the in voice, nomination, scheduling, storage, in-kind fuel purchase, allocat ion, transportation and balancing reports or other documents used as ev idence of the fuel delivery. a. The reporting entity may arrange for the documen tation to be supplied directly to the verifier if there are conf identiality 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 bio mass-derived fuels must be included in the independent review as required i n section 95131(c)(2) of this article.

2. Conformance for biomass-derived fuels is evaluat ed 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-d erived fuels are considered an omission in the evaluation for materi al 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-deriv ed CO 2

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California Air Resources Board 188 February 2015 (2) Specific biomass-derived fuel verification requ irements. (A) For urban, agricultural and forest derived wood and wood waste, the verifier must determine the reporting entity met th e requirements of section 95103(j). (B) For biodiesel and fuel ethanol, the verifier mu st determine the reporting entity met the requirements of section 95103(j) and the following requirements: 1. At combustion sources that purchase biomass-deri ved fuels, verify records to demonstrate that volume purchased equals or exceeds volume reported. 2. At combustion sources that produce their own fue l, verify: a. that raw material is sufficient to produce the q uantity 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 emiss ions. (C) For municipal solid waste and tires, the verifi er must determine the reporting entity met the requirements of section 95 103(j). (D) For biomethane and biogas, the verifier must: 1. Examine all nomination, invoice, scheduling, all ocation, 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 t he identified fuel; 2. Determine a contract is in place for the purchas e 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 mete red volumes in connection with the transportation of the biomethan e to the reporting entity; 3. Ensure any discrepancies in the fuel volumes, he at values and/or energies will be carried over into the evaluation o f material misstatement for the reporting entity; (3) Assessment. If the reporting entity is unable to demonstrate th at the biomassderived fuel is consistent with the requirements in sections 95852.1.1 and 95852.2 of the cap-and-trade regulation, the emissi on data report must be revised to list these biomass CO 2 emissions as non-exempt biomass-derived CO 2

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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 Verificatio n Bodies, Lead Verifiers,

and Verifiers of Emissions Data Reports and Offset Project Data Reports. (a) The accreditation requirements specified in thi s 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-t rade regulation. (b) The Executive Officer may issue accreditation t o 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 f ollowing information to the Executive Officer: (A) A list of all verification staff and a descript ion of their duties and qualifications, including ARB accredited verifiers on staff. The applicant shall demonstrate staff qualifications by listing e ach individual’s education, experience, professional licenses, and o ther pertinent information. 1. A verification body shall employ and retain at l east two verifiers that have been accredited as lead verifiers, as specifie d in section 95132(b)(2). 2. A verification body shall employ and retain at l east five total full-time staff. (B) The applicant shall provide a list of any judic ial proceedings, enforcement actions, or administrative actions filed against th e body within the previous 5 years, with an explanation as to the nat ure of the proceedings. (C) The applicant shall provide documentation that the proposed verification body maintains a minimum of four million U.S. dolla rs of professional liability insurance and must maintain this insuranc e 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 tha t the body has policies and mechanisms in place to prevent conflicts of int erest and to identify and resolve potential conflict of interest situatio ns if they arise. The applicant shall provide the following information: 1. Identification of services provided by the verif ication 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 Green house Gas

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2. A detailed organizational chart that includes th e verification body, its management structure, and any related entities; 3. The verification body’s internal conflict of int erest policy that identifies activities and limits to monetary or non-monetary g ifts that apply to all employees. (E) The applicant shall provide a demonstration tha t the body has procedures or policies to support staff technical training as it relates to verification. This training shall include participating in ARB ve rifier training on an ongoing basis. (F) The verification body shall notify ARB within 3 0 days of when it no longer meets the requirements for accreditation as a verif ication body in section 95132(b)(1). The verification body may request tha t 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 95 132(b)(1)(A)(2) and 95132(b)(1)(B)-(D) do not apply, except that the ap plicant shall provide a demonstration that the district has policies and me chanisms 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 acc redited verifier for two continuous years and has worked as a verifier in at least three completed verifications under the supervision of an ARB accre dited lead verifier, with evidence of favorable assessment by ARB for se rvices performed;

or, (C) Evidence that at the time of the verification t raining examination, the applicant has worked as a project manager or lead p erson 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 audito r 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 ba ckground required to act as a verifier for ARB. Minimum education backgr ound means that the applicant has either: 1. A bachelors level college degree or equivalent i n science,Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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technology, business, statistics, mathematics, envi ronmental policy, economics, or financial auditing; or 2. Evidence demonstrating the completion of signifi cant and relevant work experience or other personal development activ ities that have provided the applicant with the communication, tech nical and analytical skills necessary to conduct verification

. (B) Evidence demonstrating sufficient workplace exp erience 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 in ventories, environmental auditing, or other technical skills n ecessary to conduct verification. (4) The applicant must take an ARB approved general verification training and receive a passing score of greater than an unweight ed 70% on an exit examination. If the applicant does not pass the exa m 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 p revious 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 Ver ifiers. (A) Sector Specific Verifier . The applicant seeking to be accredited as a sector specific verifier as specified in section 95 131(a)(2) must, in addition to meeting the requirements for accredited lead verifier or verifier qualification, have at least two years of professio nal experience related to the sector in which they are seeking accreditation, take ARB sector specific verification training and receive a passin g score of greater than an unweighted 70% on an exit examination. If the a pplicant does not pass the exam after the training, they may retake t he exam a second time. Only one retake of the examination is allowed before the applicant is required to retake the ARB approved sector speci fic 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 require ments for accredited lead verifier or verifier qualification, meet one o f the following requirements: 1. Have at least two years of professional experien ce related to developing emission inventories, conducting technic al analyses, or environmental audits of the offset project type, an d 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 examinati on. If theLegal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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applicant does not pass the exam after the training , they may retake the exam a second time. Only one retake of the exam ination 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 A ction Reserve prior to October 28, 2011, taken Climate Action Reserve proj ect specific verifier training, have performed at least two proj ect verifications for a project type by October 28, 2011, and have taken ge neral ARB offset verification training, and receive a passing score of greater than an unweighted 70% on an exit examination. If the appl icant does not pass the exam after the training, they may retake t he exam a second time. Only one retake of the examination is allowe d before the applicant is required to retake the ARB approved ge neral ARB offset verification training and offset project specific v erification training. (6) Nothing in this section shall be construed as p reventing the Executive Officer from requesting additional information or documenta tion from an applicant after receipt of the application for accreditation as a verification body, lead verifier, or verifier, or from seeking additional i nformation from other persons or entities regarding the applicant’s fitness for qual ification. (c) ARB Accreditation

. (1) Within 90 days of receiving an application for accreditation as a verification body, lead verifier, verifier, sector specific veri fier, or offset project specific verifier, the Executive Officer shall inform the ap plicant 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, secto r specific verifier, or offset project specific verifier is complete, meets all ap plicable regulatory requirements, and passes a performance review as de fined in section 95102(a), the prescreening requirement is met and t he applicant will be eligible to attend the verification training requir ed by this section. (3) Within 45 days following completion of the appl ication process and all applicable training and examination requirements, t he Executive Officer shall act to issue an Executive Order to grant or withhol d accreditation for the verification body, lead verifier, sector specific v erifier, 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 accreditat ion as a verifier, lead verifier, sector specific verifier, offset project specific verifier, or verification body if the applicant has not been subject to ARB e nforcement action under this article. All ARB approved general, sector spe cific, or offset project specific verification training and examination requirements applicable at the time of reapplication must be met for accreditation to be ren ewed by the ExecutiveLegal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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Officer. In addition, the performance review requir ement set forth in section 95132(c)(2) must be met for accreditation to be ren ewed by the Executive Officer. (5) All verification body requirements in section 9 5132(b)(1) must be met for the Executive Officer to renew the verification body ac creditation. (6) The Executive Officer and the applicant may mut ually agree to longer time periods than those specified in subsections 95132(c )(1) or 95132(c)(3), and the applicant may submit additional supporting docu mentation 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 accredit ed verification body, lead verifier, sector specific verifier, offset pro ject specific verifier, or verifier shall provide written notice to the Executive Offic er of the corrective action. That notification shall include reasons for the cor rective action and the type of corrective action. The verification body or verifi er must provide additional information to the Executive Officer upon request. (8) Verifiers shall take ARB approved training to c ontinue to provide verification services after January 1, 2012. The verifier must receive a passing score of greater than an unweighted 70% on the exit examinat ion. (d) Modification, Suspension, or Revocation of an Execu tive Order Approving a Verification Body, Lead Verifier, or Verifier, and Voluntary Withdrawal from the Accreditation Program. The Executive Officer may review and, for good ca use, including any violation of subarticle 4 of this art icle 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 affordi ng the verification body, lead verifier, or verifier the opportunity for a hearing in accordance with the procedures specified in title 17, California Code of Regulatio ns, section 60055.1 et seq. (1) During suspension or revocation proceedings, th e verification body, lead verifier, or verifier may not continue to provide v erification services. (2) Within five working days of suspension or revoc ation of accreditation, a verification body must notify all reporting entitie s, offset project operators, or authorized project designees for whom it is providi ng 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 suspe nded 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 n otice to the Executive Officer requesting such withdrawal.Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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California Air Resources Board 194 February 2015 (e) Subcontracting. The following requirements shall apply to any verif ication body that elects to subcontract a portion of verification ser vices. (1) All subcontractors must be accredited by ARB to perform the verification services for which the subcontractor has been engag ed by the verification body. (2) The verification body must assume full responsi bility for verification services performed by subcontractor verifiers. (3) A verification body shall not use subcontractor s 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 servi ces for a reporting entity. (5) A verification body that engages a subcontracto r shall be responsible for demonstrating an acceptable level of conflict of in terest, 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 Veri fication Bodies.

(a) The conflict of interest provisions of this sec tion shall apply to verification bodies, lead verifiers, and verifiers accredited by ARB to perform verification services for reporting entities. Any individual person or compa ny that is hired by a reporting entity to contract with a verification body on beha lf of the reporting entity is subject to the conflict of interest assessment in this arti cle. In such instances, the verification body must assess the potential conflic t of interest between itself and the contracting entity as well as between itself and th e reporting entity, and must also address the potential conflict of interest between the contracting entity and the reporting entity, including a written assessment pr ovided and signed by the contracting entity. (b) The potential for a conflict of interest must b e deemed to be high where: (1) The verification body and reporting entity shar e any management staff or board of directors membership, or any of the senior management staff of the reporting entity have been employed by the verifica tion body, or vice versa, within the previous five years; or (2) Any employee of the verification body, or any e mployee of a related entity, or a subcontractor who is a member of the verification t eam has provided to the reporting entity any of the following services with in the previous five years:Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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(A) Designing, developing, implementing, reviewing, or maintaining an inventory or information or data management system for facility air emissions, or, where applicable, electricity or fue l transactions, unless the review was part of providing greenhouse gas verific ation services; (B) Developing greenhouse gas emission factors or o ther greenhouse gasrelated engineering analysis, including developing or reviewing a California Environmental Quality Act (CEQA) greenho use gas analysis that includes facility specific information; (C) Designing energy efficiency, renewable power, o r 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 reductio n or GHG removal offset project as defined in the cap-and-trade regu lation; (E) Owning, buying, selling, trading, or retiring s hares, stocks, or emissions reduction credits from an offset project that was d eveloped by or resulting reduction credits are owned by the reporting entity ; (F) Dealing in or being a promoter of credits on be half of an offset project operator or authorized project designee where the c redits are owned by or the offset project was developed by the reportin g entity; (G) Preparing or producing greenhouse gas-related m anuals, 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 sa fety functions for the reporting entity; (K) Bookkeeping or other services related to accoun ting records or financial statements; (L) Any service related to development of informati on systems, including consulting on the development of environmental mana gement systems, such as those conforming to ISO 14001 or energy man agement 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 repo rts in which the verification body has provided its opinion on the adequacy of co nsideration in a transaction, unless the resulting services will not be part of the verification process; (O) Any actuarially oriented advisory service invol ving the determination of amounts recorded in financial statements and relate d accounts;Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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(P) Any internal audit service that has been outsou rced by the reporting entity or offset project operator that relates to t he reporting entity’s internal accounting controls, financial systems or financial statements, unless the result of those services will not be par t of the verification process; (Q) Acting as a broker-dealer (registered or unregi stered), promoter or underwriter on behalf of the reporting entity; (R) Any legal services; (S) Expert services to the reporting entity, a trad e or membership group to which the reporting entity belongs, or a legal repr esentative for the purpose of advocating the reporting entity’s intere sts in litigation or in a regulatory or administrative proceeding or investig ation. (T) Verification services that are not conducted in accordance with, or equivalent to, section 95133 requirements, unless t he systems and data reviewed during those services, as well as the resu lt 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 e ntities of the verification body. “Member” also includes any individual with m ajority equity share in the verification body or its related entities. “Re lated entity” for the purposes of this section means any direct parent co mpany, 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 o f non-monetary incentive to a reporting entity to secure a verification serv ices 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 provi ded 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 spe cified 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 veri fication 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, sec tion 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, sec tion 95133, including, butLegal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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not limited to, third-party certification of enviro nmental management system under ISO 14001 or energy management system under 5 0001 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 f or conflict of interest will also be deemed to be medium where there are any instances o f personal or familial relationships between the members of the verificati on 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 pote ntial for conflict of interest and intends to provide verification services for the re porting entity, the verification body shall submit, in addition to the submittal req uirements 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 poten tial conflicts have been removed and insulated from the project. (B) An explanation of any changes to the organizati onal structure or verification body to remove the potential conflict of interest. A demonstration that any unit with potential conflict s has been divested or moved into an independent entity or any subcontract or with potential conflicts has been removed. (C) Any other circumstance that specifically addres ses other sources for potential conflict of interest. (2) As provided in section 95133(f)(4), the Executi ve 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 providi ng 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 Off icer a self-evaluation of the potential for any conflict of interest that the ver ification body, related entities, or any subcontractors performing verification services may have with the reporting entity for which it will perform verifica tion services. The submittal shall include the following: (A) Identification of whether the potential for con flict 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 prov ided verification services for the reporting entity or related entiti es and, if so, provide aLegal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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description of such services and the years in which such services were provided; (C) Identification of whether any member of the ver ification team, verification body, or related entity has engaged in services of any nature, other than ARB verification services, with the reporting entit y or related entities either within or outside California during the prev ious five years. If services other than ARB verification services have previously been provided, the following information shall also be s ubmitted:

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, s uch as emissions inventory, auditing, energy efficiency, renewable e nergy, or other work with implications for the reporting entity’s g reenhouse gas emissions pursuant to this article; 2. The nature of past, present or future relationsh ips of any member of the verification team, verification body, or relate d entities with the reporting entity or related entities including: a. Instances when any member of the verification te am, 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 bein g performed for the reporting entity or related entities, and if so, th e nature of the work; c. How much work was performed for the reporting en tity or related entities in the last five years, in dollars; d. Whether any member of the verification team, ver ification body, or related entities has contracts or other arrangement s to perform work for the reporting entity or a related entity; e. How much work related to greenhouse gases the ve rification team has performed for the reporting entity or rela ted 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 verificati on team’s credibility and lack of bias should not be under qu estion. (D) A list of names of the staff that would perform verification services for the reporting entity, and a description of any instance s of personal or family relationships with management or employees of the r eporting 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 Green house Gas

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(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 Interes t submittal is true, accurate, and complete.” (f) Conflict of Interest Determinations. The Executive Officer must review the selfevaluation submitted by the verification body and d etermine whether the verification body is authorized to perform verification services for the reporting entity. (1) The Executive Officer shall notify the verifica tion body in writing when the conflict of interest evaluation information submitt ed under section 95132(e) is deemed complete. Within 30 working days of deeming the information complete, the Executive Officer shall determine whe ther the verification body is authorized to proceed with verification and must so notify the verification body. (2) If the Executive Officer determines the verific ation body or any member of the verification team meets the criteria specified in s ection 95133(b), the Executive Officer shall find a high potential conflict of int erest 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 ve rification body and verification team have a medium potential for a conflict of inte rest, the Executive Officer shall evaluate the conflict of interest mitigation plan submitted pursuant to section 95133(d), and may request additional inform ation 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 curr ent and past relationships between the verification body, related entities, an d 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 au thorize the verification body to provide verification services. (g) Monitoring Conflict of Interest Situations. (1) After commencement of verification services, t he verification body shall monitor and immediately make full disclosure in wri ting to the Executive Officer regarding any potential for a conflict of interest situation that arises. This disclosure shall include a description of actions t hat 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 th e verification body or any verification team member entering into any contract with the reporting entity orLegal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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related entity for which the body has provided veri fication services, the verification body shall notify the Executive Office r of the contract and the nature of the work to be performed, and revenue rec eived. 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 revocat ion is warranted. (3) The verification body shall notify the Executiv e Office, within 30 days, of any emerging conflicts of interest during the time veri fication services are being provided. (A) If the Executive Officer determines that a disc losed emerging potential conflict is medium risk and this risk can be mitiga ted, the verification body is deemed to have met the conflict of interest requ irements to continue to provide verification services to the reporting enti ty and will not be subject to suspension or revocation of accreditation as spe cified in section 95132(d). (B) If the Executive Officer determines that a disc losed emerging potential conflict is medium or high risk and this risk canno t be mitigated, the verification body will not be able to continue to p rovide verification services to the reporting entity, and may be subjec t to suspension or revocation of accreditation under section 95132(d). (4) The verification body shall report to the Execu tive Officer any changes in its organizational structure, including mergers, acquis itions, or divestitures, for one year after completion of verification services. (5) The Executive Officer may invalidate a verifica tion finding if a potential conflict of interest has arisen for any member of the verifi cation team. In such a case, the reporting entity shall be provided 90 days to c omplete 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 sta ff, or its subcontractor(s) as provided in section 95132(d). (h) Specific Requirements for Air Quality Managemen t 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 c onflict 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 se ction 95133(e) for each reporting entity for which it intends to provide ve rification services, or shall submit an annual self-evaluation to ARB no later th an 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 Green house Gas

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California Air Resources Board 201 February 2015 (3) As part of its conflict of interest self-evalua tion submittal under section 95133(e), the air district shall certify that it wi ll prevent conflicts of interests and resolve potential conflict of interest situations p ursuant 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 sha ll 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 Green house Gas

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California Air Resources Board 202 February 2015 Subarticle 5. Reporting Requirements and Calculati on 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, a ffixed temporarily or permanently to offshore submerged lands, that house s 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 str uctures connected to the platform structure via walkways, storage tanks asso ciated with the platform structure and floating production and storage offlo ading equipment (FPSO). This source category does not include emissions fro m offshore drilling and exploration that is not conducted on production pla tforms. (2) Onshore petroleum and natural gas production. Onshore petroleum and natural gas production means all equipment on a wel l-pad or associated with a well pad (including compressors, generators, dehydr ators, storage vessels, and portable non-self-propelled equipment which inc ludes well drilling and completion equipment, workover equipment, gravity s eparation equipment, auxiliary non-transportation-related equipment, and leased, rented or contracted equipment) used in the production, extra ction, recovery, lifting, stabilization, separation or treating of petroleum and/or natural gas (including condensate). This equipment also includes associat ed storage or measurement vessels and all enhanced oil recovery ( EOR) operations (both thermal and non-thermal), and all petroleum and nat ural gas production equipment located on islands, artificial islands, o r structures connected by a causeway to land, an island, or an artificial islan d. 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 se ction 95156(a)(7)-(10) and meet the metering requirements of section 95103(k) by measuring the emulsion before the first separation tank at the on shore 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-met hane gases from produced natural gas, or the separation of NGLs into one or more component mixtures. Separation includes one or more of the following: f orced extraction of natural gas liquids, sulfur and carbon dioxide removal, fra ctionation of NGLs, or the capture of CO 2 separated from natural gas streams. This segment also includes all residue gas compression equipment owne d or operated by the natural gas processing plant. This industry segmen t includes processing plants that fractionate gas liquids, and processing plants that do not fractionate gas liquids but have an annual average throughput o f 25 MMscf per day orLegal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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greater. This industry segment also includes all b ooster stations owned and/or operated by the facility owner/operator. (4) Onshore natural gas transmission compression. Onshore natural gas transmission compression means any stationary combi nation of compressors that move natural gas from production fields, natur al 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 include s equipment for liquids separation, and tanks for the storage of water and hydrocarbon liquids. Residue (sales) gas compression that is part of ons hore natural gas processing plants are included in the onshore natur al gas processing segment and are excluded from this segment. This industry segment also includes all booster stations owned and/or operated by the facil ity owner/operator. (5) Underground natural gas storage. Underground natural gas storage means subsurface storage, including depleted gas or oil r eservoirs and salt dome caverns that store natural gas that has been transf erred from its original location for the primary purpose of load balancing (the process or equalizing the receipt and delivery of natural gas); natural g as underground storage processes and operations (including compression, de hydration and flow measurement, and excluding transmission pipelines); and all the wellheads connected to the compression units located at the f acility that inject and recover natural gas into and from the underground r eservoirs. (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 liquef ied natural gas. (7) LNG import and export equipment . LNG import equipment means all onshore or offshore equipment that receives imported LNG vi a ocean transport, stores LNG, re-gasifies LNG, and delivers re-gasified natu ral gas to a natural gas transmission or distribution system in California. LNG export equipment means all onshore or offshore equipment that receiv es 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 co mmission or that is operated as an independent municipally-owned distribution syste m. This segment also excludes customer meters and regulators, infrastruc ture, and pipelines (both interstate and intrastate) delivering natural gas d irectly to major industrial users and farm taps upstream of the local distribut ion company inlet.Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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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 emis sions 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 9 5101(b), natural gas processing facilities must also include owned or operated resi due 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 CO 2 , CH 4 , and N 2 O emissions from each industry segment specified in paragraphs (b) throug h (i) of this section, CO 2 , CH 4 , and N 2 O emissions from each flare as specified in paragra phs (b) through (i) of this section, and stationary and portable combustion emi ssions as applicable and as specified in paragraph (j) of this section. (b) For offshore petroleum and natural gas producti on, the operator must report CO 2 , CH 4 , and N 2 O emissions from equipment leaks, vented emissions, and flare emission source types as identified in the data col lection 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 §§25 0.302 through 304 (July 1, 2011), which is hereby incorporated by ref erence. Offshore platforms do not need to report portable emissions. In addition , offshore production facilities must report combustion emissions from supply and tr ansportation 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 produc tion facility, the operator must report CO 2 , CH 4 , and N 2 O emissions from the following source types on a we ll-pad, associated with a well-pad or associated with equip ment to which an emulsion is transferred: (1) Metered natural gas pneumatic device and pump v enting; (2) Non-metered natural gas pneumatic device ventin g; (3) Acid gas removal vents; (4) Dehydrator vents;Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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California Air Resources Board 205 February 2015 (5) Well venting for liquids unloading; (6) Gas well venting during well completions and wo rkovers; (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 emissi ons; (12) Centrifugal compressor venting; (13) Reciprocating compressor venting; (14) EOR injection pump blowdown; (15) Crude oil, condensate and produced water CO 2 and CH 4 ; (16) Equipment leaks from valves, connectors, open ended lines, pressure relief valves, pumps, flanges, and other equipment leak so urces (such as instruments, loading arms, stuffing boxes, compress or seals, dump lever arms, and breather caps); and (17) The operator must use the methods in section 9 5153(y) and report under this subarticle the emissions of CO 2 , CH 4 , and N 2 O from stationary or portable fuel combustion equipment that cannot move on roadways u nder its own power and drive train, and that is located at an onshore petroleum and natural gas production facility as defined in section 95150. S tationary or portable equipment includes equipment which is integral to t he extraction, processing, and movement of oil and/or natural gas; such as wel l pad construction equipment, well drilling and completion equipment, equipment used for abandoned well plugging and site reclamation, worko ver equipment, natural gas dehydrators, natural gas compressors, electrica l generators, steam boilers, and process heaters. (d) For onshore natural gas processing, the operato r must report CO 2 , CH 4 , and N 2 O 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 emissio ns; (5) Centrifugal compressor venting; (6) Reciprocating compressor venting; and (7) Equipment leaks from valves, connectors, open e nded lines, pressure relief valves, and meters.Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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California Air Resources Board 206 February 2015 (e) For onshore natural gas transmission compressio n, the operator must report CO 2 , CH 4 , and N 2 O emissions from the following sources: (1) Metered natural gas pneumatic device and pump v enting; (2) Non-metered natural gas pneumatic device ventin g; (3) Equipment and pipeline blowdowns; (4) Transmission storage tanks; (5) Flare stack or other destruction device emissio ns; (6) Centrifugal compressor venting; (7) Reciprocating compressor venting; and (8) Equipment leaks from valves, connectors, open e nded lines, pressure relief valves, and meters. (f) For underground natural gas storage, the operat or must report CO 2 , CH 4 , and N 2 O from the following sources: (1) Metered natural gas pneumatic device and pump v enting; (2) Non-metered natural gas pneumatic device ventin g; (3) Equipment and pipeline blowdowns; (4) Flare stack or other destruction device emissio ns; (5) Centrifugal compressor rod packing venting; (6) Reciprocating compressor venting; and (7) Equipment leaks from valves, connectors, open e nded lines, pressure relief valves, and meters. (g) For LNG storage, the operator must report CO 2 , CH 4 , and N 2 O emissions from the following sources: (1) Equipment and pipeline blowdowns; (2) Flare stack or other destruction device emissio ns; (3) Centrifugal compressor rod packing venting; (4) Reciprocating compressor venting; and (5) Equipment leaks from valves, pump seals, connec tors, vapor recovery compressors, and other equipment leak sources. (h) For LNG import and export equipment, the operat or must report CO 2 , CH 4 , and N 2 O emissions from the following sources: (1) Equipment and pipeline blowdowns; (2) Flare stack or other destruction device emissio ns; (3) Centrifugal compressor rod packing venting; (4) Reciprocating compressor venting; andLegal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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California Air Resources Board 207 February 2015 (5) Equipment leaks from valves, pump seals, connec tors, vapor recovery compressors, and other equipment leak sources. (i) For natural gas distribution, the operator must report CO 2 , CH 4 , and N 2 O 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-dis tribution transfer stations; (3) Equipment leaks at above grade metering-regulat ing stations that are not above grade transmission-distribution transfer stat ions; (4) Equipment leaks at below grade metering-regulat ing stations. (5) Distribution main equipment leaks; (6) Distribution services equipment leaks; (7) Report under section 95150 of this article the emissions of CO 2 , CH 4 , and N 2 O from stationary fuel combustion sources following t he methods in 95153(y); (8) Flare stack emissions; (9) Equipment and pipeline blowdowns; (10) CO 2 and CH 4 emissions from customer meters (N 2 O emissions excluded); and (11) CO 2 and CH 4 emissions from pipeline dig-ins (N 2 O emissions excluded). (j) Except for facilities under onshore petroleum a nd natural gas production and natural gas distribution, the operator of a facilit y must report emissions of CO 2 , CH 4 , and N 2 O for each stationary fuel combustion unit by follo wing the requirements of section 95115 of this article. Operators of onshor e petroleum and natural gas production facilities must report stationary and po rtable combustion emissions as specified in paragraph (c) of this section. Natura l gas distribution facilities must report stationary combustion emissions as specified in paragraph (i) of this section. (k) Operators of facilities must report CO 2 emissions captured and transferred off site by following the requirements of section 95123 of t his 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 Green house Gas

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California Air Resources Board 208 February 2015 § 95153. Calculating GHG Emissions.

The operator of a facility must calculate and repor t 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 type s 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 requir ements 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 me tered. 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 intermi ttent bleed natural gas powered devices. For unmetered devices the operator must u se the method specified in section 95153(b). Vented emissions from natural ga s driven pneumatic pumps covered in paragraph (d) of this section do not hav e to be reported under paragraph (a) of this section. (1) The operator must calculate vented emissions fo r all metered natural gas powered pneumatic devices and pumps using the follo wing equation:

d e = ∑ 

  < (Eq. 1)

Where:

E m = Annual natural gas emissions at standard conditi ons, in cubic feet, for all metered natural gas powered pneumatic devices.

n = Total number of meters.

B n = Natural gas consumption for meter n. (2) For both metered and unmetered natural gas powe red devices, CH 4 and CO 2 volumetric and mass emissions must be calculated fr om 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 CH 4 and CO 2 emissions from all un-metered natural gas powered pneumatic intermittent bleed and continuous low and high blee d devices using the following method:

d e,,g = ∑ ∑ dh  g <  < ∗ _

,g (Eq. 2)

Where: E nm,i,x = Annual natural gas emissions at standard conditio ns 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 Green house Gas

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California Air Resources Board 209 February 2015

EF i = Population emission factor for natural gas pneum atic device type i (scf/hour/component) listed in Tables 1A, 3, and 4 of Appendix A for onshore petroleum and natural gas production, onshore natur al gas transmissions compression, and underground natural gas facilities , respectively.

T i,x = Total number of hours type i component x was in service. Default is 8760 hours. (1) GHG (CO 2 and CH 4 ) volumetric and mass emissions must be calculated from volumetric natural gas emissions using methods in p aragraphs (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 absorbent s and adsorbents), the operator must calculate emissions for CO 2 only (not CH 4 ) 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 calculat ion 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 CO 2 concentration monitor and volumetric flow rate met er, they must calculate CO 2 emissions under this subarticle by following the T ier 4 Calculation Methodology and all associated calculat ion, quality assurance, reporting, and recordkeeping requirements for Tier 4 in section 95115 (stationary fuel combustion sources). Alternativel y, the operator may follow the manufacturer’s instructions or industry standar d practice. If a CO 2 concentration monitor and volumetric flow rate moni tor are not available, the operator may elect to install a CO 2 concentration monitor and a volumetric flow rate monitor that comply with all the requirements specified for the Tier 4 Calculation Methodology in section 95115 (stationar y fuel combustion sources). The calculation and reporting of CH 4 and N 2 O emissions is not required as part of the Tier 4 requirements for AGR s. (2) Calculation Methodology 2 . If CEMS is not available but a vent meter is installed, the operator must use the CO 2 composition and annual volume of vent gas to calculate emissions using Equation 3 of this section.

d ,j = k

 ∗ kR` j (Eq. 3)

Where: E a,CO2 = Annual volumetric CO 2 emissions at actual conditions, in cubic feet per year.

V s = Total annual volume of vent gas flowing out of t he AGR unit in cubic feet per year at actual conditions as determined by flow meter using methods set forth in section 95154(b). Alternative ly, the facility operator may follow the manufacturer’s instructions for cali bration of the vent meter.

Vol CO2 = Annual average volumetric fraction of CO 2 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 Green house Gas

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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 CO 2 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.

E

α ,CO2 = V in * [(Vol

I - Vol O )/(1-Vol O )] (Eq. 4A)

E

α ,CO2 = V out * [(Vol

I – Vol O )/(1-Vol

I )] (Eq. 4B)

Where: E α , CO2 = Annual volumetric CO 2 emissions at actual conditions, in cubic feet per year.

V in = Total annual volume of natural gas flow into the AGR unit in cubic feet per year at actual condition as determined using me thods specified in paragraph (c)(4) of this section.

V out = Total annual volume of natural gas flow out of th e AGR unit in cubic feet per year at actual condition as determined using me thods specified in paragraph (c)(4) of this section.

Vol I = Volume fraction of CO 2 content in natural gas into the AGR unit as determined in paragraph (c)(6) of this section.

Vol o = Volume fraction of CO 2 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 outle t natural gas stream of an AGR unit using a meter according to methods set forth i n section 95154(b). If the operator does not have a continuous flow meter, eit her install a continuous flow meter or use an engineering calculation to det ermine 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 sampl es from the vent gas stream to determine Vol CO2 according to methods set forth in section 95154(b). (6) If a continuous gas analyzer is installed on th e inlet gas stream, then the continuous gas analyzer results must be used. If c ontinuous gas analyzer is not available, either install a continuous gas anal yzer or take quarterly gas samples from the inlet gas stream to determine Vol I according to methods set forth in section 95154(b). (7) Determine volume fraction of CO 2 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 th e 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 Green house Gas

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(B) If a continuous gas analyzer is not available o r installed, quarterly gas samples may be taken from the outlet gas stream to determine Vol O according to methods set forth in section 95154(b). (C) Use sales line quality specification for CO 2 in natural gas. (8) Calculate CO 2 volumetric emissions at standard conditions using c alculations in paragraph (r) of this section. (9) Mass CO 2 emissions shall be calculated from volumetric CO 2 emissions using calculations in paragraph (t) of this section. (10) Determine if emissions from the AGR unit are r ecovered and transferred outside the facility. Adjust the emission estimate d in paragraphs (c)(1) through (c)(10) of this section downward by the magnitude o f emission recovered and transferred outside the facility. (d) Dehydrator vents. For dehydrator vents, calculate annual CH 4 , CO 2 , and N 2 O emissions using any of the calculation methodologie s 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 coeffic ient, speciates CH 4 and CO 2 emissions from dehydrators, and has provisions to i nclude 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 m ust 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 pn eumatic/air pneumatic/electric). (E) Absorbent circulation rate. (F) Absorbent type: including triethylene glycol (T EG), 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 pa rameter by selecting one of the methods described in subparagraphs (1) – (4) below. 1. Use the wet natural gas composition as defined i n section 95153(s)(2).Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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California Air Resources Board 212 February 2015

2. If wet natural gas composition cannot be determi ned using paragraph 95153(s)(2) of this section, select a representativ e analysis. 3. The facility operator may use an appropriate sta ndard method published by a consensus-based standards organizati on or the facility operator may use an industry standard prac tice 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 reco very. Adjust the emissions estimated in paragraphs (d)(1) or (d)(4) of this se ction downward by the magnitude of emissions captured. (3) Calculate annual emissions from dehydrator vent s to flares or regenerator firebox/fire tubes as follows: (A) Use the dehydrator vent volume and gas composit ion 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 ve ssel when it is depressurized for the desiccant refilling process u sing Equation 5 of this section.

d , = P l ∗ W j ∗ m ∗ %n ∗ L j / 4 ∗ L

< $ $ (Eq. 5)

Where: E S,n = Annual natural gas emissions at standard conditi ons 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 (e xpressed as a decimal, e.g.,15% = 0.15).

P 1 = Atmospheric pressure (psia).

P 2 = Pressure of the gas (psia). (5) For glycol dehydrators, both CH 4 and CO 2 mass emissions must be calculated from volumetric GHG i emissions using calculations in paragraph (t) of t his section. For dehydrators that use desiccant, both CH 4 and CO 2 volumetric and mass emissions must be calculated from volumetr ic natural gas emissions using calculations in paragraphs (s) and (t) of thi s section.Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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California Air Resources Board 213 February 2015 (e) Well venting for liquids unloadings. Calculate CO 2 and CH 4 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 sect ion. (1) Calculation Methodology 1 . Calculate the total emissions for well venting f or liquids unloading without plunger lift assist using Equation 6 of this section.

d , = ∑ q k

r ∗ s 0.37 ∗ 10 v $ ∗ W r j ∗ W r ∗ wL

r x + ∑ y whz r ∗ y lz r,{ − 1.0 | ∗ } r,{ | ~  r;< Ä Å r;< (Eq. 6) Where: E S,n = Annual natural gas emissions at standard conditi ons, 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 u nloading in the basin.

CD p = Casing diameter for each well, p, in inches.

WD p = Well depth from either the top of the well or th e lowest packer to the bottom of the well, for each well, p, in feet.

SP p = For each well, p, shut-in pressure or surface pr essure for wells with tubing production and no packers or casing pressure for each well, p, in pounds per square inch absolute (psia).

V p = Number of unloading events per year per well, p.

SFR p = Average flow-line rate of gas for well p, at sta ndard conditions in cubic feet per hour. Use Equation 29 to calculate the av erage flow-rate at standard conditions.

HR p,q = Hours that each well, p, was left open to the atm osphere during each unloading event, q. 1.0 = Hours for average well to blowdown casing vol ume at shut-in pressure.

Z p,q = If HR p,q is less than 1.0 then Z p,q is equal to 0. If HR p,q is greater than or equal to 1.0 then Z p,q is equal to 1. (A) Both CH 4 and CO 2 volumetric and mass emissions shall be calculated from volumetric natural gas emissions using calcula tions 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 , = ∑ q k

r ∗ s 0.37 ∗ 10 v $ ∗ _W r j ∗ W r ∗ wL

r x + ∑ y whz r ∗ y lz r,{ − 0.5 | ∗ } r,{ | ~  {;< Ä Å r;< (Eq. 7) Where: E S,n = Annual natural gas emissions at standard conditi ons, in cubic feet/year.Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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California Air Resources Board 214 February 2015

W = Total number of well venting liquid unloading e vents 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 pou nds per square feet).

TD p = Tubing internal diameter for each well, p, in in ches.

WD p = Tubing depth to plunger bumper for each well, p, in feet.

SP p = Flow-line pressure for each well, p, in pounds p er square inch absolute (psia).

V p = Number of unloading events per year for each wel l, p.

SFR p = Average flow-line rate of gas for well, p, at st andard conditions in cubic feet per hour. Use Equation 29 to calculate the average flow-line rate at standard conditions.

HR p,q = Hours that each well, p, was left open to the atm osphere during each unloading, q. 0.5 = Hours for average well to blowdown tubing vol ume at flow-line pressure.

Z p,q = If HR p,q is less than 0.5, then Z p,q is equal to 0. If HR p,q is greater than or equal to 0.5, then Z p,q is equal to 1. (3) Both CH 4 and CO 2 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 w orkovers . Using one of the calculation methodologies in this paragraph (f)(1) through (f)(5) below, operators must calculate CH 4 , CO 2 and N 2 O (when flared) annual emissions from gas well venting during both conventional completions and co mpletions involving hydraulic fracturing in wells and during both conventional we ll 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 lin e ahead of a flare or vent id used. The facility operator must correct total gas volume vented for the volume of CO 2 or N 2 :

d  = 	 k

É − 	k

ÑÖÜ	áà	âÜ (Eq. 8)

Where: E a = Gas emissions during the well completion or work over at actual conditions (m 3 ).

V M = Volume of vented gas measured during well complet ion or workover (m 3 ).

V CO2 or N2 = Volume of CO 2 or N 2 injected during well completion or workover (m 3 ).Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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(A) All gas volumes must be corrected to standard t emperature and pressure using methods in section(r). (B) Calculate CO 2 and CH 4 volumetric and mass emissions using the methodologies in sections (s) and (t). (2) Calculation Methodology 2. (A) Record the well flowing pressure upstream (P 1 ) and downstream (P 2 ) of a well choke, upstream temperature and elapsed time o f venting according to methods set forth in section 95154(b) to calcula te the well backflow during well completions and workovers. (B) The operator must record this data at a time in terval (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 P 2 /P 1 ≤ 0.542. (D) Calculate the average flow rate during sonic co nditions using Equation 9 of this section:

hz  = 1.27 ∗ 10 ã ∗ ! ∗ å 187.08 ∗ _  (Eq. 9)

Where: FR a = Average flow rate in cubic feet per hour, under actual sonic flow conditions. A = Cross sectional open area of the restriction or ifice (m 2 ).

T u = Upstream temperature (degrees Kelvin).

187.08 = Constant with units of m 2 /(sec 2 x K).

1.27 x 10 5 = Conversion from m 3 /second to ft 3

/hour.

(E) Calculate total gas volume vented during sonic flow conditions as follows:

k  = hz  ∗ _

 (Eq. 10)

Where: V s = Volume of gas vented during sonic flow condition s (scf).

T S = Length of time that the well vented under sonic conditions (hours). (F) For each of the sets of data points (T u , P 1 , P 2 , and elapsed time under subsonic flow conditions) recorded as the well vent ed under subsonic flow conditions, calculate the instantaneous gas fl ow rate as follows:

hz  = 1.27 ∗ 10 ã ∗ ! ∗ å3430 ∗ _

 ∗ V L j /L < $ <.ã<ã

− L

j /L < $ <.éãè \ (Eq. 11)

Where: FR a = Instantaneous flow rate in cubic feet per hour, under actual subsonic flow conditions. A = Cross sectional open area of the restriction or ifice (m 2 ).Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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California Air Resources Board 216 February 2015

P 1 = Upstream pressure (psia).

T u = Upstream temperature (degrees Kelvin).

P 2 = Downstream pressure (psia).

3430 = Constant with units of m 2 /(sec 2 xK).

1.27 x 10 5 = Conversion from m 3 /second to ft 3

/hour. (G) Calculate the total gas volume vented during su bsonic flow conditions, V SS , as the total volume under the curve of a plot of FR a and elapsed time under subsonic flow conditions. (H) Correct V SS to standard conditions using the methodology found in paragraph (r) of this section. (I) Sum the vented volumes during subsonic and soni c flow and adjust vented emissions for the volume of CO 2 and N 2 injected and the volume of gas recovered to a sales line as follows:

d  = k  + k  − k

êëÜ

íÜ − k ì (Eq. 12)

Where: E s = Total volume of gas vented during the well compl etion or workover (scf).

V s = Volume of gas vented during sonic flow condition s for the well completion or workover (scf) (see Eq. 10).

V ss = Volume of gas vented during subsonic flow condit ions for the well completion or workover (scf) (see 95153(f)(2)(G) ab ove).

V CO2/N2 = Volume of CO 2 or N 2 injected during the well completion or workover (scf).

V SG = Volume of gas recovered to a sales line during t he well completion or workover (scf). (3) The volume of CO 2 or N 2 injected into the well reservoir during energized hydraulic fractures must be measured using an appro priate 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 usi ng calculations in paragraph (r) of this section. (4) Determine if the backflow gas from the well com pletion or workover is recovered with purpose designed equipment that sepa rates 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 V SG in Equation 8 of this section to adjust the emissi ons estimated in paragraphs (f)(1) through (f)(4) of th is section by the magnitude of emissions captured using purpose desig ned equipment thatLegal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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California Air Resources Board 217 February 2015

separates saleable gas from the backflow as determi ned by engineering estimate based on best available data. (B) Calculate gas volume at standard conditions usi ng calculations in paragraph (r) of this section. (5) Both CH 4 and CO 2 volumetric and mass emissions must be calculated f rom volumetric total emissions using calculations in pa ragraphs (s) and (t) of this section. (g) Equipment and pipeline blowdowns . Calculate CO 2 and CH 4 blowdown emissions from depressurizing equipment and natural gas pipel ines to reduce system pressure for planned or emergency shutdowns resulti ng from human intervention or to take equipment out of service for maintenance (e xcluding depressurizing to a flare, over-pressure relief, operating pressure con trol venting and blowdown of nonGHG gases; desiccant dehydrator blowdown venting be fore 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 bo ttles, and vessels) between isolation valves determined by engineering estimate s based on best available data. Engineering estimates based on best availabl e data may also be used to determine the temperature and pressure variables used in the Equations 13 and 14 if monitoring data is unavailable. Equipmen t blowdowns with a unique physical volume (including pipelines, compressor ca se or cylinder manifolds, suction bottles, discharge bottles and vessels) of less than 50 cubic feet (cf) between isolation valves are not subject to the req uirements of 95153(g). (2) Calculate the total annual venting emissions fo r unique volumes using either Equation 13 or 14 of this section.

d , = î ∗ sk s ïãñ.óéò ô $ ö ïãñ.óéò

ö $ ô x − k ∗ x (Eq. 13)

Where: E s,n = Annual natural gas venting emissions at standard conditions from blowdowns in cubic feet.

N = Number of occurrences of blowdowns for each uni que physical volume in the calendar year. V = Unique physical volume (including pipelines, co mpressors and vessels) between isolation valves in cubic feet. C = Purge factor that is 1 if the unique physical v olume is not purged or zero if the unique physical volume is purged using non-GHG gases.

T s = Temperature at standard conditions (60 ̊F).

T a = Temperature at actual conditions in the unique p hysical volume ( ̊F).

P s = Absolute pressure at standard conditions (14.7 p sia).

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California Air Resources Board 218 February 2015 d , = ∑ ∑ Vk 459.67 + _  $ L ,,r $ − L ,,r $ $/ 459.67 + _ ,r $	L  $\  < ~ < (Eq. 14)

Where: E s,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 uni que physical volume. V = Total physical volume (including pipelines, com pressors and vessels) between isolation valves in cubic feet for each blo wdown “p”.

T s = Temperature at standard conditions (60 ̊F).

T a,p = Temperature at actual conditions in the unique p hysical volume ( ̊F).

P s = Absolute pressure at standard conditions (14.7 p sia).

P a,b,p = Absolute pressure at actual conditions in the un ique physical volume (psia) at the beginning of the blowdown “p”.

P a,e,p = Absolute pressure at actual conditions in the un ique physical volume (psia) at the end of the blowdown “p”; 0 if blowdow n volume is purged using non-GHG gases. (3) Calculate both CH 4 and CO 2 volumetric and mass emissions using calculations in paragraph (s) and (t) of this secti on. (4) Calculate total annual venting emissions for al l blowdown vent stacks by adding all standard volumetric and mass emissions d etermined by Equation 13 or 14 and paragraph (g)(3) of this section. (h) Dump Valves. Calculate emissions from occurren ces 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 compr ession and onshore petroleum and natural gas production, the operator of a facil ity must calculate CH 4 , CO 2 and N 2 O annual emissions from condensate scrubber dump va lve leakage as follows: (1) Monitor the tank vapor vent stack annually for emissions using an optical gas imaging instrument according to methods set forth i n 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 i n section 95154(b). Or the facility operator may annually monitor leakage thro ugh 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 Green house Gas

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California Air Resources Board 219 February 2015 (2) If the tank vapors from the vent stack are cont inuous 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, calibrate d bag, or high flow sampler to estimate tank vapor volumes from the ven t stack according to methods set forth in section 95154(b) through (d). If a continuous flow measurement device is not installed, the facility o perator 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 s crubber dump valve connected to the tank according to the method set f orth in section 95154(a)(5). (C) Use the appropriate gas composition in paragrap h (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 ye ar. If the leaking dump valve is fixed following leak detection, the leak d uration 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 t o flares as follows: (A) Use the storage tank emissions volume and gas c omposition as determined in paragraphs (i)(1) through (i)(3) of t his 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 CH 4 , CO 2 and N 2 O (when flared) gas and oil well testing venting and flaring emissions as follows: (1) Determine the gas-to-oil ratio (GOR) of the hyd rocarbon 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 ac cording to one of the two procedures in paragraph (j)(2) of this section to d etermine GOR. (A) The facility operator may use an appropriate st andard method published by a consensus-based standards organization if such a method exists; or (B) The facility operator may use an industry stand ard practice as described in section 95154(b).Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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California Air Resources Board 220 February 2015 (3) Estimate venting emissions using Equation 15 (f or oil wells) or Equation 16 (for gas wells) of this section.

d , = n#z ∗ hz ∗ W (Eq. 15)

d , = Lz ∗ W (Eq. 16)

Where: E S,n = Annual volume of gas emissions from well(s) testi ng in cubic feet under actual conditions.

E a,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 c ubic feet of gas per barrel of oil; oil here refers to hydrocarbon liquids produce d 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 t ested. (4) For equation 16 calculate natural gas volumetri c emissions at standard conditions using calculations in paragraph (r) of t his section. (5) Calculate both CH 4 and CO 2 volumetric and mass emissions from volumetric natural gas emissions using the calculations in par agraphs (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 c omposition 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 th e flare. (k) Associated gas venting and flaring. Calculate CH 4 , CO 2 and N 2 O (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 s ame 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 d etermine GOR. (A) Use an appropriate standard method published by a consensus-based standards organization if such a method exists, inc luding ARB’s sampling methodology and flash liberation test procedure in Appendix B of this regulation; orLegal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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California Air Resources Board 221 February 2015

(B) The facility operator may use an industry stand ard practice as described in section 95154(b). (3) Estimate venting emissions using Equation 17 of this section.

d , = ∑ n#z r,{

g r;< ∗ k

r,{ (Eq.17)

Where: E a,n = Annual volumetric natural gas emissions, at the f acility level, from associated gas venting under actual conditions, in cubic feet.

GOR p,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 produce d of all API gravities.

V p,q = Volume of oil produced, for well p in basin q, in barrels in the calendar year during which associated gas was vented or flar ed.

x = Total number of wells in the basin that vent or flare associated gas. (4) Calculate natural gas volumetric emissions at s tandard conditions using calculations in paragraph (r) of this section. (5) Calculate both CH 4 and CO 2 volumetric and mass emissions from volumetric natural gas emissions using calculations in paragra phs (s) and (t) of this section. (6) Calculate emissions from associated gas to flar es as follows: (A) Use the associated natural gas volume and compo sition 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 CO 2 , CH 4 and N 2 O emissions from a flare stack or other destruction d evice as follows: (1) For the purposes of this reporting requirement, the facility operator must calculate emission from all flares, incinerators, o xidizers and vapor combustion units. (2) If a continuous flow measurement device is inst alled on the flare or destruction device, the measured flow volumes must be used to c alculate 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 devic e, then the flow not measured can be estimated using engineering calcula tions 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 bes t 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 Green house Gas

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California Air Resources Board 222 February 2015

(A) For onshore natural gas processing, when the st ream going to the flare is natural gas, use the GHG mole percent in feed natur al gas for all streams upstream of the de-methanizer or dew point control, and GHG mole percent in facility specific residue gas to transmi ssions pipeline systems for all emissions sources downstream of the de-meth anizer overhead or dew point control for onshore natural gas processin g facilities. For onshore natural gas processing plants that solely f ractionate a liquid stream, use the GHG mole percent in feed natural ga s liquid for all streams. (B) For any applicable industry segment, when the s tream going to the flare is a hydrocarbon product stream, such as methane, e thane, 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 manu facturer specifications. If not available, assume that flare combustion efficiency is 98 percent. (5) Calculate GHG volumetric emissions at actual co nditions using Equations 18 and 19 of this section.

d ,ï = k

 ∗ ù ï ∗ V 1 − ƞ $ ∗ } ü + } † \ (Eq. 18)

d ,j = k

 ∗ ù j + ∑ yƞ ∗ k

 ∗ ° ¢ ∗ z ¢ ∗ } ü | ã ¢;< (Eq. 19)

Where: E a,CH4 = Annual CH 4 emissions from flare stack in cubic feet, under ac tual conditions.

E a,CO2 = Annual CO 2 emissions from flare stack in cubic feet, under ac tual conditions.

V a = Volume of gas sent to flare in cubic feet, durin g the year. Ƞ = Fraction of gas combusted by a burning flare (de fault is 0.98). For gas sent to an unlit flare, ƞ is zero.

X CH4 = Mole fraction of CH 4 in gas to the flare.

Z L = Fraction of the feed gas sent to a burning flare (equal to 1 – Z U ).

Z U = Fraction of the feed gas sent to an unlit flare determined by engineering estimate and process knowledge based on best availa ble data and operating records.

X CO2 = Mole fraction of CO 2 in gas to the flare.

Y j = Mole fraction of gas hydrocarbon constituents j ( such as methane, ethane, propane, and pentanes-plus).

R j = Number of carbon atoms in the gas hydrocarbon co nstituent 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 Green house Gas

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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 CH 4 and CO 2 mass emissions from volumetric CH 4 and CO 2 emissions using calculation in paragraph (t) of thi s section. (8) Calculate N 2 O 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 CO 2 concentration monitor and volumetric flow rate moni tor, calculate only CO 2 emissions for the flare. The facility operator mus t follow the Tier 4 Calculation Methodology and all associated calculation, quality assurance, reporting, and record keeping requirements for Tier 4 in section 9 5115. If a CEMS is used to calculate flare stack emissions, the requirements s pecified in paragraphs (l)(1) through (l)(8) are not required. If a CO 2 concentration monitor and volumetric flow rate monitor are not available, the facility o perator may elect to install a CO 2 concentration monitor and a volumetric flow rate m onitor that comply with all of the requirements specified for the Tier 4 Ca lculation Methodology in section 95115 of this article (stationary fuel comb ustion sources). (10) The flare emissions determined under paragraph (l) of this section must be corrected for flare emissions calculated and report ed under other paragraphs of this section to avoid double counting of these e missions. (11) If source types in section 95153 use Equations 18 and 19 of this section, use volume under actual conditions for the parameter, V a , in these equations. (m) Centrifugal compressor venting. Calculate CH 4 , CO 2 and N 2 O (when flared) emissions from both wet seal and dry seal centrifug al compressor vents as follows: (1) For each centrifugal compressor with a rated ho rsepower 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 cale ndar year. Measure emissions from all vents (including emissions manif olded to common vents) including wet seal oil degassing vents, unit isolat ion valve vents, and blowdown valve vents. Record emissions from the fo llowing vent types in the specified compressor modes during the annual measur ement:

(A) Operating mode, blowdown valve leakage through the blowdown vent, wet seal and dry seal compressors. For all centrif ugal compressor start-ups where natural gas is used as spin-up or s tarting gas (i.e. not combusted in the compressor), venting of this gas m ust be quantified and reported as follows:

d ì = ∑ k

£ 1 − h $ °

  < (Eq. 20)

Where:

E SGi = Annual GHG i (CO 2 and CH 4 ) vented emissions at standard conditions in cubic feet.Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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California Air Resources Board 224 February 2015

n = number of compressor start-ups using spin gas.

V sg = Volume of spin-up gas in standard cubic feet det ermined by metering or engineering estimates based on best ava ilable 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.

Y i = Mole fraction of GHG i in the vent gas.

Calculate both CH 4 and CO 2 mass emissions from volumetric emissions using calculations in paragraph (t) of th is section. (B) Operating mode, wets seal oil degassing vents. (C) Not operating depressurized mode, unit isolatio n valve leakage through open blowdown vent, without blind flanges, wet seal and dry seal compressors. 1. For the not operating depressurized mode, each c ompressor must be measured at least once in any three consecutive cal endar 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 wit hout blind flanges in place and is not operated throughout the three year period, it must be measured in the standby depressurized mo de. 2. An engineering estimate approach based on simila r equipment specifications and operating conditions may be used to determine the MT m variable in place of actual measured values for cen trifugal compressors that are operated for no more than 200 hours in a calendar year and used for peaking purposes in plac e of metered gas emissions if an applicable meter is not present on the compressor. (2) For wet seal oil degassing vents, determine vap or volumes sent to an atmospheric vent or flare, using a temporary meter such as a vane anemometer or permanent flow meter according to sec tion 95154(b) of this section. If a permanent flow meter is not installe d, 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 baggin g or high volume sampler according to methods set forth in sections 95154(c) and 95154(d), respectively. For through valve leakage, such as i solation valves, the facility operator may install a port for insertion of a temp orary meter, or a permanent flow meter, on the vents. (4) To determine Y i , use gas composition data from a continuous gas an alyzer 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 Green house Gas

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California Air Resources Board 225 February 2015 (5) Estimate annual emissions using the flow measur ement and Equation 21 of this section.

d ,,e = ∑ Z_

e e ∗ _

e ∗ °  ∗ 1 − h $ (Eq. 21)

Where: E s,i,m = Annual GHG (either CH 4 or CO 2 ) volumetric emissions at standard conditions, in cubic feet.

MT m = Measured gas emissions in standard cubic feet pe r hour during operating mode m as described in sections (m)(1)(A) through (m)(1)(C).

T m = Total time the compressor is in the mode for whi ch E s,i is being calculated, in the calendar year in hours.

Y i = Mole fraction of GHG i in the vent gas. CF = Fraction of centrifugal compressor vent gas th at 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 t he amount of gas that is directed to the fuel gas or vapor recovery system. (6) For each centrifugal compressor with a rated ho rsepower 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 t his section.

d , = RcPQ ∗ dh

 (Eq. 22)

Where: E s,i = Annual total volumetric GHG emissions at standard conditions from centrifugal compressors (<250hp) in cubic feet.

Count = Total number of centrifugal compressors less tha n 250hp.

EF i = Emission factor for GHGi. Use 1.2 x 10 7 standard cubic feet per year per compressor for CH 4 and 5.30 x 10 5 standard cubic feet per year per compressor for CO 2 at 60 ̊F and 14.7 psia. (7) Calculate both CH 4 and CO 2 mass emissions from volumetric emissions using calculations in paragraph (t) of this section. (8) Calculate emissions from seal oil degassing ven t vapors to flares as follows: (A) Use the seal oil degassing vent vapor volume an d gas composition as determined in paragraphs (m)(2) through (m)(4) of t his 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 CH 4 and CO 2 , and N 2 O (when flared) emissions from all reciprocating compressor vents a s 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 measur ement for eachLegal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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California Air Resources Board 226 February 2015

compressor in each operating mode in which it is fo und for more than 200 hours in a calendar year. Measure emissions from ( including emissions manifolded to common vents) reciprocating rod packi ng vents, unit isolation valve vents, and blowdown valve vents. Record emis sions 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 emiss ions. (C) Not operating depressurized mode, unit isolatio n 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 thro ughout the three year period, measurement is not required in this mo de. If the compressor is in standby depressurized mode without blind flanges in place and is not operated throughout the three y ear period, it must be measured in the standby depressurized mode. 2. An engineering estimate approach based on simila r equipment specifications and operating conditions may be used to determine the MT m variable in place of actual measured values for rec iprocating compressors that are operated for no more than 200 hours in a calendar year and used for peaking purposes in plac e 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 metho ds to calculate emissions: (A) Measure emissions from all vents (including emi ssions manifolded to common vents) including rod packing, unit isolation valves, and blowdown vents using either calibrated bagging or h igh 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) i ncluding rod packing vents and unit isolation valve leakage through blow down vents according to methods set forth in section 95154(b). If a per manent 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 ve nts. For throughvalve leakage to open ended vents such as unit isol ation valves on not operating, depressurized compressors, use an acoust ic detection device according to methods set forth in section 95154(a).Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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California Air Resources Board 227 February 2015 (3) If reciprocating rod packing is not equipped wi th a vent line use the following method to calculate emissions: (A) The facility operator must use the methods desc ribed in section 95154(a) to conduct annual leak detection of equipment leaks from the packing case into an open distance piece, or from the compr essor crank case breather cap or other vent with a closed distance p iece. (B) Measure emissions found in paragraph (n)(2)(A) of this section using an appropriate meter, or calibrated bag, or high volum e sampler according to the methods set forth in sections 95154(b), (c), an d (d) respectively. (4) To determine Y i , use gas composition data from a continuous gas an alyzer 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 measur ement and Equation 23 of this section.

d ,,e = ∑ Z_

e e ∗ _

e ∗ Y  ∗ 1 − h $ (Eq. 23)

Where: E s,i,m = Annual GHG i (either CH 4 or CO 2 ) volumetric emissions at standard conditions, in cubic feet.

MT m = Measured gas emissions in standard cubic feet.

T m = Total time the compressor is in the mode for whi ch E s,i,m is being calculated, in the calendar year in hours.

Y i = Mole fraction of GHG i in the vent gas. CF = Fraction of reciprocal compressor vent gas tha t is sent to vapor recovery or fuel gas as determined by keeping logs of the nu mber 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: E s,i = Annual total volumetric GHG emissions at standard conditions from reciprocating compressors in cubic feet. Count = Total number of reciprocating compressors f or the facility operator.

EF i = Emission factor for GHG i . Use 9.48 x 10 3 standard cubic feet per year per compressor for CH 4 and 5.27 x 10 2 standard cubic feet per year per compressor for CO 2 at 60 ̊F and 14.7 psia.Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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California Air Resources Board 228 February 2015 (7) Estimate CH 4 and CO 2 volumetric and mass emissions from volumetric natu ral 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 detec tion(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 CH 4 plus CO 2 by weight. Component types in streams with gas content less than 10 percent CH 4 plus CO 2 by weight do not need to be reported. Tubing systems equal to or less th an 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 rep orting 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). U se Equation 26 for natural gas distribution facilities as defined in section 95150 (a)(8). Use methods found in section 95153(t) to convert GHG i volume emissions to GHG i mass emissions.

d , = nln  ∗ ∑ ydh ∗ _ r | g r;< (Eq. 25)

d , = nln  ∗ ∑ ∑ ydh ∗ _ r,{ | g r;<  {;ò< (Eq. 26)

Where: E s,i = Annual total volumetric GHG emissions at standar d 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.

GHG i = For onshore petroleum and natural gas production facilities, concentration of GHG i , CH 4 or CO 2 , in produced natural gas as defined in paragraph (s)(2)(A) of this section; For onshore na tural gas processing facilities, concentration of GHG i , CH 4 or CO 2 , in the total hydrocarbon of the feed natural gas; for onshore natural gas transmission compressi on and underground natural gas storage, GHG i equals 0.975 for CH 4 and 1.1 x 10 -2 for CO 2 ; for LNG storage and LNG import and export equipment, GHG i equals 1 for CH 4 and 0 for CO 2 ; and for natural gas distribution, GHG i equals 1 for CH 4 and 1.1 x 10 -2 for CO 2 or use the experimentally determined gas composition f or CO 2 and CH 4

. T p = The total time the component, p, was found leaki ng 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 le aking 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 lea king in the previous survey) or the beginning of the calendar year (if it was found leaking in the previousLegal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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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 o f the calendar year. t = Calendar year of reporting. n = The number of years over which one complete cyc le 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 fo r years that the data is available.

T p,q = The total time the component, p, was found leaki ng 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 m ultiple leak detection surveys are conducted, assume the component found to be lea king 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 las t 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 s urveys 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 fa cilities 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 Append ix A for equipment leaks detected from valves, connectors, open ended lines, pressure relief valves, and meters. (4) Onshore natural gas transmission facilities sha ll use the appropriate default leaker emission factors listed in Table 3 of Append ix 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, o pen ended lines, pressure relief valves, and meters. (6) LNG storage facilities shall use the appropriat e 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 fo r equipment leaks detected from valves, pump seals, connectors, and other equi pment.Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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California Air Resources Board 230 February 2015 (8) Natural gas distribution facilities for above g round transmission-distribution transfer stations, shall use the appropriate defaul t leak emission factors listed in Table 7 of Appendix A for equipment leaks detect ed from connectors, block valves, control valves, pressure relief valves, ori fice meters, regulators, and open ended lines. Leak detection at natural gas di stribution facilities is only required at above grade stations that qualify as tr ansmission-distribution transfer stations. Below grade transmission-distri bution transfer stations and all metering-regulating stations that do meet the d efinition 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 stat ion 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 gre ater than 10 percent CH 4 plus CO 2 by weight. Emissions sources in streams with gas c ontent less than 10 percent CH 4 plus CO 2 by weight do not need to be reported. Tubing syst ems equal to or less than one half inch diameter are exempt from th e requirements of paragraph (p) of this section and do not need to be reported. Ca lculate emissions from all sources listed in this paragraph using Equation 27 of this section.

d , = RcPQ  ∗ dh  ∗ nln  ∗ _

 (Eq. 27) Where: E s,i = Annual volumetric GHG emissions at standard condi tions from each component type in cubic feet.

Count s = Total number of this type of emission source at the facility. Underground natural gas storage shall count the com ponents listed for population emission factors in Table 4. LNG storag e shall count the number of vapor recovery compressors. LNG import and expo rt 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.

EF s = Population emission factor for the specific comp onent 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., acc ording to Table 1(A) – 1(C) of Appendix A. EF for meter/regulator runs at abov e grade metering-regulator stations is determined in Equation 28 of this secti on.
GHG i = For onshore petroleum and natural gas production facilities, concentration of GHG i , CH 4 or CO 2 , in produced natural gas as defined in paragraph (s)(2) of this section; for onshore natur al gas transmissionLegal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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California Air Resources Board 231 February 2015

compression and underground natural gas storage, GH G i equals 0.975 for CH 4 and 1.1 x 10 -2 for CO 2 ; for LNG storage and LNG import and export equipment, GHG i equals 1 for CH 4 and 0 for CO 2 ; for natural gas distribution, GHG i equals 1 for CH 4 and 1.1 x 10 -2 for CO 2 or use the experimentally determined gas composition for CO 2 and CH 4

. T s = Total time that each component type associated w ith the equipment leak emission was operational in the calendar year, in h ours, using engineering estimate based on best available data, assume T s = 8760 hours for section 95152(i)(10). (1) Calculate both CH 4 and CO 2 mass emissions from volumetric emissions using calculations in paragraph (t) of this section. (2) Onshore petroleum and natural gas production fa cilities must use the appropriate default population emission factors lis ted in Table 1A of Appendix A for equipment leaks from valves, connect ors, 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 a nd major natural gas equipment in reference to Table 1B of Appendix A. Major equipment and components associated with crude oil wells are cons idered crude service components in reference to Table 1A of Appendix A a nd 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 re cycle CO 2 stream. The component count can be determined using either of t he methodologies described in this paragraph (p)(2). The same metho dology 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 t he following activities: 1. Count all major equipment listed in Table 1B and Table 1C of Appendix A. For meters/piping, use one meters/pipi ng per well-pad. 2. Multiply major equipment counts by the average c omponent 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 op erations in Eastern and Western U.S. according to the mapping i n Table 1B of Appendix A. (B) Component Count Methodology 2 . Count each component individually for the facility. Use the appropriate factor in Ta ble 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 lis ted in Table 4 of Appendix A for equipment leak from connectors, valves, pressur e relief valves and open ended lines.Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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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 equipme nt leak from vapor recovery compressors. (5) LNG import and export facilities must use the a ppropriate emission factor listed in Table 6 of Appendix A for equipment leak from vapor recovery compressors. (6) Natural gas distribution facilities must use th e appropriate emission factors as described in paragraph (p)(6) of this section. (A) Below grade metering-regulating stations; distr ibution mains; distribution services; and customer meters must use the appropri ate default population emission factors listed in Table 7 of Ap pendix 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-regulat ing stations (including above grade T-D transfer stations) must be calculat ed by applying the emission factor calculated in Equation 28 and the t otal 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 b y 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 tr ansfer stations that were monitored over the years that constitute one c omplete 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 gra de metering-regulating stations only and do not have to comply with sectio n 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 GHG i in cubic feet per meter/regulator run per hour. E s,i = Annual volumetric GHG i emissions, CO 2 or CH 4 , at standard condition from each component type at all above grade T-D tra nsfer 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 c omplete cycle as per paragraph (o)(8)(A) of this section. 8760 = Conversion to hourly emissions. (q) Offshore petroleum and natural gas production facil ities. Operators must report CO 2 , CH 4 , and N 2 O emissions for offshore petroleum and natural gas production from all equipment leaks, vented emission, and flar e emission source types as identified in the data collection and emissions est imate study (Year 2008 GulfwideLegal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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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 jur isdiction must report the same annual emissions as calculated and reported by BOEM RE in data collection and emissions estimate study published by BOEMRE an d referenced in 30 CFR §§250.302 through 304 (July 1, 2011) Gulfwide O ffshore 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 pre vious year’s BOEMRE data and adjust the emissions based on the o perating time for the facility relative to the operating time in the previous year’s BOEMRE data. (2) Offshore production facilities that are not und er BOEMRE jurisdiction must use monitoring methods and calculation methodologies pu blished by BOEMRE and referenced in 30 CFR §§250.302 through 304 (Jul y 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 pre vious year’s BOEMRE data and adjust the emissions based on the o perating time for the facility relative to the operating time in the previous year’s BOEMRE data. (3) If BOEMRE discontinues or delays their data col lection 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 met hods to report emission from the facility sources. (4) For either the first or subsequent year of repo rting, offshore facilities either within or outside of BOEMRE jurisdiction that were not covered in the previous BOEMRE data collection cycle must use the BOEMRE da ta collection and emissions estimation methods published by BOEMRE an d 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 alrea dy at standard conditions, which results in volumetric em issions 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 s tandard conditions using actual natural gas emission temperature and pressure, and Equation 29 of this section.

d , = d , ∗ 459.67 + _  $ ∗ L  / 459.67 + _

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California Air Resources Board 234 February 2015 Where: E s,n = Natural gas volumetric emissions at standard temp erature and pressure (STP) conditions in cubic feet except E s,n equals (FR s,p ) for each well p, when calculating either subsonic or sonic flow rates und er section 95153(f).

E a,n = Natural gas volumetric emissions at actual condit ions in cubic feet.

T s = Temperature at standard conditions (60 ̊F).

T a = Temperature at actual conditions ( ̊F).

P s = Absolute pressure at standard conditions (14.7 p sia).

P a = 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: E s,i = GHG i volumetric emissions at standard condition s in cubic feet. Ea,i = GHG i volumetric emissions at actual conditi ons 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 temp erature 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 e ngineering estimate based on best available data unless otherwise specified. (1) Estimate CH 4 and CO 2 emissions from natural gas emissions using Equation 31 of this section.

d , = d , ∗ Z  (Eq. 31)

Where: E s,i = GHG i (either CH 4 or CO 2 ) volumetric emissions at standard conditions in cubic feet.

E s,n = Natural gas volumetric emissions at standard cond itions in cubic feet.

M i = Mole fraction of GHG i in the natural gas. (2) For Equation 31 of this section, the mole fract ion, M i , must be the annual average mole fraction for each basin or facility, a s 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 Green house Gas

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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. I f the facility has a continuous gas composition analyzer for produced na tural gas, the facility operator must use an annual average of these values for determining the mole fraction. If the facility does not have a con tinuous gas composition analyzer, then it must use an annual average gas co mposition based on the most recent available analysis of the facility. (B) GHG mole fraction in feed natural gas for all e missions sources upstream of the de-methanizer or dew point control and GHG m ole fraction in facility specific residue gas to transmission pipel ine system for all emissions sources downstream of the de-methanizer overhead or dew point control for onshore natural gas processing fa cilities. For onshore natural gas processing plants that solely fractiona te 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 det ermining the mole fraction. If the facility does not have a continuo us gas composition analyzer, then annual samples must be taken accordi ng to methods set forth in section 95154(b). (C) GHG mole fraction in transmission pipeline natu ral gas that passes through the facility for the onshore natural gas tr ansmission compression industry segment. If the facility has a continuous gas composition analyzer, the facility operator must use these valu es for determining the mole fraction. If the facility does not have a con tinuous gas composition analyzer, then annual samples must be taken accordi ng 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 con tinuous gas composition analyzer, the facility operator must use these valu es for determining the mole fraction. If the facility does not have a con tinuous gas composition analyzer, then annual samples must be taken accordi ng 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 comp osition analyzer, the facility operator must use these values for determi ning the mole fraction. If the facility does not have a continuous gas comp osition analyzer, then annual samples must be taken according to methods s et 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 valu es for determining the mole fraction. If the facility does not have a con tinuous gas composition analyzer, then annual samples must be taken accordi ng to methods set forth in section 95154(b).Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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California Air Resources Board 236 February 2015

(G) GHG mole fraction in local distribution pipelin e natural gas that passes through the facility for natural gas distribution f acilities. If the facility has a continuous gas composition analyzer, the facility o perator must use these values for determining the mole fraction. If the f acility does not have a continuous gas composition analyzer, then annual sa mples must be taken according to methods set forth in section 951 54(b). (t) GHG mass emissions. Calculate GHG mass emissions by converting the GH G volumetric emissions at standard conditions into ma ss emissions using Equation 32 of this section.

ZYUU  = d

, ∗ •  ∗ 10 v (Eq. 32)

Where: Mass i = GHG i (either CH 4 , CO 2 , or N 2 O) mass emissions in metric tons GHG i

. E s,i = GHG i (either CH 4 , CO 2 , or N 2 O) volumetric emissions at standard conditions, in cubic feet.

Ρ i = Density of GHG i . Use 0.0526 kg/ft 3 for CO 2 and N 2 O, and 0.0192 kg/ft 3 for CH 4 at 60 ̊F and 14.7 psia. (u) EOR injection pump blowdown. Calculate CO 2 pump blowdown emissions from EOR operations using critical CO 2 injection as follows:

ZYUU j = î ∗ k

¶ ∗ z ∗ nln  ∗ 10 v (Eq. 33)

Where: Mass CO2 = Annual EOR injection gas venting emissions in me tric tons from blowdowns. N = Number of blowdowns for the equipment in the ca lendar year.

R c = Density of critical phase EOR injection gas in k g/ft 3 . The facility operator may use an appropriate standard method published by a consensus based organization if such a method exists or the facilit y operator may use an industry standard practice to determine density of super-critical emissions.

V v = Total volume in cubic feet of blowdown equipment chambers (including pipelines, manifolds and vessels) between isolation valves.

GHG i = Mass fraction of GHG i in critical phase injection gas.

1x 10 -3 = Conversion factor from kilograms to metric tons. (v) Crude Oil, Condensate, and Produced Water Dissolved CO 2 and CH

4 . The operator must calculate dissolved CO 2 and CH 4 in crude oil, condensate, and produced water. This reporting requirement include s emissions from hydrocarbon liquids and water produced using EOR operations. E missions must be reported for crude oil, condensate, and produced water sent to s torage 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 Green house Gas

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California Air Resources Board 237 February 2015 (1) Calculate CO 2 and CH 4 emissions from crude oil, condensate, and produced water using Equation 33A:

d j/ï = w ∗ k $ y1 − kz ∗ d $ | (Eq. 33A)

Where: E CO2/CH4 = Annual CO 2 or CH 4 emissions in metric tons.

S = Mass of CO 2 or CH 4 liberated in a flash liberation test per barrel of crude oil, condensate, and produced water (as deter mined in paragraph (v)(1)(A)1. or mass of CO 2 or CH 4 recovered in a vapor recovery system per barrel of crude oil, condensate, or produced wa ter (as determined in paragraph (v)(1)(A)2. V = Barrels of crude oil, condensate, or produced w ater 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 sy stem (expressed as a decimal). (A) S (the mass of CO 2 or CH 4 per barrel of crude oil, condensate, or produced water) shall be determined using one of th e following methods:

1. Flash liberation test. Measure the amount of CO 2 and CH 4 liberated from crude oil, condensate, or produced water when the crude oil, condensate, or produced water changes temperature a nd pressure from well stream to standard atmospheric conditions , using ARB’s sampling methodology and flash liberation test proc edure entitled “Flash Emissions of Greenhouse Gases and Other Comp ounds from Crude Oil and Natural Gas Separator and Tank System s,” which is included as Appendix B of this article. The flash liberation test results must provide the metric tons of CO 2 and CH 4 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 CO 2 and CH 4 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 CO 2 and CH 4 in the gas stream using the gas stream volume and mole percentage of CO 2 and CH 4 as determined by a laboratory analysis of an annua l gas stream sample. c. Calculate S by dividing the total mass of CO 2 and CH 4 in the gas stream by the total volume, in barrels, of the crud e oil,Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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California Air Resources Board 238 February 2015

condensate, or produced water throughput of the sto rage tank system. d. Vapor recovery system measurements and analyses may include gases from crude oil, condensate, and produced wate r. 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 s eparation 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 specif ied in section 95152(i)(11), operators may either use measured dat a or use engineering estimation based on best available data to quantify the volume of natural gas released from pipeline dig-in events. Volumetric e missions must be converted into mass emissions of CO 2 and CH 4 using the applicable methods in paragraphs (r), (s), and (t) of this section. (x) Reserved. (y) Onshore petroleum and natural gas production and na tural gas distribution combustion emissions. Calculate CO 2 , CH 4 , and N 2 O combustion-related emissions from stationary or portable equipment, ex cept as specified in paragraph (y)(3) and (y)(4) of this section as follows: (1) If a fuel combusted in the stationary or portab le equipment is listed in Table C-1 of Subpart C of 40 CFR Part 98, or is a blend c ompletely consisting of one or more fuels listed in Table C-1, calculate emissi ons according to paragraph (y)(1)(A). If the fuel combusted is natural gas an d is of pipeline quality specification, use the calculation methodology desc ribed in paragraph (y)(1)(A) and the facility operator may use the emi ssion 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 f or each stream of hydrocarbon going to the combustion unit as specifi ed in paragraph (s)(2) of this section. If the fuel is field gas, process ve nt 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 comple tely consisting of one or more fuels listed in Table C-1 of Subpart C, calcul ate CO 2 , CH 4 , and N 2 O emissions according to any Tier listed in section 9 5115. (2) For fuel combustion units that combust field ga s, process vent gas, a blend containing field gas or process vent gas, or natura l gas that is not of pipeline quality, calculate combustion emissions as specifie d below:Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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California Air Resources Board 239 February 2015

(A) The operator may use company records, which inc ludes the common pipe method, to determine the volume of fuel combus ted in the unit during the reporting year. (B) If a continuous gas composition analyzer is ins talled and operational on fuel supply to the combustion unit, the operator mu st use these compositions for determining the concentration of g as hydrocarbon constituent in the flow of gas to the unit. If a c ontinuous 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 co nditions using Equations 35 and 36 of this section:

d ,j = ∑ ß k  ∗ ° j $ + ƞ ∑ k

 ∗ ° ¢ ∗ z ¢ ã ¢;< ® <j ;< (Eq. 35)

d ,ï = ∑ V k

 ∗ 1 − ƞ $ ∗ °

ï \ <j ;< (Eq. 36)

Where: E a , CO2 = Contribution of annual CO 2 emissions from portable or stationary fuel combustion sources in cubic feet, u nder actual conditions.

V a = Volume of fuel gas sent to combustion unit in cu bic feet, during the month.

Y CO2 = Monthly concentration of CO 2 constituent in gas sent to combustion unit.

E a,CH4 = Contribution of annual CH 4 emissions from portable or stationary fuel combustion sources in cubic feet, u nder actual conditions. Ƞ = Fraction of gas combusted for portable and stati onary equipment determined using an engineering estimation. For in ternal combustion devices, a default of 0.995 can be used.

Y j = Monthly concentration of gas hydrocarbon constit uent j (such as methane, ethane, propane, butane and pentanes plus) in gas sent to combustion unit.

R j = Number of carbon atoms in the gas hydrocarbon co nstituent j; 1 for methane, 2 for ethane, 3 for propane, 4 for but ane, and 5 for pentanes plus, in gas sent to combustion unit.

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California Air Resources Board 240 February 2015

Calculate CO 2 and CH 4 , volumetric emissions at standard conditions using the provisions of section 95153(r). Use the provis ions in sections 95153(s) and (t) to convert volumetric gas emission s to GHG volumetric and GHG mass emissions respectively.

(D) Calculate N 2 O mass emissions using Equation 37 of this section.

ZYUU j = 1	]	10 v $ ∗ hcM` ∗ llk ∗ dh (Eq. 37)

Where: Mass N2O = Annual N 2 O emissions from the combustion of a particular typ e of fuel (metric tons N 2 O). Fuel = Mass or volume of the fuel combusted (mass o r volume per year, choose appropriately to be consistent with the unit s 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 N 2 O/MMBtu.

1 x 10 -3 = Conversion factor from kilograms to metric tons. (3) External fuel combustion sources with a rated h eat capacity equal to or less than 5 MMBtu/hr do not need to report combustion em issions or include these emissions for threshold determination in section 95 101(e). The operator must report the type and number of each external fuel co mbustion unit. (4) Internal fuel combustion sources, not compresso r-drivers, with a rated heat capacity equal to or less than 1 MMBtu/hr (or equiv alent of 130 horsepower), do not need to report combustion emissions or inclu de these emissions for threshold determination in section 95101(e). The o perator must report the type and number of each internal fuel combustion un it. (5) Calculate sorbent CO 2 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 ga s emissions sources must be quality assured as applicable and as specified in t his section. Offshore petroleum and natural gas production facilities must adhere to th e monitoring and QA/QC requirements as set forth in 30 CFR §250 (July 1, 2011), which i s 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-valveLegal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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California Air Resources Board 241 February 2015 leakage from all source types listed in sections 95 153(i), (m), (n) and (o) that occur during a calendar year, except as provided in parag raph (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 mo nitoring 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 sh all 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 distan ces, and excluding requirements for video records (July 1, 2011, which is hereby incorporated by reference). Any emissions detected by the optical g as 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) m onitoring, in which case 10,000 ppm or greater is designated a leak. In add ition, facility operators must operate the optical gas imaging instrument to image the source types required by this subarticle in accordance with the instrumen t 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 elevat ing the monitoring personnel more than two meters above a support surf ace. (2) Method 21. Use the equipment leak detection methods in 40 CFR Part 60, appendix A-7, Method 21 (July 1, 2011). If using M ethod 21 monitoring, if an instrument reading of 10,000 ppm or greater is meas ured, a leak is detected. Inaccessible emissions sources, as defined in 40 CF R 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 i s 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 op erate the infrared laser beam illuminated instrument to detect the source types r equired by this subarticle in accordance with the instrument manufacturer’s opera ting 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 tha n 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 acous tic leak detection device to quantify the through-valve leakage, use the inst rument manufacturer’s calculation methods to quantify the through-valve l eak. When using theLegal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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acoustic leak detection device, if a leak of 3.1 sc f per hour or greater is calculated, a leak is detected. In addition, the f acility operator must operate the acoustic leak detection device to monitor the s ource valves required by this subarticle in accordance with the instrument m anufacturer’s operating parameters. Acoustic stethoscope type devices desi gned to detect through valve leakage when put in contact with the valve bo dy and that provide an audible leak signal but do not calculate a leak rat e can be used to identify nonleakers with subsequent measurement required to cal culate the rate if through-valve leakage is identified. Leaks are rep orted if a leak rate of 3.1 scf per hour or greater is measured. In addition, the f acility operator must operate the acoustic leak detection device to monitor the s ource valves required by this subarticle in accordance with the instrument m anufacturer’s operating parameters. (b) The operator must operate and calibrate all flo w meters, composition analyzers and pressure gauges used to measure quantities reported in section 95153 according to the procedures in section 95103(k) and the procedur es 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 consensu s-based standards organization if such a method exists or use an indu stry standard practice. (c) Use calibrated bags (also known as vent bags) o nly where the emissions are at near-atmospheric pressures and below the maximum te mperature specified by the vent bag manufacturer such that the vent bag is saf e 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 s ource to capture the entire emissions and record the time required for complete ly filling the bag. If the bag inflates in less than one second, assume one se cond 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 st andard conditions using calculations in section 95153(r). (4) Estimate CH 4 and CO 2 volumetric and mass emissions from volumetric natu ral gas emissions using the calculations in sections 95 153(s) and (t). (d) Use a high volume sampler to measure emissions within the capacity of the instrument. (1) A technician following manufacturer instruction s shall conduct measurements, including equipment manufacturer’s operating proced ures and measurement methodologies relevant to using a high volume sampl er, including positioning the instrument for complete capture of the equipmen t leak without creating backpressure on the source. (2) If the high volume sampler, along with all atta chments available from the manufacturer, is not able to capture all the emissi ons from the source then useLegal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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anti-static wraps or other aids to capture all emis sions without violating operating requirements as provided in the instrumen t manufacturer’s manual. (3) Estimate natural gas volumetric emissions at st andard conditions using calculations in section 95153(r). Estimate CH 4 and CO 2 volumetric and mass emissions from volumetric natural gas emissions usi ng 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 CH 4 by using calibrated gas samples by following manuf acturer’s instructions for calibration. (e) Peng-Robinson Equation of State means the equat ion of state defined by Equation 38 of this section.

X = ©

~ TM  $ − Y ́/ k

e j + 2 ̈k

e −  ̈ j $ (Eq. 38)

Where: p = Absolute pressure. R = Universal gas constant T = Absolute temperature. V m = Molar volume. Y = 0.45724z j _ j /X  ̈ = 0.7780z_ /X  ́ = s1 + 0.37464 + 1.54226­ − 0.26992­ j $ y1 − å _/_ |x j

Where:

ω = Acentric factor of the species. T c = Critical temperature. P c = 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 lo st or an error occurs during annual emissions estimation or measurements, the operator must repeat the estimation or measurement activity for those sources within the m easurement period. In cases where repeat sampling and/or analysis cannot be com pleted, the operator must follow the missing data substitution procedures out lined below: (1) To substitute for missing data for emissions re ported under section 95115 of this article (stationary combustion units and units using continuous emissions monitoring systems), the operator must follow the r equirements of section 95129 of this article.Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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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 generat e 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 substi tute for each missing value with the highest quality assured value record ed for the parameter during the given data year, as well as the two prev ious data years. (C) If the analytical data capture rate is less tha n 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 requir ements 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 qu antify 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 measu rement system meets the criteria in section 95103(k). Any changes in the covered produ ct 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 951 57, the operator of an onshore or offshore petroleum and natural gas production facil ity must report the following data for the facility, disaggregated within the basin by sub-facility : (1) CO 2 e emissions, including CO 2 , CH 4 , and N 2 O 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 cons umed within the facility (i.e., exported offsite or to another facility owne r/operator);Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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California Air Resources Board 245 February 2015 (4) For steam generator sources: (A) Total thermal energy generated (MMBtu) and the CO 2 e 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 CO 2 e emissions associated with this output; (5) For electricity generation sources not included in section 95156(a)(3): (A) Net electricity generation (MWh) and the CO 2 e emissions associated with this generation; (B) Amount of electricity generation (MWh) not cons umed within the facility (i.e., exported offsite or to another facility owne r/operator) and the portion of CO 2 e emissions associated with this generation; (6) Total steam (MMBtu) utilized but not generated at the facility and the CO 2 e emissions associated with this output, if known; (7) Barrels of crude oil produced using thermal enh anced oil recovery. This means the volume of crude oil produced within the f acility 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 f acility 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 fractio n piped as an emulsion as defined in section 95102(a). Associated gas may be quantified using production or sales meters as appropriate. Associa ted gas may also be quantified by multiplying the barrels of crude oil produced during the data year by a representative GOR measurement plus the repres entative GWR measurement multiplied by the produced water volume . When GOR and GWR measurements are used for quantifying associate d gas, these measurements must be the most disaggregated data av ailable (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 c ontent in MMBtu. HHV measurements must be collected and averaged consist ent 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 associate d gas fraction piped as an emulsion as defined in section 95102(a). Associate d gas may be quantified using production or sales meters as appropriate. As sociated gas may also be quantified by multiplying the barrels of crude oil produced during the data year by a representative GOR measurement plus the repres entative GWR measurement multiplied by the annual produced water volume. When GORLegal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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and GWR measurements are used for quantifying assoc iated gas, these measurements must be the most disaggregated data av ailable (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 c ontent in MMBtu. HHV measurements must be collected and averaged consist ent with the frequency requirements in 95153(y)(2)(D). (b) For dry gas production, the operator of an onsh ore petroleum and natural gas production facility must report its annual heat ene rgy of dry gas produced (MMBtu). The average HHV of the produced gas must be multipl ied by the data year volume to determine the heat energy in MMBtu. HHV measurem ents must be collected and averaged consistent with the frequency requirements in 95153(y)(2)(D); (c) The operator of a natural gas liquid fractionat ing facility, a natural gas processing facility, or an onshore petroleum and natural gas p roduction facility with a natural gas processing plant that processes less than 25 MM scf per day must report the annual production of the following natural gas liqu ids 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 pro duced 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 shal l 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 sectio n 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 he at 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 d etermine the heat energy inLegal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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California Air Resources Board 247 February 2015 MMBtu. HHV measurements must be collected and aver aged 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 producti on, report emissions of CH 4 , CO 2 , and N 2 O as applicable to the source type (in metric tons per year at standard conditions) individually for all of the emissions s ource 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 opera tes 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 un der this paragraph routes gas to flare, separately report the emissions that were vented directly to the atmosphere without flaring, and the emissions that resulted fr om 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 Equ ations 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 Green house Gas

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(C) Actual count and estimated count separately of natural gas pneumatic intermittent bleed devices, as applicable. (D) Report annual CO 2 and CH 4 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 pn eumatic devices; low bleed pneumatic devices. (2) For natural gas driven pneumatic pumps (refer t o Equation 1 and 2 of section 95153), report the following: (A) Count of natural gas driven pneumatic pumps. (B) Report annual CO 2 and CH 4 emissions at the facility level, expressed in metric tons for each gas, for all natural gas drive n pneumatic pumps combined. (3) For each acid gas removal unit (refer to Equati on 3 and Equations 4A-B of section 95153), report the following: (A) Total throughput of the acid gas removal unit u sing 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 M ethodology 2 of section 95153(c), annual fraction of CO 2 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 CO 2 content of natural gas into and out of the acid ga s removal unit (refer to section 95153(c)(6)). (D) Report the annual quantity of CO 2 , expressed in metric tons that was recovered from the AGR unit and transferred outside the facility, under section 95153. (E) Report annual CO 2 emissions for the AGR unit, expressed in metric to ns. (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 95 153(d)(1)), report the following: 1. Glycol dehydrator feed natural gas flow rate in MMscfd, determined by engineering estimate based on best available dat a. 2. Glycol dehydrator absorbent circulation pump typ e. 3. Whether stripper gas is used in glycol dehydrato r. 4. Whether a flash tank separator is used in glycol dehydrator.Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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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 CH 4 and CO 2 in wet natural gas. 9. What vent gas controls are used (refer to sectio ns 95153(d)(3) and (d)(4)). 10. For each glycol dehydrator, report annual CO 2 and CH 4 emissions that resulted from venting gas directly to the atmo sphere, expressed in metric tons for each gas. 11. For each glycol dehydrator, report annual CO 2 , CH 4 , and N 2 O emissions that resulted from flaring process gas fr om 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 dehydr ator. (B) For absorbent desiccant dehydrators (refer to E quation 5 of section 95153), report the following: 1. Count of desiccant dehydrators. 2. Report annual CO 2 and CH 4 emissions at the facility level, expressed in metric tons for each gas, for all absorbent desi ccant dehydrators combined. (5) For well venting for liquids unloading, report the following: (A) For Calculation Methodology 1 (refer to Equatio n 6 of section 95153(e)), report the following: 1. Count of wells vented to the atmosphere for liqu ids unloading. 2. Count of plunger lifts. Whether the well had a p lunger lift (yes/no). 3. Cumulative number of unloadings vented to the at mosphere. 4. Internal casing diameter or internal tubing diam eter 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 CO 2 and CH 4 emissions, expressed in metric tons for each gas. (B) For Calculation Methodologies 2 (refer to Equat ion 7 of section 95153(e)), report the following for each basin: 1. Count of wells vented to the atmosphere for liqu ids unloading.Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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2. Count of plunger lifts. 3. Cumulative number of unloadings vented to the at mosphere. 4. Average internal casing diameter, in inches, of each well, where applicable. 5. Report annual CO 2 and CH 4 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 t otal 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 tot al field count of oil well workovers by average depth (in thousands of feet) i n calendar year. 1. Total number of gas well workovers by average de pth (in thousands of feet) using hydraulic fracturing; 2. Total number of oil well workovers by average de pth (in thousands of feet) using hydraulic fracturing; (C) Report number of completions employing purposel y designed equipment that separates natural gas from the backflow and th e amount of natural gas, in standard cubic feet, recovered using engine ering 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 b est available data. (E) Annual CO 2 and CH 4 emissions that resulted from venting gas directly to the atmosphere, expressed in metric tons for each g as. (F) Annual CO 2 , CH 4 , and N 2 O emissions that resulted from flares, expressed in metric tons for each gas. (G) The following field average activity data for o il 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 Green house Gas

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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 follow ing: (A) For each unique physical volume that is blowdow n more than once during the calendar year, report the following: 1. Total number of blowdowns for each unique physic al volume, expressed in metric tons for each gas.

2. Annual CO 2 and CH 4 emissions for each unique physical blowdown volume, expressed in metric tons for each gas. 3. A unique name or ID number for the unique physic al 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 physica l volumes in the calendar year.

2. Annual CO 2 and CH 4 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 atmos pheric tanks: (A) If a wellhead separator dump valve is functioni ng improperly during the calendar year (refer to section 95153 (i)), report the following: 1. Count of wellhead separators that dump valve fac tor is applied.

2. Annual CO 2 and CH 4 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 usin g optical gas imaging instrument pursuant to section 95154(a) (refer to s ection 95153(i)), or acoustic leak detection of scrubber dump valves, report the following: (A) For each vent stack, report annual CO 2 and CH 4 emissions that resulted from venting gas directly to the atmosphere, expres sed in metric tons for each gas. (B) For each transmission storage tank, report annu al CO 2 , CH 4 and N 2 O emissions that resulted from flaring process gas fr om the transmission storage tank, expressed in metric tons for each gas

. (C) A unique name or ID number for the vent stack m onitored 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 ye ar. (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 Green house Gas

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(D) Report annual CO 2 and CH 4 emissions at the facility level, expressed in metric tons for each gas, emissions from well testi ng venting. (E) Report annual CO 2 , CH 4 and N 2 O emissions at the facility level, expressed in metric tons for each gas, emissions fr om 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 n atural gas in a calendar year. (B) Average gas-to-oil ratio for each basin. (C) Report annual CO 2 and CH 4 emissions at the facility level, expressed in metric tons for each gas, emission s from associate d natural gas venting. (D) Report annual CO 2 , CH 4 and N 2 O emissions at the facility level, expressed in metric tons for each gas, emissions fr om associated natural gas flaring. (12) For flare stacks (refer to Equation 18, 19, an d 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 y ear. (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 CH 4 emissions, in metric tons (refer to Equation 18 of section 95153). (G) Report CO 2 emissions, in metric tons (refer to Equation 19 of section 95153). (H) Report N 2 O 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 CO 2 emissions for the flare stack, indicate that a CEMS was used in the annual report and report the combusted CO 2 and uncombusted CO 2 as a combined number. (13) For each centrifugal compressor: (A) For compressors with wet seals in operational m ode (refer to Equation 21 and 22 of section 95153(m)), report the following f or 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 Green house Gas

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2. Fraction of vent gas recovered for fuel or sales or flared. 3. Annual throughput in million scf, use an enginee ring 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 com pressors measured (refer to Equation 21 of section 95153) and for com pressors 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 operati ng 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 shutdow n, 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 a ll modes of operation. (14) For reciprocating compressors: (A) For reciprocating compressors rod packing emiss ions with or without a vent in operating mode, report the following: 1. Annual throughput in million scf, use an enginee ring 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 mea sured (refer to Equation 23 of section 95153). (B) For reciprocating compressors blowdown vents no t 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 Green house Gas

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(C) For reciprocating compressors in not operating, depressurized mode report the following: 1. Total time the compressor is in not operating de pressurized mode. 2. Facility operator emission factor for isolation valve emissions in not operating mode, depressurized mode in cubic feet pe r hour. 3. Report the isolation valve leakage emissions in not operating, depressurized mode. (D) Report total annual compressor emissions from a ll modes of operation. (E) For reciprocating compressors in onshore petrol eum 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 (ref er 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 surv ey 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 con centrations of CH 4 and CO 2

. 3. Annual CO 2 and CH 4 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 CO 2 and CH 4 emissions, in metric tons for each gas by component type. (16) For local distribution companies, report the f ollowing: (A) Total number of above grade T-D transfer statio ns in the facility. (B) Number of years over which all T-D transfer sta tions will be monitored atLegal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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California Air Resources Board 255 February 2015

least once. (C) Number of T-D stations monitored in calendar ye ar. (D) Total number of below grade T-D transfer statio ns in the facility. (E) Total number of above grade metering-regulating stations (this count will include above grade T-D transfer stations) in the f acility. (F) Total number of below grade metering-regulating stations (this count will include below grade T-D transfer stations) in the f acility. (G) Leak factor for meter/regulator run developed i n Equation 28 of section 95153. (H) Number of miles of unprotected steel distributi on 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 servic es. (M) Number of protected steel distribution services

. (N) Number of plastic distribution services. (O) Number of copper distribution services. (P) Annual CO 2 and CH 4 emissions, in metric tons for each gas, from all below grade T-D transfer stations combined. (Q) Annual CO 2 and CH 4 emissions, in metric tons for each gas, from all above grade metering-regulating stations (including T-D transfer stations) combined. (R) Annual CO 2 and CH 4 emissions, in metric tons for each gas, from all below grade metering-regulating stations (including T-D transfer stations) combined. (S) Annual CO 2 and CH 4 emissions, in metric tons for each gas, from all distribution mains combined. (T) Annual CO 2 and CH 4 emissions, in metric tons for each gas, from all distribution services combined. (U) Annual CO 2 and CH 4 emissions, in metric tons for each gas, from customer meters serving residential, commercial, an d industrial customers, respectively. (V) Annual CO 2 and CH 4 emissions, in metric tons for each gas, from pipeline dig-ins. (W) Number of customer meters at residential, comme rcial, and industrial premises, respectively. (X) Number of pipeline dig-ins.Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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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 CO 2 and CH 4 emissions, expressed in metric tons for each gas. (18) For crude oil, condensate, and produced water dissolved CO 2 and CH 4 (refer to section 95153(v)), report the following: (A) Volume of crude oil produced in barrels per yea r. (B) Report annual CO 2 and CH 4 emissions at the basin level. (19) For onshore petroleum and natural gas producti on and natural gas distribution combustion emissions, report the following: (A) Cumulative number of external fuel combustion u nits with a rated heat capacity equal to or less than 5 MMBtu/hr, by type of unit. (B) Cumulative number of external fuel combustion u nits with a rated heat capacity larger than 5 MMBtu/hr, by type of unit. (C) Report annual CO 2 , CH 4 , and N 2 O 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 u nit. (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 u nits, not compressordrivers, with a rated heat capacity equal to or les s than 1 MMBtu/hr or 130 horsepower, by type of unit. (F) Report annual CO 2 , CH 4 and N 2 O 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 u nit. (G) Cumulative volume of fuel combusted in internal combustion units with a rated heat capacity larger than 1 MMBtu/hr or 130 h orsepower, 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 fa cilities may voluntarily report total thermal input (MMBtu) to EOR wells gen erated using renewable energy source(s) as defined in section 95 102(a).Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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California Air Resources Board 257 February 2015 (d) Report annual throughput as determined by engin eering 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 productio n, 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 re quirements 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 Green house Gas

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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 ReportingLegal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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California Air Resources Board A-2 February 2015 Table 1A Default Whole Gas Emission Factors for Onshore Petr oleum and Natural Gas Production

Onshore petroleum and natural gas production Emissi on factor (scf/hour/ component) Western U.S. Population Emission Factors All components, Gas Ser vice: 1
Valve 0.121 Connector 0.017 Open-ended line 0.031 Pressure relief valve 0.193 Low Continuous Bleed Pneumatic Device Vents 2 1.39 High Continuous Bleed Pneumatic Device Vents 2 37.3 Intermittent Bleed Pneumatic Device Vents 2 13.5 Pneumatic Pumps 3 13.3 Population Emission Factors

– All Components, Light Crud e Service: 4
Valve 0.05 Flange 0.003 Connector 0.007 Open-ended Line 0.05 Pump 0.01 Other 5 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 Other 5 0.003

1 For multi-phase flow that includes gas, use the ga s 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 ̊AP I are considered “light crude.”

5 “Other” category includes instruments, loading arm s, pressure relief valves, stuffing boxes, compressor seals, dump lever arms, and vents.

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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 Oi l 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 0Heatertreater 8 12 20 0 0

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California Air Resources Board A-4 February 2015 Table 2 Default Total Hydrocarbon Emission Factors for Onsh ore Natural Gas Processing

Onshore natural gas processing Emission Factor (scf/hour/component) Leaker Emission Factors

– Compressor Components, Gas Service Valve 1 14.84 Connector 5.59 Open-Ended Line 17.27 Pressure Relief Valve 39.66 Meter 19.33 Leaker Emission Factors

– Non

- Compressor Components, Gas Service Valve 1 6.42 Connector 5.71 Open-Ended Line 11.27 Pressure Relief Valve 2.01 Meter 2.93

1 Valves include control valves, block valves and reg ulator valves.

Table 3 Default Total Hydrocarbon Emission factors for Onsh ore Natural Gas Transmission Compression

Onshore Natural Gas Transmission compression Emissi on Factor (scf/hour/component) Leaker Emission Factors

– Compressor Components, Gas Service Valve 1 14.84 Connector 5.59 Open-Ended Line 17.27 Pressure Relief Valve 39.66 Meter 19.33 Leaker Emission Factors

– Non

- Compressor Components, Gas Service Valve 1 6.42 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 Vents 2 1.37 High Continuous Bleed Pneumatic Device Vents 2 18.20 Intermittent Bleed Pneumatic Device Vents 2 2.35

1 Valves include control valves, block valves, and r egulator valves.

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California Air Resources Board A-5 February 2015 Table 4 Default Total Hydrocarbon Emission Factors for Unde rground Natural Gas Storage

Underground natural gas storage Emission Factor (scf/hour/component) Leaker Emission Factors

– Storage Station, Gas Service Valve 1 14.84 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 Valve 1 0.1 Pressure Relief Valve 0.17 Open Ended Line 0.03 Population Emission Factor

– Other Components, Gas Service Low Continuous Bleed Pneumatic Device Vents 2 1.37 High Continuous Bleed Pneumatic Device Vents 2 18.20 Intermittent Bleed Pneumatic Device Vents 2 2.35

1 Valves include control valves, block valves and re gulator valves.

2 Emission Factor is in units of “scf/hour/device.

Table 5 Default Methane Emission Factors for Liquefied Natu ral Gas (LNG) Storage

LNG Storage Emission Factor (scf/hour/component) Leaker Emission Factors

– LNG storage Components, Gas and Liquid s Service Valve 1.19 Pump Seal 4.00 Connector 0.34 Other 1 1.77 Population Emission Factors

– LNG Storage Compressor, Gas Service Vapor Recovery Compressor 2 4.17

1 “other” equipment type should be applied for any e quipment type other than connectors, pumps, or valves.

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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 Emiss ion Factors

– LNG Terminals Components, Gas and Liquid Service Valve 1.19 Pump Seal 4.00 Connector 0.34 Other 1 1.77 Population Emission Factors

– LNG Terminal Compressor, Gas Service Vapor Recovery Compressor 2 4.17

1 “other” equipment type should be applied for any e quipment type other than connectors, pumps, or valves.

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California Air Resources Board A-7 February 2015 Table 7 Default Methane Emission Factors for Natural Gas Di stribution

Natural gas distribution Emission Factor (scf/hour/component) Leaker Emission Factors

– Above Grade M&R at City Gate Stations 1 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 psi g 1.30 Below Grade M&R Station, Inlet Pressure 100 to 3 00 psig 0.20 Below Grade M&R Station, Inlet Pressure <100 psi g 0.10 Population emission Factors

– Distribution Mains, Gas Service 4 Unprotected steel 12.58 Protected Steel 0.35 Plastic 1.13 Cast Iron 27.25 Population Emission Factors

– Distribution Services, Gas Service 5 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 excludin g 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.”

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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 SystemsLegal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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Air Resources Board B-2 February 2015 Test Procedure

Flash Emissions of Greenhouse Gases and Other Compo unds 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 natura l 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 dete rmine the composition and volume of gas released from the liquids while they change from reservoir to standard atmospheric conditions. The laboratory re sults are used in conjunction with throughput to calculate the emission rates per year. The sampling and lab analyses may also be conducted to evaluate emission s 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 alt ernative methodology is included for determining the specified emissions ra tes using measured vapor recovery system parameters provided the system meet s the requirements specified in Section 9.

2. PRINCIPLE AND SUMMARY OF TEST PROCEDURE

The sampling and laboratory methods specified in th is procedure are used to take samples of liquids and conduct a Flash Analysi s on crude oil or natural gas separator and tank systems and are based on America n Standards and Testing Materials (ASTM), US Environmental Protection Agenc y (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 samp ling. Typical sampling points are from pressurized Two-Phase or Three-Phas e Separators or vessels used to measure Percent Water Cut (e.g., Automatic Well Tester). The liquids found in these vessels contain gases that will flas h 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 emulsi on do not contain enough crude oil to be evaluated by a laboratory and are n ot 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 natur e of the laboratory analyses and the design of the sampling cylinders. Produced water cannot be displacedLegal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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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-Pis ton Cylinder.

The laboratory methods are used to measure the comp osition and volume of gas that flash from liquids while they cool or depressu rize 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 pe r 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 Gr eenhouse 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 ha ve an impact on the laboratory methods and the final results reported. All samples must be gathered in adherence with the minimum procedures a nd 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 c onnected to a vapor recovery system will produce non-representative res ults.

4.3 All pressure and temperature measurements must be acquired using calibrated instruments as described in Section 5. U n-calibrated equipment, including pressure or temperature gauges installed on vessels, may produce non-representative results. This may resul t in data errors when analyzing samples in a laboratory.

4.4 The analytical portion of this procedure must be c onducted by laboratories experienced with laboratory instrumentation, analyt ical methods, and the laboratory methods specified in this procedure.

5. EQUIPMENT SPECIFICATIONS

5.1 A pressure gauge capable of measuring liquid pressu re less than 200 pounds per square inch pressure within +/-10% accur acy.

5.2 A pressure gauge capable of measuring liquid pressu re greater than 200 pounds per square inch pressure within +/- 5% accur acy.

5.3 A temperature gauge capable of reading liquid tempe rature to within +/- 2 o F. The range of the gauge must be at least 32 to 2 00 o F.Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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Air Resources Board B-4 February 2015 5.4 A volume meter with a minimum of +/- 5% accuracy o ver the entire range of flow rates for which the meter is used. Volume meters must be calibrated annually against a NIST traceable standa rd.

6. TEST EQUIPMENT

6.1 A Double-Valve Cylinder filled with laboratory grad e water for crude oil or condensate or a Floating-Piston Cylinder for produc ed water.

6.2 A Graduated Cylinder to measure displaced laborator y grade water from a Double-Valve Cylinder.

6.3 A waste container suitable for capturing and dispo sing sample liquid.

6.4 High-pressure rated components and control valves t hat can withstand pressure under the same operating conditions as the vessel sampled.

6.5 A low-pressure and a high-pressure measuring devic e with minimum specifications listed in Section 5.

6.6 A temperature measuring device with minimum specif ications listed in Section 5.

6.7 A calibrated volume meter with temperature and pre ssure 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 preven t sample contamination.

7. SAMPLING METHODS

Pre-Sampling Requirements

Prior to gathering liquid samples, the sampling tec hnician must be provided with the vessel description, Throughput, Percent Water C ut, Days of Operation, and a description of the vapor recovery system on downstr eam 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 samp ling liquids that may contain proprietary compounds, such as those used i n hydraulic fracturing liquids, a Tentatively Identified Compound List mus t 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 usin g the Crude Oil orLegal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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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 li quids. This is accomplished by taking samples from different levels in a pressu rized separator, which may be a permanent or temporarily installed vessel. Liqui d 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 b e pressurized. Samples must not be taken from tanks or separators open to atmosphere.

When a liquid sample is gathered, the technician me asures the pressure and temperature of the liquid using the calibrated gaug es specified and records the vessel and liquid characteristics as reported by th e facility operator. The cylinder is then identified with a Cylinder Identification T ag (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 an d performs a Flash Analysis which measures the rate and composition of gas evol ved from the liquid while it cools and depressurizes to specified atmospheric co nditions.

7.1 CRUDE OIL OR CONDENSATE SAMPLING METHOD

The Crude Oil or Condensate Sampling Method is cond ucted by displacing laboratory grade water with pH between 5 and 7 from a Double-Valve Sampling Cylinder. Figure 1 illustrates a Double-Valve Cyli nder sampling train. The configuration shows a cylinder outfitted with high- pressure rated components that can be used for controlling the flow of liquid. Ca librated temperature (Gauge L) and pressure (Gauge M) gauges are included for cond ucting field measurements. Sample liquid enters the cylinder wh en water is displaced into a graduated cylinder. The amount of sample liquid co ntained in the cylinder is equal to the amount of laboratory grade water measu red in the graduated cylinder.Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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Air Resources Board B-6 February 2015 Figure 1

Double-Valve Cylinder Sampling Train

(a) If samples are to be shipped to a laboratory, c alculate 90% of the cylinder volume, which will be the volume of sample to gathe r. 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 f or flashing during shipping and to prevent an explosive situation from occurring. If samples are not going to be shipped to a laboratory, this s tep 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 clo sed, route the outlet of Valve B into a suitable waste container to purge sa mple liquid. Slowly open Valve B. Slowly open Valve A and allow air an d 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 posit ion.Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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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 pressur e from Gauge M while the liquid is filling the cylinder. Do not take te mperature or pressure measurements on stagnant liquid. If the sample is to be shipped as described in (a), continue displacing the laborator y grade water from the cylinder until 90% of the water is displaced. If t he cylinder is not going to be shipped, continue filling the cylinder with samp le 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 Val ve C or D is leaking, drain the cylinder into a suitable waste container and us e a different cylinder to obtain a new sample.

(k) Wrap the threaded connections of the cylinder w ith Teflon tape and cap using threaded metal caps to protect the threads an d ensure the cylinder is securely sealed for shipping.

(l) Identify the sample cylinder as specified in Se ction 8.

7.2 PRODUCED WATER SAMPLING METHOD

The Produced Water Sampling Method is conducted usi ng a Floating-Piston Cylinder. This allows the sample liquid to be extr acted 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 p sig 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 p roduced water from the cylinder without commingling the sample liquid with laboratory grade water.

Prior to gathering a sample, the technician first m easures the vessel pressure and temperature using the calibrated gauges specifi ed. The technician then bleeds off excess pressure from the piston to at le ast 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 l iquid from flashing gases within the sample cylinder.Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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Air Resources Board B-8 February 2015 Figure 2 shows a Floating-Piston Cylinder sample tr ain outfitted with high-pressure rated components. Calibrated tempera ture (Gauge L) and pressure (Gauge M and N) gauges are included for co nducting 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 clo sed, route the outlet of Valve B into a suitable waste container to purge sa mple liquid. Slowly open Valve A to the full-open position. Slowly ope n Valve B and allow liquid to purge. Continue purging until a consiste nt, 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 pressu re until the pressure indicated on Gauge N is equal to Gauge M. When bot h gauges read equal pressure, close Valve D and prepare to gather sample liquid.

(e) Slowly open Valve D and allow liquid to enter t he cylinder at a slow rate of approximately 60 ml per minute to prevent liquid fr om flashing within the sampling cylinder. Use the measurement scale locat ed on the sampling cylinder and a stopwatch to measure the rate at whi ch liquid is gathered.Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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Air Resources Board B-9 February 2015 (f) Record the temperature from Gauge L and pressu re from Gauge M while liquid is gathered. Do not take measurements on st agnant liquid.

(g) Continue gathering liquid until the cylinder is 80% full as indicated on the cylinder scale. The rate at which liquid enters th e cylinder, and the volume of liquid in the cylinder, are indicated on the sample cylinder. No outage is required when using a Floating-Piston Cyl inder.

(h) Close valves D, C, and A in that order.

(i) Purge the line pressure: slowly open Valve B a nd allow pressurized liquid to drain into the waste container.

(j) Disconnect the Floating-Piston Cylinder from th e sampling train and disconnect the sampling train from the pressurized vessel.

(k) Check Valves C and D for leaks. If either Valv e C or D is leaking, drain the cylinder into a suitable waste container and us e a different cylinder to obtain a new sample.

(l) Wrap the threaded connections of the cylinder w ith Teflon tape and cap using threaded metal caps to protect the threads an d ensure the cylinder is securely sealed for shipping.

(m) Identify the sample cylinder as specified in Se ction 8.

7.3 LOW API GRAVITY CRUDE OIL SAMPLING METHOD

In some cases, low API gravity crude oil may not fl ow 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 assis t with the collection of liquid. The pump must be outfitted with one-way check valve s 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 sy stem pressure.

(a) Install the stainless steel hand pump equipped with one-way check valves as described in Section 6 at the inlet of the Doubl e-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 Identificatio n Tag. Both the tag and a copy of Form 1 must be completed prior to sampling using informationLegal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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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 barr els 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 e mission rates using a vapor recovery system in lieu of gathering and evaluating liquid samples. This methodology requires that all gases flashed from li quid are collected and measured, and that a vapor recovery system is insta lled on a minimum of the primary and secondary vessels, and that intermediat e vessels be covered and controlled using a pressure/vacuum valve, at minimu m, 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 rate s are calculated using the measured annual vapor recovery gas volume meter ed by the system and an annual gas composition analysis. The annual measur ed gas volume is adjusted to account for capture efficiency of the vapor reco very system.

(a) Measure the annual gas volume recovered by the vapor recovery system using the calibrated meter outfitted with temperatu re and pressure gauges as described in Section 6.Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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Air Resources Board B-11 February 2015 (b) Obtain an annual gas sample of the vapor recove ry gas and evaluate it for all gaseous compounds, the molecular weight, and th e weight percent of Greenhouse Gases and other compounds.

(c) Calculate the annual emission rates as describe d in Section 10.2.

10. CALCULATING RESULTS

10.1 Flash Emission Calculation Methodology for Liq uid Samples

The following is used in conjunction with vessel in formation and a laboratory analysis to calculate metric tons of Greenhouse Gas es (CO 2 and CH 4 ) or short tons of other compounds (VOC C3-C9 or BTEX). The same formulas may be applied to crude oil, condensate, and produced wate r.
(a) If required, calculate the barrels per day of c rude oil or condensate in emulsion using the Percent Water Cut:



## ( ) ( )

Throughput Cut Water Percent Day Barrels

−

= 1 / Equation 1A

Where:

Barrels/Day = barrels per day crude oil or condens ate

Percent Water Cut = percentage of produced water in emulsion

Throughput = barrels per day of emulsion

(b) If required, calculate the barrels per day of p roduced water in emulsion using the Percent Water Cut:



## ( ) ( )

Throughput Cut Water Percent Day Barrels = / 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 G Year Ft / 3 Equation 2Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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Air Resources Board B-12 February 2015 Where:

Ft 3 /Year = standard cubic feet of gas produced per yea r
G = Gas-to-Oil Ratio or Gas-to-Water Ratio (from l ab analysis)

Barrels/Day = barrels per day crude oil, condensat e, 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 mole gram mole gram gram Year Ft Year Mass Gas 

### 454 317 .28

690 .23 / 3

3

Where:

Mass Gas /Year = pounds of gas per year

Ft 3 /Year = cubic feet of gas produced per year (Eq. 2)

Gram/Gram-Mole = Molecular Weight of gas sample (fr om lab analysis)

23.690 l/gr-mole = molar volume of ideal gas at 14. 696 psi and 60 0 F

(e) Calculate the mass of GHG or other compound:



###                      

= lb ton metric

Year Mass GHG WT Year Mass Gas GHG 

### 2205

100 % / Equation 4



###                    

= lb ton

Year Mass Compound WT Year Mass Gas Compound 

### 2000

100 % / Equation 5

Where:

Mass GHG /Year = metric tons of CO 2 or CH 4 (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 CO 2 or CH 4 (from lab analysis)

WT% Compound = Weight % of VOC C3-C9 or BTEX (from lab analysis)Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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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( / / / 

### CE Year Mass Emissions Compound GHG Compound GHG 

### −

= Equation 6

Where:

Emissions GHG/Compound = controlled GHG or other compound emissions

Mass GHG/Compound /Year = uncontrolled GHG or other compound emissio ns per year (Eq. 4 or 5)

CE = capture and control efficiency of vapor recove ry system

10.2 Emission Calculation Methodology Using Measured Vap or Recovery System Parameters

(a) Convert the total volume of vapor measured usin g the calibrated meter and average annual vapor temperature and pressure t o standard conditions:

      +      

= 696.14

696.14 67. 519 / 3 P

T V Year Ft Equation 7

Where:

Ft 3 /Year = annual cubic feet of gas corrected to stand ard conditions (scf)

V = annual volume of gas going to the vapor recover y system, measured by the calibrated meter (cubic feet)

T = average annual vapor temperature measured at th e meter (degrees R)

P = average annual gauge pressure measured at the m eter (psig)

(b) Convert the total gas volume to pounds:

Equation 8



###                      

−        

−        

= grams lb

Ft l

l mole gram mole gram gram Year Ft Year Mass Gas 

### 454 317 .28

690 .23 / 3

3

Where:

Mass Gas /Year = pounds of gas per year

Ft 3 /Year = cubic feet of gas produced per year (Eq. 6)

Gram/Gram-Mole = Molecular Weight of gas sample (fr om lab analysis)Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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Air Resources Board B-14 February 2015

23.690 l/gr-mole = molar volume of ideal gas at 14. 696 psi and 60 0 F

(c) Calculate the mass of GHG or other compound:



###                      

= lb ton metric

Year Mass GHG WT Year Mass Gas GHG 

### 2205

100 % / Equation 9



###                    

= lb ton

Year Mass Compound WT Year Mass Gas Compound 

### 2000

100 % / Equation 10

Where:

Mass GHG /Year = metric tons of CO 2 or CH 4 (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 CO 2 or CH 4 (from lab analysis)

WT% Compound = Weight % of VOC C3-C9 or BTEX (from lab analysis)

(d) Adjust the annual emission rate as follows:

Equation 11



# ( )      

−

= CE CE Year Mass Emissions Compound GHG Compound GHG 

### 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, pro cessing, or storage. All results shall be reported to at least three significant fig ures. All supporting information used to derive the emission estimates, including sa mple information, laboratory results, and calculations must be maintained by the reporting entity for a minimum of three years in order to reproduce the es timated 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 Green house Gas

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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 o ther 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 throu ghput;

(c) All calculations and calculated results;

(d) Annual emission rates of Greenhouse Gases and o ther 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 cylind er, the cylinder must be heated to the same temperature as measured at the t ime of sampling. The laboratory apparatus must be temperature and pr essure controlled by a means that allows cooling and depressurizing liqu id 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 sys tem 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 21 77-03.

12.2 Laboratory Methods

The following methods are required to evaluate and report flash emission rates from crude oil, condensate, and produced water. Al l methods and quality control requirements shall be conducted as specified in eac h method.Legal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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Air Resources Board B-16 February 2015 (a) Hydrogen Sulfide (Low-Level): Evaluate using E PA Method 15 and EPA Method 16 or use ASTM D-1945-03 (Thermal Conductivi ty Detector), ASTM D-5504-08 (sulfur chemiluminescence detector), and ASTM D6228-10 (flame photometric detector) as alternate m ethods.

(b) Oxygen, Nitrogen, Carbon Dioxide, Hydrogen Sulf ide (High-Level), Methane, Ethane, Propane, i-Butane, n-Butane, i-Pen tane, n-Pentane, Hexanes, Heptanes, Octanes, Nonanes, and Decanes+: Evaluate per ASTM D-1945-03, ASTM D-3588-98(2003), and ASTM D-25 97- 94(2004)(GC/TCD). Note: This analysis requires all three methods specified. The base method is ASTM D-1945-03, whic h is modified to extend the hydrocarbon analysis range based on info rmation from the other two methods.

(c) BTEX: Evaluate per EPA 8021 B (GC/FID) or use A STM D-3170, GPA 2286, EPA 8260B, EPA TO-14, and EPA TO-15 as altern ate methods.

(d) API Gravity of liquid phase crude oil or conden sate at 60 degrees Fahrenheit (60 o F): Evaluate per ASTM D-287-92-(2006) using measure d result of Specific Gravity. Note: If water is entr ained in the sample, measure the API Gravity using ASTM D-287-92 (2006)( API Hydrometer) and calculate the Specific Gravity using the measur ed API Gravity.

(e) Specific Gravity of pre-flash liquid phase crud e 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 calculatio n 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 collec tion, storage, interpretation, adjustment, or quantification of chromatograph dete ctor 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 minim um information describedLegal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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Air Resources Board B-17 February 2015 below and in Table 1 must be provided to the facili ty operator so they can calculate and report the results specified in Secti ons 10 and 11:

(a) The gaseous phase WT% of CO 2 , CH 4 , the gaseous phase WT% of C2 through C9 and C10+, the gaseous phase WT% of BTEX, and the gaseous phase WT% of O 2 , N 2 , and H 2 S;

(b) The gaseous phase Gram Molecular Weight of the total gas sample;

(c) The liquid phase API Gravity of crude oil or co ndensate at 60 o F;

(d) Volumetric Gas-to-Water Ratio (GWR) for produce d 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 Green house Gas

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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 vesse ls)

• Presence of VR System

• Vapor Processing & Type

• Vapor End Use(s)

Tentatively Identified Compound List (if sampling p roprietary 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 GravityLegal Disclaimer: Unofficial electronic version of the Regulation for the Mandatory Reporting of Green house Gas

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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 Chromatograp hy

ASTM D-3588-98(2003) Standard Practice for Calculating Heat Value,

Compressibility Factor, and Relative Density of Gas eous Fuels

ASTM D-4007-08 Standard Test Method for Water and Sediment in Crud e 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 Dens ity

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 fr om Stationary Sources

EPA Method 8021B (1996) Aromatic and Halogenated Volatiles By Gas

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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 Cani sters With Subsequent Analysis By Gas Chromatography

EPA Method TO-15(1999) Determination Of Volatile Organic Compounds

(VOCs) In Air Collected In Specially-Prepared Canis ters 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 Mixtur es by Gas Chromatography

GPA 2286-95 Extended Gas Analysis Utilizing a Flame Ionization

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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 ve ssel):

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

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Air Resources Board B-22 February 2015