# California Climate Action Registry Gener al Reporting Protocol

Repor ting Entity-W ide Gr eenhouse Gas Emissions



# V ersion 2.2 Mar ch 2007 Califor nia Climate Action Regist ry 515 S. Flower Street, Suite 1640 Los Angeles, CA 9007 1

# Acknowledgements

The Registry would like to thank and acknowledge the many experts who have helped make both the General Reporting Protocol and the Registry a reality. While it is impossible to properly acknowledge everyone who contributed to this document, the following organizations have provided valuable guidance and insightful feedback throughout this project: Arthur D. Little / ICF Consulting California Climate Action Registry Technical Advisory Committee
California Council for Environmental and Economic Balance California Energy Commission California Energy Commission Registry Workgroup

California EPA

CH2M Hill

First Environment Lawrence Berkeley National Laboratory

Natural Resources Defense Council Convened State Registry Collaborative Pacific Gas & Electric Corporation Pew Center on Global Climate Change Sacramento Municipal Utility District Science Applications International Corporation (SAIC) U.S. Department of Energy U.S. Energy Information Administration (1605(b) Program) U.S. Environmental Protection Agency

U.S. EPA Climate Leaders World Business Council for Sustainable Development

World Resources Institute The Registry is also grateful to all of the individuals who participated in the Registry’s public workshops and meetings. Most notably, Jill Gravender, Pierre duVair, Jeff Wilson, Robyn Camp, Mike McCormick, Sam Hitz, and Rachel Tornek should be singled out for their extensive contributions in the drafting and finalization of this report. The Registry would like to extend a special acknowledgement to the World Business Council for Sustainable Development and the World Resources Institute for the excellent work and leadership embodied in their “Greenhouse Gas Protocol: A corporate accounting and reporting standard.” Their work has provided the foundation for the Registry’s General Reporting Protocol. In addition, the California Energy Commission has played an instrumental role in developing and recommending technical and policy guidance to the Registry’s staff and board of directors for the General Reporting Protocol. The Registry wishes to extend a special thank you to SAIC for their help preparing the General Reporting Protocol. The Registry also wishes to thank its members and certifiers whose application of earlier versions of the protocol have informed the clarifications provided in this version. Finally, the Registry wishes to thank the California Energy Commission and the Energy Foundation for their generous financial support of the Registry. 

# Table of Contents

Abbreviations and Acronyms

Key Terms

Part I Introduction 1

I.1 How to Use the General Reporting Protocol 1

I.2 Background on the California Climate Action Registry 2

I.3 GHG Accounting and Reporting Principles 3

I.4 Reporting Requirements and Disclosure 3

I.5 Reporting Uncertainty vs. Inherent Uncertainty 4

I.6 Web-Based Reporting 5

I.7 Technical Assistance 5

I.8 New Member Orientation 5

I.9 Key Questions 5



## Part II Determining What You Should Report 10 Chapter 1	 Geographic Boundaries 11

II.1.1 Reporting National and California-Based Emissions 11

II.1.2 Reporting Worldwide Emissions 12

II.1.3 Example: Determining Geographic Boundaries 12 

### Chapter 2	 Organizational Boundaries 13

II.2.1 Defining Your Entity 13

II.2.2 Reporting Options and Organizational Boundaries 13

II.2.3 Reporting Based on Management Control 14

II.2.4 Reporting Based on an Equity Share Basis 15

II.2.5 Choosing Both Management Control and Equity Share Reporting 16

II.2.6 Parent Companies and Subsidiaries 16

II.2.7 Partnerships and Joint Ownership 16

II.2.8 Leased Facilities/Vehicles and Landlord/Tenant Arrangements 16

II.2.9 Example: Management Control vs. Equity Share Reporting 17 

### Chapter 3	 Operational Boundaries: Required Direct and Indirect Emissions 19

II.3.1 Double Counting Direct and Indirect Emissions 19 

### Chapter 4	 Establishing and Updating a Baseline 20

II.4.1 Establishing Your Baseline 20

II.4.2 Rationale for Setting a Baseline 20

II.4.3 Updating Your Baseline 21

II.4.4 Examples: Updating Your Baseline 22

## Part III Quantifying Your Emissions 25 Chapter 5 De Minimis Emissions and Significance 26

III.5.1 Understanding De Minimis and Significant Emissions 26
III.5.2 Rationale for Calculating De Minimis Emissions 26
III.5.3 Reporting Your Significant Emissions 27
III.5.4 De Minimis Emissions and Geographic Boundaries 27
III.5.5 Identifying De Minimis Emissions 27
III.5.6 Using CARROT to Document De Minimis Emissions 27
III.5.7 Example: Determining De Minimis 28 

### Chapter 6 Indirect Emissions from Electricity Use 30

III.6.1 Calculating Indirect Emissions from Electricity Use 30
III.6.2 Alternative Methods to Estimate Electricity Use 33
III.6.3 Example: Indirect Emissions from Electricity Use 35 

### Chapter 7 Direct Emissions from Mobile Combustion 36

III.7.1 Calculating Carbon Dioxide Emissions for Mobile Combustion 36
III.7.2 Calculating Methane and Nitrous Oxide Emissions for Mobile Combustion 37
III.7.3 Example: Direct Emissions from Mobile Combustion 39 

### Chapter 8 Direct Emissions from Stationary Combustion 42

III.8.1 Emission Factors for Stationary Combustion 42
III.8.2 Estimating Emissions Based on Higher Heating Value 42
III.8.3 Using Continuous Emissions Monitoring Systems Data 42
III.8.4 Calculating Emissions from Stationary Combustion 43
III.8.5 Allocating Emissions from Co-generation 44
III.8.6 Example: Direct Emissions from Stationary Combustion 46 

### Chapter 9 Indirect Emissions from Imported Steam, and District Heating, or Cooling (and Electricity from a Co-Generation Plant) 48

III.9.1 Calculating Indirect Emissions from Heat and Power Produced at a Co-generation Facility 48
III.9.2 Calculating Indirect GHG Emissions from Imported Steam or District Heating from a Conventional Boiler Plant 49
III.9.3 Calculating Indirect GHG Emissions from District Cooling 50
III.9.4 Example: Indirect Emissions from District Cooling 53 

### Chapter 10 Direct Emissions from Manufacturing Processes 54
Chapter 11 Direct Fugitive Emissions 56

III.11.1 Calculating Direct Fugitive Emissions from Refrigeration Systems 56
III.11.2 Other Fugitive Emissions 59
III.11.3 Example: Direct Fugitive Emissions from Refrigeration Systems 60 

### Chapter 12 Optional Reporting 62

III.12.1 Reasons to Report Optional Information 62 III.12.2 Efficiency Metrics 62
III.12.3 Other Emissions Information 63
III.12.4 Optional Indirect Emissions 63



## Part IV Completing and Submitting Your Report 65 Chapter 13 Reporting Your Emissions 66

IV.13.1 Submitting Your Report Using the CARROT 66
IV.13.2 CARROT Guidance and Technical Assistance 66
IV.13.3 Accessing Your Certified Emissions Data 66
IV.13.4 Movement Reports 67
IV.13.5 Utilizing Your Certified Emissions Data 68 

### Chapter 14 Certification 69

IV.14.1 GHG Reporting Principles and Certification 69

IV.14.2 Certification Standard 69
IV.14.3 Minimum Quality Standard 70
IV.14.4 The Certification Process 70
IV.14.5 Professional Judgment 71
IV.14.6 Conflict of Interest 71
IV.14.7 Reporting and Certification Deadlines 71
IV.14.8 CEC Role in Certification 72
IV.14.9 Key Certification Steps 72
IV.14.10 Preparing for Certification 72
IV.14.11 The Certification Cycle 74
IV.14.12 Online Reporting 75
IV.14.13 Documentation for Review 75
IV.14.14 Batch Certification 77
IV.14.15 Certification Report and Opinion 77
IV.14.16 Submitting a Certified Emissions Report to the Registry 78
IV.14.17 Record Keeping and Retention 78
IV.14.18 Correcting or Revising your GHG Emissions Report 78
IV.14.19 Dispute Resolution 79
IV.14.20 Key Certification Questions 79



## Appendices Appendix A Glossary 81 Appendix B Common Conversion Factors 83 Appendix C Calculation References 85 Converting to CO 2 Equivalent 85 Emission Factors for Electricity Use 86 Table C.1: EPA eGRID Carbon Dioxide Electricity Emission Factors by Subregion (Year 2000–2003) 86Table C.2: Methane and Nitrous Oxide Electricity Emission Factors by State and Region (Average Years 2001–2003) 87
Emission Factors for Mobile Combustion 89 Table C.3: Carbon Dioxide Emission Factors for Transport Fuels (kg CO 2 /gallon) 89 Table C.4: Methane and Nitrous Oxide Emission Factors for Mobile Sources by Vehicle and Fuel Type (g/mi) 90 Emission Factors for Stationary Combustion 91
Table C.5: Carbon Dioxide Emission Factors and Oxidation Rates for Stationary Combustion (kg/MMBtu or kg/gallon) 92
Table C.6: Methane and Nitrous Oxide Emission Factors for Stationary Combustion by Sector and Fuel Type (kg/MMBtu) 93 Appendix D Electricity Emission Factors–All Fuels (lbs. CO 2 / kWh for Non–U.S. Countries 94 Appendix E Industry-Specific Metrics for Determining Emission Intensity 99 Appendix F References 106



## List of Tables and Figures

Table I.1 Reporting Years 8
Table II.2.1 Reporting Based on Management Control 14
Table II.2.2 Reporting Based on Equity Share 16 Figure III.6.1 EPA’s eGRID Power Pool Regions 31
Table III.6.1 Comparison of GWPs from the IPCC’s Second and Third Assessment Reports 32
Table III.8.1 Conversion Factors for Stationary Combustion Calculations 43
Table III.9.1 Typical Chiller Coefficients of Performance 51
Table III.11.1. Refrigerant Loss Rates 57
Table III.11.2 Composition of Refrigerant Blends 57
Table III.11.3 Base Inventory (for mass balance determinations) 58
Table III.11.4 Inventory Changes (for mass balance determinations) 58
Table IV.13.1 Sample Movement Report 67 Figure IV.14.1 Core Certification Process 69
Table IV.14.1 Documents to be Reviewed During Certification Activities 75



## List of Equations Equation III.6a Monthly Electricity Use 30 Equation III.6b Total Emissions from Indirect Electricity Use 32 Equation III.6c Converting Non-CO 2 GHGs to Carbon Dioxide Equivalent 32 Equation III.6d Total GHG Emissions from Electricity Use 32 Equation III.7a Total Annual Fuel Consumption from Bulk Fuel Records 37 Equation III.7b Fuel Use in Motor Vehicles from Mileage Records 37 Equation III.7c Total CO 2 Emissions from Mobile Combustion 37 Equation III.7d Vehicle Miles Travelled 38 Equation III.7e Total CH 4 or N 2 O Emissions from Mobile Combustion 38 Equation III.8a Annual Consumption of Fuels 43 Equation III.8b Total CO 2 Emissions (Fuel Consumption is in MMBtu) 44 Equation III.8c Total CO 2 Emissions (Fuel Consumption is in gallons) 44 Equation III.8d Total CH 4 or N 2 O Emissions (Fuel Consumption is in MMBtu) 44 Equation III.8e Total CH 4 or N 2 O Emissions (Fuel Consumption is in gallons) 44 Equation III.8f Steam and Electricity Emissions Allocation 45 Equation III.9a Net Heat Production 48 Equation III.9b Indirect Emissions Attributable to Electricity Consumption 49 Equation III.9c Indirect Emissions Attributable to Heat Consumption 49 Equation III.9d Steam Energy Consumption (from therms) 49 Equation III.9e Steam Energy Consumption (from pounds) 50 Equation III.9f Energy Input by Steam or District Heating Plant 50 Equation III.9g Energy Input (Plant Efficiency Unknown) 50 Equation III.9h Total Emissions for Steam System 50 Equation III.9i Annual Cooling Demand 51 Equation III.9j Energy Input from Cooling Demand 51 Equation III.9k Total Cooling Emissions – Simplified Approach 51 Equation III.9l Cooling Emissions (from plant with multiple product streams) 52 Equation III.9m Annual Cooling Emissions 52 Equation III.11a HFC Emissions from Refrigerant Leakage 57 Equation III.11b Total Annual Emissions from Refrigerant Leakage 59

# Abbreviations and Acronyms

Btu British thermal unit(s)

CARB California Air Resources Board

CARROT Climate Action Registry Reporting Online Tool

CEC California Energy Commission

CEMS Continuous Emissions Monitoring Systems

CHP combined heat and power

CH 4 methane

COP coefficient of performance

CO 2 carbon dioxide

CO 2 e carbon dioxide equivalent

EIA U.S. Energy Information Administration

EIIP Emissions Inventory Improvement Program
EPA U.S. Environmental Protection Agency

g gram(s)

GCV gross caloric value

GHG greenhouse gas

GRP General Reporting Protocol

GWP global warming potential

ha hectare(s)

HDV heavy duty vehicle

HFC hydrofluorocarbon

HHV higher heating value

IPCC Intergovernmental Panel on Climate Change

IPP independent power producer kg kilogram(s)

kWh kilowatt-hour(s)

lb pound

LDT light duty truck

LHV lower heating value

LPG liquefied petroleum gas

Mcf thousand cubic feet

mi mile(s) MMBtu one million British thermal units

MWh megawatt-hour(s)

NCV net caloric value

NOx oxides of nitrogen

N 2 O nitrous oxide

PFC perfluorocarbon

RFA Request for Applications

SAR IPCC Second Assessment Report (1996)

SB 1771 California Senate Bill 1771 (passed August 31, 2000)

SB 527 California Senate Bill 527 (passed September 14, 2001)

SF6 sulfur hexafluoride

TAR IPCC Third Assessment Report (2001)

T&D transmission and distribution

UNFCCC United Nations Framework Convention on Climate Change

WBCSD World Business Council for Sustainable Development

WRI World Resources Institute

Abbreviations and Acronyms10 

# Key Terms

term definition

Baseline Datum against which to measure GHG emissions performance over time.

Base Year The first year in which GHG emissions are reported.

Batch Certification Simultaneous certification process arranged by the Registry for multiple participants with simple GHG emissions (typically only indirect emissions from electricity consumption and direct emissions from stationary combustion at a single site and/or direct emissions from a small number of vehicles).
CO 2 -equivalent* (CO 2 e) The quantity of a given GHG multiplied by its total global warming potential. This is the standard unit for comparing the degree of warming which can be caused by different GHGs.
Certification The process used to ensure that a given participant’s greenhouse gas emissions inventory (either the baseline or annual result) has met a minimum quality standard and complied with the Registry’s procedures and protocols for calculating and reporting GHG emissions.
Certified Member

Certifier A Registry participant that has a current certified annual emissions report to the Registry. A firm or team of firms that has been State- and Registry-approved to conduct certification activities under the Registry program. A certifier may also refer to a single employee within a State- and Registry-approved firm who conducts certification activities

Datum A reference or starting point.

De Minimis A quantity of GHG emissions from one or more sources, for one or more gases, which, when summed equal less than 5% of an organization’s total emissions.

Direct Emissions Emissions from sources that are owned or controlled by the reporting organization.
Emission Factor* A factor relating activity data and absolute GHG emissions. Equity Share Fractional percentage or share of an interest in an entity based either on ownership interest, or on some other contractual basis negotiated among the entity’s stakeholders. Fugitive Emissions* Intentional and unintentional releases of GHGs from joints, seals, gaskets, etc. Global Warming Potential* (GWP) The ratio of radiative forcing (degree of warming to the atmosphere) that would result from the emission of one unit of a given GHG compared to one unit of CO 2 . Greenhouse Gases (GHG) For the purposes of the Registry, GHGs are the six gases identified in the Kyoto Protocol: Carbon Dioxide (CO 2 ), Nitrous Oxide (N 2 O), Methane (CH 4 ), Hydrofluorocarbons (HFCs), Perfluorocarbons (PFCs), and Sulphur Hexafluoride (SF 6 ).
Indirect Emissions Emissions that are a consequence of the actions of a reporting entity , but are produced by sources owned or controlled by another entity. Leakage A situation where emissions shift from one location to another resulting in a direct increase in emissions.

Key TermsManagement Control The ability of an entity to govern the operating policies of another entity or facility so as to obtain benefits from its activities.

Material Means any emission of greenhouse gas that is not de minimis. Material Discrepancy With respect to verifying an entity’s emission inventory, a material discrepancy occurs when a difference in reported emissions between an entity and a certifier exceeds 5% of the reported emissions. A difference is immaterial if it is less than 5% of reported emissions.
Mobile Combustion* Burning of fuels by transportation devices such as cars, trucks, airplanes, vessels,
etc. Member An entity that is preparing its annual GHG Emission Report, but does not hav e a current certified Emission Report with the Registry. Outsourcing* The contracting out of activities to other businesses.

Process Emissions* Emissions generated from manufacturing or other activity processes, such as cement or ammonia production. Project Baseline Datum against which to measure GHG emissions performance of a specific emissions reduction project over time, usually annual emissions measured from a base year. Significance Threshold Significance, in the context of the Registry, is defined as including all sources that are not de minimis. For the purposes of the Registry, the significance threshold is set at 95%. Stationary Combustion* Burning of fuels to generate electricity, steam, or heat.

*Definitions of key terms obtained from “The Greenhouse Gas Protocol, A Corporate Accounting and Reporting Standard,” World Business Council for Sustainable Development and World Resources Institute, Switzerland, September 2004 (GHG Protocol, 2004)

Key Terms

# Part I Introduction

The General Reporting Protocol (the Protocol or GRP) provides guidance for businesses, government agencies, and non-profit organizations to participate in the California Climate Action Registry (the Registry), a voluntary greenhouse gas (GHG) registry. The Protocol provides the principles, approach, methodology, and procedures required for participation in the Registry. It is designed to support the complete, transparent, and accurate reporting of an organization’s GHG emissions inventory in a fashion that minimizes the reporting burden and maximizes the benefits associated with understanding the connection between fossil fuel consumption, electricity use, and GHG emissions in a quantifiable manner. The Protocol guides participants through the reporting rules, emission calculation methodologies, and the Registry’s standardized reporting mechanism via its web-based reporting system, the Climate Action Registry Reporting Online Tool (CARROT). Reporting guidance for individual industries in the form of industry-specific protocols will be developed over time, and will supplement this document. Guidance on reporting emission reduction projects will also append this document. (The current version of the General Reporting Protocol and its appendices is available
at www.climateregistry.org/Protocols ).In addition to the GRP, the Registry offers three industryspecific protocols:

• Forest Protocols,

• Power/Utility Protocols, and

• Cement Protocols Additional protocols will be developed over time. The sector-specific protocols are considered appendices to the General Reporting Protocol. Forest companies, power generators and electric utilities, and cement companies should refer to the GRP as well as their respective industry-specific protocol for a complete set of emissionaccounting and reporting instructions. The industryspecific protocols are also available for download on the Registry’s website. By joining the Registry, participants agree to report their annual GHG emissions according to the guidelines in this Protocol and its appendices. The GRP is intended to be used in combination with the Registry’s Certification Protocol and web-based calculation and reporting tools. 

## I.1 How to Use the General
Reporting Protocol

Who Should Use the GRP

• Businesses, government agencies, and non-profit organizations who want to learn about greenhouse gas emissions tracking for California or nationwide

• Registry members who are reporting their general emissions or emissions related to a specific sector (forests or utilities)

• Certifiers of general or sector-specific emissions reports

• Technical advisors to companies who report emissions through the Registry

• The interested general public


### How the Protocol is Organized

This Protocol is based on the “Greenhouse Gas Protocol: A Corporate Accounting and Reporting Standard”, developed by the World Business Council for Sustainable Development and the World Resources Institute (WBCSD/ WRI) through “a multi-stakeholder effort to develop a standardized approach to the voluntary reporting of GHG emissions.” 1 The calculations and emission factors were selected based on technical advice provided to the Registry by the California Energy Commission.
This Protocol will continue to be refined over time, to add clarity and specificity, to provide guidance for specific industries, and to incorporate new understanding in GHG accounting. Comments on the GRP or other protocols may be submitted to the Registry using the Protocol Comment Forms, also posted on the Registry’s website. The Protocol is divided into four parts, composed of a total of fourteen chapters. Each chapter provides guidance on the specific steps participants will need to take to complete and submit their GHG Emissions Report to the Registry. Depending upon the complexity and the nature of reported GHG emissions, some of the steps in this Protocol may not apply to all organizations. Nevertheless, the Registry encourages participants to review the document as a whole to ensure that they have identified all reporting requirements.

1“The Greenhouse Gas Protocol, A Corporate Accounting and Reporting Standard,” World Business Council for Sustainable Development and World Resources Institute, Switzerland, March 2004 (GHG Protocol, 2004) Part I 

### Part I: Introduction

Contains:

• An overview of the General Reporting Protocol and the reporting process

• An introduction to online reporting

• A brief background on the creation and objectives of the Registry

• Answers to key questions about using the Protocol



### Part II: Reporting Your Emissions (Chapters 1-4) Provides guidance on:

• Determining geographic boundaries (i.e., California, the entire U.S., or worldwide)

• Determining organizational boundaries

• Determining operational boundaries

• Setting an emission baseline



### Part III: Quantifying Your Emissions (Chapters 5-12) Provides guidance on calculating:

• Indirect emissions from electricity

• Direct emissions from mobile combustion

• Direct emissions from stationary combustion

• Indirect emissions from co-generation, imported steam, and district heating or cooling

• Direct process emissions

• Direct fugitive emissions

• Optional emissions


### Part IV: Completing and Submitting Your Report (Chapters 13-14) Describes how to finalize Emission Reports by:

• Determining de minimis emissions

• Preparing and submitting an annual GHG Emission Report using CARROT

• Providing an overview of the certification process


### Related Registry Documents

General Certification Protocol: for approved certifiers, Registry members and the public interested in certification. Forest Protocols: for landowners with at least 100 acres of forestland in California. The Forest Protocols consist of three documents: 1) an entity-level protocol, 2) a project protocol, and 3) a certification protocol. Like the GRP and the General Certification Protocol, the forest sector entity-level and certification protocols provide GHG emissions accounting, reporting, and certification guidance at the entity level; the forest sector project protocol provides guidance to forest companies that wish to account and report GHG emission reductions resulting from one of three planned activities taking place on the forest company’s land: conservation, reforestation and conservation-based forest management. Power/Utility Protocols: for companies that generate and sell electricity for the wholesale or retail market and/or provide electricity transmission and distribution services. The Power/Utility Protocols consist of two documents: 1) an entity-level protocol and 2) a certification protocol.
Cement Protocols: for companies that manufacture cement. The Cement Protocols consist of two documents: 1) the entity-level protocol and 2) a certification protocol.



## I.2 Background on the California
Climate Action Registry The Registry is a non-profit public/private partnership that serves as a voluntary greenhouse gas (GHG) registry to protect, encourage, and promote early actions to reduce GHG emissions. The Registry provides leadership on climate change by promulgating credible and consistent GHG reporting standards and tools for organizations to measure, report, certify, and reduce their GHG emissions in California and/or the U.S. Following considerable initiative and input from various stakeholders from the business, government, and the environmental communities, the California State Legislature established the Registry in 2000, with technical modifications in 2001. 2 The purposes of the Registry are as follows:

• To enable participating entities to voluntarily measure and record GHG emissions made after 1990 in an accurate manner and consistent format that is independently certified;

• To establish standards that facilitate the accurate, consistent, and transparent measurement and monitoring of GHG emissions;

• To help various entities establish emissions baselines against which any future federal GHG emissions reduction requirements may be applied;

2 California Senate Bill 1771 was signed into law on September 30, 2000, and Senate Bill 527 on October 13, 2001. See CA Health and Safety Code §§42800 et seq • To encourage voluntary actions to increase energy efficiency and reduce GHG emissions;

• To ensure that participating organizations receive appropriate consideration for certified emissions results under any future state, federal or international regulatory regime relating to GHG emissions;

• To recognize, publicize, and promote participants in the Registry; and

• To recruit broad participation in the process. The Registry was created by the State of California to be a non-profit organization operating outside of the state government, but working closely with the State to develop its reporting and certification procedures such that the State is confident in the quality of the data to which it will give appropriate consideration in the future. To this end, the State has worked closely with the Registry since its inception to develop its reporting and certification guidance, including both this General Reporting Protocol, the companion Certification Protocol, and also industry-specific reporting protocols. Joining the Registry provides several benefits, such as:

• Addressing inefficiency – understanding that emissions indicate waste and inefficiency has led many companies to insights for redesigning business operations and processes, spurring innovation, improving products and services, and helping to build competitive advantage.

• Managing risk – taking steps to protect early actions ahead of possible future GHG regulations is a wise risk-management strategy.

• Preparing for trading – developing credible and transparent measurement, verification and reporting methods in order to participate in any future emission trading system.

• Showing environmental leadership – acting early to address climate change to better influence future policy, and to understand the most cost-effective means of managing and reducing emissions.

• Demonstrating action on GHG emissions – reporting certified information to the Registry helps to address shareholder concerns about adequate corporate actions to reduce GHG emissions.

• Preparing for regulation – certifying annual GHG inventory helps to support mandatory GHG reporting and informs State consideration for GHG regulation. 

## I.3 GHG Accounting and Reporting
Principles The following principles, which serve as the basis of reporting and certifying emissions with the Registry, are consistent with the WRI/WBCSD GHG Protocol Initiative. 3 Completeness . Complete GHG inventories include emissions from all significant GHG sources and activities within the specified scope of the participant’s report. Baseline and annual emissions results include all sources that are not de minimis in quantity; vertical and horizontal integration should be properly accounted for. Consistency. Consistently developed GHG inventories enable meaningful comparison of emissions performance over time and across similar organizations. Additionally, changes to a participant’s emission baselines are certified to ensure appropriate comparisons. Comparability. Acertified emission report should be comparable across similar organizations reporting to the Registry. The report should allow comparison of direct and indirect emissions against those of other reports with similar geographic and organizational scopes. Accuracy. Accurate GHG inventories must be within the materiality threshold of 5% of the certifier’s estimate of total emissions. The certification process validates the accounting and reporting decisions made by the participant and ensures that the GHG emissions reports are precise and credible. Transparency. Reporters must make available to their certifiers the necessary information and documentation used to produce the inventory. Additionally, the certification process should be clearly and thoroughly documented to allow the possibility for outside reviews by the CEC or the Registry.



## I.4 Reporting Requirements and
Disclosure
Required Reporting Registry participants must submit their GHG emissions to the Registry each year. Any entity that conducts business activities in the State of California—such asa corporation or other legally constituted body, a nonprofit organization, any city, county, or State government agency—may join the Registry. If an organization does not have emissions in California, then it may report its total U.S. emissions, and indicate that California emissions are zero. At a minimum, participants must report at least 95% of their entity-wide emissions for each of the following categories:

3 GHG Protocol, 2004 Part I • Direct emissions from mobile source combustion,

• Direct emissions from stationary combustion,

• Indirect emissions from electricity use and imported steam, district heating and cooling,

• Direct process emissions, and

• Direct fugitive emissions For the first three years after joining the Registry participants must report at a minimum their CO 2 emissions in CA or in the U.S., depending on the geographic scope of their inventory. Starting with the fourth year, participants must report all Kyoto GHGs (CO 2 , CH 4 , N 2 O, HFCs, PFCs, SF 6 ). Participants must submit annual GHG emission reports (emission reports) via CARROT. Each annual GHG emission report must contain at least the following information:

• The geographic scope of the emission report (whether California-only or nationwide);

• The operational and organizational boundaries of the reporting entity for which GHG emission data is reported;

• A GHG emissions baseline to assess changes in total emissions from year to year, if a participant chooses to define a baseline;

• Total significant direct GHG emissions (including mobile and stationary combustion, process, and fugitive); and

• Total significant indirect GHG emissions (from electricity usage, and from co-generation, steam imports, district heating and cooling). Before emission reports will be accepted by the Registry, this information must be certified by an approved certifier. Participants are eligible to report and receive certification through the Registry for both California-only and national GHG emission inventories. Approved certifiers are screened and approved by the State of California and the Registry to ensure that they have the necessary skills to appropriately evaluate emission reports. The purpose of the certification process is to ensure that the emission report meets the following criteria:

• Completeness: Report all significant emissions, defined as at least 95% of the total (both direct and indirect emissions), entity-wide sources (either California-only or nationwide).

• Consistency: Report total emissions each year of participation in the Registry.

• Comparability: Calculate your emissions in a standardized fashion, using the methodologies and emission factors outlined in the General Reporting Protocol and its appendices.

• Transparency: Report emissions to the Registry using the Registry’s standardized reporting tool, the Climate Action Registry Reporting Online Tool (CARROT).

• Accuracy: Less than a 5% difference between your calculated total emissions and what an approved certifier calculates your emissions to be. The State of California has promised to use its best efforts to ensure that reported emissions receive appropriate consideration in the event of future GHG regulation. For every year that a participant has a current annual emissions report, they are considered a Climate Action Leader.


### Optional Reporting Each annual GHG emission report may also contain optional information provided by the participant to highlight their organization’s environmental goals, policies, programs and performance and report other GHG emissions information. This information is not required to be reported and thus is not certified. While valuable in providing transparency and enhancing public knowledge, non-required information is not guaranteed appropriate consideration by the State of California in the event of future GHG regulation. All emissions reports will clearly distinguish between information that is and is not certified. Once accepted by the Registry, optional information is made available to the public as part of the emission report. Participants disclose to the public only information contained in the emissions reports generated through CARROT that include entity-wide emissions from direct and indirect sources, as well as any optional data they consider relevant. Although the Registry will make available aggregated entity-level emissions data to the public, it will keep all other data (i.e., from the facility- or source-level) confidential, such as activity data, methodologies, and emissions factors. Only the participant, the participant’s certifier, and the Registry can access confidential information, unless the participant allows others to access such information.



## I.5 Reporting Uncertainty vs.
Inherent Uncertainty Reporting uncertainty entails the mistakes made in identifying emissions sources, managing data or information, and calculating GHG emissions. Inherent uncertainty refers to scientific uncertainty associated with measuring GHG emissions. The Registry is aware that there is inherent uncertainty in emissions factors and measurement of activity data through metering and instrumentation – even after the calibration of meters and other data collection methods are certified as accurate. The GHG emissions accounting and reporting guidelines in the General Reporting Protocol and the independent certification process developed by the Registry are designed to reduce reporting uncertainty such that it is less than the minimum quality standard. Determining scientific accuracy is not the focus of the Registry or its General Reporting Protocol.



## I.6 Web-Based Reporting

CARROT (Climate Action Registry Reporting Online Tool) Submitting the Annual GHG emission report to the Registry is designed to be as simple and straightforward as possible. Based on this Protocol, the Registry has developed a web-based reporting application called CARROT (Climate Action Registry Reporting Online Tool), that enables participants to submit emission reports online. CARROT serves two purposes: (1) it is the tool through which participants report their emissions and (2) for many categories of data, it can assist with emissions calculations. It is accessed through the Registry’s website (www. climateregistry.org/CARROT). All emissions information must be reported through CARROT. Its webpage providesa variety of technical resources for getting started, contextbased Help links and other supporting information including an electronic version of this Protocol. There is also a brief Getting Started Guide that orients new users to CARROT. A short demonstration of CARROT application can also be found on the Registry’s website.



## I.7 Technical Assistance The Registry has a number of ways to help you as you proceed through the emissions reporting process. Contact the Registry for assistance in the following ways if you have questions or problems:

• Registry Technical Email Address: help@climateregistry.org

• Make an appointment with Registry Technical Staff: 213-891-1444 Additionally, CARROT contains online help features that should answer most of your questions. Should you need additional assistance, you can also hire a firm to provide technical assistance. A list of State- and Registry-approved technical assistance providers is on the Registry’s website. 

## I.8 New Member Orientation The Registry facilitates regular New Member Orientation sessions to help participants understand how to use the General Reporting Protocol and CARROT application. These workshops include specific guidance on calculating and certifying GHG emissions. All interested parties are invited to participate. Please contact the Registry for more details (213-891-1444) and see the website for a calendar of upcoming workshops ( www.climateregistry.org ).



## I.9 Key Questions

Below are clarifications on some basic issues that should assist you as you begin to prepare your annual GHG emission report. If you have a question that is not answered in this Protocol, please feel free to contact the Registry.


### Membership and Fees: How do I join the Registry? What does it cost? If you are interested in joining the Registry, please call the Registry’s main office at 213-891-1444 or visit the website (www.climateregistry.org) for more information and instructions on getting started. Membership fees are tiered based on the size of your organization, and are not expected to discourage anyone from participation. Specific information is available on the Registry website. Once you sign a Statement of Intent and pay your annual membership fees, you are a Member of the California Climate Action Registry. Once you have reported and certified one year’s emissions data in CARROT, you become a certified member of the California Climate Action Registry, a Climate Action Leader . To remain a Climate Action Leader , you must report and certify your annual GHG emission report each year.



### Member Benefits: What are some of the advantages of joining the Registry? Joining the Registry provides several important benefits to participants, such as addressing inefficiency, managing risk, preparing for emissions trading, showing environmental leadership, demonstrating action on GHG emissions, and preparing for possible CO 2 regulation.



### Emissions Trading: Can I use my Registry GHG emission report to trade GHG emissions? The Registry collects information on an organization’s entity-wide GHG emissions inventory for consideration by the State of California in the event of future GHG regulation. The Registry itself does not serve as a Part I brokerage house for GHG emissions trading, but the reporting and certification processes adopted by Registry participants will promote credibility, transparency, and accuracy of the data reported. It is possible that information reported to the Registry can be used by the participant to facilitate participation in private or government-sponsored trading programs in the future, although it is likely that any emissions to be traded will be documented and certified from emissions reduction projects. The Registry is in the process of developing a wider range of emissions reduction project-based reporting and certification protocols to complement its forest project protocol.


### Eligibility to Report: Who may report their GHG emissions? Any organization can participate in the Registry if it can report either its total California emissions, or its total U.S. emissions. If an organization does not have emissions in California, then it may report its total U.S. emissions, and indicate that its California emissions are zero. Organizations with operations in multiple states may not register a single state’s emissions (except California emissions). Partial nation-wide reporting is not permitted.


### Adhering to the Protocol Guidelines: Must a company or organization follow this Protocol to participate in the Registry? Participants in the Registry are expected to make every effort to report in a manner consistent with this Protocol. However, the Registry recognizes that participants may face unique situations not addressed in the Protocol or in some cases the implementation of the Protocol would create undue burden. While the Registry seeks to maintain consistency in reporting, participants may use calculation methodologies and emission factors that are certified as more accurate than the default calculations. The Registry also welcomes suggested revisions to the Protocol.

All comments about the Protocol should be submitted to the Registry using the Protocol Comment Form, available on the website ( www.climateregistry.org/Protocols ). Forms are also available to respond to Protocol Comments. Suggestions should clearly document an alternative approach and the manner in which the alternative approach would continue to improve the Protocol. Suggested revisions will be reviewed by Registry staff and advisors, the California Energy Commission, then summarized and presented to the Registry Board for review at each of the Board’s meetings. Changes to the Protocol will be approved by the Board and publicly announced. 

### Level of Reporting: Are participants permitted to report only individual facilities? At a minimum, you are required to report emissions from all sources in the state of California. If you have multiple facilities, you must report emissions from all facilities. The Registry encourages to report at a sub-entity or facility level as part of your entity-wide GHG emission report in CARROT.” The Registry does encourage you to report at a sub-entity or facility level as part of your entity-wide GHG emission report. A sub-entity may be a business unit, a department or other grouping that you define. If reporting at the sub-entity level, you must report all of your organization’s facilities or operations, such that all sub-entity emissions equal your entity’s total CA or U.S. emissions.


### Required Emission Reporting: Which GHGs do participants report? Each participant must evaluate its emissions to ensure that at least 95% of emissions are reported. The Registry accepts GHG emission reports that include emissions of the following six GHGs (Kyoto gases):

• Carbon Dioxide (CO 2 )

• Methane (CH 4 )

• Nitrous Oxide (N 2 O)

• Hydrofluorocarbons (HFCs)

• Perfluorocarbons (PFCs)

• Sulfur Hexafluoride (SF 6 ) Although participants are encouraged to report all of these gases starting in year one, participants may opt to limit their reports to only carbon dioxide (CO 2 ) emissions during the first three years of participation in the Registry. After the third year of Registry participation, participants will be required to include emissions from all six of the Kyoto GHGs (if applicable) in the annual emission report. For example, if you join the Registry in January 2006, you must report at least your CO 2 emissions emitted during the calendar years 2006-2008. Beginning in 2009, you must report all six Kyoto gases for every subsequent year. You should report all significant direct and indirect emissions. Significant emissions are those that comprise at least 95% of your organization’s total direct and indirect GHG emissions. Direct emissions are those emitted from sources owned or controlled by the reporting entity. For example, a cement manufacturer would report direct emissions resulting from the process of manufacturing cement. Indirect emissions are those that result from a participant’s actions but are produced from sources owned or controlled by another entity. For example, a participant whose emissions result only from the consumption of electricity would calculate its indirect emissions from the amount of electricity it consumes.



### What are de minimis emissions? Do I have to calculate and report absolutely everything? To be certified, your emissions report must identify all of the sources in your inventory, no matter how small. However, to help reduce reporting burdens and concentrate efforts on your significant emissions, the Registry permits you to designate a small portion of your emissions as de minimis. De minimis emissions comprise less than 5% of your organization’s total GHG emissions, as produced from any combination of sources and gases. For some participants, identifying, quantifying, and reporting all of their GHG emissions would be unduly burdensome and not cost-effective. A participant may operate hundreds, if not thousands, of small facilities where the known emissions—including, for example, indirect emissions from electricity consumption or direct emissions from motor vehicle operation—are a small fraction of larger emissions sources from industrial activities. For this category, if you can provide estimates that these emissions total less than 5% of your total annual GHG emissions, you do not have to report them. For example, a participant estimates that it emits 1,000 metric tons of CO 2 each year. Most of these emissions come from an on-site heating and cooling system in its buildings. In addition, this participant also has one company car that is driven approximately 20,000 miles each year. This participant estimates that between 800 and 1000 gallons of gasoline are consumed by this car each year. Using the upper estimate of 1000 gallons, the participant calculates the emissions from this source as 8.8 tons of CO 2 /year, and finds that this amount falls below the de minimis threshold of 5% or 50 metric tons CO 2 /year. The participant can provide this estimation to the certifier, along with vehicle records showing the actual miles traveled of the car. In subsequent years, if the operation patterns do not change significantly, the participant can continue to declare the emissions from this source de minimis, and will only need to re-estimate this information every three years.



### Historic Data: Can I report emissions data for years prior to the year I joined the Registry? Some participants may wish to report GHG emissions data for years prior to the year in which they join the Registry. When you join the Registry, you must specify which calendar year of emissions you will first report to the Registry and report your emissions according to the version of the General Reporting Protocol in force at the time of joining. Emissions reported prior to the actual year a participant joins the Registry are considered “historical data.” For each year of historical data, you must report at least your emissions of CO 2 . You may also report entitywide emissions of individual gases for which you have certifiable data, and for which you can report it from that point forward. All historical data must be certified before it can be accepted into the Registry. Reporting multiple years’ worth of certifiable data provides additional information for state consideration. For every year that you report to the Registry, you must report the emissions associated with all of your operations (within your report scope, either CA or U.S). When you choose to report historic data, you must also report all of the emissions associated with all of the facilities you owned or operated in each calendar year, even if you no longer own or operate that facility. By providing this information, you provide an accounting of your organization’s emissions over time. When you re-adjust your emissions baseline to reflect structural changes, you demonstrate your emissions performance over time. The Registry supports consistent and transparent reporting and certification of annual GHG emissions. In this regard, emission reports for years prior to joining the Registry need to comply with the same requirements as for current annual GHG emissions inventories.



### Reporting and Reporting Deadlines: How do I report? When do I report? All participants must report at least their California-wide emissions of carbon dioxide (years 1-3) and all Kyoto gases (years 4+) in five reporting categories to the Registry using CARROT, the online reporting tool. You can also choose to input your source- and facility-level emissions information using CARROT. CARROT can also help you calculate your emissions in many common emission categories. You should work to report your emissions no later than August 31 of the year after they were produced, and complete certification by December 31 of the same year. For instance, you should report your 2006 emissions by August 31, 2007 and complete certification by December 31, 2007. There cannot be any gap years in the data you report. For example, if you join the Registry in January 2006, you will report at least your CO 2 emissions for 2006 by August 31, 2007. You will follow the same timetable for reporting your 2007 and 2008 emissions. Beginning with your 2009 emissions, you must report all 6 GHGs by August 31, 2010. Table I.1 illustrates the minimum reporting requirements over time for a new participant. Part I 

### Year Participant Action

2006 Participant joins the Registry and tracks 2006 emissions

2007 Participant tracks 2007/reports 2006 CO 2 emissions

2008 Participant tracks 2008/reports 2007 CO 2 emissions

2009 Participant tracks 2009/reports 2008 CO 2 emissions

2010 Participant tracks 2010/reports 2009 emissions for 6 GHGs 

### Table I.1: Reporting Years

Confidentiality: Will the information I report be kept confidential? As described above, the public can only view aggregated entity-level emissions data reported to the Registry. Confidential information will only be accessible to you, the Registry, and your chosen certifier, unless you allow others to access such information or wish to have it available to the public.



### Certification: Must my report be certified? Yes. However, the Registry understands that in the initial years of participation, some reports may not be certifiable due to the need to change data collection practices or other factors that make it impossible to meet the reporting requirements. Thus, while you must calculate and certify your emissions for each year you wish to report, you are not required to submit your Certification Opinion to the Registry for the first two years of your participation in the Registry. This flexibility is intended to allow you to have time to fully understand the calculating, reporting, and certification processes before your emissions information is made available to the public. Participants are eligible to receive certification for California-only or U.S emission reports. At this time, international emission reports do not qualify for certification through the Registry, although you can store international data.



### Minimum Quality Standard: What are the requirements for certifying my emission report? Any emission report submitted to the Registry must be free of material discrepancies in order to be certified. It is possible that during the certification process, differences will arise between the emissions estimated by the Registry participant and those estimated by the certifier. These differences between participant and certifier estimations may be classified as either material or immaterial discrepancies. A discrepancy is considered to be material if the overall reported emissions differ from the overall emissions estimated by the certifier by 5% or more. Otherwise the difference is considered to be immaterial.


### Registry-Approved Certifiers: Who must certify a GHG emission report? In order to accept your emission report into the Registrydatabase, it must be certified by an independent thirdparty organization that has been approved by the state of California and the Registry. A list of approved certifiers is provided to all Registry participants and is available on the Registry’s website. The certification process is outlined in Chapter 14. Before your preferred certifier is approved, the Registry will review any pre-existing relationship between you and the certifier you select to determine if there is potential for conflict of interest. Also, a state of California representative may accompany a certifier on site visits, as part of their oversight of the certification process. If, in the course of these activities the state representative needs to view confidential information, the state representative will sign a confidentiality agreement with both you and your certifier to protect any information you designate as sensitive.


### Registry-Approved Technical Assistance Providers: What role do they play? Some participants may desire expert assistance, to collect, document and report their emissions to the Registry and/ or otherwise manage and reduce their GHG emissions. The State and the Registry approve firms qualified to serve as technical assistance providers (TAs). Approved companies have been screened as firms experienced in providing GHG emissions services, and many of them have attended Registry-sponsored training sessions. Participants are not required to use approved TAs. Neither the Registry nor the State is responsible for any consulting services or recommendations they may provide. All firms approved as certifiers also are automatically qualified to act as TAs. A firm cannot provide both technical assistance and certification services to the same client at the same time.



### Role of California State Agencies: What is the relationship between the Registry and State agencies? Why do multiple parties play a role in certification? The Registry was established by California statute as a non-profit voluntary registry for greenhouse gas (GHG) emissions inventories, to help organizations to establish GHG emissions baselines against which any future GHG emission reduction requirements may be applied. The State of California, in turn, will offer its best efforts to ensure that participants receive appropriate consideration for early actions in the event of any future state, federal or international GHG regulatory scheme. The enabling legislation directs two state agencies, the California State Resources Agency and the California Environmental Protection Agency (CalEPA), to provide technical guidance to the Registry, including developing certification procedures. The state is required to identify and qualify third-party organizations to act as certifiers and technical assistance providers, and oversee certification activities. This includes randomly accompanying certifiers on site visits to evaluate the participant’s program for reporting and the reasonableness of the participant’s reported data. State agencies involved in this process include the California Energy Commission (CEC), the California Air Resources Board (CARB) and California Department of Forestry and Fire Protection (CDF). The Registry and state agencies, in the course of these activities, work together and keep each other informed about current activities. In addition, the Registry gives great weight to state agency guidance, and relies in large part on these recommendations when developing Registry policies, procedures and tools, including reporting and certification protocols, and the online reporting tool. However, final Registry policy and technical decisions are made independently by the Registry’s Board of Directors.10 Part II 

# Part II Determining What You Should Report

As you begin to prepare your annual GHG emission report to the Registry, you first need to consider the geographic and organizational boundaries of your organization. That is, you need to determine which sources of emissions to include in your report based on their location, your organizational structure, and operations. For many Registry participants, particularly firms that are wholly-owned entities operating entirely within the State of California, establishing reporting boundaries will be straightforward. For participants whose operations consist of jointly-owned entities and those with operations outside of California, the process may be more involved. Part II is designed to help your organization assess what emissions and activities you should include in your report. Chapter 1 begins at the broadest possible level—your report’s geographic boundaries. It discusses options for reporting your organization’s emissions within the borders of the United States or for those only within the state of California—the minimum requirement for reporting to the Registry. After addressing geographic boundaries, Chapter 2 focuses more narrowly on organizational boundaries. The basic unit of participation in the Registry is an entity in its entirety, as it relates to the geographic boundaries specified in Chapter 1. While only entity-level reporting is required, the Registry strongly encourages organizations to report at the facility-, or sub-entity level; this greater level of detail builds a more credible database of information and facilitates certification. Organizations that wholly own and fully control all of their GHG emission sources will simply report all of their significant emissions to the Registry. For facilities that are owned or controlled by more than one organization, determining organizational boundaries may be more complicated. Once you have determined your geographic and organizational boundaries, Chapter 3 will help you consider the operational boundaries of your emissions, based on whether they are directly or indirectly caused by your organization. Chapter 4 provides guidance on selecting a baseline year, and on adjusting your baseline over time to capture any changes in the size and scope of your organization. After you have categorized your emissions and defined operational boundaries, you will be ready to move onto estimation methods in Chapters 5-11.11 Part II Chapter 1 

# Chapter 1 Geographic Boundaries

II.1.1 Reporting National and California-Based Emissions The first step in determining what to report to the Registry is to decide on the geographic scope of your report. You have the option of reporting California-only emissions, or both California and U.S. GHG emissions.


### Reporting U.S. and CA-Based Emissions The Registry supports the most comprehensive reporting possible and encourages you to report emissions associated with all of your organization’s activities in the United States. If you choose to report your U.S. emissions,you will also need to specifically report your Californiabased emissions. The Registry’s web-based reporting software is designed to capture your organization’s U.S. and California emissions separately so reporting both is easy. Alternately, participants can begin the program by reporting California emissions only and later move to U.S. reporting. If you are reporting at the national level but do not presently have any emissions in California, please report zero California emissions. At this time the Registry will store but does not accept for certification information on emissions released by sources outside of the United States. 

### Reporting California-Only Emissions If you do not have operations, or do not wish to report your emissions outside the State of California, please report your emissions for California-only. To estimate your California-only emissions you must identify those sources within your organization located in California. Emissions associated with the electricity purchased and consumed in buildings and manufacturing processes occurring in California should be included in the calculation of California-only emissions, regardless of the likely location of the power generation. Regarding mobile sources, you should report the total GHG emissions for mobile sources registered in California regardless of whether the vehicles travel inside or outside of the state, or whether vehicle fuel was purchased inside or outside of California. Such vehicles may include those your organization owns or leases (see Chapter 3). Vehicles registered by the California Department of Motor Vehicles are considered to be based in California.


### Organizations without California Emissions If you do not have emissions in California, but wish to report to the Registry, you must report your California emissions as zero. You are able to report to the Registry and have this information certified, although you may also be assessed an additional registration fee to help coverthe State’s costs in overseeing certification of the nonCalifornia data.


### Determining Whether to Report California-only or U.S. Emissions There are several reasons why you may wish to complete a U.S. report of your organization’s emissions, such as:

• An existing environmental management system already captures emissions at the national-level;

• It will help you prepare for a future Federal regulatory regime;

• Corporate decision-making must look at the “big picture” when making efforts to improve efficiency and make least-cost reductions in GHG emissions;

• It enhances your credibility to investors and customers; and

• Environmental stewardship goals are nationwide (and often worldwide). 

### Who should read Chapter 1: Chapter 1 applies to all participants. 

### What you will find in Chapter 1: This chapter explains the options and requirements for determining the geographic scope of your GHG emission report. 

### Information you will need:
You will need basic information about the location of your organization’s facilities in the State of California and, if you are reporting all national emissions, throughout the U.S. 

### Cross-References: It may also be useful to refer to Chapter 2 on organizational boundaries as you examine your geographic boundaries.1 2 Part II Chapter 1 You may also report only California emissions. Examples of the rationale for taking this approach include the following:

• A participant has only California emissions;

• Completing a report for California offers a good learning experience for implementing a more comprehensive national or international corporate accounting scheme in the future;

• Conducting nation-wide accounting is simply too complex and burdensome at this time; and

• The participant owns and controls 100% of all operations in California, while having only partial ownership in operations outside of California, making California-only reporting more straightforward and less burdensome.



## II.1.2 Reporting Worldwide Emissions As some Registry participants have operations both in the U.S. and abroad – and because the issue of climate change knows no international borders – the Registry is developing options to incorporate worldwide GHG emissions reporting in the near future. The Registry does accept standardized GHG emissions data from operations outside the U.S. and participants can gather and store data into CARROT. However, the Registry does not have Board-approved reporting and certification protocols for international data; thus, international GHG emission data is not certified for state consideration at this time.



## II.1.3 Example: Determining
Geographic Boundaries The following example describes how geographic boundaries impact a company’s GHG inventory.



### An Express Mail Delivery Company with a Fleet Based Inside and Outside of California An express mail delivery company operates a fleet of 1000 vehicles, both inside the State of California and outside the state; 350 of the vehicles are registered in California and 650 are registered outside of California. If the express mail delivery company is reporting California-only emissions, they would report emissions for only the 350 vehicles registered in California. If the company is reporting its U.S. emissions, they wouldreport the emissions associated with the 350 Californiaregistered vehicles, and separately report the emissions associated with the 650 non-California based vehicles.1 3 Part II Chapter 2 

# Chapter 2 Organizational Boundaries

II.2.1 Defining Your Entity Once you have determined the geographic boundaries of your report, you should identify the significant emissions for each calendar year within those boundaries that are attributable to facilities and operations that you own or control. For the purposes of this Protocol, the basic unit of participation in the Registry is an entity in its entirety, such as a corporation or other legally constituted body, a city or county, a state government agency, a non-profit organization, etc. At a minimum, you must report your entity-wide (total) emissions. However, the Registry strongly encourages you to report GHG emissions information at the facility- or source-level as part of your entity-level report. Although facility-level reporting may require more data-entry work into CARROT for participants, it will provide a more detailed and comprehensive picture of your emissions profile and could reduce certification costs.



## II.2.2 Reporting Options and
Organizational Boundaries To establish your organizational boundary, you should evaluate all operations, facilities, and sources that fall within your chosen geographic boundary. For those operations and facilities that are wholly-owned, you should report all of the associated emissions. For those operations or facilities in which you have a partial ownership share or working interest, hold an operating license, lease, or otherwise represent joint ventures or partnerships of some kind (both incorporated and unincorporated), you have two options for determining the GHG emissions you should report: Option 1

– Management Control : Report 100% of the emissions from operations, facilities, and sources that your organization controls. If you choose to use the management control approach, the Registry requires participants to determine control based on financial or operational criterion, which must be consistently applied to all operations, facilities, and sources to determine whether or not the associated emissions fall within your organizational boundary. 1 Option 2 – Equity Share : Report a percentage of the emissions, based on your share of financial ownership of an entity, operation, facility, or source. Some participants may have contracts or legal agreements that assign ownership of specific GHG emissions or emissions reductions. Contracts or agreements may serve to clarify your selected organizational boundary. Where you have agreements regarding emission rights or responsibilities, you may wish to disclose this information to the public in the optional section of your emissions report. However, you are required to report your entity-wide emissions using either the management control and/or equity share emissions consolidation approach, regardless of contractual agreements that assign emission rights or responsibilities. Companies can choose to establish an organizational boundary based upon management control (either financial or operational), or equity share only, but may also report based upon both emissions consolidation approaches. The method chosen must be applied consistently across all operations, facilities, and sources. Once you have selected an approach to define your organizational boundary, the Registry requires that you use it consistently for each year of reporting. 2

1 Defining management control in either financial or operational terms is consistent with The GHG Protocol; a discussion of the management control criterion and the operational control criterion can be found in section II.2.3. 2 You may in subsequent years choose to report based upon an additional consolidation methodology, but must continue to report according to the initial methodology you select. 

### Who should read Chapter 2: Chapter 2 applies to all participants. 

### What you will find in Chapter 2: This chapter considers the options and requirements for determining the organizational scope of your GHG emission report. 

### Information you will need: You will need information that will help you determine which sources of emissions are to be included in your organizational structure and operations, including information about joint ventures, subsidiaries, and similar entities. 

### Cross-References: It may also be useful to refer to Chapter 1 on geographic boundaries and Chapter 3 on operational boundaries as you examine your organizational boundaries.1 4 Part II Chapter 2 depend on which of the approaches to control you select. However, in some sectors such as the oil and gas industry, complex joint ventures and ownership/operator structures can exist where financial and operational control are not vested with the same organization. In these cases the choice to apply a financial or operational definition of control can be significant. In making this decision, participants should take into account their individual situation, and select a criterion that best reflects your actual level of control and the standard practice within your industry. Additionally, industry- specific guidance developed by the Registry, included as appendices to this reporting protocol, may provide additional guidance on choosing a criterion for determining management control. Table II.2.1 provides an illustration of the reporting responsibility under the management control reporting option. Financial control is the ability to dictate or direct the financial policies of an operation or facility with the ability to gain the economic rewards from activities of the operation or the facility. One or more of the following conditions establishes financial control:

• Wholly owning an operation, facility, or source

• Considering an operation to be, for the purposes of financial accounting, a group company or subsidiary, and consolidating its financial accounts in your organization’s financial statements

• Governing the financial policies of a joint venture The consistent use of a single emissions consolidation approach facilitates comparisons of annual emissions reports, helps identify trends in emissions, and supports establishing baseline emissions. The consistent use of an approach to set your organizational boundary will also reduce the cost of future year certifications.



## II.2.3 Reporting Based on
Management Control Management control can be defined in either operational or financial terms. When using control to determine how to report GHG emissions associated with joint ventures and partnerships you should first select between either the financial or operational criterion, and consistently apply the definitions below in determining how to report these emissions. One or more conditions from those listed below can be used to establish your choice of control approach. If you determine you have control over a particular joint venture or partnership, you should report 100% of the significant emissions of that entity (all of its operations, facilities, and sources). If you determine you do not have control, you should not report any of the emissions associated with the entity. In most cases, financial control and operational control of an operation, facility or source reside with the same entity. The organization that has financial control typically also has operational control. Consequently, whether or not a joint venture or partnership is deemed to be controlled by your company, and as a result its emissions fall within your organizational reporting boundary, generally will not



### Level of Control of facility/source Percent of GHGs to Report Under Financial Criterion Percent of GHGs to Report Under Operational Criterion
Wholly owned 100% 100% Partially owned with financial and operational control 100% 100%

Partially owned with financial control;

no operational control 100% 0%

Partially owned with operational control; no financial control 0% 100%

Not owned but have a capital or financial lease 100% 100%

Not owned but have an operating lease 0% 100% 

### Table II. 2.1: Reporting Based on Management Control1 5 Part II Chapter 2 operation may implement its own operating policies. In such a case, neither partner would report.


### Rationale for Choosing Management Control An important reason for choosing to report emissions based on management control is that when you control how an operation or a facility is managed, you are able to control factors such as capital investment and technology choice, how energy is used and the level of emissions generated. Thus, reporting emissions using the management control approach reflects your ability to implement actions that could reduce GHG emissions. This approach also helps you to monitor performance of an operation, at a facility, and for the entity. Most criteria pollutant emission reduction programs, regulations, and trading systems are based on management control rather than equity ownership. When you have management control of an operation or at a facility, you typically have greater access to the information and records needed to calculate and report emissions information, helping to minimize the administrative costs of maintaining a GHG emissions inventory.
Note: Management control is the default method used by CARROT to calculate emissions.



## II.2.4 Reporting Based on an Equity Share Basis If you have facilities and operations in which your share of ownership ranges from 1% to 99%, you may choose to report on an equity share basis—either in addition to, or instead of, reporting based on management control. When reporting on an equity share basis, you should include the portion of the emissions from the facility or operations equal to your equity share of the total emissions. If more than one owner of a facility is a participant in the Registry and one owner chooses to report based on equity share, then each participating owner must agree in advance to also report on an equity share basis. The collective accounting methodologies of multiple owners should ensure that all applicable emissions are reported and no double counting occurs in the reports. Participants will need to provide an attestation of their ownership share, prepared by either a certified legal or financial advisor. This document should identify all owners of the facilities, including their respective shares of ownership. Table II.2.2 provides an illustration of the reporting responsibility under the equity share reporting option. under a statute or agreement or contract

• Retaining the rights to the majority of the economic benefits and/or financial risks from an operation or facility that is part of a joint venture or partnership (incorporated or unincorporated), however these rights are conveyed. These rights may be evident through the traditional conveyance of equity interest or working/participating interest or through nontraditional arrangements. The latter could include your organization casting the majority of votes at a meeting of the board of directors or having the right to appoint/remove a majority of the members of the board in the case of an incorporated joint venture. Operational control is the authority to develop and carry out the operating or health, safety and environmental (HSE) policies of an operation or at a facility. 3 One or more of the following conditions establishes operational control:

• Wholly owning an operation, facility, or source

• Having the full authority to introduce and implement operational and health, safety and environmental (HSE) policies. In many instances, the authority to introduce and implement operational and HSE policies is explicitly conveyed in the contractual or legal structure of the partnership or joint venture. While in most cases, holding an operator’s license is an indication of your organization’s authority to implement operational and HSE policies, this may not always be so. If your organization holds an operating license and you believe you do not have operational control, you will need to explicitly demonstrate that your authority to introduce operational and HSE policies is significantly limited or vested with a separate entity. It should be noted that your organization need not be able to control all aspects of operations within a joint venture to have operational control. For instance, making decisions on major capital investments without the approval of other parties in a venture may be beyond the authority of the entity with operational control. In the case of joint control, two entities each have 50% equity ownership and no stipulations exist to demonstrate that either organization has control of the financial or operating policies of the venture. If you have joint control over a facility and are using financial control as your control criterion, you should report a pro rata share of your emissions based on your economic interest in and/or benefit derived from the operation or activities at a facility. In this case, you would report 50% of the controlled entity’s emissions. If you are using operational control as your control criterion, it may be that neither partner has operational control; a separate entity conducting the

3 GHG Protocol, 20041 6 Part II Chapter 2 

### Rationale for Choosing Equity Share Setting organizational boundaries based on equity share reflects a commercial reality that entities profiting from a business activity typically have an interest in the operation of the activity. Consequently, ownership of GHG emissions could reasonably be based on the level of economic interest in the organization that generated the GHG emissions. In some instances, management control is not always the best measure of “control” or “influence” over a shared facility. Furthermore, with respect to risk, ultimate financial liability is distributed based on equity share. Thus, this approach could allow for a more complete coverage of liability and risk.



## II.2.5 Choosing Both Management Control and Equity Share
Reporting Optimally, you should report your GHG emissions using both the management control and equity share approaches. Given the uncertainty of the exact nature of future GHG emissions trading or regulatory regimes, reporting using both methods will provide the greatest flexibility and maximum use of your emissions data in the future. Also, your choice of a geographic boundary for your report may be affected by the number and diversity of operations and facilities for which you have partial ownership and the method you select for accounting for those emissions. Thus, if you have partial ownership of multiple facilities, you should consider your approach to emissions reporting in light of both your geographic and organizational boundary alternatives. Where you share ownership of operations or facilities, all owners will need to clarify who will report emissions. 

## II.2.6 Parent Companies,
Subsidiaries and Holding Companies If your organization is a subsidiary that is a corporation or other legally constituted body you may join the Registry as a participant, if your parent organization is not already participating in the Registry. However, participants that report baselines and annual results as subsidiaries must clearly define the parent organization to the Registry. The parent organization need not participate in the Registry merely because one or more of its subsidiaries chooses to participate. However, if the parent organization later joins the Registry, the parent would report emissions from all its subsidiaries and subsidiaries would not be able to report separately. Holding companies (corporations that are made up of several other corporations) would report following the management control approach described above. If the holding company controls several subsidiaries, it would report the total emissions from each of its subsidiaries.



## II.2.7 Partnerships and joint
Ownership Situations may exist in which no party in your organization has sufficient management to claim responsibility for reporting. For example, in a Limited Liability Partnership (LLP), it is possible that no single entity would have a controlling or majority equity share. In such a case, the collective partners would come to a mutual agreement to divide the responsibilities for reporting GHG emissions to the Registry and report accordingly. For some sectors such as the petroleum industry, it is common to have joint ownership with a single operator. Holding the operating license may not be a sufficient condition for being able to influence the operating policies of an entity or facility. Therefore, you should review all the conditions for management control listed above to determine what emissions you should report.



## II.2.8 Leased Facilities/Vehicles and Landlord/Tenant
Arrangements Reporters shall account for and report emissions from leased facilities and vehicles according to the type of lease associated with the facility or source and the organizational boundary approach selected. This guidance applies to Registry participants that rent office space (i.e., tenants), vehicles, and other facilities or sources (e.g., industrial equipment). 

### Level of Ownership Percent of GHG Emissions to Report Wholly-owned 100% Not wholly-owned, but controlled By equity share

Partially-owned, no control By equity share 

### Table II.2.2. Reporting Based on Equity Share1 7 Part II Chapter 2 There are two types of leases: 4

• Finance or capital lease. If you have an asset under a finance or capital lease, the Registry considers this asset to be wholly owned by you.

• Operating lease. If you have an asset under an operating lease, such as a building or vehicle, the Registry considers this asset to be under your operational control but you do not have any financial risk or reward from owning the asset. The Registry considers any lease that is not a finance or capital lease to be an operating lease. In most cases, operating leases cover rented office space and leased vehicles, whereas finance or capital leases are for large industrial equipment. 

### Reporting emissions from leased assets You shall account for and report emissions from a facility/source under a finance or capital lease as if it is an asset wholly owned and controlled by your company or organization, regardless of the organizational boundary approach selected. With respect to facilities/sources under an operating lease (e.g., most office space rentals and vehicle leases), the organizational boundary approach selected will determine whether reporting the asset’s associated emissions is required or optional. If the organizational boundary approach is either the equity share approach or the financial control criterion under the management control approach, then reporting the emissions from a facility/ source with an operating lease is optional. On the other hand, if you choose the operational control criterion under the management control approach then you are required to report emissions from assets for which you have an operating lease.



### Example II.2.1 Companies with Ownership Divided 60%-40% Company A has 60% ownership and management control, under both the financial and operational control criterion. Company B has 40% ownership of the facility, and does not have management control Under either criterion for management control, Company A would report 100% of GHG emissions. It has financial control based on its 60% share and there are not other provisions that vest operational control with its minority partner. Under equity share, Company A and Company B would report 60% and 40% of GHG emissions respectively, based on their share of ownership and voting interest.



### Participant Facility Management Control Equity Share Reporting Financial Reporting Operational Reporting
Company A 60% ownership & voting interest 100% 100% 60% Company B 40% ownership & voting interest 0% 0% 40%

4 Financial Accounting Standards Board, Statement of Financial Accounting Standards, No. 13. Accounting for Leases. 1976 

## II.2.9 Examples of Management Control vs. Equity Share Reporting The following examples are provided to assist you as you determine whether to report using the management control or the equity share basis. Remember, although these examples are provided for individual facilities, you should choose either or both the management control or the equity share approach for your report in its entirety.1 8 Part II Chapter 2



### Example II.2.2 Companies with Ownership Divided 60%-40% and Voting Interests Divided 45%-55% Company A has 60% ownership of the facility and a 45% voting interest. Company B has 40% ownership of the facility and a 55% voting interest. Company B is also explicitly named as the operator and has the authority to implement its operational and HSE policies. Company B has management control (according to both the financial and operational criteria). Under management control (either financial or operational criterion), Company B would report 100% of GHG emissions and Company A would report none, because Company B has a majority voting interest. Under equity share, Company A would report 60% of GHG emissions and Company B would report 40%, based on ownership share.



### Example II.2.3. Two Companies with 50% Ownership Each Company A and Company B each have 50% ownership of the facility. Company B has the authority to implement its operational and HSE policies, but all significant capital decisions require approval of both Company A and Company B. Each reports 50% of GHG emissions under the financial criterion of management control and equity share. Under the operational criteria of management control, Company B reports 100% of the facility’s emissions while Company A reports 0%.



### Example II.2.4 Three Companies with Ownership Divided 55%-30%-15% Company A has 55% ownership of the facility, Company B has 30% ownership of the facility, and Company C has 15% ownership.. The majority owner has the authority to implement its operational and HSE policies. Under either criterion of management control, Company A would report 100% of GHG emissions because it holds a majority interest in the control of the facility, and Companies B and C would report no emissions. Under equity share, each company would report according to its equity share of ownership and voting interests. 

### Participant Facility Management Control Equity Share Reporting Financial Reporting Operational Reporting
Company A 60% ownership & 45% voting interest 0% 0% 60%

Company B 40% ownership & 55% voting interest 100% 100% 40%



### Participant Facility Management Control Equity Share Reporting Financial Reporting Operational Reporting
Company A 50% ownership & voting interest 50% 0% 50% Company B 50% ownership & voting interest 50% 100% 50%



### Participant Facility Management Control Equity Share Reporting Financial Reporting Operational Reporting
Company A 55% ownership & voting interest 100% 100% 55% Company B 30% ownership & voting interest 0% 0% 30% Company C 15% ownership & voting interest 0% 0% 15%1 9 Part II Chapter 2 

# Chapter 3 Operational Boundaries: Required Direct and Indirect Emissions

The next step in compiling your GHG emission report is to divide your emission sources into emission source categories. Emission sources produce either direct or indirect emissions.

Direct emissions are those emissions from sources that are owned or controlled by your organization. You must report all of your significant direct emissions. These emissions originate from:

• Mobile combustion sources (i.e., from cars, trucks, rail, air, and other transport) owned or leased by your organization and used for moving raw materials, finished products, supplies, or people;

• Stationary combustion sources used for the production of electricity, steam, or district heating and cooling;

• Process emissions that occur during the production of cement, adipic acid, and ammonia, as well as emission from agricultural processes; and

• Fugitive sources, for example methane leaks from pipeline systems or leaks of HFCs from air conditioning systems.
Indirect emissions are emissions that occur because of your organization’s actions, but are produced by sources owned or controlled by another entity. 1 You should report all of your company’s indirect emissions from the following sources: • Purchased and consumed electricity;

• Purchased and consumed heat, steam, or cooling; You are also encouraged, but not required, to report indirect GHGs from other activities of your organization that produce emissions. This could include, for instance, employee commuting and business travel, off-site waste disposal, and other emissions resulting from your demand for goods and services each year. The Registry currently provides limited guidance for estimating emissions from these optional indirect sources, and identifies some existing tools to help you in this process. More information is available in Chapter 11.



## II.3.1 Double Counting Direct and Indirect Emissions The Registry recognizes that a company accounting for its indirect emissions may double count the direct emissions from a separate entity. For example, the indirect emissions from electricity use in a participant’s inventory double counts the direct emissions from the electricity generator that produced the participant’s power. The Registry requires participants to inventory both direct and indirect emissions to create a comprehensive emissions profile of the entity. This yields a complete picture of the emissions produced by sources owned or controlled by the participant and the emissions produced as a consequence of the participant’s activities. The Registry strives to avoid confusion by requiring participants to report direct and indirect emissions separately. Double counting direct and indirect emissions does not misrepresent a company’s emission profile. It only impacts a company in terms of how the reported information is used. For instance, emissions regulatory regimes could impose limits on emissions that apply to direct or indirect emissions. 1

1 The GHG Protocol, 2004 

### Who should read Chapter 3: Chapter 3 applies to all participants. 

### What you will find in Chapter 3: This chapter provides guidance on determining what direct and indirect GHG emissions your organization must report to the Registry. 

### Information you will need:
You will need information about the size and nature of GHG-emitting operations throughout your organization in order to determine which emissions are directly and which are indirectly caused by your organization. 

### Cross-References: It will be useful to consider your geographical and organizational boundaries addressed in Chapters 1 and 2, and de minimis and significant emissions addressed in Chapter 12.2 0 Part II Chapter 4 

# Chapter 4 Establishing and Updating a Baseline

II.4.1 Establishing Your Baseline A baseline is a datum or reference point against which to measure GHG emissions increases and decreases over time. Baselines are used in a regulatory contextto establish a clear threshold for compliance and noncompliance. However, participants can also benefit from establishing a baseline with the Registry. For example, the State of California has committed “to use its best efforts to ensure that organizations that establish greenhouse gas emissions baselines and register emissions results that are certified in accordance with this chapter receive appropriate consideration under any future international, federal, or state regulatory scheme relating to greenhouse gas emissions.” 1 Additionally, setting a baseline also allows participants to scale structural changes to their organization back to a benchmark emission profile. This aspect of baselines is called “normalization”. For example, as explained below, an acquisition of a company could dramatically increase a participant’s emissions relative to previous reporting years. To account for the impact on its emissions profile due to acquisition, a participant would adjust its baseline to incorporate the additional emissions associated with the acquired company, thereby showing that the change in emissions occurred because of structural changes. In the Registry’s program, participants select their baseline according to the year that best represents their standard emissions profile. The baseline year will serve as the benchmark to which you will compare other reporting years. In the context of the Registry, a baseline is a “base year” that serves as a benchmark to compare emissions produced by an entity over time. The baseline is adjusted to reflect structural changes in your organization. 2 A baseline may also change if there are fundamental changes in generally accepted GHG emissions accounting methodologies. Although the Registry strongly encourages participants to set a baseline, you are not required to do so. However, if you choose not to establish a baseline, reviewers of your emission trend might compare successive reporting years back to your first year of reporting, regardless of whether it is indicative of your current structure or operating conditions or not. A participant may begin reporting emissions to the Registry for any year from 1990 forward; likewise it can establish as its baseline any reporting year from 1990 forward. After establishing a baseline participants should report certified emissions results for each subsequent year. If an organization’s participation in the Registry lapses temporarily, it must report emissions for all intervening years upon renewing its participation, or establish a new baseline. If its boundaries do not change significantly, the baseline will remain fixed over time.



## II.4.2 Rationale for Setting a
Baseline There are several issues to consider when deciding whether to establish a baseline, including:

• Data certainty – do you have sufficient data to certify your emissions against the requirements in the General Reporting Protocol for the baseline year?

1 Section 42801 of the California Health and Safety Code. 2 In the GRP, baselines refer strictly to entity-level baselines. The GRP does not provide guidance on setting project-level baselines. Participants should refer to the Registry project protocols for direction on this activity, which is currently available only for forest projects. For all other projects types Registry guidance is forthcoming. 

### Who should read Chapter 4: Chapter 4 applies to all participants. 

### What you will find in Chapter 4: This chapter considers the options and requirements for determining your organization’s baseline. 

### Information you will need: You will need information that will help you determine the basis for selecting a baseline year, such as, historic emissions data to determine the earliest year (back to 1990) for which you can assemble the required emissions data to complete an emission report. You will also need to consider any information, if applicable, describing new or recent mergers and acquisitions, divestitures, outsourcing and insourcing of services, and other changes to your organization affecting your total emissions. 

### Cross-References: You will need to refer to all applicable chapters relating to quantifying your emissions (Chapters 5-11) in determining your baseline.2 1 Part II Chapter 4 • Comparable organizational structure – is your organization sufficiently comparable in its composition and structure to support a meaningful comparison with the baseline year?

• Relative emission levels – which year minimizes or maximizes your emissions relative to most recent levels, and what are the benefits of doing so? Your baseline should not be adjusted for the organic growth or decline of your organization. Organic growth or decline refers to the increase or decrease in production output, changes in product mix, plant closures, and the opening of new plants that are not the result of changes in the structure of the participant’s organization or the result of shifting operations into or out of California or the U.S. Many organizations experience growth and thus their total absolute emissions will increase from year to year, regardless of their organization’s operational efficiency. Such organizations, in addition to reporting their total emissions, may also elect to report an efficiency metric, that measures GHG emissions per unit of performance or output compared to the baseline ratio (e.g., CO 2 /ft 2 of office space, CO 2 /customer, CO 2 /kWh, CO 2 /$ of revenue, etc.) A list of industry-specific metrics is provided in Appendix D.



## II.4.3 Updating Your Baseline
Conditions for Updating Your Baseline The purpose of a baseline is to compare your organization’s emission levels from a point in the past. To allow for this comparison, you must have comparable boundaries over time. If your organization’s boundaries change with time, you will need to adjust baseline emissions to permit accurate comparison. 3 This Protocol identifies six circumstances that would require you to update your baseline:

Structural Changes in Your Organization

1. Mergers and Acquisitions;

2. Divestitures;

3. Outsourcing – contracting activities to outside parties that were previously conducted internally;

4. Insourcing – conducting activities internally that were previously contracted to outside parties; Shifting of Emissions Sources

5. A shift in the location of an emission sources (e.g., due to relocating of operations into or out of the U.S. or the State of California, depending on your geographic boundaries); and Improved GHG Accounting Methodologies

6. Fundamental changes in generally accepted GHG emissions accounting methodologies (e.g., significant changes in emission factors or understanding of Global Warming Potential). All required sources of direct and indirect emissions must be included in a participant’s entity-wide baseline for reporting and adjustment purposes. However, participants identify and account for direct and indirect emissions separately. Thus, participants may consider tracking both types of emissions separately in terms of a baseline. Both direct and indirect emission baselines are meaningful for purposes of the Registry.


### Threshold for Updating a Baseline For many organizations, particularly large ones, mergers, acquisitions, and divestitures, as well as the other listed organizational changes, are common occurrences. Rather than requiring baseline adjustments whenever any changes occur in your organization, however insignificant, you need only adjust your baseline whenever you estimate that the cumulative effect of such changes affects your organization’s total reported emissions by plus or minus 10% relative to the baseline. You may adjust your baseline every year, if you wish. You do not need to adjust your baseline when emissions change by plus or minus 10% at any individual facility unless this facility-level change also affects your total entity emissions by plus or minus 10%. However, if the company that your organization acquired or merged with did not exist at the time your company set its baseline, then you should not adjust your baseline to account for the change in emissions. This is considered organic growth. In some situations, year-to-year changes to total emissions resulting from structural or other changes to your organization may fall below the 10% threshold for updating your baseline. You will need to update your baseline if and when the cumulative effect is greater than 10%. An example of cumulative changes to total emissions is provided in Example II.4.7, below. When you specify a baseline, for every year after the baseline year, your certifier will also need to verify that your total emissions have not changed by more than 10% from the baseline due to any cause except organic growth. This is intended to provide a check that you are correctly tracking and reporting the emissions associated with your organization’s structure.

3 Participants also have the option to change their baseline at their discretion.22 Part II Chapter 4



### Example II.4.1 Mergers and Acquisitions Your organization merges with Mergitrex, raising your total GHG emissions by over 10%.

Adjust your baseline emissions to include Mergitrex’s baseline emissions (provided Mergitrex existed in your baseline year). If Mergitrex did not exist in the baseline year, do not adjust your baseline emissions. If your merger with Mergitrex led to less than a 10% increase in GHG emissions, do not adjust your baseline emissions unless the acquisition, when combined with other non-organic changes to the organization, changes your annual emissions by more than 10%. If Mergitrex does not have sufficient data to establish baseline emissions for your organizations baseline year, you will need to select a new baseline year for which both companies have sufficient data to allow the baseline emissions to be certified.



### Example II.4.2 Divestitures Your organization divests three divisions over the second, third, and fourth reporting years. Each of these divisions account for 4% of your GHG emissions, for a 12% total reduction in emissions by year four.

Because the cumulative effect of these divestitures reduces your company’s emissions by more than 10% in year four, you will need to adjust your baseline by subtracting the emissions of the three divisions from those reported during your baseline year and adjust the baseline accordingly. M 30 %

Yo ur Co

. 10 0% Yr

. 1 Baselin e

Ye ar 1 M 30 %

Yo ur Co

. 10 0% Upd at ed Baselin e

Ye ar 2 M 7%

Yo ur Co

. 10 0% Yr

. 1 Baselin e

Ye ar 1 M 7%

Yo ur Co

. 10 0% Same Baselin e

Ye ar 2 GHGs Ra is ed Le ss Than 1 0%: Sa me Ba se lin e GHGs Ra is ed Ov er 10 %: Update d Ba se li ne

GHGs Reduc ed by Mo re T han 10% : Update d Ba se li ne

Z 4%

Re st of Co

. 88 % Same Baselin e

Ye ar 2 Y 4% 96%

Z 4%

Re st of Co

. 88 % Same Baselin e

Ye ar 3 92%

Re st of Co

. 88 %

Adjuste d Baselin e

Ye ar 4 88% Z 4%

Re st of Co

. 88 % Yr

. 1 Baselin e

Ye ar 1 Y 4% X 4% 10 0% 

## II.4.4 Example: Updating Your Baseline23 Part II Chapter 4



### Example II.4.3 Outsourcing Your organization contracts out activities previously included in your baseline. If your organization contracts out activities previously included in its baseline inventory, you should treat these activities similar to a divestiture. Emissions associated with the outsourced activity should now be reported as optional emissions and subtracted from the baseline emissions. If this shift affects your emissions by more than 10%, you should adjust your baseline. There is no need to adjust your baseline for outsourcing of activities that did not exist during your baseline year. As part of your annual GHG emissions reporting, you will attest that your organization has not outsourced any emissions, or, if you have, that these emissions have been subtracted from your baseline or that they fall below the minimal level.



### Example II.4.4 Insourcing Your organization begins to conduct business activities not previously included in its baseline inventory. Insourcing is the converse of outsourcing. You should treat these activities as an acquisition. Emissions associated with the insourced activity should be reported as direct or indirect depending on the owner of the emissions and not included with optional emissions. You should not adjust the baseline for insourcing of activities that began after your baseline
year.



### Example II.4.5 Shifting the Location of Emissions Sources Your organization moves operations out of or into California or the U.S. If you shift operations outside of California, which reduces the sum of your direct and indirect emissions by 10% or more, subtract the emissions of the shifted operations from your baseline. Shifts of operations into California should be addressed by increasing your baseline to include emissions from those operations. A U.S. baseline should be adjusted similarly for shifts of operations outside or into the U.S. Where you identify leakage or shifting of emissions—where reducing emissions at one location leads to an increase of emissions at another location—because of shifts in the location of your emission sources, you should document the estimated impacts in your annual movement report.



### Example II.4.6 Change in Emissions Accounting Methodologies Your organization employs a new methodology that is approved by the Registry Your baseline emissions should be recalculated for any changes in calculation methodologies if such changes will alter your total emissions in the current reporting year more than 10%. This ensures a comparative time-series of emission estimates.24 Part II Chapter 4



### Example II.4.7 Cumulative Changes to Total Emissions Your organization acquires three companies over three years, raising your GHG emissions by 12%.

Your company acquires Reyes Rockets, Sierra Spaceworks, and Trinity Telescopes in reporting years two, three, and four representing GHG emission increases of 3%, 5%, and 4%, respectively. While these acquisitions individually represent less than the required 10% increase for a baseline adjustment, they amount to a 12% cumulative increase in total emissions. Thus, you would be required to update your baseline in year four (assuming each company existed in your baseline year).25 

# Part III Quantifying Your Emissions

Having determined your geographic, organizational, and operational boundaries and your emission baseline (if you choose to have one), you are ready to begin estimating your organization’s overall emissions. For many participants, the only significant emissions of GHGs you will have to report are indirect emissions from the purchase and consumption of electricity. Thus, this Protocol begins its series of emissions estimation methods with indirect emissions from electricity consumption. Next, it provides guidance for the next most common emission sources for participants: direct emissions from mobile sources. The following chapters provide guidance on calculating emissions from other required sources and optional sources. Part III provides you with the technical methodologies needed to quantify the GHG emissions you will be reporting to the Registry. Chapter 5 provides an explanation of de minimis and significant emissions. De minimis emissions represent a quantity of GHG emissions from one or more sources, and/or one or more gases, which, when summed, equal less than 5% of your organization’s total emissions. Chapters 6 though 11 provide estimation methods for the following categories of emissions:

• Chapter 5 – De minimis Emissions and Significance;

• Chapter 6 – Indirect Emissions from Grid-Delivered Electricity Use;

• Chapter 7 – Direct Emissions from Mobile Combustion;

• Chapter 8 – Direct Emissions from Stationary Combustion;

• Chapter 9 – Indirect Emissions from Co-Generation, Imported Steam and District Heating or Cooling;

• Chapter 10 – Direct Process Emissions; and

• Chapter 11 – Direct Fugitive Emissions. Chapter 12 provides guidance on efficiency metrics and reporting emissions outside of your entity’s influence, which the Registry considers Optional Reporting.26 Part III Chapter 5 

# Chapter 5 De Minimis Emissions and Significance

The rules, methodologies and standards in this Protocol are designed to support the reporting of GHG emissions in a manner that minimizes the reporting burden and maximizes the benefit of standardized GHG emissions data.



## III.5.1 Understanding De minimis and Significant Emissions For the purposes of this Protocol, de minimis emissions are a quantity of GHG emissions from any combination of sources and/or gases, which, when summed equal less than 5% of your organization’s total emissions. Significant emissions are any emissions of GHGs that are not de minimis in quantity when summed across all sources of your organization. For many participants, identifying, quantifying, and reporting all of their GHG emissions would be unduly burdensome and not cost-effective. Some participants may operate hundreds, if not thousands, of small facilities where the known emissions—including, for example, indirect emissions from electricity consumption or direct emissions from motor vehicle operation—are a small fraction of larger emissions sources from industrial activities. To reduce the reporting burden, the Registry requires that entities report at least 95% of their emissions. Thus, if necessary, up to 5% of emissions do not need to be reported. However, the Registry strongly encourages entities to report 100% emissions where possible.



## III.5.2 Rationale for Calculating De Minimis Emissions You must identify all of the emissions in your inventory. For significant sources, you must calculate these using required methodologies. For insignificant sources, you may use a rough, upper bounds estimate to determine the amount of emissions that are de minimis. In the first year, you need to identify what sources fall into the de minims pool and their estimated total tons of emissions. This information must be reviewed and accepted by your certifier. In subsequent years, if these emissions do not change significantly, you can hold these assumptions constant, and your certifier may not need to re-examine your estimates. This may help to reduce your reporting burden over time For example, a participant estimates they emit about 1,000 metric tons of CO 2 each year. Most of these emissions come from an on-site heating and cooling system that services their buildings. In addition, this participant also has one company car that is driven about 20,000 miles each year. This participant estimates that between 800 and 1000 gallons of gasoline are consumed by this car each year. Taking the upper estimate of 1000 gallons, the participant calculates the emissions from this source as 8.8 metric tons of CO 2 /year, and finds that this amount falls below the de minimis threshold of 5% or 50 tons CO 2 /year. The participant can provide this estimation to the certifier, along with vehicle records showing the actual miles traveled of the car. In subsequent years, where the operation patterns do not change significantly, the participant can continue to declare the emissions from this source de minimis, and will need to re-calculate this information only every three years. You may use alternative methods to demonstrate that emissions are de minimis. For example, if your emissions come only from electricity and fuel consumption, it would be sufficient to show that the emission factors for methane and nitrous oxide, when multiplied by their global warming potentials and added together, are less than 5% of the corresponding emission factor for carbon dioxide. Assuming you deemed no other type of emissions to be 

### Who should read Chapter 5: Chapter 5 applies to all participants. 

### What you will find in Chapter 5: This chapter provides guidance on determining significant emissions that should be reported, and estimating de minimis emissions that will not need to be reported. 

### Information you will need:
You will need information about the size and nature of GHG-emitting operations throughout your organization, particularly to be able to identify emissions sources that would amount to less than 5% of your company’s total emissions. 

### Cross-References: It will be useful to consider your geographical and organizational boundaries addressed in Sections II.1 and II.2, respectively, operational boundaries considered in Section II.3, and all relevant quantification issues raised in Sections III.6 - III.11.27 Part III Chapter 5 de minimis, the total de minimis emissions would be less than the 5% threshold. You should base your de minimis assumptions on the IPCC ‘s Second Assessment Report (SAR) global warming potential values. Your estimations and assumptions in calculating your de minimis emissions will need to be provided to and verified by your certifier. If your operations do not change significantly from year to year, you will only need to re-calculate and have certified your de minimis emissions every three years.



## III.5.3 Reporting Your Significant Emissions You must report at least 95% of your organization’s overall emissions. Your certifier will assess that you have reported at least 95% of your emissions, and with less than a 5% margin of error. Even so, the Registry strongly encourages you to report 100% of your emissions if you are able.



## III.5.4 De Minimis Emissions and
Geographic Boundaries If you are only reporting California emissions, the 5% threshold for de minimis refers to the sum of emissions from sources in the State of California. If you are reporting at the national level, the 5% threshold applies separately to emissions from all sources in the U.S. and to emissions from sources located in California. This is consistent with the requirement that participants report emissions from U.S. sources separately from California sources.



## III.5.5 Identifying De Minimis Emissions The sources and gases that will be de minimis will vary from participant to participant. For example, fugitive GHG emissions may be de minimis for many participants but will likely be significant for participants involved in the transportation and distribution of natural gas. Similarly, many participants may choose to select non-CO 2 gases as de minimis since non-CO 2 gas emissions are not significant for many operations. On the other hand, some companies where the majority of emissions are of non-CO 2 gases—such as gas transmission and distribution firms— are not likely to simply consider non-CO 2 emissions as de minimis. As demonstrated in the examples on the following pages, you have some discretion in identifying which de minimis emissions not to report. As Examples III.5.1 and III.5.2 demonstrate, there may be instances where you identify multiple sources as de minimis, which, when added together, equal less than 5% of your emissions. Example III.5.3 illustrates how emissions of different kinds of gases can also be considered de minimis if their combined total is less than 5% of your overall emissions.



## III.5.6 Using CARROT to Document De Minimis Emissions CARROT can help you to calculate and track your de minimis emissions over time. In the first year you report using CARROT, you should enter information to calculate all of your emissions. Once you have reported your inventory, you can designate any combination of individual sources or gases as de minimis. CARROT will then track this information for you, in a category separate from the rest of your emissions.28 Part III Chapter 5



### Example III.5.1 Significance where De Minimis Emissions are Five Percent or Less Your company intends to report GHG emissions from seven sources ( A through G). You have calculated your total GHG inventory (including de minimis emissions) to determine the 5% threshold. Your total emissions inventory from all seven sources is 100,000 metric tons CO 2 e. Therefore, the 5% de minimis threshold is 5,000 metric tons CO 2 e. This means that you can decide which 5,000 metric tons of emissions you want to classify as de minimis. The sum of the GHG emissions from Source A, Source B, and Source C is equal to 5% of your company’s total emissions or 5,000 metric tons. As a result, you may choose not to report emissions from Source A, Source B, and Source C as they are de minimis sources. Note, however, that each source is the sum of all GHGs emitted for that source. For example, Source C is a combination of 1,350 metric tons CO 2 equivalent and 650 metric tons of CO 2 e of methane, for a total of 2,000 metric tons of CO 2 e

2% 2% 1%

So ur ce B 2, 00 0 So ur ce A

1, 00 0

So ur ce C

2, 00 0

So ur ce D 20 ,00 0 MT

CO 2 e So ur ce E 19 ,00 0 MT

CO 2 e So ur ce F
21 ,00 0 MT

CO 2 e So ur ce G
35 ,00 0 MT

CO 2 e De Mini mi s Em is si on s Th e su m of So ur ce A, B, an d C

is eq ua l to or le ss th an 5% of
th e to ta l o f al l G H G em issi on

so u r c e s.

CH 4 65 0 MT
CO 2 e

CO 2 1, 35 0 M T

CO 2 e Ea ch so u r c e is a su mma ti on of al l G H Gs em i t te d by th at

so u r c e in CO 2 eq u i va le nt s (C O 2 e)

.

So ur ce C 2, 00 0 M T CO 2 e 5, 00 0 is 5% of the to ta l

e miss io ns of 1 0 0,0 00 me tr ic
to ns of C O 2 e.

2, 50 0 5, 00 0 7, 50 0

0 20 ,00 0 21 % 35 %

20 %

19 % Si gn i f ic an t Em is si on s Th e su m of So u r c es E th ro ugh G co m p ris e 95 % of the
to ta l. 

## III.5 .7 Example: Determining De Minimis29 Part III Chapter 5



### Example III.5.2 Significance where De Minimis Emissions are Greater than Five Percent Your company intends to report GHG emissions from 6 sources. You have estimated that your total GHG emissions inventory from all 6 sources, including de minimis sources, is 200,000 metric tons of CO 2 e. Therefore, your 5% threshold is 10,000 metric tons of CO 2 e. You have three sources, Source A, Source B, and Source C, that are each below the 5% threshold. However, you will need to select a combination of sources that, when added together, are less than or equal to the 5% threshold. For example, you may choose to classify Source A and Source B as de minimis and therefore include Source C in your annual report. Likewise, you could also choose to classify Source C as de minimis and include Source A and Source B in your annual report.



### Example III.5.3 Significance where Different Sources of CO 2 

### and CH 4 

### Emissions are De Minimis Your company plans to report both carbon dioxide and methane emissions from four sources. You have estimated your total GHG emissions from all four sources at 100,000 metric tons of CO 2 e. The emissions from the four sources are as follows: 34 % 33 %

So ur ce C 9, 00 0 MT

CO 2 e So ur ce D 50 ,00 0 MT

CO 2 e So ur ce E 68 ,00 0 MT

CO 2 e So ur ce F 66 ,00 0 MT

CO 2 e 4.5% 25 % Si gn i f ic an t Em is si on s Th e su m of So u r c es C th ro ugh F co mpr i se 96. 5% of
th e to ta l. De Mi ni mi s Em is si on s Th e su m of So ur ce A an d B is

eq ua l to or l e ss th an 5 % of th e to ta l of al l GH G em issi on

so u r c e s.

1.5% 2% So ur ce A 4, 00 0

So ur ce B

3, 00 0 10 ,00 0 is 5% of the to ta l

e miss io ns of 2 0 0,0 00 me tr ic
to ns of C O 2 e.

5, 00 0 10 ,0 0 15 ,00 0



### Source CO 2 

### Emissions (metric tons) CH 4 

### Emissions (metric tons CO 2 

### e) Total Source Emissions (metric tons CO 2 

### e)

Source 1 39,900 100 40,000

Source 2 29,900 100 30,000

Source 3 19,900 100 20,000

Source 4 3,000 7,000 10,000

Total 100,000

De Minimis Threshold 5,000 De minimis emissions = 3,300 Reported emissions = 96,7003 0 Part III Chapter 6 

# Chapter 6 Indirect Emissions from Electricity Use

III.6.1 Calculating Indirect Emissions from Electricity
Use Nearly all companies are likely to have some indirect emissions associated with the purchase and use of electricity. In some cases, indirect emissions from electricity use may be the only GHG emissions that a company will have to report. To calculate indirect emissions from electricity use, you should follow this simple five-step process:

1. Determine your annual electricity use in each applicable state or region where you have operations;

2. Select the appropriate electricity emission factors that apply to the electricity used;

3. Determine your total annual emissions in metric tons;

4. Convert non-CO 2 gases to carbon dioxide equivalent (CO 2 e); and

5. Total the sum of all CO 2 and CO 2 e gases emitted from electricity use. The generation of electricity through the combustion of fossil fuels typically yields carbon dioxide, and to a much smaller extent, nitrous oxide and methane. This Protocol provides annual emission factors for all three. However, if you are reporting only indirect emissions from electricity use, both nitrous oxide and methane are likely to be de minimis. Where these emissions are significant, you are required to report them beginning with the fourth year of your participation in the Registry. Step 1: Determine annual electricity consumption. Reporting indirect emissions from electricity consumption begins with determining annual electricity use. The preferred method for establishing annual electricity use relies on the energy use information provided by the electric utility company. A participant’s monthly utility bills contain the number of kilowatt-hours consumed. A kilowatt-hour (kWh) is a measure of the energy used by electric loads, such as lights, office equipment, air conditioning, or machinery. Depending on the organization of your company and its facilities, you may need to aggregate multiple electricitybills. Collect your monthly bills and record the kilowatthours consumed each month. Then, add together your total kWh per state for the year. When your electric bill does not begin or end exactly on January 1 and December 31, but spans two calendar years, you must pro-rate your emissions according to the number of days billed in each year; refer to Equation III.6a.

Equation III.6a Monthly Electricity Use

Electricity
Use (kWh) = 

# ( Electricity
Use (kWh) in Period Billed ÷ Number of Days in Period Billed 

# ) x Number of Days of Bill Period

To calculate your emissions for January from an electric bill spanning December and January, first, divide your total kilowatt-hours used by the number of days in your billing cycle. Then, calculate the number of days from your bill that fall in January. Multiply the electricity use per day by the number of days in January. Add this amount to any other electric bill that includes days in January. If an organization is unable to obtain energy use information from the utility, the Registry offers two alternative methodologies for estimating energy consumption. Instructions for following these approaches are provided in section III.6.2. 

### Step 2: Select electricity emission factors applicable to the area the energy was consumed. An electric grid emission factor represents the amount of GHGs emitted per unit of electricity consumed from the electricity transmission and distribution system, and is reported in pounds per kilowatt-hour (lbs/kWh or /MWh). 

### Who should read Chapter 6: Chapter 6 applies to all participants. Any organization that purchases and consumes electricity from an electric utility should complete this chapter. 

### What you will find in Chapter 6: This chapter provides guidance on calculating your indirect emissions from electricity consumption. 

### Information you will need: Organizations will simply need to refer to monthly utility electricity bills for information about electricity consumed. 

### Cross-References: This chapter may be useful in completing Chapter 9 on quantifying indirect emissions from co-generation, steam, or district heating or cooling.3 1 Part III Chapter 6 However, as a practical matter it is often very difficult to determine the exact fuel source for your electricity. Thus, regional/power pool emission factors for electricity consumption can be used to determine emissions based on electricity consumed. If you can obtain certifiable emission factors specific to the supplier of your electricity, you are encouraged to use those factors in calculating your indirect emissions from electricity generation. If your electricity provider reports an electricity delivery metric under the Registry’s Power/Utility Protocol, you may use this factor to determine your emissions, as it is more accurate than the default regional factor. Fuel use to generate electricity varies from year to year, so emission factors also fluctuate. When possible, you should use emission factors that correspond to the calendar year of data you are reporting. However, if emission factors are not available for the year you are reporting, use the most recently published figures. This Protocol provides power pool-based carbon dioxide emission factors from the U.S. EPA’s eGRID database (see Figure III.6.1), which are provided in Appendix C, Table C.1. These are updated in the Registry’s reporting tool, CARROT, as often as they are updated by eGRID.

Default methane and nitrous oxide emission factors are provided in Appendix C, Table C.2. 

### EPA’s Emissions and Generation Resource Integrated Database (eGRID) The Emissions & Generation Resource Integrated Database (eGRID) provides information on the air quality attributes of almost all the electric power generated in the United States. eGRID provides search options including information for individual power plants, generating companies, states, and regions of the power grid. eGRID integrates 24 different federal data sources on power plants and power companies, from three different federal agencies: EPA, the Energy Information Administration (EIA), and the Federal Energy Regulatory Commission (FERC). Emissions data from EPA are combined with generation data from EIA to produce values like pounds per megawatt-hour (lbs/ MWh) of emissions, which allows direct comparison of the environmental attributes of electricity generation. eGRID also provides aggregated data to facilitate comparison by company, state, or power grid region. eGRID’s data encompass more than 4,700 power plants and nearly 2,000 generating companies. eGRID also documents power flows and industry structural changes. www.epa.gov/cleanenergy/egrid/index. htm.



### Figure III.6.1 EPA’s eGRID Power Pool Regions

Source: EPA’s eGRID Subregion File (Year 2000 Data)32 Chapter 6 

### Step 3:	 Determine total annual emissions and
convert to metric tons. Multiply your electricity use in kilowatt-hours from Step 1 by the emission factors for CO 2 , CH 4 , and N 2 O from Step 2. To convert pounds into metric tons, divide the total by 2204.62 lbs/metric ton. (See Equation III.6b) Repeat this step for each region in which you purchased electricity.

Equation III.6b Total Emissions from Indirect Electricity Use

Total CO 2 Emissions (metric tons) = Electricity
Use (kWh) x Electricity Emission Factor (lbs CO 2 /kWh) 

### ÷ 2,204.62 lbs/metric ton

Total CH 4 Emissions (metric tons) = Electricity
Use (kWh) x Electricity Emission Factor (lbs CH 4 /kWh) 

### ÷ 2,204.62 lbs/metric ton

Total N 2 O Emissions (metric tons) = Electricity
Use (kWh) x Electricity Emission Factor (lbs N 2 O/kWh) 

### ÷ 2,204.62 lbs/metric ton

Step 4: Convert Non-CO 2 Emissions to CO 2 e and sum the total. To incorporate non-CO 2 gases in your GHG emissions inventory, the mass estimates of these gases will need to be converted to CO 2 equivalent. To do this, multiply the non-CO 2 GHG emissions in units of mass by its global warming potential (GWP). Table III.6.1 lists the 100-year GWPs to be used to express emissions on a CO 2 equivalent basis. Equation III.6c shows the calculation to determine CO 2 e from the total mass of a given non-CO 2 GHG using the GWPs published by the IPCC. If you use CARROT to calculate your emissions, it will automatically perform this calculation for you. Sum your CO 2 + CO 2 e emissions (see Equation III.6d).

If non-CO 2 gases are de minimis when converted to CO 2 e, you do not need to report them to the Registry (see Chapter 5). Also, you are not required to report non-CO 2 gases until the fourth year that you report emissions to the Registry. 

### Greenhouse Gas GWP (SAR, 1996) GWP (TAR, 2001)

CO 2 1 1

CH 4 21 23

N 2 O 310 296

HFC-23 11,700 12,000

HFC-125 2,800 3,400

HFC-134a 1,300 1,300

HFC-143a 3,800 4,300

HFC-152a 140 120

HFC-227ea 2,900 3,500
HFC-236fa 6,300 9,400

HFC-43-10mee 1,300 1,500

CF4 6,500 5,700

C2F6 9,200 11,900

C3F8 7,000 8,600

C4F10 7,000 8,600

C5F12 7,500 8,900

C6F14 7,400 9,000

SF6 23,900 22,000 

### Table III.6.1: Comparison of GWPs from the IPCC’s Second and Third Assessment Reports

Source: U.S. Environmental Protection Agency, U.S. Greenhouse Gas Emissions and Sinks: 1990-2000 (April 2002).

Equation III.6c Converting Non-CO 2 GHGs to Carbon Dioxide Equivalent

Metric Tons of
CO 2 e = Metric Tons of non
COe GHG x GWP (SAR, 1996)

Equation III.6d Total GHG Emissions from Electricity Use

Total CO 2 e Emissions (metric tons) = Total CO 2 Emissions (metric tons) + Total CO 2 e Emissions (metric tons)33 Part III Chapter 6 

### Method 1 The following steps provide instructions on how to arrive at an estimate of energy use by determining your proportion of the building’s total energy use. 

### Step 1: Determine your building’s total annual electricity consumption. Collect your building’s monthly electricity bills and record the kilowatt-hours consumed each month. Then, add together the total kWh for the year. When your electric bill does not begin or end exactly on January 1 and December 31, but spans two calendar years, you should pro-rate your emissions according to the number of days billed in each year, and include only the usage associated with the days in the calendar year you are reporting. Step 2 Calculate your organization’s share of total building electricity consumption. Next, you must identify your organization’s total square footage occupied and determine what percentage this is of the building’s total square footage. Multiply this percentage by the building’s total annual electricity consumption. Step 3: Select electricity emission factors that apply to your region and multiply electricity use. Obtain the best available electricity emission factor that is available for your state or power pool. Step 4: Convert Non-CO 2 Emissions to CO 2 e and sum the total. Where these are significant, use the global warming potential factors from Table III.6.1 to convert methane and nitrous oxide to carbon dioxide equivalent. Sum all gases. (See Equation III.6c and III.6d.)



### Method 2 Companies that choose to estimate their electricity use through and energy audit should consult with the Registry in order to receive approval for its methodology. 

## III.6.2 Alternate Methods to Estimate Electricity Use Some office-based organizations have difficulty reporting their indirect emissions from purchased electricity because their electricity use is not separately metered. As mentioned above, these organizations must still calculate and report their estimated indirect emissions. To calculate their electricity use, such organizations have two options.

1. Estimate energy use based on a participant’s share (percent of square footage) of the building in which they are using energy and the building’s total annual electricity consumption.

2. Estimate energy use based on an energy audit. Participants using either alternative to estimate electricity consumption must disclose in CARROT that they are unable to obtain their electric bills and are estimating their emissions. Both of these options yield less exact energy usage information and will trigger greater certifier scrutiny. Reporters should clearly indicate which methodology it used to estimate its indirect emissions from purchased electricity, if it cannot obtain actual electricity meter readings.



### GWPs from the IPCC’s Second Assessment and Third Assessment Reports Global Warming Potentials (GWPs) were developed by the Intergovernmental Panel on Climate Change (IPCC) to quantify the globally averaged relative radiative forcing effects of a given GHG, using carbon dioxide as the reference gas. In 1996, the IPCC published a set of GWPs for the most commonly measured greenhouse gases in its Second Assessment Report (SAR). In 2001, the IPCC published its Third Assessment Report (TAR), which adjusted the GWPs to reflect new information on atmospheric lifetimes and an improved calculation of the radiative forcing of carbon dioxide. However, SAR GWPs are still used by international convention and the U.S. to maintain the value of the carbon dioxide “currency“. To maintain consistency with international practice, the Registry requires participants to use GWPs from the SAR when determining de minimis emissions, establishing baselines, and making baseline adjustments. For comparison, participants may also calculate their inventories using TAR values. As the IPCC publishes additional updates to GWP, these values may also be used for comparison.34 Chapter 6 

### Recognizing the Benefits of Green-Power and Renewable Energy Certificates Purchases The Registry recommends participants use the following guidance to show how grid-related “green power” purchases and renewable energy credits (REC) impact indirect emissions estimates from electricity consumption. This informationwill be represented in the optional section of your annual emission report, which will not be reviewed by your thirdparty certifier. The objective in providing guidance for optional reporting is to facilitate consistency and transparencyin how renewable energy purchases are accounted for and reported in GHG inventories. The procedure uses a lineitem adjustment of your indirect emissions from electricity consumption to reflect the impact of your renewable energy purchases.* Step 1: Distinguish and classify the type of renewable energy purchase. Your renewable energy purchases will come either from your participation in a “green power” program (offered by an electric utility or an independent power provider), or from your direct purchase of renewable energy credits (RECS). Step 2: Itemize total renewable energy purchases, by type For each type of renewable energy purchase, determine the total kWh bought and record separately. The renewable power generated should occur within the same year as the scope of your report. Step 3: Select the electricity emissions factor(s) from Appendix C, Table C.1 that apply to the area in which the renewable power was generated. If you bought renewable energy through a “green power” program, the Registry recommends that you contact your “green power” program administrator for information on determining the geographic origin of renewable energy. REC purchases should have this information in the purchase agreement. The Registry recommends that you determine the carbon dioxide impact as well as methane and nitrous oxide. Therefore, you should select an emission factor from Appendix C that corresponds to each gas. Step 4: Multiply the total renewable energy purchase, by type, by the emission factor(s) selected in Step 3, convert non-CO 2 emissions to CO 2 e, and sum the total The “emissions” estimates calculated by multiplying the “green power” and REC purchases by the appropriate emission factors will ultimately be subtracted from your total indirect emissions from electricity consumption. Use the Global Warming Potentials in table III.6.1 to convert non-CO 2 emissions to CO 2 e. Add together the CO 2 e “emissions” from the two types of purchases to determine total “emissions.” 

### Step 5: Subtract the total “emissions” from renewab le energy purchases from the total indirect emissions from electricity consumption calculated in III.6.1 or III.6.2. A line-item adjustment of your total indirect emissions from electricity consumption will show the positive impact associated with purchasing renewable energy through a “green power” program or from purchasing RECs. You should disclose, to the extent possible, the type of resource that generated the renewable power in the purchase agreement. EPA’s Green Power Program provides additional information on what qualifies as an “eligible” or “new” renewable resources, see www.epa.gov/greenpower. * The Registry’s recommended approach is consistent with EPA’s current draft guidance for reporting purchases of green power and renewable energy certificates. 

### Note on Alternative Methods to Estimate Electricity Use: The Registry provides these alternatives to report indirect emissions because it believes that participants should report estimates of electricity use rather than nothing at all. Reporting this information will help your organization identify opportunities for energy conservation and efficiency, and can also help to educate your property management on the importance of GHG accounting. However, emissions data estimated through these alternative approaches may not be eligible for State of California consideration in the event of any future GHG regulatory system.35 Part III Chapter 6 Step 3:	 Determine total annual emissions and convert to metric tons.

Equation III.6b Total Carbon Dioxide, Methane, and Nitrous Oxide Emissions for Electricity Use from Each Utility
Los Angeles,
CA = 1,600 MWh x 804.54 (lbs/MWh) 

### ÷ 2,204.62 lbs/mt = 583.89 mt CO 2
Portland, OR = 600 MWh x 671.04 (lbs/MWh) 

### ÷ 2,204.62 lbs/mt = 182.63 mt CO 2

Tucson, AZ = 800 MWh x 1,423.95 (lbs/MWh) 

### ÷ 2,204.62 lbs/mt = 516.71 mt CO 2

Subtotal = 1,283.23

mt

CO 2 Los Angeles,
CA = 1,600 MWh x 0.0037 (lbs/MWh) 

### ÷ 2,204.62 lbs/mt = 0.00269 mt N 2 O

Portland, OR = 600 MWh x 0.0034 (lbs/MWh) 

### ÷ 2,204.62 lbs/mt = 0.00093 mt N 2 O

Tucson, AZ = 800 MWh x 0.0154 (lbs/MWh) 

### ÷ 2,204.62 lbs/mt = 0.00559 mt N 2 O

Subtotal = 0.00921 mt N 2 O Los Angeles,
CA = 1,600 M Wh x 0.0067 (lbs/MWh) 

### ÷ 2,204.62 lbs/mt = 0.00486 mt CH 4

Portland, OR = 600 M Wh x 0.0033 (lbs/MWh) 

### ÷ 2,204.62 lbs/mt = 0.00090 mt CH 4

Tucson, AZ = 800 M Wh x 0.0068 (lbs/MWh) 

### ÷ 2,204.62 lbs/mt = 0.00247 mt CH 4

Subtotal = 0.00823 mt CH 4 

## III.6.3 Example: Indirect Emissions from Electricity Use

Costlo Clothing Distributors Costlo is a discount retail clothing chain with two outlets in Los Angeles, California, one in Portland, Oregon, and one in Tucson, Arizona. The company only purchases electricity and has no other GHG emissions. 

### Step 1:	 Determine annual electricity consumption. Step 2: Select electricity emission factors that apply to the electricity purchased Because emission factors for electricity vary from region-to-region, Costlo tracks its electricity purchases by utility providing the electricity.



### Region/ State Power Generator Annual Electricity Purchases (MWh) CO 2 

### lbs/ MWh CH 4 

### lbs/ MWh N 2 

### O lbs/ MWh

CALI/California Los Angeles 1,600 804.54 0.0067 0.0037 NWPN/Oregon Portland 600 671.04 0.0033 0.0034
WSSW/Arizona Tuscan 800 1,423.95 0.0068 0.0154 

### Annual Electricity Emissions and Emissions Factors

Step 4: Convert Non-CO 2 Emissions to CO 2 e and sum the total. Use Equation III.6c and III.6d

Equation III.6c Convert Non-CO 2 GHGs to Carbon Dioxide Equivalent and Sum Total

Metric Tons of
CO 2 e = Metric Tons of GHG x GWP (SAR, 1996)

Metric Tons of CO 2 

### = 1,283.23 metric tons CO 2

CH 4 Tons of CO2e = 0.00823 metric tons N

2 O x 21 (GWP) 

### = 0.17283 metric tons CO 2 e

N 2 O Tons of CO 2 e = 0.00921 metric tons N

2 O x 310 (GWP) 

### = 2.8551 metric tons CO 2 e

Total 

### = 1,286.28 metric tons CO 2 e36 Part III Chapter 7 

# Chapter 7 Direct Emissions from Mobile Combustion

Mobile combustion sources are non-stationary emitters of GHGs such as automobiles, motorcycles, trucks, off-road vehicles such as forklifts and construction equipment, boats, and airplanes. On-road mobile sources include vehicles authorized by the California Department of Motor Vehicles to operate on public roads. Non-road mobile sources include, among other things, trains, ocean-going vessels and commercial airplanes. Combustion devices that can be transported from one location to another (i.e., small diesel generators) are not considered mobile combustion sources. Reporters should refer to section III.8 to calculate emissions from such equipment. Significant emissions from mobile sources must be included in your emissions report, and can be calculated based on fuel use and/or vehicle miles traveled. Carbon dioxide emissions, the primary GHG emissions from mobile sources, are directly related to the quantity of fuel consumed. Thus, emission factors are expressed in fuel quantity. On the other hand, combustion emissions of methane and nitrous oxide, while also related to fuel consumption, depend more on the emission control technologies employed in the vehicle. For this reason, their emission factors are typically expressed in terms of mass of compound emitted per distance traveled (gram/mile), and the method of calculating these emissions is based on mileage. If you have your vehicles’ annual fuel consumption information, you are ready to begin your CO 2 emissions calculations. If you have only information on your vehicle miles traveled, you will need to convert that data to fuel consumption based on U.S. EPA’s mileage per gallon (mpg) estimates for your vehicles. 1 The U.S. EPA provides estimates of on-road fuel consumption for passenger cars and light trucks. The California ARB also provides data on composite groups of passenger cars, heavy trucks, and motorcycles. For all other mobile sources, you will need to determine fuel consumption based either on your operating data or published information that is applicable to your vehicle application. EPA fuel economy figures are available at www.fueleconomy.gov/feg/ . This website provides two figures for your calculation: one for city driving, and one for highway driving.



## III.7.1 Calculating Carbon Dioxide Emissions for Mobile
Combustion The method for estimating carbon dioxide emissions from mobile sources includes three steps:

1. Identify total annual fuel consumption by fuel type;

2. Select the appropriate CO 2 emission factor from Appendix C, Table C.2; and

3. Multiply fuel consumed by the emission factor to calculate total CO 2 emissions and convert kilograms to metric tons. If you have fuel consumption information, CARROT can calculate your CO 2 emissions for you. 

### Step 1: Identify total annual fuel consumption by fuel type. If you are a fleet operator and store fuel at any of your facilities, you can also determine your annual fuel consumption from bulk fuel purchase records.

1 The guidance for calculating methane and nitrous oxide emissions from mobile combustion relies on equipment make, model, and miles driven. 

### Who should read Chapter 7: Chapter 7 applies to all participants that operate motor vehicles or other forms of transportation. 

### What you will find in Chapter 7: This chapter provides guidance on calculating your direct emissions from mobile combustion. 

### Information you will need: You will need information about the types of vehicles your organization operates, where they are registered, and fuel consumption and miles traveled for each type of vehicle. Fuel consumption data may be obtained from bulk fuel purchases, fuel receipts, or direct measurements of fuel use, such as official logs of vehicle fuel gauges or storage tanks. Sources of annual mileage data could include: odometer readings, trip manifests that include mileage to destinations, hours of operation, or maintenance records. 

### Cross-References: Be sure to complete Chapter 11 to determine any fugitive emissions you may have from motor vehicle air conditioning units, if applicable. Review Chapter 1 on geographic boundaries in considering which vehicles are based in California, and which are not.37 Part III Chapter 7 Use Equation III.7a to help you determine your annual fuel consumption. The total annual fuel purchases should include both fuel purchased for the bulk fueling facility and fuel purchased for the vehicles at other fueling locations.

Besides bulk storage fuel purchases, additional sources of fuel consumption data may be obtained from collected fuel receipts (for non-bulk purchases) or direct measurements of fuel use, such as official logs of vehicle fuel gauges or storage tanks. If you only have annual mileage information for the vehicles you own and operate, you may estimate your fuel consumption by using the following procedure or applying a default fuel economy factor.

1. Identify the vehicle make, model, fuel, and model years for all the vehicles you own and operate;

2. Identify the annual mileage by vehicle type; and

3. Convert annual mileage to fuel consumption using EPA’s fuel economy formula (Equation III.7b). If you have very accurate information about the driving patterns of your fleet, consider applying a more specific mix of city and highway driving, otherwise you may assume, as EPA does, that 45% of your vehicles’ mileage is highway driving and 55% is city driving (see Equation III.7b). If you utilize more than one type of vehicle in your operations, you must calculate the fuel use for each of your vehicle types and sum them together. Sources of annual mileage data could include odometer readings or trip manifests that include mileage to destinations. Vehicle mileage may be converted to fuel consumption using the EPA fuel economy of the specific vehicle models in the fleet ( www.fueleconomy.gov ). Carbon dioxide emissions are then calculated based on the fuel consumption. For heavy-duty trucks for which no fuel efficiency information is available, you should assume fuel efficiency of 6 mpg for gasoline-powered trucks and 7 mpg for diesel-powered trucks. 2 Step 2: Select the appropriate carbon dioxide emission factor for each fuel from Appendix C, Table C.3 to calculate carbon dioxide emissions. Appendix C, Table C.3 provides carbon dioxide emission factors for fuel combusted in motor vehicles and other forms of transport. Step 3: Multiply fuel consumed by the emission factor
to calculate total CO 2 emissions and convert to metric tons. Multiply your fuel use from Step 1 by the CO 2 emission factor from Step 2 (See Equation III.7c) and convert kilograms to metric tons.



## III.7.2 Calculating Methane and Nitrous Oxide Emissions for
Mobile Combustion The method for estimating emissions of methane and nitrous oxide from mobile sources involves six steps:

1. Identify the vehicle types, fuel, and model years of all the vehicles you own and operate;

2. Identify the annual mileage by vehicle type;

3. Select the appropriate emission factor for each vehicle and fuel type (using Appendix C, Table C.4);

4. Calculate each vehicle type CH 4 and N 2 O emissions and convert grams to metric tons;

5. Sum the emissions over each vehicle and fuel type; and

6. Convert CH 4 and N 2 O Emissions to CO 2 e and sum the subtotals. Step 1: Identify the vehicle types, fuel, and model years of all the vehicles you own and operate. Vehicle types and fuel by model year are shown in Appendix C, Table C.4 for passenger cars, light-duty trucks, heavy-duty trucks, and motorcycles. The emission factors vary with model year because of changes in emission controls and catalysts.

2 U.S. Department of Energy, Transpotation Energy DATA book edition 20 - 2000, Table 8.1

Equation III.7a Total Annual Fuel Consumption

– From Bulk Fuel Records

Total Annual Consumption = Total Annual Fuel Purchases + Amount Stored at Beginning of the
Year – Amount Stored at End of Year

Equation III.7b Fuel Use in Motor Vehicles

Total Fuel Use (gallons) = Total Mileage (miles) 

### ÷ 

# ( Fuel Economy City (mpg) x 55% + Fuel Economy Highway (mpg) x 45% 

# ) Equation III.7c Total CO 2 Emissions from Mobile Combustion

Total Emissions (metric tons) = Fuel Consumed (gallons) x Emission Factor (kg CO 2 /gallon) x 0.001 metric tons/kg38 Part III Chapter 7 Step 2: Identify the annual mileage by vehicle type. If you do not have mileage but you do have fuel consumption by vehicle type model and year you can estimate the vehicle miles traveled using the EPA fuel economy of the specific vehicle models in the fleet. You can then calculate methane and nitrous oxide emissions based on vehicle miles traveled. If you have only bulk fuel purchase data, you should allocate consumption across vehicle types and model years in proportion to the fuel consumption distribution among vehicle type and model years, based on your usage data. EPA fuel economy figures are available at www.fueleconomy.gov/feg/ . Two figures are provided: one for city driving, and one for highway driving. You may assume, as EPA does, that 45% of your vehicles’ mileage is highway driving and 55% is city driving unless you have specific information to indicate otherwise (see Equation III.7d). Step 3: Select the appropriate emission factor from Appendix C, Table C.4 for each vehicle and fuel type Reporters should consult with the Registry for methane and nitrous oxide emission factors for non-road mobile sources. These emissions will likely be de minimis.

Step 4: Calculate each vehicle type CH 4 and N 2 O emissions and convert to metric tons. Use Equation III.7e to calculate total emissions for CH 4 and

N 2 O for each vehicle type. 

### Step 5: Sum the emissions for each vehicle and fuel type.

Add emissions for each vehicle and fuel combination to obtain the total emissions from all mobile sources. Step 6 Convert CH 4 and N 2 O Emissions to CO 2 e and

sum the subtotals. Use the IPCC global warming potential factors from Table III.6.1 to convert methane and nitrous oxide to carbon dioxide equivalent. Note, if non-CO 2 gases are de minimis after they are converted to CO 2 e and metric tons, you do not need to report them to the Registry. Step 7 Total CO 2 e Emissions from Mobile Combustion Once you have completed the steps for estimating carbon dioxide, methane, and nitrous oxide emissions, and converted methane and nitrous oxide to carbon dioxide equivalents, determine your total CO 2 e emissions from mobile combustion.

Equation III.7e Total CH 4 or N 2 0 Emissions from Mobile Combustion

Total Emissions (metric tons) = Emission Factor by Vehicle and Fuel Type (g/mi) x Annual Mileage x 0.000001 metric tons/g 

### Emissions from Alternative Fuel Vehicles: Emissions from Alternative Fuel Vehicles (AFV) are calculated in the same manner as other gasoline or diesel mobile sources, except for electric vehicles. For instance, participants with compressed natural gas or propane fueled vehicles must, as in Section III.7.1, determine the total amount of fuel consumed and apply the appropriate emission factor to calculate emissions. Emission factors for AFVs are included in Appendix C. Electric vehicles are powered by internal batteries that receive a charge from the electricity grid. Therefore, using electric vehicles produces indirect emissions from purchased electricity. Participants are also encouraged to note the indirect emissions associated with their electric vehicles in the Optional section of their emission report. Equation III.7d Total CH 4 or N 2 0 Emissions from Mobile Combustion

Total Mileage (mi.) = Fuel use (gallons) x 

# ( Fuel Economy City (mpg) x 55%ç + Fuel Economy Highway (mpg) x 45% 

# )39 Part III Chapter 7 

## III.7.3 Example: Direct Emissions
from Mobile Combustion
GOFAST Vehicle Rental Agency GOFAST Vehicle Rental is an independent vehicle renting company located in California, with a fleet of 200 model year 2000 passenger cars, 25 model year 2000 light duty trucks, and two model year 1998 heavy duty diesel powered trucks. GOFAST typically purchases its fuel in bulk. Last year, the company purchased 235,000 gallons of motor gasoline and 5,000 gallons of CA diesel fuel. GOFAST began the year with 20,000 gallons of motor gasoline in stock and ended with 10,000 gallons of motor gasoline in stock. The company also began the year with 500 gallons of CA diesel fuel in stock and ended with 1,000 gallons of CA diesel fuel in stock.



### Carbon Dioxide Emissions Calculation Step 1: Identify the total annual fuel consumption by fuel type.
Equation III.7a Total Annual Fuel Consumption by Fuel Type

Total Fuel Consumption = Total Annual Fuel Purchases + Amount Stored at Beginning of the Year - Amount Stored at End of Year

Total Gasoline Consumption = 235,000 gallons + 20,000 gallons - 10,000 gallons = 245,000 gallons

Total Diesel Consumption = 5,000 gallons + 500 gallons 

### - 1,000 gallons 4,500 gallons
Step 2: Select the appropriate carbon dioxide emission factor for each fuel from Appendix C, Table C.3 to calculate carbon dioxide emissions.

The CO 2 emission factor for motor gasoline is 8.55 kilograms per gallon and for diesel fuel it is 9.96 kilograms per gallon. Step 3: Multiply fuel consumed by the emission factor
to calculate total CO 2 emissions.



### Methane and Nitrous Oxide Emissions Calculation Step 1: Identify the vehicle types, fuel, and model years of all the vehicles you own and operate



### Vehicle Type Fuel Model Year Passenger Cars Motor Gasoline 1998 through 2002

Light Duty Trucks Motor Gasoline 1998 through 2002

Heavy Duty Trucks Diesel 1998 

### Vehicle Type, Fuel, and Model Year

Step 2: Identify the annual mileage by vehicle type First, GOFAST will have to allocate gross fuel consumption (gallons consumed per year) by vehicle type and model year. For the purposes of this example, it is assumed that GOFAST is able to calculate total fuel consumption provided based on fuel purchase receipts to arrive at total gallons of fuel consumed for each vehicle type

Then GOFAST must determine vehicle miles traveled using EPA mpg estimates, using Equation III.7d.

Equation III.7c Carbon Dioxide (CO 2 ) Emissions Contribution of Each Fuel

CO 2 from
Motor Gasoline = 8.55 kg/gallon x 245,000 gallons x 0.001 metric tons/kg = 2,094 metric tons CO 2

CO 2 from Diesel Fuel = 9.96 kg/gallon x 4,500 gallons x 0.001 metric tons/kg = 45 metric tons CO 2

Total = 2,139 metric tons CO 2



### Carbon Dioxide Emission Factor
Fuel kg CO 2 

### / MMBtu kg CO 2 

### / gallon

CA Gasoline NA 8.55
CA Diesel Fuel NA 9.96 

### Carbon Dioxide Emission Factors for Transport Fuels4 0 Part III Chapter 7 Equation III.7b Annual Vehicle Miles Traveled

Total Mileage (mi.) = Fuel use (gallons) x 

# ( Fuel Economy City (mpg) x 55% + Fuel Economy Highway (mpg) x 45% 

# )

Total Mileage –passenger (mi.) = 225,000 gallons x 

# ( 20 mpg x 55% + 25 mpg x 45% 

# )

= 5,006,250 miles

Total Mileage – light duty (mi.) = 20,000 gallons x 

# ( 15 mpg x 55% + 20 mpg x 45% 

# )

= 345,000 miles

Total Mileage – heavy duty (mi.) = 4,500 gallons x 

# ( 8 mpg x 55% + 10 mpg x 45% 

# )

= 40,050 miles 

### Vehicle Type Fuel Model Year Fuel Consumption Passenger Cars Motor Gasoline 2000 225,000 gallons

Light Duty Trucks Motor Gasoline 2000 20,000 gallons Heavy Duty Trucks CA Diesel 1998 4,500 gallons 

### Gross Fuel Consumption by Vehicle Type

Vehicle Type Fuel Model Year Methane (g/mi) Nitrous Oxide (g/mi) Passenger Cars Motor Gasoline 2000 0.04 0.04 Light Duty Trucks Motor Gasoline 2000 0.05 0.06 Heavy Duty Trucks CA Diesel 1998 0.06 0.05 

### Emission Factors for Each Fuel and Vehicle Type Step 3: Select the appropriate emission factor from Appendix C, Table C.4 for each vehicle and fuel type.

Step 4:	 Calculate each vehicle type CH 4 and N 2 O emissions and convert to metric tons.

Equation III.7e Passenger Cars: Total CH 4 and N 2 O Emissions

CH 4 Emissions (metric tons) = 0.04 g/mi x 2,647,750 (mi) x 0.000001 metric tons/g = .1324 metric tons CH 4

N 2 O Emissions (metric tons) = 0.04 g/mi x 2,647,750 (mi) x 0.000001 metric tons/g = .106 metric tons N 2 O Equation III.7e Light-Duty Trucks: Total CH 4 and N 2 O Emissions

CH 4 Emissions (metric tons) = 0.05 g/mi x 362,250 (mi) x 0.000001 metric tons/g = .0163 metric tons CH 4
N 2 O Emissions (metric tons) = 0.06 g/mi x 362,250 (mi) x 0.000001 metric tons/g = .0217 metric tons N 2 O4 1 Part III Chapter 7 Step 6: Convert CH 4 and N 2 O Emissions to CO 2 e and sum the subtotals using the GWPs in Table III.6.1.



### GHG metric tons CO 2 

### e

CO 2 2,139.00

CH 4 4.62

N 2 O 69.12

Total 2,212.74 metric tons CO 2 e 

### Total CO 2 

### e Emissions from Mobile Combustion Vehicle Type Fuel Model Year CH 4 

### (metric tons) N 2 

### O (metric tons)

Passenger Cars Motor Gasoline 2000 0.2003 0.2003 Light Duty Trucks Motor Gasoline 2000 0.0173 0.0207
Heavy Duty Trucks CA Diesel 1998 0.0024 0.0020

Total 0.2199 0.2230 

### Total Emissions from Mobile Combustion

Equation III.7f Convert to Carbon Dioxide Equivalent

Total CO 2 e (metric tons) = Total Emissions (metric tons) x GWP factor

= .02199 metric tons CH 4 21 (GWP) = 4.62 metric tons CO 2 e

= .223 metric tons N 2 O x 310 (GWP) = 69.12 metric tons CO 2 e Step 5: Sum the methane and nitrous oxide emissions for each vehicle and fuel type. Equation III.7f Heavy-Duty Trucks: Total CH 4 and N 2 O Emissions

CH 4 Emissions (metric tons) = 0.06 g/mi x 40,050 (mi) x 0.000001 metric tons/g = .0024 metric tons CH 4

N 2 O Emissions (metric tons) = 0.05 g/mi x 40,050 (mi) x 0.000001 metric tons/g = .0020 metric tons N 2 O42 Part III Chapter 8 

# Chapter 8 Direct Emissions from Stationary Combustion

Stationary combustion sources are non-mobile sources emitting GHGs from fuel combustion. Typical large stationary sources include power plants, refineries, and manufacturing facilities. Smaller stationary sources include commercial and residential furnaces. If you combust fuels to produce electricity for your own use or make steam or district heating or cooling for your own use or to sell, then it should also follow the GHG emissions accounting and reporting guidelines in this chapter. However, if you combust fossil fuels to produce electricity and sell the power to other parties (an electric power generator) then you should use the Registry’s Power/Utility Protocol.



## III.8.1 Emission Factors for
Stationary Combustion Default emission factors are taken from EIA publications and provided in Appendix C, Tables C.5 and C.6. If your company has certifiable emission factors that are more accurate for the fuels and combustion devices that your organization employs, you may use these factors. If you decide not to use the Registry-approved emission factors, you will need to demonstrate to your certifier that the use of the alternative emission factors results in a more accurate measurement of your emissions. The following is a list of sources where you can obtain additional emissions factors:

• U.S. EPA, Compilation of Air Pollutant Emission Factors AP-42, www.epa.gov/ttn/chief/ap42 ;

• U.S. EPA Emissions Inventory Improvement Program (EIIP) Introduction to Estimating Greenhouse Gas Emissions: Volume VII (EIIP, 1999), www.epa.gov/ttn/ chief/eiip/techreport/volume08/index.html ;

• IPCC Revised 1996 IPCC Guidelines for National Greenhouse Gas Inventories, Greenhouse Gas Inventories Reference Manual (IPCC, 1996), www.ipccnggip.iges.or.jp/public/gl/invs1.htm ; and

• UK Department for Environment, Food, and Rural Affairs, Guidelines for the Measurement and Reporting of Emissions in the UK Emissions Trading Scheme (DEFRA, 2001b), www.defra.gov. uk/environment/climatechange/trading.



## III.8.2 Estimating Emissions Based
on Higher Heating Value To estimate stationary combustion emissions, the Protocol utilizes GHG emission factors that are based on the “higher” heating value (HHV) (or “gross” heating value (GHV)) for combusted fossil fuels. When hydrocarbons are combusted, heat, water vapor, and CO 2 are emitted, along with trace levels of other GHGs like CH 4 and N 2 O. In the United States, a HHV is used to measure the heat content of fuels and is therefore used to estimate GHG emissions from the combustion process. This approach is used by the U.S. Energy Information Administration (EIA). However, it should be noted that the “lower” heating value (LHV) is typically used internationally. 1



## III.8.3 Using Continuous Emissions
Monitoring System Data Typically, participants calculate GHG emissions from stationary combustion using the process outlined in the subsequent section. However, if you use a Continuous Emissions Monitoring System (CEMS) to measure emissions, you may also report your stationary combustion emissions from your CEMS reports. Participants using CEMS should refer to the Registry’s Power/Utility Protocol for guidance on reporting 

### Who should read Chapter 8: Chapter 8 applies to participants who generate energy on-site. 

### What you will find in Chapter 8: This chapter provides guidance on determining direct emissions from stationary combustion, such as through power generation, manufacturing, or other industrial activities involving the combustion of fossil fuels. 

### Information you will need: You will need information about the type of fuels consumed by your organization, and how much was combusted in the reporting year, or CEMS data. 

### Cross-References: If your organization imports steam or district heating or cooling, you will utilize the calculation guidelines in chapter 9 to assist you in calculating these indirect emissions.

1 Converting from HHVs to LHVs is an imperfect process. Emissions estimates based on LHVs are between 5% to 10% higher because the Btu content of the fuel is around 5% to 10% lower. See OECD, Estimation of Greenhouse Gas Emissions and Sinks, Final Report (Paris, France, August 1991), pp. 2-12 – 2-15.43 Part III Chapter 8 emissions from combustion devices equipped with CEMS units.


### Stationary Emissions from Agriculture Residue Burning: This Protocol does not include specific guidance on estimating emissions from agricultural residue burning. Useful information is provided in the CEC’s Guidance to the California Climate Action Registry: General Reporting Protocol, P500-02-005F (June 2002).



## III.8.4 Calculating Emissions from
Stationary Combustion Emissions estimation for stationary combustion involves the following process:

1. Identify all types of fuel directly combusted in your operations;

2. Identify annual consumption of each fuel;

3. Select the appropriate adjusted emission factor for each fuel;

4. Calculate each fuel’s CO 2 emissions and convert to metric tons;

5. Calculate each fuel’s CH 4 and N 2 O emissions and convert to metric tons; and

6. Convert CH 4 and N 2 O emissions to CO 2 e and sum all subtotals. CARROT can also calculate this information for you, and will prompt you to enter your fuel type and inputs. Step 1: Identify all types of fuel directly combusted in your operations. Fuel types can include, for example: coal, residual fuel oil, distillate fuel (diesel), liquefied petroleum gas (LPG), and natural gas. Step 2: Determine annual consumption of each fuel. This can be done by direct measurement, recording fuel purchase, or sales invoices measuring any stock change (measured in million Btus, gallons or therms) using Equation III.8a. If your fuel consumption is not available in million Btus, gallons or therms, you can convert it using the conversion factors in Table III.8.1. Source: Energy Information Administration, Annual Energy Review 2000 (2002)



### Unit Multiplied by Equals

Barrels 42.0 1 Gallon
Therms of Natural Gas 0.1 Million Btus

Thousand Cubic Feet of Natural Gas 1.03 Million Btus

Metric Tons of Coal, Electric Utility 22.488 Million Btus

Metric Tons of Coal, Industrial Coke 30.232 Million Btus

Metric Tons of Coal, Other Industry 24.790 Million Btus

Metric Tons of Coal, Residential & Commercial 26.323 Million Btus 

### Table III.8.1: Conversion Factors

Step 3: Select the appropriate emission factor for each fuel from Appendix C, Tables C.5 and Table C.6. Each fuel type has a specific emission factor that relates the amount of CO 2 , CH 4 , or N 2 O emitted per unit of fuel consumed (either in kilograms per MMBtu of fuel, or kilograms per gallon of fuel). CO 2 emission factors depend almost completely on the carbon content of the fuel. CH 4 and N 2 O emission factors also depend on the type of combustion device and the combustion conditions.
Carbon Dioxide. Appendix C, Table C.5 provides CO 2 emission factors for the most common fuel types in kilograms of CO 2 per million Btu (MMBtu) and in kilograms of CO 2 per gallon for liquid fuels. If you burn a fuel that is not listed in Appendix C, Table C.5, such as refinery fuel gas, you should estimate an emission factor based on the specific properties of the fuel and document those properties. Note, the CO 2 emission factors provided in Appendix C, Table C.5 already incorporate a factor for the fraction of carbon oxidized. The CO 2 fraction reflects the fact that slightly less than 100% of the fuel consumed is completely Equation III.8a Annual Consumption of Fuels

Annual Consumption (MMBtu or gallons) = Total Annual Fuel Purchases - Total Annual Fuel Sales + Amount Stored at Beginning of Year - Amount Stored at Year End44 Part III Chapter 8 combusted.
Methane and Nitrous Oxide. Appendix C, Table C.6 presents CH 4 and N 2 O emission factors by activity sector and fuel type. For petroleum products, emission factors for CH 4 and N 2 O are provided in kilograms per gallon consumed. Step 4: Calculate each fuel’s carbon dioxide emissions and convert to metric tons. If the fuel consumption is expressed in MMBtu, use Equation III.8b. If fuel is expressed in gallons, use Equation III.8c.

Equation III.8b Total CO 2 Emissions (Fuel Consumption is in MMBtu)

Total Emissions (metric tons) = Emission Factor (kg CO 2 /Btu) x Fuel Consumed (MMBtu) x 0.001 metric tons/kg

Equation III.8c Total CO 2 Emissions (Fuel Consumption is in Gallons)

Total Emissions (metric tons) = Emission Factor (kg CO 2 /gallon) x Fuel Consumed (gallon) x 0.001 metric tons/kg Step 5: If you are reporting methane and nitrous oxide emissions, calculate each fuel’s methane and nitrous oxide emissions and convert to metric
tons. If your fuel consumption is expressed in MMBtu, use Equation III.8d. If it is expressed in gallons, use Equation III.8e. Note, non-CO 2 gases may be de minimis.

Equation III.8d Total CH 4 or N 2 O Emissions (Fuel Consumption is in MMBtu)

Total Emissions (metric tons) = Emission Factor (kg CH 4 or N 2 O /MMBtu) x Fuel Consumed (MMBtu) x 0.001 metric tons/kg

Equation III.8e Total CH 4 or N 2 O Emissions (Fuel Consumption is in Gallons)

Total Emissions (metric tons) = Emission Factor (kg CH 4 or N 2 O /gallon) x Fuel Consumed (gallon) x 0.001 metric tons/kg 

### Step 6: Convert CH 4 

### and N 2 

### O Emissions to CO 2 

### e and

sum all subtotals. Use the IPCC global warming potential factors from Table III.6.1 to convert CH 4 and N 2 O to CO 2 equivalent.



## III.8.5 Allocating Emissions from
Co-generation Accounting for the GHG emissions from a co-generation or combined heat and power (CHP) facility is unique because it produces more than one useful product from the same amount of fuel combusted, namely, electricity and heat or steam. As such, apportionment of the fuel and the GHG emissions between the two different energy streams is useful. 2 Ultimately, to comply with Registry reporting guidelines, reporters only have to determine absolute emissions from a co-gen plant. This is done in a manner identical with the calculation procedure for non-co-generation plants.That is, to calculate total emissions associated with a cogeneration plant participants multiply the fuel input by a fuel specific emission factor. Alternatively participants can allocate emissions according to each final product stream, i.e. electricity or steam. The three most commonly-used methods to allocate emissions of CHP plants between the electric and thermal outputs are:

1. Efficiency method: On the basis of the energy input used to produce the separate steam and electricity products.

2. Energy content method: On the basis of the energy content of the output steam and electricity products.

3. Work potential method: On the basis of the energy content of the steam and electricity products.


### Considerations in Selecting an Approach to CHP Emissions Allocation Efficiency Method

• Allocates emissions according to the amount of fuel energy used to produce each final energy stream.

• Assumes that conversion of fuel energy to steam energy is more efficient than converting fuel to electricity. Thus, focuses on the initial fuel-to-steam conversion process.

• Actual efficiencies of heat and of power production will not be fully characterized, necessitating the use of assumed values. Energy Content Method

• Allocates emissions according to the useful energy contained in each CHP output stream.

• Need information regarding the intended use of the heat energy.

• Best suited where heat can be characterized as useful energy, e.g., for process or district heating.

• May not be appropriate where heat used for mechanical work because it may overstate the amount of useful energy in the heat, resulting in a low

2 Many CHP systems capture the waste-heat from the primary electricity generating pathway and use it for non-electricity purposes. When the waste-heat is used directly to drive a thermal generator or to make steam that in turn drive s an electric generator, these combined electricity production processes are grouped as a unit and called a combined cycle power plant. (The Registry treats emissions resulting from combined cycle power plants as stationary combustion emissions.)45 Part III Chapter 8 Equation III.8f Steam and Electricity Emissions Allocation



### E H = H 

# / e H



### H 

# / e H 

### + P 

# / e P x 

### E T



### and E P = 

### E T - 

### E H emissions factor associated with the heat stream.

Work Potential Method

• Allocates emissions based on the useful energy represented by electric power and heat, and defines useful energy on the ability of heat to perform work.

• Appropriate when heat is to be used for producing mechanical work (where much of the heat energy will not be characterized as useful energy).

• May not be appropriate for systems that sell hot water because hot water cannot be used, as steam can, to perform mechanical work. In order to insure a consistent approach in allocating GHG emissions in CHP applications, the Registry recommends the use of the efficiency method. A default quantification methodology is provided below for this method. For more information on alternative CHP methods, see the GHG Protocol. 3


### Using the Efficiency Method to Allocate Emissions from CHP Facilities
For this method, emissions are allocated based on the separate efficiencies of steam and electricity production. You will need to know the total emissions from the CHP plant, the total steam (or heat) and electricity production, and the steam (or heat) and electicity efficiency of the facility. Use the following steps to determine the share of CO 2 emissions attributable to steam (or heat) and electricity production: 

### Step 1: Determine the total direct emissions from the CHP system. Calculate total direct GHG emissions using Equation III.8b or III.8c, above. Like the guidance for non-cogeneration stationary combustion, calculating total emissions from CHP sources is based on fuel input values. 

### Step 2: Determine the total steam and electricity output for the CHP system. To determine the total energy output of the CHP plant attributable to steam production, use published steam tables that provide energy content (enthalpy) values for steam at different temperature and pressure conditions.Obtain steam energy content values from the IAPWSIF97 steam tables. 4 Energy content values multiplied by the quantity of steam produced at the temperature and pressure of the CHP plant yield energy output values; express in units of MMBtu. Alternatively, use Equation III.9a to determine the total net heat steam (or heat) production. To convert total electricity production from MWh to MMBtu, multiply by 3.415. 5 

### Step 3: Determine the efficiencies of steam and electricity production. Identify steam (or heat) and electricity production efficiencies. If actual efficiencies of the CHP plant are not known, use a default value of 80% for steam and a default value of 35% for electricity. 6 

### Step 4: Determine the fraction of total emissions to allocate to steam and electricity production. Allocate the emissions from the CHP plant to the steam and electricity product streams by using Equation III.8f.

where:

E H = Emissions allocated to steam production

H = Total steam (or heat) output (MMBtu)

e H = Efficiency of steam (or heat) production

P = Total electricity output (MMBtu)

e P = Efficiency of electricity generation

E T = Total direct emissions of the CHP system

E P = Emissions allocated to electricity production

3 GHG Protocol, 2004 . 4 IAPWS Industrial Formulation 1997 for the Thermodynamic Properties of Water and Steam (IAPWS-IF97), International Association for the Properties of Water and Steam. This publication replaces IFC-67. 5 MWh to MMBtu conversion source – EIA, Annual Energy Review 1995, DOE/EIA-0384(95) (Washington, DC, July 1996), Appendix B. 6 The use of default efficiency values may, in some cases, violate the energy balance constraints of some CHP systems. However, total emissions will still be allocated between the energy outputs. If the constraints are not satisfied the efficiencies of the steam and electricity can be modified until constraints are met.46 Part III Chapter 8 

### kg CO 2 

### per kg CH 4 

### per kg N 2 

### O per
Fuel Sector Location MMBtu gallon MMBtu gallon MMBtu gallon

Natural Gas Industrial California 52.78

– 0.0059

– 0.0001

–

Coal Industrial California 92.07

– 0.0111

– 0.0016

–

Distillate Fuel/ Diesel Commercial California

– 10.05

– 0.0014

– 0.0001 

### Emission Factors by Fuel Type, Sector, and Location Step 3:	 Select the appropriate emission factors for each fuel from Appendix C, Tables C.5 and Table C.6. 

### F&M Manufacturing F&M is a manufacturing facility located in California. It has tw o 10 MW generating units, one burning natural gas and one coal-fired unit. F&M also has a commercial office building in California that is heated with diesel. Step 1:	 Identify all types of fuel directly combusted in your operations.

Step 2:	 Determine annual consumption of each fuel. F&M measures heat input (MMBtus of fuel used) into its plants, and purchases its heating fuel for commercial use in bulk by the barrel. Last year it consumed 788,400 MMBtus of natural gas and 946,000 MMBtus of coal. It also purchased 265 barrels of distillate fuel for heating and sold 15 barrels. F&M began the y ear with 12 barrels in storage and ended the year with 24 barrels in storage. Using Equation III.8a, F&M determined distillate fuel consumption. The result, 238 barrels can be converted to gallons by multiplying by 42. See Table III.8.1. 

### Fuel Sector Location

Natural Gas Industrial California

Coal Industrial California

Diesel Commercial California 

### Fuel Type, Sector, and Location 

## III.8.6 Example: Direct Emissions from Stationary Combustion

Annual Consumption of Fuels

Annual Consumption (MMBtu or gallons) = Total Annual Fuel Purchases - Total Annual Fuel Sales + Amount Stored at Beginning of Year - Amount Stored at Year End
Annual Consumption of Distillate Fuel = 265 barrels

- 15 barrels + 12 barrels

- 24 barrels = 238 barrels consumed

238 barrels consumed x 42 gallons/ barrel = 9,996 gallons47 Part III Chapter 8 Carbon Dioxide Emissions from Distillate Fuel (Gallons)

Total Emissions (metric tons) = 10.05 kg CO 2 /gallon x 9,996 gallons x 0.001 metric tons/kg = 100.5 metric tons CO 2

Total CO 2 from All Sources = 128,810.5 metric tons CO 2 Carbon Dioxide Emissions from Natural Gas (MMBtu)

Total Emissions (metric tons) = 52.78 kg CO 2 / MMBtu x 788,400 MMBtu x 0.001 metric tons/kg = 41,611.8 metric tons CO

2 Step 4:	 Calculate each fuel’s carbon dioxide emissions Use Equation III.8b if the fuel consumption is expressed in MMBtu, and Equation III.8c if it is expressed in gallons.

Carbon Dioxide Emissions from Coal (MMBtu)

Total Emissions (metric tons) = 92.07 kg CO 2 / MMBtu x 946,000 MMBtu x 0.001 metric tons/kg = 87,098.2 metric tons CO

2

Step 5:	 Calculate each fuel’s methane and nitrous oxide emissions. Use Equation III.8d if the fuel consumption is expressed in MMBtu, and Equation III.8e if it is expressed in gallons. Note, both methane and nitrous oxide emissions from stationary combustion are likely to be de minimis.

Methane Emissions from Natural Gas (MMBtu)

Total Emissions (metric tons) = 0.0059 kg CH 4 / MMBtu x 788,400 MMBtu x 0.001 metric tons/kg = 4.652 metric tons CH

4 Step 6:	 Convert CH 4 and N 2 O Emissions to CO 2 e and

sum the subtotals. Use Equation III.8d if the fuel consumption is expressed in MMBtu, and Equation III.8e if it is expressed in gallons.

Nitrous Oxide Emissions from Natural Gas (MMBtu)

Total Emissions (metric tons) = 0.0001 kg N 2 O/ MMBtu x 788,400 MMBtu x 0.001 metric tons/kg = 0.0788 metric tons N

2 O

Methane Emissions from Coal (MMBtu)

Total Emissions (metric tons) = 0.0111 kg CH 4 / MMBtu x 946,000 MMBtu x 0.001 metric tons/kg = 10.501 metric tons CH

4 Nitrous Oxide Emissions from Coal (MMBtu)

Total Emissions (metric tons) = 0.0016 kg N 2 O/ MMBtu x 946,000 MMBtu x 0.001 metric tons/kg = 1.514 metric tons N

2 O

Nitrous Oxide Emissions from Distillate Fuel (Gallons)

Total Emissions (metric tons) = 0.0001 kg N 2 O /gallon x 9,996 gallons x 0.001 metric tons/kg = 0.0010 metric tons N 2 O

Total N 2 O from All Sources = 1.594 metric tons N 2 O

Converting Mass Estimates to Carbon Dioxide Equivalent

Metric Tons of CO 2 e = Metric Tons of
GHG x GWP (SAR, 1996) = 128,810.5 metric tons CO 2 e

CH 4 Tons of
CO 2 e = 15.17 metric tons CH

4 x 21 (GWP) = 318.6 metric tons CO 2 e

N 2 O Tons of
CO 2 e = 1.594 metric tons CH

4 x 310 (GWP) = 494.2 metric tons CO 2 e

Total = 129,623.3 metric tons CO 2 e

Methane Emissions from Distillate Fuel (Gallons)

= 0.0014 kg CH 4 / gallon x 9,996 gallons x 0.001 metric tons/kg = 0.014 metric tons CH 4

Total CH 4 from All Sources = 15.17 metric tons CH 448 Part III Chapter 9 

# Chapter 9 Indirect Emissions from Imported Steam, and District Heating, or Cooling (and Electricity from a Co-Generation Plant)

This chapter applies to organizations that purchase steam, district heat, cooling or electricity from a co-generation or conventional boiler plant that they do not own or operate. Emissions associated with these sources are considered to be indirect. If you own or operate a co-generation or conventional boiler plant, you should calculate your direct emissions from the combustion of the fossil fuels at the plant as described in Chapter 7.



## III.9.1 Calculating Indirect Emissions from Heat and
Power Produced at a Co-Generation Facility Emissions from co-generation facilities—also referred to as combined heat and power (CHP) plants—represent a special case for estimating indirect emissions. Because co-generation simultaneously produces electricity and heat (or steam), attributing total GHG emissions to each product stream would result in double counting. Thus, when two or more different parties receive the energy streams from co-generation plants, GHG emissions must be determined and allocated separately for heat production and electricity production. Since the output from co-generation results simultaneously in heat and electricity, you can determine what “share” of the total emissions is a result of electricity and heat by using a ratio based on the Btu content of heat and/or electricity relative to the co-generation plant’s total output. The process for estimating indirect emissions from heat and power produced at a co-generation facility involves the following five steps:

1. Obtain total emissions and power and heat generation information from co-generation facility;

2. Determine emissions attributable to net heat production and electricity production;

3. Calculate emissions attributable to your portion of heat and electricity consumed;

4. Convert any non-CO 2 emissions to carbon dioxide equivalent, as applicable; and

5. Sum CO 2 e. 

### Step 1: Obtain emissions and power and heat information from the co-generation facility. You will need to obtain the following information from the CHP plant owner or operator to estimate indirect GHG emissions:

1. Total emissions of carbon dioxide (and methane and nitrous oxide when they are being reported) from the co-generation facility - based on fuel input information;

2. Total electricity production from the co-generation plant - based on generation meter readings; and

3. Net heat production from the co-generation plant. Net heat production refers to the useful heat that is produced in co-generation, minus whatever heat returns to the boiler as steam condensate, as shown in Equation III.9a. 1



### Step 2: Determine emissions attributable to net heat production and electricity production for the co-generation plant. Refer to Section III.8.5 in the Stationary Combustion chapter titled “Allocating Emissions from Co-Generation” to calculate emissions attributable to net heat and electricity production. 

### Who should read Chapter 9: Chapter 9 applies to organizations that purchaseelectricity, steam, heating or cooling from a cogeneration plant or conventional boiler that they do not own or operate. 

### What you will find in Chapter 9: This chapter provides guidance on estimating indirect emissions from co-generation, imported steam, and district heating or cooling. The chapter includes the quantification methodology for co-generation and an example addressing indirect emissions from district heating. 

### Information you will need:You will need information about the type of cogeneration, imported steam and heat, and imported cooling your organization uses, and the types and amounts of fuel consumed by the plant to generate that electricity, heating, or cooling. For example, for heat or electricity from a co-generation facility, you will need information about the plant’s net heat production and net electricity production, in addition to your organization’s own consumption of that power.

Equation III.9a Net Heat Production

Net Heat Production (MMBtu) = Heat of Steam Export (MMBtu) - Heat of Return Condensate (MMBtu)

1 Alternatively, refer to p. 45 “Step 2” for guidance on determining net heat production from steam temperature and pressure data.49 Part III Chapter 9 

### Step 3: Calculate emissions attributable to your portion of heat and electricity consumed. Once you have determined total emissions attributable to heat (or steam) and electricity production, you will need to determine your portion of heat or electricity consumed, and thus your indirect GHG emissions associated with heat or electricity use. First, obtain your electricity and heat (or steam) consumption information, then use Equations III.9b and III.9c to calculate your share of emissions, as appropriate.



### Step 4: Convert any non-CO 2 

### emissions to CO 2 

### e, as applicable, and sum subtotals. Use the IPCC Second Assessment Report global warming potential factors from Table III.6.1 to convert methane and nitrous oxide to carbon dioxide equivalent.



## III.9.2 Calculating Indirect GHG Emissions from Imported
Steam or District Heating
from a Conventional Boiler
Plant The following process leads participants through a procedure to calculate emissions from imported steam or district heating produced at a conventional boiler plant that does not generate electricity – i.e., the boiler plant is not a co-generation facility. Quantifying indirect emissions from imported steam or district heating largely mirrors that for calculating direct emissions from stationary combustion, with the additional step to incorporate efficiency losses for steam generation and distribution. In order to calculate fuel consumption at the boiler, you can use the heat contained in the steam or hot water you receive, rather than rely on actual fuel measurements, which may not be available. (See Equation III.9d and

Equation III.9c Indirect Emissions Attributable to Heat (or Steam) Consumption

Indirect Emissions Attributable
to Heat Consumption (metric tons) = CHP Emissions Attributable
to Heat Production (metric tons) x 

# ( Your Heat Consumption (MMBtu) ÷ CHP Net Heat Production (MMBtu) 

# ) III.9e.) Once you have identified fuel consumption at the boiler, you can calculate total emissions by multiplying total energy by the emission factors provided in Appendix C, Tables C.5 and Table C.6. If you know the efficiency factor for generation and transmission of imported steam or hot water, please use it in your calculation. (Note, heat loss during transmission should be reflected in this efficiency factor.) If the efficiency is unknown, use an efficiency factor of 75%. Use the following four steps to estimate your total GHG emissions from imported steam or district heating:

1. Determine energy obtained from steam or district heating;

2. Determine energy consumed at the steam or district heating plant;

3. Determine appropriate emission factor for the fuel; and

4. Multiply energy consumed by the emissions factor to derive emission estimates. 

### Step 1: Determine energy obtained from steam or district heating. You can use monthly energy bills to determine the energy obtained from steam or district heating. The monthly bills should be summed together over the year to give annual consumption. You will want to total your data in million Btus (MMBtu). Heating Bills Expressed in Therms. If your heating bills are expressed in therms, you can convert the values to MMBtu by multiplying by 0.1, as shown in the Equation III.9d.

Equation III.9d Steam Energy Consumption (from therms)

Energy Consumption (MMBtu) = Energy Consumption (therms) x 0.1 MMBtu/ therm

Heating Bills Expressed in Pounds of Steam. If your steam consumption is billed in pounds (lbs), you either need to monitor the temperature and pressure of the steam you have received, or request it from the steam supplier. Calculate the thermal energy of the steam using saturated water at 212 O F as the reference. 2 The thermal energy consumption is calculated as the difference between the enthalpy of the steam at the delivered conditions and the enthalpy (or heat content) of the saturated water at the reference conditions (or heat content). The enthalpy of the Equation III.9b Indirect Emissions Attributable to Electricity Consumption

Indirect Emissions Attributable to Electricity Consumption = CHP Emissions Attributable to Electricity Production (metric tons) x 

# ( Your Electricity Consumption (kWh) 

### ÷ Total CHP Electricity Production (kWh) 

# )

2 American Petroleum Institute, Compendium of Greenhouse Gas Emissions Estimation Methodologies for the Oil and Gas Industry (2001). 3 See, for example, J.H. Keenan, Keyes, Hill, et al, Steam Tables (1969) and R.J. Reed, Ed., North American Combustion Handbook, Second Edition (1978), pages 349.5 0 Part III Chapter 9 from imported steam or hot water.



### Step 5: Convert any CH 4 

### and N 2 

### O Emissions to CO 2 

### e and sum all subtotals. Use the IPCC Second Assessment Report global warming potential factors from Table III.6.1 to convert methane and nitrous oxide to carbon dioxide equivalent.



## III.9.3 Calculating Indirect GHG Emissions from District
Cooling When you purchase cooling services using district cooling, the compressor system that produces the cooling is driven by either electricity or fossil fuel combustion. Your indirect emissions from district cooling represent your share of the total cooling demand from the cooling plant, multiplied by the total GHG emissions generated by that plant. You can begin the process of estimating your indirect emissions from district cooling by summing together the total cooling on your monthly cooling bills. Once you have determined your total cooling, you can use one of two options—either a simplified or more detailed approach—to estimate your GHG emissions. Simplified Approach (Option 1). The simplified approach uses an estimated value for the ratio of cooling demand to energy input for the cooling plant, known as the “coefficient of performance” (COP). Thus, this approach allows you to estimate the portion of energy used at the district cooling plant directly attributable to your cooling. Detailed Approach (Option 2) . COPs for chillers may vary by more than an order of magnitude, making it necessary to obtain the COP for the cooling plant. The more detailed approach allows you to determine the total cooling-related steam can be found in standard steam tables. 3 The enthalpy of saturated water at the reference conditions is 180 Btus per pound. The thermal energy consumption for the steam can then be calculated as shown in Equation III.9e. 

### Step 2: Determine the energy consumed by the
steam or district heating plant. Once you have estimated your steam consumption, you can estimate the energy consumed at the steam or district heating plant by dividing your energy consumption by the system efficiency. If you can obtain information about the efficiency of the boiler used to produce the steam or hot water and any transport losses that occur in delivering the steam, use Equation III.9f. If transport losses or boiler efficiency vary seasonally, energy input should be calculated on a monthly or seasonal basis, and summed together to arrive at the total annual energy input for Step 4.

Estimated System Efficiency. As shown in Equation III.9g, if you are unable to obtain the system efficiency, divide energy consumption from Step 1 by an estimated total efficiency—boiler efficiency and transport losses combined—of 75%.



### Step 3: Determine appropriate emission factors. Because emissions will vary with fuel type, you need to know the type of fuel that is burned in the plant supplying your steam or hot water. You can obtain this information from the plant’s energy supplier. Once you have the type of fuel being combusted to generate the steam or hot water, use the emission factors for stationary fuel combustion in Appendix C, Tables C.5 and Table C.6. 

### Step 4: Calculate total emissions from imported
steam or district heating. Once you have both the value of total energy consumed from Step 2 and the appropriate emission factor from Step 3, use Equation III.9h to calculate total GHG emissions

Equation III.9e Steam Energy Consumption (from pounds)

Energy Consumption (MMBtu) = 

# ( Enthalpy of Delivered
Steam (Btu/lb) - 180 (Btu/lb) x 

# ) Mass of Steam Consumed (lbs) 

### ÷ 1,000,000 (Btu/MMBtu)

Equation III.9f Energy Input by Steam or District Heating Plant

Energy Consumption (MMBtu) = Energy Use for Heating (MMBtu) 

### ÷ 

# [ Fractional Boiler Efficiency x 

## ( 1



### - Fractional Transport Losses 

## ) 

# ]

Equation III.9g Energy Input (Plant Efficiency Unknown)

Energy Input (MMBtu) = Energy Consumption (MMBtu) 

### ÷ 0.75 Equation III.9h Total Emissions from Steam System

Total Emissions (metric tons) = Energy Consumed (MMBtu) x Emission Factor (kg/MMBtu) x 0.001 metric tons/kg5 1 Part III Chapter 9 

### Step 4: Calculate total GHG emissions resulting from cooling.

Where Cooling Plant Uses Absorption Chillers or Engine-Driven Compressors. If you can determine what type of fuel is being used, multiply the energy input by the appropriate emission factor in Appendix C, Table C.5 and Table C.6. If the fuel type cannot be determined, assume natural gas and multiply the energy input by the emission factors for natural gas according to Equation III.9k.

Where Cooling Plant Uses Electric-Driven Compressors. If the cooling plant uses an electrically driven compressor, calculate emissions using the procedures described in Chapter 6 on indirect emissions from electricity consumption.



### Detailed Approach Based on Cooling Plant Emissions and Your Organization’s Share of Total Cooling Demand

- Option 2 Step 1 Determine total cooling-related emissions from the district cooling plant. District cooling plants take a variety of forms and may produce electricity, hot water, or steam for sale in addition to cooling.

Where Cooling Plant Produces Only Cooling. In the simplest case, all of the fuel consumed by the plant is used to provide cooling. In that case, you will be able to determine total cooling emissions based on (1) total indirect emissions from cooling plant electricity and heat consumption (metric tons), and (2) total direct emissions from cooling plant fuel combustion (metric tons). The process for calculating the indirect and direct indirect emissions is described in Sections III.6 and III.8. You will need to obtain the emission values from the district cooling plant, or calculate the emissions based on the fuel consumption, as well as electricity and steam consumption information, provided by the plant.

Where Cooling Plant Produces More than Cooling. In many cases, the simple situation described above will not apply. Instead, the cooling plant will be integrated into a combined heat and power plant, where some of the steam and electricity produced by the plant may be used for cooling, and some may be used for other purposes. In this case, the emissions from the combined heat and power plant will need to be allocated between heating and emissions from the district cooling plant and your fraction of total load hours.


### Simplified Approach Using an Estimated Coefficient of Performance

- Option 1 Step 1: Determine your annual cooling demand. While your cooling bill may be reported in terms of million Btu (MMBtu), it will typically report cooling demand in ton-hours. You can convert ton-hours of cooling demand

to MMBtu using Equation III.9i. If you are billed monthly, sum together your cooling demand for every month to yield an annual total. 

### Step 2: Estimate COP for the plant’s cooling system. If you are able to obtain the COP for the cooling plant, proceed to Step 3. However, if you cannot obtain the COP itself, try to determine the type of chiller used by

the district cooling plant. With that information, a rough estimate of the COP may be selected from the typical values shown in Table III.9.1. 

### Step 3: Determine energy input. To determine the energy input to the system resulting from your cooling demand, use Equation III.9j. For an electric driven compressor, convert the energy input in MMBtu into kWh by multiplying by 293.1.

Equation III.9i Annual Cooling Demand

Cooling Demand (MMBtu) = Cooling Demand (ton-hours) x 12,000 (Btus/ton-hour) x 0.000001 (MMBtu/Btu)

Equation III.9j Energy Input

Energy Input (MMBtu) = Cooling Demand (MMBtu) 

### ÷ COP Equation III.9k Total Cooling Emissions

Total Cooling Emissions (metric tons) = Energy Input (MMBtu) x Emission Factor (kg/MMBtu) x 0.001 metric tons/kg



### Equipment Type Coefficient of Performance (COP) Energy Source

Absorption Chiller 0.8 Natural Gas

Engine-Driven Compressor 1.2 Natural Gas

Electric-Driven Compressor 4.2 Electricity 

### Table III.9.1: Typical Chiller Coefficients of Performance52 Part III Chapter 9 electricity production (or shaft work in the case of internal combustion engines), and these emissions will have to be scaled by the fraction of the heat or electricity that is used for cooling, as shown in Equation III.9l, which assumes 90% efficiency for boiler emissions and allocates all other waste heat to electrical efficiency. The attribution of emissions to the heat and power streams is done in the same manner as described above. 

### Step 2: Determine fraction of cooling emissions attributable to your operations. The next step in calculating your GHG emissions from cooling is to scale the total plant cooling emissions by the percentage of your share of the cooling load. Equation III.9m demonstrates how the total cooling load on the plant is scaled to determine your cooling emissions. 

### Step 3: Determine total yearly emissions. For each month (or longer period) of the year, cooling emissions should be calculated as described in Steps 1 and 2, above. The duration of the periods for which the emissions are calculated will depend on the data available. Ideally, calculations would be made monthly for cooling plants integrated with CHPs, as emissions associated with cooling will depend on how the CHP outputs are distributed. If data for making these calculations are not available on a monthly basis, then longer periods will be used. In either case, the emissions for each period must be summed over the year to obtain the annual total.

Equation III.9l Cooling Emissions (from plant with multiple product streams)

Total Cooling Emissions (metric tons) 

## = 

# [ Fraction of CHP Electricity Prod. Used for Cooling 

### x 

# ( ( Total Fuel Heat Input (MMBtu) 

### - Net Heat Production (MMBtu) 

## ) ÷ 0.9 

# ) ÷ Total Fuel Heat Input (MMBtu) ] 

# ]

+ 

# [ Fraction of CHP Heat Prod. Used for Cooling 

### x 

# ( Net Heat Production (MMBtu) 

### ÷ 

## ( 0.9 

### x Total Fuel Heat Input (MMBtu) 

## ) 

# ) ] x Total CHP Emissions (metric tons) Additional guidance on estimating GHG emissions from co-generation electricity and heat can be found through the following:

• Corporate GHG Accounting Calculation Tools, prepared under the GHG Protocol Initiative by the World Resources Institute and World Business Council for Sustainable Development (October 2001). The tool entitled “Calculating CO 2 Emissions from Stationary Sources” addresses emissions from co-generation facilities. www.ghgprotocol.org/standard/tools.htm.

• Guidelines for the Measurement and Reporting of Emissions in the UK Emissions Trading Scheme, prepared by the U.K. Department for Environment, Food and Rural Affairs (August 2001). www.defra.gov. uk/environment/climatechange/trading.

• EPA Climate Leaders Inventory Protocol, U.S. Environmental Protection Agency (in development as of August 2002). EPA’s protocol includes a module focusing on indirect emissions from electricity and/or steam purchases. www.epa.gov/climateleaders/index.

Equation III.9m Annual Cooling Emissions

Participant Cooling Emissions (metric tons) 

### = Total Cooling Emissions (metric tons) x 

# ( Participant Cooling Load (ton-hour) 

### ÷ Total Cooling Load (ton-hour) 

# )53 Part III Chapter 9 

### Fuel Gas Emitted Emission Factor

Natural Gas Carbon Dioxide 52.78 kg/MMBtu

Natural Gas Methane 0.0059 kg/MMBtu

Natural Gas Nitrous Oxide 0.0001 kg/MMBtu 

### Emission Factors for Natural Gas Step 3:	 Determine appropriate emission factors. Since natural gas is used to generate the steam, use emissions factors in MMBtus from Appendix C, T ables C.5 and C.6

Equation III.9k Total Emissions

Total Carbon Dioxide (CO 2 ) Emissions (kg) = 750.94 MMBtu x 52.78 kg/MMBtu x 0.001 metric tons/kg = 39.63 metric tons CO 2 Total Methane (CH 4 ) Emissions (kg) = 750.94 MMBtu x 0.0059 kg/MMBtu x 0.001 metric tons/kg = .0044 metric tons CH 4 Total Nitrous Oxide (N 2 O) Emissions (kg) 750.94 MMBtu x 0.0001 kg/MMBtu x 0.001 metric tons/kg = 0.000075 metric tons N 2 O Equation III.9f Energy Input

Energy Input (MMBtu) = 600 MMBtu 

### ÷ 

# [ 0.85 (boiler efficiency) x 

## ( 1



### - 0.06 

## ) 

# ]

= 750.94 MMBtu

Step 5:	 Convert CH 4 and N 2 O Emissions to CO 2 e and

sum all subtotals.

Step 4:	 Calculate Total Emissions.
Steam-related methane and nitrous oxide emissions are likely to be de minimis. Equation III.6b Converting Mass Estimates to Carbon Dioxide Equivalent

Metric Tons of
CO 2 e Metric Tons of
GHG x GWP (SAR, 1996)

Metric Tons of CO 2 = = 39.63 metric tons CO 2 e

CH 4 Metric Tons of CO 2 e = 0.0044 metric tons CO 2 e x 21 (GWP) = 0.0924 metric tons CO 2 e

N 2 O Metric Tons of CO 2 e 0.000075 metric tons N 2 O x 310 (GWP) = 0.0233 metric tons CO 2 e

Total = 39.746 metric tons CO 2 e 

### Socal Manufacturing Company The Socal Manufacturing Company imports steam at its Bakersfield facility . The steam is imported from a conventional natural gas-fired boiler. The boiler efficiency is 85% and the loss factor is 6%. Step 1: Determine energy obtained from steam or district heating. Since its energy consumption is provided in therms on its monthly billing, Socal uses Equation III.9d to determine energy consumption. Socal consumed 6,000 therms in the past year. 

## III.9.4 Example: Indirect Emissions from District Heating

Equation III.9d Energy Consumption for Steam

Steam Energy Consumption (MMBtu) = 6,000 Therms x 0.1 MMBtu/ therm = 600 MMBtu

Step 2: Determine the energy consumed by the steam or district heating plant. Socal uses its boiler efficiency of 85% and loss factor of 6% to calculate its Energy Input.54 Part III Chapter 10 

# Chapter 10 Direct Emissions from Manufacturing Processes

The Registry’s Cement Protocol provides guidance for calculating CO 2 emissions associated with manufacturing cement. Cement companies should refer this document for procedures to account for process-related emissions from the calcination of clinker. Power companies and utilities should refer to the Power/Utility Protocol for guidance on accounting for process-related emissions associated with emission control technologies, coal gasification, and hydrogen production. For other manufacturing processes, the Registry is still formulating specific guidelines and rules for calculating direct GHG emissions. When developed, participants with process emissions will need to follow the reporting guidance specific to their industry. These will become industry-specific reporting protocols, and will be appended to this document. Without this guidance in place, CARROT is not yet able to help you calculate process emissions. However, you should calculate your emissions offline and report to the Registry in CARROT. In the meantime, a variety of useful resources exist that may help you to calculate your process emissions. The Registry recommends reviewing relevant methodologies and/or calculations with technical assistance providers or other environmental experts. Until specific guidance is developed, certification of emissions from manufacturing processes will be determined by the expertise and professional judgment of the certifier. Should you have questions about criteria or questions about a certifier’s judgments during the certification cycle, you can contact the Registry at any time. The following is a list of resources for use in making your calculations:

• Corporate GHG Accounting Calculation Tools, prepared under the GHG Protocol Initiative by the World Resources Institute and World Business Council for Sustainable Development (October 2004). The following list of calculation tools are available form the GHG Protocol Initiative website, at www.ghgprotocol. org/standard/tools.htm:

 ̇ Calculating N 2 O Emissions from the Production of

Adipic Acid

 ̇ Calculating CO 2 and PFC Emissions from the

Production of Aluminum

 ̇ Calculating CO 2 Emissions from the Production of

Ammonia

 ̇ Calculating HFC-23 Emissions from the Production of

HCFC-22

 ̇ Calculating CO 2 Emissions from the Production of

Iron and Steel

 ̇ Calculating CO 2 Emissions from the Production of

Lime

 ̇ Calculating N 2 O Emissions from the Production of

Nitric Acid

 ̇ Calculating PFC Emissions from the Production of

Semi-Conductor Wafers

• Guidelines for the Measurement and Reporting of Emissions in the UK Emissions Trading Scheme, prepared by the U.K. Department for Environment, Food and Rural Affairs (August 2001). The following list of calculation tools for process-based CO 2 emissions are available in Annex B of the UK Guidelines, located
at www.defra.gov.uk/environment/climatechange/trading:

 ̇ Protocol B1: Cement Manufacture

 ̇ Protocol B2: Lime Production

 ̇ Protocol B3: Limestone and Dolomite Use

 ̇ Protocol B4: Soda Ash

 ̇ Protocol B5: Ammonia – Use of Fuels as Feedstock

 ̇ Protocol B6: Metal Production

 ̇ Protocol B7: Waste Incineration – Municipal Solid

Waste (MSW) and Sewage

• Guidance to the California Climate Action Registry: General Reporting Protocol, Appendix B and Appendix C, prepared by the California Energy Commission, P500-02-005F (June 2002), located at www.climateregistry.org . The following list of citations 

### Who should read Chapter 10: Chapter 10 applies to organizations with process emissions only. 

### What you will find in Chapter 10: This chapter provides several resources you may use to calculate your direct emissions from manufacturing
processes. 

### Information you will need:
Your information needs will be based on the calculation methodology you select.55 Part III Chapter 10

provide some guidance on quantifying process emissions:

 ̇ CO 2 emissions from lime production: Appendix B

page B-11, Appendix C page C-6;

 ̇ CO 2 emissions from limestone and dolomite

consumption: Appendix B page B-12;

 ̇ N 2 O from nitric acid production: Appendix B page

B-16, Appendix C page C-7;

 ̇ FC-23, CF 4 , C2F 6 , and SF 6 emissions from

semiconductor manufacturing: Appendix B page B-18, Appendix C page C-9;

 ̇ CO 2 emissions from soda ash production and

consumption: Appendix B page B-19, Appendix C page C-11.

• Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000, U.S. Environmental Protection Agency (April 2002). See www.epa.gov/globalwarming/ publications/emissions/us2002/index.html.

• Revised 1996 IPCC Guidelines for National Greenhouse Gas Inventories Reference Manual (Volume 3), prepared by the Intergovernmental Panel on Climate Change (1996). Volume 3 addresses GHG emissions from industrial processes. See www.ipccnggip.iges.or.jp/public/gl/invs6b.htm.

• Inventory of California Greenhouse Gas Emissions and Sinks: 1990-1999, prepared by the California Energy Commission, November 2002. See www.energy.ca.gov/ global_climate_change.

• EPA Climate Leaders Inventory Protocol, U.S. Environmental Protection Agency (in development as of the time of publication of this Protocol). See www. epa.gov/climateleaders/index.html.56 Part III 

### Chapter 11 

# Chapter 11 Direct Fugitive Emissions

Power companies and utilities should refer to the Power/ Utility Protocol for guidance on accounting for fugitive emissions associated with electricity transmission and distribution, fuel handling and storage, air conditioning and refrigerant systems, and fire suppression equipment. The majority of fugitive GHG emissions are specific to various industrial sectors or processes, including: manufacturing, natural gas transport and distribution, coal mining, waste management, wastewater treatment, and refrigerant leakage from air conditioning and refrigeration equipment. This chapter provides specific guidance on direct fugitive emissions from air conditioning and refrigeration systems below.



## III.11.1 Calculating Direct Fugitive Emissions from
Refrigeration Systems Leakage from refrigeration systems, such as air conditioners and refrigerators, is common across a wide range of entities. Only those refrigerants that contain or consist of compounds of the required GHGs should be reported. Hydrofluorocarbons (HFCs) are the primary GHG of concern for refrigeration systems, particularly for motor vehicle air conditioners. Today, HFC-134a is the standard refrigerant for mobile air conditioning systems. For most Registry participants, emissions of HFCs from air conditioning systems will be negligible in comparison to other GHG emissions.



### Use the following three step process to calculate HFC emissions from air conditioners:

1. Determine whether HFC emissions are significant or de minimis (see Section III.5 for guidance on de minimis);

2. Perform a mass balance calculation; and

2. Convert each HFC emission to CO 2 e. Step 1 estimates whether your fugitive emissions are significant and warrant a more comprehensive review. If the fugitive emissions are not significant, and you wish to categorize them as de minimis, you do not need to complete this section. To perform the significance analysis, you will need information on:

• The types and quantities of air conditioning equipment;

• The total refrigerant charge;

• The annual leak rates; and

• The types of refrigerant. If you find that your fugitive emissions are indeed significant, continue to Steps 2 and 3 for a more accurate quantification of HFC emissions. If you find that your emissions are not significant, proceed to Section III.12. 

### Step 1: Determine whether HFC emissions are significant or de minimis. This step helps organizations roughly estimate emissions and determine whether HFC emissions from air conditioning systems are significant or de minimis. Consistent with the Registry’s definition of significance, HFC emissions from air conditioners greater than or equal to 5% of a participant’s total emission are considered significant, assuming the participant has no other de minimis emissions. Fugitive emissions less than 5% are considered de minimis, and do not need to be reported as long as total de minimis emissions are less than 5%. However, if emissions are considered substantial and possibly significant, then a more comprehensive and accurate mass balance approach is required to determine actual emissions. Upper Bounds of Air Conditioner Loss Rates: Table III.11.1 provides upper bounds values for leakage rates for the purposes of determining de minimis levels, refrigerant charges, and type of refrigerant for various refrigeration systems. 

### Who should read Chapter 11: Chapter 11 applies to organizations with fugitive emissions only. 

### What you will find in Chapter 11: This chapter provides guidance on determining direct fugitive emissions, specific guidance and an example on fugitive refrigerant emissions of HFCs, and guidance on additional resources to use for other fugitive emissions. 

### Information you will need: To complete this chapter you will need information on: the types and quantities of air conditioning equipment, total refrigerant charge, annual leak rates, and the types of refrigerant, as applicable. 

### Cross-References:
See Section III.5 on De Minimis Emissions and Significance in estimating HFCs from refrigerants.57 Part III Chapter 11 Several of the refrigerants listed in Table III.11.1 are blends of HFCs. The composition of these blends is shown in Table III.11.2. Using assumed annual loss rates and refrigerant change values from Table III.11.1, apply Equation III.11a to estimate HFC significant or de minimis emissions from refrigeration. Equation III.11a HFC Emissions from Refrigerant Leakage

HFC Emissions from Refrigerant Leakage (kg) = Total Annual Refrigerant Charge (kg) x Assumed Annual Leak Rate (%) Note: Information included in this table is based on Alliance for Responsible Atmospheric Policy, Global comparative analysis of HFC and Alternative Technologies for Refrigeration, Air Conditioning, Foam, Solvent, Aerosol Propellant, and Fire protection Applications, Final Report (March 2002), at www.arap.org/adlittle/toc.html

.



### Type of AC Systems Upper Bounds Annual Loss Rate Refrigerant Charge (kg) Type of Refrigerant

Large Automobile 35 % 1.0 HFC-134a

Small Automobile 35 % 0.5 HFC-134a

Residential Central Air System (3 ton) 35 % 2.8 R407C

Commercial AC System (7 ton) 35 % 6.9 R407C

Commercial Chiller (350 ton) 35 % 480 HFC-23
Commercial Chiller (350 ton) 35 % 432 HFC-134a
Commercial Chiller (1000 ton) 35 % 1,225 HFC-23
Commercial Chiller (1000 ton) 35 % 1,120 HFC-134a Direct Expansion (DX) Central Refrigeration System 15 % 6% of floor area (ft2) R404A,R507

Water-Cooled Distributed System 15 % 0.66% of floor area (ft 2 ) R404A,R507

Secondary Loop System 15 % 1.5% of floor area (ft 2 ) R404A,R507 

### Table III.11.1: Refrigerant Loss Rates Note, all values are estimates and are intended only to serve as guidelines for evaluating de minimis.



### Blend HFC 32 HFC-125 HFC-134a HFC-143a

R404A NA 44% 4% 52%

R407C 23% 25% 52% NA

R507 NA 50% NA 50%

R507 NA 50% NA 50% 

### Table III.11.2: Composition of Refrigerant Blends58 Part III Chapter 11 Next, use the IPCC Second Assessment Report global warming potential factors from Table III.6.1 to convert HFCs to carbon dioxide equivalent. If the sum of the CO 2 e emissions for HFC (plus other estimated de minimis emissions) is less than 5% of total assumed emissions, you do not need to report HFC emissions. Proceed to Steps 2-3 if your HFCs are significant. 

### Step 2: Mass-Balance Calculation: Determine base inventory for each HFC and calculate changes to base inventory. Step 2 utilizes a comprehensive, mass-balance approach toaccurately determine HFC emissions. Essentially, the massbalance method works by starting with a base inventory of all HFCs in use, and adjusts that total based on purchases and sales of HFCs, and changes to the total refrigerant charge remaining in the equipment. The used HFCs that cannot be accounted for are assumed to have been emitted to the atmosphere. The four elements of these adjustments and changes are described here, with references to Tables III.11.3 and III.11.4, as applicable. Base Inventory. The first step in calculating HFC emissions is to determine the difference between the quantity of the HFC in storage at the beginning of the year (A) and the quantity in storage at the end of the year (B) , as shown in Table III.11.3. Note, this quantity will be negative if the inventory increases over the course of the year. Those HFCs contained in cylinders and other storage containers are considered to be HFCs “in inventory”—not HFCs held in operating equipment. Additions and subtractions refer to HFCs placed in or removed from the stored inventory, respectively. The next items in calculating HFC emissions include purchases or acquisitions of refrigerant, sales or disbursements or refrigerant, and any changes to total full charge of refrigeration equipment. Purchases/Acquisitions of Refrigerant. This is the sum of all the HFCs acquired during the year either in storage containers or in equipment (C) , as shown in Table III.11.4. Sales/Disbursements of Refrigerant. This is the sum of all the HFCs sold or otherwise disbursed during the year either in storage containers or in equipment (D) , as shown in Table III.11.4. Change to Total Full Charge of Equipment. This is the net change to the total equipment volume for a given HFC during the year (E) , as shown in Table III.11.4. Note that the change to total full charge of equipment refers to the full and proper charge of the equipment rather than to the actual charge, which may reflect leakage. It accounts for the fact that if new equipment is purchased, the HFC that is used to charge that new equipment should not be counted as an emission. On the other hand, it also accounts for the fact that if the amount of refrigerant recovered from retiring equipment is less than the full charge, then the difference between the full charge and the recovered amount has been emitted. Note that this quantity will be negative if the retiring equipment has a total full charge larger than the total full charge of the new equipment.



### Inventory Amount (kgs)

A Beginning of year

B End of year 

### Table III.11.3: Base Inventory

Inventory Amount (kgs)

Additions to Inventory

1 Purchases of HFCs (including HFCs in new equipment)

2 HFCs returned to the site after offsite recycling

C Total Additions (1+2)

Subtractions from Inventory

3 Returns to supplier

4 HFCs taken from storage and/or equipment and disposed of

5 HFCs taken from storage and/or equipment and sent offsite for recycling or reclamation

D Total Subtractions (3+4+5)
Change to Full Charge/Nameplate Capacity

6 Total full charge of new equipment

7 Total full charge of retiring equipment

E Change to nameplate capacity (6-7) 

### Table III.11.4: Inventory Changes59 Part III Chapter 11 To sum the total annual emissions of each type of HFC, use Equation III.11b.

Equation III.11b Total Annual Emissions

Total Annual Emissions = A - B + C - D + E


### Step 3: Convert HFC emissions to CO 2 

### e (and convert to metric tons) and sum all subtotals. Finally, use the IPCC Second Assessment Report global warming potential factors from Table III.6.1 to convert each HFC to carbon dioxide equivalent, and sum the totals.



## III.11.2 Other Fugitive Emissions The Registry is still formulating the specific guidelines and rules involved in calculating other direct fugitiveGHG emissions. These will be developed as industryspecific reporting protocols, and will be appended to this document. Without this guidance in place, CARROT is not yet able to help you calculate fugitive emissions, but you should calculate your emissions offline and still use CARROT to report them to the Registry. In the meantime, a variety of useful resources exist that may help you to calculate your fugitive emissions. The Registry recommends reviewing relevant methodologies and/or calculations with technical assistance providers or other environmental experts. Until specific guidance is developed, certification of fugitive emissions will be determined by the expertise and professional judgment of the certifier. Should you have questions about criteria or questions about a certifier’s judgments during the certification cycle, you can contact the Registry at any time. The following is a list of resources for use in making your calculations:

• Corporate GHG Accounting Calculation Tools, prepared under the GHG Protocol Initiative by the World Resources Institute and World Business Council for Sustainable Development (2004). www.ghgprotocol. org/standard/tools.htm.

• Guidelines for the Measurement and Reporting of Emissions in the UK Emissions Trading Scheme, prepared by the U.K. Department for Environment, Food and Rural Affairs (August 2001). www.defra.gov. uk/environment/climatechange/trading.

• EPA Climate Leaders Inventory Protocol, U.S. Environmental Protection Agency (in development as of August 2002). EPA’s protocol includes core modules addressing methane emissions from solid waste disposal at landfills as well as HFC emissions from refrigeration/air conditioning use. www.epa. gov/climateleaders/index.html.

• Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000, U.S. Environmental Protection Agency (April 2002). www.epa.gov/globalwarming/publications/ emissions/us2002/index.html.

• Inventory of California Greenhouse Gas Emissions and Sinks: 1990-1999, prepared by the California Energy Commission, November 2002. See www.energy.ca.gov/ global_climate_change.

• American Petroleum Institute, Compendium of Greenhouse Gas Emissions Estimation Methodologies for the Oil and Gas Industry (2001).

• Guidance to the California Climate Action Registry: General Reporting Protocol, Appendix B and Appendix C, prepared by the California Energy Commission, P500-02-005F (June 2002), located at www.climateregistry.org . The following list of citations provide some guidance on quantifying direct fugitive emissions:

 ̇ CH 4 emissions from coal mining: Appendix B page

B-5, Appendix C page C-3;

 ̇ CH 4 emissions from natural gas systems: Appendix B

page B-15, Appendix C page C-9;

 ̇ CH 4 emissions from petroleum systems: Appendix B

page B-17, Appendix C page C-9;

 ̇ SF 6 emissions from electricity transmission and

distribution equipment: Appendix B page B-6, Appendix C page C-4;

 ̇ N 2 O emissions from wastewater: Appendix B page

B-9;

 ̇ CH 4 emissions from wastewater: Appendix B page

B-15;

 ̇ CH 4 emissions from landfills: Appendix B page B-10;

 ̇ N 2 O emissions from agricultural soil management:

Appendix B page B-2;

 ̇ CH 4 emissions from livestock as a result of enteric

fermentation: Appendix B page B-7;

 ̇ CH 4 and N 2 O emissions from manure management:

Appendix B page B-13;

 ̇ CH 4 emissions from rice cultivation: Appendix B page

B-18.6 0 Part III Chapter 11 Equation III.6c Converting Mass Estimates to Carbon Dioxide Equivalent

HFC-23 metric tons of CO 2 e = 1.286 metric tons HFC-23 x 11,700 (GWP) = 15,046.2 metric tons CO 2 e

HFC-134a metric tons of CO 2 e = .001 metric tons HFC-134a x 1,300 (GWP) = 1.3 metric tons CO 2 e

Total = 15,047.50 metric tons CO 2 e 

## III.11.3 Example: Direct Fugitive Emissions from Refrigeration Systems

Produce Chillers, Inc. Produce Chillers, Inc. is based in California, and operates three large commercial chillers to refrigerate v egetable produce shortly after harvest, as well as three trucks. Step 1:	 Determine whether HFC emissions are significant or de minimis. Produce Chillers’ first step is to determine whether its HFC emissions are significant. The upper bound loss rates for Produce Chiller’s AC types are shown in Table III.11.1



### Type of AC Systems Upper Bounds Annual Loss Rate Refrigerant Charge (kg) Type of Refrigerant

Commercial Chiller (1000 ton) 35 % 1,225 HFC-23

Large Automobile 35% 1.0 HFC-134a 

### Air Conditioner Loss Rates for Produce Chillers, Inc.

Equation III.11a Assumed HFC Emissions from Annual Air Conditioning

HFC Emissions from Annual Air Conditioning (kg) = Total Annual Refrigerant Charge (kg) x Annual Leak
Rate (%) x Number of Systems x .001 metric tons/kg

Commercial Chiller (1000 ton) = 1,225 kg x 0.35 x 3 x .001 metric tons/kg = 1.286 metric tons HFC-23

HFC Emissions from Large Automobiles (kg) = 1.0 kg x 0.35 x 3 x .001 metric tons/kg = .001 metric tons HFC-134a

Produce Chillers has estimated that its total entity-wide GHG emissions are 50,000 metric tons. Consequently, they may choose to not report de minimis emissions of 2,500 metric tons (i.e., 5% of 50,000 metric tons). Its estimated fugitive emissions of HFC-23 will be significant, but HFC -134a will be insignificant. It decides not to report the HFC -134a emissions. But it must now calculate its HFC-23 emissions. Produce Chillers then uses Equation III.11a to estimate assumed HFC emissions from air conditioning.

Produce Chillers must then convert its assumed fugitive HFCs to CO 2 e, using Equation III.6c6 1 Part III Chapter 11 

### Inventory Amount (kgs)

Additions to Inventory

1 Purchases of HFCs (including HFCs provided by equipment manufacturers with or inside new equipment) 197.5

2 HFCs returned to the site after offsite recycling 0.0

C Total Additions (1+2) 197.5

Subtractions from Inventory

3 Returns of HFCs to supplier 0.0

4 HFCs taken from storage and/or equipment and disposed of 0.0

5 HFCs taken from storage and/or equipment and sent offsite for recycling or reclamation 53.3

D Total Subtractions (3+4+5) 53.3
Change to Full Charge/Nameplate Capacity

6 Total full charge of new equipment 19.5

7 Total full charge of retiring equipment 0.0

E Change to nameplate capacity (6-7) 19.5 

### Inventory Changes for Produce Chillers, Inc. HFC-23 from Commercial Chillers Equation III.11b Total Annual Emissions of HFC-23 (kgs)

Total Annual Emissions = A - B + C - D + E

Total Annual Emissions HFC-23 = 812.6 – 805.1 + 197.5 – 53.3 + 19.5 = 171.2 kg HFC-23

Equation III.6c Converting Mass Estimates to Carbon Dioxide Equivalent

Metric tons of
CO 2 e = Metric tons of
GHG x GWP (SAR, 1996)

HFC-23 metric tons of CO

2 e = 132.2 kg HFC-23 x 11,700 (GWP) x 0.001 metric tons/kg = 1.5467 metric tons CO

2 e

Total = 1.5467 metric tons CO

2 e Step 2:	 Determine base inventory for HFC 23 and calculate changes to base inventory. Produce Chillers increased its total vegetable produce refrigeration capacity by 18% with new equipment, decommissioned one refrigeration unit for recycling, and recharged sev eral of its refrigeration units. It also purchased a new truck in the past year. Using Table III.11.3 it shows that the inventory at the beginning of the year is 812.6 kg and at the end of the year it is 805.1 kg.

Using its purchase and charge records, Produce Chillers calculates its total annual emissions using T able III.11.4 and Equation III.11b 

### Inventory Amount (kgs)

A Beginning of year 812.6

B End of year 805.1 

### Base Inventory for Produce Chillers, Inc. HFC-23 from Commercial Chillers

Step 3:	 Convert HFC emissions to CO 2 e and convert to metric tons.62 Part III Chapter 1 2 

# Chapter 12 Optional Reporting

In addition to reporting required emissions, you can also provide information to the Registry about other activities of your organization that can serve to help describe your entity’s GHG activities and inventory. Examples of these include:

• Renewable Energy Certificate purchases;

• off-site waste disposal, including transport;

• employee commuting, including business travel;

• production of purchased raw materials, including transport;

• product use and disposal; and

• outsourced activities and contracting (especially if, in prior years, you generated these emissions directly). You can also provide descriptive information about your organization’s programs, projects to reduce emissions, environmental goals, awards and choose to provide quantitative information, including reporting of emissions efficiency metrics, or other indirect emissions. A key feature of the Registry’s program is the reporting of efficiency metrics. GHG emissions are sometimes reported on a normalized basis – as a ratio – instead of, or in addition to, reporting in absolute terms. Normalized emissions are emissions divided by some measure of output for the reporting entity. The specific output measure depends on the nature of the organization that is reporting and may range from physical units of output (e.g., pound of cement for a cement plant) to economic output (e.g., dollars of revenue for a diversified manufacturer). Reporting normalized emissions allows trends in the emissions intensity of an activity to be gauged by removing the effects of changing outputs

on the results. The common term for these measures is “efficiency metrics.” Sample efficiency metrics are listed in Appendix D.



## III.12.1 Reasons to Report Optional Emissions There are potentially many reasons to report optional information:

• To provide a more complete or descriptive picture of your organization’s environmental performance.

• To centralize information pertaining to other GHG accounting programs.

• To track other internal programs to monitor GHG emissions performance related to other corporate programs.

• To provide greater public education on sources of GHG emissions. Guidelines for reporting these types of information are provided below. There are no protocols for reporting or certifying optional information. Consequently, it is also not eligible for consideration by the State in the event of a future GHG regulatory regime. While you may obtain certification for other GHG accounting programs and store this information in CARROT, the State of California will only provide appropriate consideration for certified emission reports, based upon Registry Board-approved protocols. Even so, reporting these kinds of information can serve to improve your organization’s understanding of the sources of its emissions and its emission performance over time. Also, the Registry encourages you to document and report your GHG emissions internationally in the same categories as you report your California or U.S. emissions. Doing so will only increase your ability to measure and manage your total emissions. However, until such time as this information may be required by the State, it is also not eligible for state consideration. In the process of developing industry-specific guidance, additional recommendations may be developed for 

### Who should read Chapter 12: Chapter 12 applies to all participants. 

### What you will find in Chapter 12: This chapter provides resources for calculating and/or estimating emissions from sources that are not required to be reported, such as from employee commuting, business travel, waste and more. 

### Information you will need:
You will need information about the size and nature of GHG emitting operations throughout your organization. 

### Cross-References: It will be useful to consider your geographical and organizational boundaries addressed in Chapters 1 and 2, operational boundaries considered in Chapter 4, and all relevant quantification issues raised in Chapters 5-11.63 Part III Chapter 10 Chapter 1 2 optional information reported by industry.



## III.12.2 Efficiency Metrics Many organizations experience business growth and thus their total emissions may increase from year-to-year, regardless of their organization’s operational efficiency. Such organizations, in addition to reporting their total emissions, may also elect to report efficiency metrics that measure GHG emissions per unit of performance or output (e.g., lbs CO 2 /ft 2 of office space, lbs CO 2 /customer, lbs CO 2 /kWh, lbs CO 2 /$ of revenue, etc.). A list of some industry-specific metrics is provided in Appendix D. This information may be reported in CARROT at either the entity- or facility-level, but CARROT is not able to calculate this statistic for you. For organizations reporting under the General Reporting Protocol, metrics are optional. As the Registry develops its industry-specific reporting guidance, affected industries may be required to report one or more metrics appropriate to their industry; for instance, power sector companies are required to report three metrics according to the Power/ Utility Protocol as well as cement companies under the Cement Protocol.



## III.12.3 Other Emissions
Information When reporting information in CARROT, the tool will prompt you to provide descriptive information about your organization in the following areas: Entity description – You can provide basic information about your organization, including size, types of business and products, number of employees, etc.

Emission management programs —In this section, you can document the efforts of your organization to monitor and evaluate how and where your organization is producing GHG emissions. This could also include a description of other GHG accounting programs to which your organization belongs.

Emission reduction goals –You can enter information on your organization’s goals to decrease your emissions of GHGs.

Emission reduction projects —Until additional guidance is developed to provide standardized, certifiable accounting principles for discrete projects to reduce emissions, you can provide descriptions of specific activities, as well as provide a limited amount of statistical information.

Link to external website —You can provide a link or links to external websites that contain information about your organization. Space constraints in CARROT may limit how much information can be entered, but you can provide your own categories and update this information from year-to-year. You can also upload related documents in CARROT and attach them to your public emission report.



## III.12.4 Optional Indirect Emissions In addition to reporting indirect emissions from your electricity use, you are encouraged to optionally report other indirect GHGs. Examples of other sources of indirect emissions that you may choose to report include:

• off-site waste disposal, including transport;

• employee commuting, including business travel;

• production of purchased raw materials, including transport;

• product use and disposal; and

• outsourced activities and contracting. The Registry is still formulating specific guidance on estimating emissions from additional indirect sources such as those listed above. However, a variety of useful resources exist that may help you to estimate emissions from these types of activities. Some of these include:


### Off-site waste disposal, including transport

• EPA Climate and Waste Program http://yosemite.epa. gov/oar/globalwarming.nsf/WARM?OpenForm


### Employee commuting, including business travel

• Calculating GHG emissions from office-based organizations, www.ghgprotocol.org/standard/tools.htm

• Safe Climate, www.safeclimate.net/business/measuring/ tools.php

• Climate Care, www.climatecare.org/Calculator/index.cfm

• Bonneville Foundation, www.greentagsusa.org/ GreenTags/calculator_intro.cfm

• EPA, Web Site Guide to Global Climate Change, www. epa.gov/region01/eco/cchange/webgd.pdf



### Production of purchased raw materials, including transport

• Paper Products, www.safeclimate.net/business/ measuring/WRI_CO 2 Guide.pdf (pages 60-61)

• Carpet Products, www.terrachoice.com/flooring_product_ profile.pdf

• Calculating GHG emissions from office-based organizations, www.ghgprotocol.org/standard/tools.htm

• Climate Care, www.climatecare.org/Calculator/index.cfm64 Part III Chapter 10 Chapter 1 2 • Bonneville Foundation, www.greentagsusa.org/ GreenTags/calculator_intro.cfm

• EPA, Web Site Guide to Global Climate Change, www. epa.gov/region01/eco/cchange/webgd.pdf The Registry will review optionally reported information of participants. It reserves the right to ask for appropriate modifications or removal of specific optionally reported information, if it deems such changes are necessary.65 

# Part IV Completing and Submitting Your Report

Now that you have established your reporting parameters in Part II and quantified your emissions in Part III, you are ready to complete your annual GHG emission report, certify your emissions, and submit your inventory to the Registry. Chapter 13, Reporting Your Emissions, describes the steps you need to follow to report your emissions using CARROT, the Registry’s online reporting tool, as well as the steps for formally registering your emission report with the Registry once you have received certification from a certifier. Chapter 14, Certification, explains the certification process. This chapter begins with an overview of the importance of certification, requirements for meeting certification standards, the process for identifying and working with certifiers, documentation and other items you will need to prepare for certification, the reports you and the Registry will receive at the conclusion of the process, and the process for correcting your emission report, if necessary.66 Part IV Chapter 1 3 

# Chapter 13 Reporting Your Emissions

Now that you have established your reporting parameters in Part II and quantified your emissions in Part III, you are ready to report your emissions to the Registry using the Registry’s online reporting tool, CARROT.



## IV.13.1 Submitting Your Report Using CARROT You must report your organization’s annual GHG emission report via the Registry’s web-based reporting application and database, known as the Climate Action Registry Reporting Online Tool (CARROT).

CARROT has four main functions:

1. Helps Registry participants calculate their annual GHG emissions and/or report these emissions to the Registry;

2. Allows approved certifiers to review participants’ annual GHG emission reports and submit their certification information to the Registry;

3. Permits the general public to view aggregated reports of participants’ annual GHG emissions and their progress in managing these emissions;

4. Enables Registry staff to efficiently manage and track participants’ data. CARROT provides you with a secure, on-line workspace to manage, report, certify, and register your emissions. The Registry has designed CARROT to facilitate and ease emissions reporting. CARROT is also designed to streamline the emissions registration process by providing emissions calculations tools, simple reporting features, and administrative controls that allow participants to delegate reporting within your organization. When you join the Registry, your organization’s technical contact will be provided a UserID and Password that will allow you to access CARROT through the Registry’s website, www.climateregistry.org/CARROT. Other users within your organization can request access from your organization’s technical contact.



## IV.13.2 CARROT Guidance and Technical Assistance If you have questions about using CARROT, the Registry provides reporting assistance and support through the following tools:

• “CARROT Getting Started Guide”, available online in PDF format;

• CARROT on-line help, and on-line documentation;

• Email user support, help@climateregistry.org; and

• Phone user support (213-891-1444). Prospective participants and other interested parties can see how CARROT works by viewing a short demonstration of the tool, accessible on the Registry’s website ( www.climateregistry.org/CARROT/Demo ). Participants can also familiarize themselves with CARROT by using the CARROT Training Site. Access to the training site may be requested by sending an email to help@ climateregistry.org.



## IV.13.3 Accessing Your Certified Emissions Data CARROT provides a variety of tools to help you manage and use your emissions data, and will be regularly updated to reflect current emissions reporting policies. The following are some of the features that will assist you in managing your reported GHG emissions information.


### Participant’s Administrative Module CARROT allows you to manage separate emissions submissions, as needed, from within your organization, depending on how many individuals are responsible for reporting a subset of your total GHG emission report. This is done by creating different types of users within CARROT. Administrators are responsible to manage each entity’s 

### Who should read Chapter 13: Chapter 13 applies to all participants. 

### What you will find in Chapter 13: This chapter provides guidance on submitting your emission report to and accessing your report from the Registry. 

### Information you will need: In order to submit your GHG emission report, you will need a password from the Registry, as well as all the relevant information required in your report. 

### Cross-References: It may be useful to review the requirements in Section IV.14 on Certification.67 Part IV Chapter 1 3 annual emission report, creating other users to help them input or review data, and submitting an entity’s report for certification and finally to the Registry. They have full read/write access to data for all reported years. Users are assigned to one or more facilities, and can enter information for specific locations for specific years, and submit it to the Administrator for review. For example, if your organization owns and operates five different facilities, the Administrator can grant permission to five different facility managers to enter the GHG emissions information from their respective facilities. The Administrator will be able to visually assess the status of each of the five facilities by viewing a CARROT work flow report, and will be the only party with the permission to submit and classify the entity emission report as “Certification Ready.”


### Participant Database Query and Reporting Once you have entered your emissions data, CARROT helps you generate detailed and summary reports of your information. This information can be produced in spreadsheet software. Examples of CARROT reports include: Reports for Participants

• Total Reported Emissions – Entity

• Total Reported Emissions – by Facility (if applicable)

• Facility Administrative Summary (if applicable) Reports for the Public In addition to collecting your GHG emissions data, CARROT will also make limited information about your GHG emission report and overall Registry participation available to the public. The public will see the following information that you are required to report:

• Company name, address, and contact

• Reporting year

• Total emissions, by gas and by category (stationary combustion, mobile combustion, process emissions, fugitive emissions and indirect emissions)

• Baseline year In addition, the public will see the following information that you may choose to report. This optional information is not certified.

• Reduction goals, projects, management programs

• Entity description

• Other optional information 

### Archive Feature CARROT maintains annual versions of your GHG emission report submissions. Also, CARROT will keep copies of any revisions with your comments, to enable you to correct your submissions, and for Registry-approved Certifiers to certify your data. You can revise your report at any time; however, once it has been submitted for certification, any subsequent changes will need to be re-certified.



## IV.13.4 Movement Reports For your second year of reporting to the Registry and for every subsequent year of emissions data collection, CARROT will ask you to prepare a “Movement Report”, in which you identify the major factors that have affected your emissions. This should include:

• A list of structural changes (mergers, acquisitions, divestitures, outsourcing);

• A discussion of how your organization’s business cycle is affecting your emissions; and

• A list of any emission reduction projects undertaken by your organization. Table IV.13.1 provides a sample Movement Report For each category, CARROT will ask you to provide an explanation of each change to emissions, as well as an estimate of the impact on your total emissions. Thus, for an acquisition, you would indicate the name, location and size of the acquisition, and the estimated associated emissions per year (tons CO 2 e/year). One purpose of this Movement Report is to facilitate certification. Certifiers will reference this Movement Report to understand changes in your emissions data from year to year; however, this information will not be certified for accuracy nor provided to the public.68 Part IV Chapter 1 3 In addition, you may publish your certified emissions data in order to demonstrate your organization’s commitment to environmental goals and to addressing climate change, and to disseminate transparent information about the specific steps your organization has taken to achieve reductions in GHG emissions. 

### Factor Affecting Performance Details

Structural Change: Acquisition Divestiture Insourced Activities Outsourced Activities Leakage Name Location Business Unit Affected Change due to Registry participation Estimated impact on emissions Organic Growth or Decline: New Construction Plant Closing Decrease in Production Increase in Production Business Cycle Fluctuation Name Location Business Unit Affected Estimated Impacts on Production Estimated impact on emissions

Emission Reduction Activities: Purchased Offsets Avoided Emissions Sequestration Project Name Location Estimated impact on emissions

Other 

### Table IV.13.1: Sample Movement Report



## IV.13.5 Utilizing Your Certified Emissions Data While the Registry cannot predict the full range of ways you can utilize your certified emissions data, there are some important uses that are worth considering. For example, once you have started entering your information in the Registry’s CARROT reporting system, you will be able to maintain and track your organization’s progress in meeting internal GHG reduction targets with every annual GHG emission report. As mentioned earlier, under a possible future regulatory regime, your certified emissions data could provide the basis for any determination of protections or other regulatory rewards for taking early steps to reduce your GHG emissions. Future regulations by the State of California or the Federal government might reward those organizations taking significant steps to reduce GHG emissions. Similarly, your GHG emissions data might be applicable for participating in voluntary GHG emissions reduction programs, both in the United States and abroad, or ISO 14064 1 for GHG emission reduction practices. 1 The ISO 14064 standards for greenhouse gas accounting and verification published in March 2006 by ISO (International Organization for Standardization) provide government and industry with an integrated set of tools for programs aimed at reducing greenhouse gas emissions, as well as for emissions trading. www.iso.org69 Part IV Chapter 1 4 This chapter provides context for the principles underlying certification, explains the certification standards, and overviews the entire certification process. This General Reporting Protocol is designed to direct the complete, transparent, and accurate reporting of your organization’s GHG emissions. Certifying your emission report is the final step in the reporting process. Certification is the process used to ensure that a participant’s GHG emission report has met a minimum quality standard and complied with an appropriate set of Registry-approved procedures and protocols for submitting emissions inventory information. For most Registry participants, meeting the requirements of the General Reporting Protocol should be sufficient to complete certification. Where a participant is eligible for an industry-specific protocol, they will need to meet those requirements to achieve certification. Participants with relatively small and simple emissions (<500 tons CO 2 e per year) may be eligible for batch certification - see Section IV.14.14 for more information on eligibility. The Registry’s certification process has been designed to promote the credibility, accuracy, transparency, and usefulness of emissions data reported to the Registry. Once 

# Chapter 14 Certification

an approved certifier has determined that the emission report meets a minimum quality standard and is free of material discrepancies, the participant’s reported emissions data will be reviewed by the Registry and accepted into the Registry’s database. If you are interested in understanding and preparing for the certification process in more detail, and to see the specific process approved certifiers will be using to certify your GHG emission report, you may obtain a copy of the Certification Protocol, the Registry’s guidance for approved certifiers, from the Registry’s website.



## IV.14.1 GHG Reporting Principles
and Certification The purpose of certification is to provide an independent review of data and information submitted to the Registry, which ensures the credibility of the GHG inventories. To accomplish this objective, the independent certification process maintains the criteria of comparability, completeness, consistency, transparency, and accuracy as its underlying principles. These accounting and reporting principles are described in Section I.4.



## IV.14.2 Certification Standard At a minimum, each annual GHG emission report (emission report) must contain all of an entity’s significant emissions of CO 2 in the state of California for a calendar year, reported in five categories: 1) indirect emissions from purchased electricity, imports of steam, district heating/ cooling, and direct emissions from 2) mobile combustion, 3) stationary combustion, 4)process emissions, and 5) fugitive emissions. Where a participant is reporting its U.S. emissions, the report must contain all their significant emissions nationally. Starting with the fourth year of reporting, each emission report must contain all significant emissions of all six greenhouse gases (CO 2 , CH 4 , N 2 O, HFCs, PFCs, SF 6 ). If a participant is reporting process or fugitive emissions, a separate industry specific protocol may also be used and cited. Emission reports may also contain other information about an organization and its emissions that does not require certification. Your certifier will not consider this information when developing an opinion regarding your certifiable annual GHG emissions inventory results. Additional guidance on reporting optional information is provided in Chapter 12. 

### Who should read Chapter 14: Chapter 14 applies to all participants. 

### What you will find in Chapter 14: This chapter provides guidance on the process for certifying your GHG emission report, including how to obtain certification services from an approved certifier, and what you will need to prepare for certification. 

### Information you will need: Chapter 14 will guide you through the steps involved in determining what information you will need for certification. Table IV.14.1 in this chapter provides a list of specific documentation that will be needed for certification. 

### Cross-References: All other chapters in the General Reporting Protocol may be considered during the certification process. In addition, you should review the Certification Protocol, to be used by approved certifiers, in preparing for certification.7 0 Part IV Chapter 1 4 

## IV.14.3 Minimum Quality Standard An Emission Report submitted to the Registry must be free of material discrepancies to be certified. In other words, a certifier’s calculation estimates of the entire inventory must not differ from a participant’s estimates of the entire inventory by more than 5%. It is possible that during the certification process differences will arise between the emissions totals estimated by participants and those estimated by certifiers. Differences of this nature may be classified as either material or immaterial discrepancies. A discrepancy is considered to be material if the overall reported emissions differ from the overall emissions estimated by the certifier by 5% or more. Otherwise it is immaterial.



## IV.14.4 The Certification Process The certification process outlined in the Certification Protocol is designed to be applied consistently across all participants. However, based on the size and complexity of participants’ operations and management systems, certification activities and the duration of the process will vary. At a minimum the certification process will include the following steps:

• Conducting an evaluation of Conflict of Interest by the Registry

• Provide notification of certification activities to the State

• Scoping and planning a participant’s certification activities

• Conducting certification activities

· Identifying emissions sources

· Reviewing methodologies and management systems

· Verifying emission estimates

• Preparing a participant’s Certification Report and Certification Opinion

• Submitting a Certification Opinion and Certification Activities Log to the Participant Upon the completion of the above steps, the Registry will accept a participant’s certified data into its emissions database. A step-by-step description of the certification process is described in section IV.14.9.



### Core Certification Activities The certification process is designed to ensure that there have been no material discrepancies of your reported entity-wide inventory. In order to ensure consistency in the application of certification, the Registry provides all certifiers with a Certification Protocol that is based on theguidance contained in this Protocol and any industryspecific protocol. The Certification Protocol is a guidance document. However, since certifiers face potential financial liability for reports they have certified, it is ultimately at the certifier’s discretion whether to certify your report. Once the certifier has completed the preparations for certification including the kick-off meeting and the selection of a general approach to certification, the core certification activities can begin. The core certification activities include three primary elements:

1. Identifying emissions sources;

2. Understanding management systems and estimation methods used;

3. Verifying emission estimates. The core certification activities are fundamentally a risk assessment and data sampling effort aimed at ensuring hat no significant sources are excluded and that the risk of error is assessed and addressed through appropriate sampling and review. The complete core certification process is illustrated in Figure IV.14.1.



### Figure IV.14.1 Core Certification Process

Ve rifying Emission Estimates Identifying Emission Sources

Risk Analysis & Uncertainty Assessment Reviewing Methodologies &

Management

Systems7 1 Part IV Chapter 1 4 

## IV.14.5 Professional Judgment Approved Certifiers must certify participants’ annual GHG emission reports against the Registry’s General Reporting Protocol using the process outlined in the Certification Protocol. The Registry asks certifiers to use their professional judgment when executing the certification activities described in this Certification Protocol. The purpose of the certifier approval process is to find certification firms that demonstrate, through their staff’s professional qualifications and experience, their ability to render sound professional judgments about GHG emission reports. Application of a certifier’s professional judgment is expected in the following areas:

• Implementation of certification activities with appropriate rigor for the size and complexity of a participant’s organization and with regard to the uncertainty of calculations associated with the participant’s emissions sources;

• Review of the appropriateness of a participant’s GHG emissions tracking and monitoring procedures, calculation methodologies, and management systems for providing information to the California Climate Action Registry;

• Evaluation of participant compliance with the Registry’s General Reporting Protocol;

• Assessment of methods used for estimating emissions from sources for which the General Reporting Protocol does not provide specific guidance, such as process and fugitive emissions, and indirect emissions from sources other than electricity, imported steam, district heating/cooling; and

• Appraisal of assumptions, and estimation methods and emission factors that are selected as alternatives to those provided in the General Reporting Protocol. The Certification Protocol and training provided by the Registry are intended to explain to the certifier the Registry’s guidelines and expectations and thus what types of professional judgments are appropriate for this program. In addition to these resources, certifiers and participants may contact the Registry at any time for clarification of Registry guidelines, expectations and policies.



## IV.14.6 Conflict of Interest In order to ensure the credibility of the emissions data reported to the Registry and its applicability under any future regulatory regime, it is critical that the certification process is completely independent from the influence of the participant submitting the emission report. While conducting certification activities for Registry participants, certifiers must work in a credible, independent, nondiscriminatory and transparent manner, complying with applicable state and federal law and the Registry’s Conflict of Interest determination process. In their applications to become approved, certifiers must provide information to the Registry about their organizational relationships and internal structures for identifying potential conflicts of interest (organizational COI). Then, on an individual basis, the Registry will review any pre-existing relationship between a certifier and participant and will assess the potential for conflict of interest (case-by-case COI) in conducting a certification. When the Registry determines there is a low risk of COI, the participant and certifier can finalize negotiations of their contract. Following completion of a certification, the certifier must monitor their business relationships for the next year for situations that may create a COI (emerging COI). As an added protection, a certifier may provide certification services to a Registry participant for, at most, six consecutive years. After a six-year period, the Registry participant must engage a different certifier. The original certifier may not provide certification services to that participant for three years. This three year hiatus begins with any lapse in providing annual certification services to a Registry participant. This conflict of interest clause does not preclude a certifier from engaging in consulting services for other clients that participate in the Registry for whom the certifier does not provide any certification activities.
In the event that a certifier violates these conditions, the Registry, in consultation with the CEC, and at its discretion, may disqualify an approved certifier for a period of up to five years.



## IV.14.7 Reporting and Certification
Deadlines You must submit your uncertified GHG emission report by August 31 of the year following the emissions year to the Registry to initiate certification activities. Certification should be completed by December 31 of the year the report is submitted to the Registry. In other words, an uncertified GHG emission report for 2006 emissions should be submitted by August 31, 2007, and the certification process should be completed by December 31, 2007. Participants who anticipate that certification could take more than four months to complete will need to report their emissions in advance of August 31. Participants who are not able to meet these deadlines must72 Part IV Chapter 1 4 request a reporting or certification extension from the Registry.



## IV.14.8 State Role in Certification The Registry’s enabling legislation directs two state agencies, the Resources Agency and the Environmental Protection Agency, to provide technical guidance to the Registry, including developing certification procedures. The State of California is required to identify and qualify third-party organizations to act as certifiers and technical assistance providers, and oversee certification activities. This includes randomly accompanying certifiers on site visits to evaluate the participant’s GHG reporting program and the reasonableness of the participant’s reported data. The State works through the California Energy Commission, the California Air Resources Board and the California Department of Forestry and Fire Protection to conduct this oversight.



## IV.14.9 Key Certification Steps Certification consists of a number of procedural steps that must be taken to ensure that the obligations and responsibilities of both the certifier and participant are clear, as well as certification activities that ascertain the accuracy and completeness of an emissions report. The following summary of the major steps of the certification process is provided as a reference.
1.	 Certifier Receives State and Registry approval: The certifier, in response to a state-issued Request for Applications, must be approved by the State. Next, the certifier attends a Registry-sponsored certification training workshop, and is approved by the Registry. 2.	 Participant Selects Certifier: The participant may contact one or more State/Registry-approved certifiers to discuss certification activities. The participant selects a company to certify its GHG emissions results and begins to negotiate contract terms.
3.	 Certifier Submits Case-Specific Evaluation of Conflict of Interest (COI) Form: After a participant chooses a certifier, the certifier must submit a Conflict of Interest Evaluation Form to the Registry to establish that the likelihood of a COI between parties is low or that risk of any conflict can be sufficiently mitigated by the certifier. 4.	 Registry Sends COI Determination to Certifier: The Registry reviews the Evaluation of COI Form and supporting information to determine the level of risk associated with the proposed participant/ certifier relationship, and notifies the certifier of its determination.
5.	 Certifier & Participant Finalize Contract: When the Registry provides a favorable COI determination between a participant and a certifier, certifiers may finalize their contract with a Registry participant.
6.	 Certifier Submits Certification Notification Form to State: After the participant has completed its analysis of its GHG emissions and submits its uncertified report to the Registry, the certifier is ready to begin work. At this point, the certifier must complete and submit a Certification Notification Form to the State at least 10 business days prior to beginning certification activities.
7.	 Certifier Conducts Certification Activities: The certifier follows the guidance in the Certification Protocol to evaluate a participant’s annual GHG emission report.
8.	 Certifier Prepares Certification Report and Certification Opinion for Participant: The certifier prepares a detailed summary (Certification Report) of the certification activities for the participant. The certifier also prepares a Certification Opinion for the participant’s review, and a Certification Activities Log.
9.	 Certifier & Participant Discuss Certification Report and Opinion: The certifier meets with the participant to discuss Certification Report and Opinion.
10.	Certifier Completes Certification Form via CARROT: Once authorized by a participant, the certifier completes the Certification Form via CARROT. 11.	Participant Forwards Documentation to the Registry: The participant mails the original Certification Opinion and Certification Activities Log to the Registry. 12.	Registry Completes Reporting Process: The Registry reviews the Certification Opinion and Certification Activities Log and evaluates the participant’s emission report. Once accepted by the Registry, a participant’s aggregated entity-level emissions become available to the public via CARROT.



## IV.14.10 Preparing for
Certification The pre-certification process involves several steps, including:

• Identifying approved certifiers on the Registry’s website;

• Executing a competitive bid process or awarding a sole 

### Reporting Deadline: August 31

Certification Deadline: December 3173 Part IV Chapter 1 4 source contract for certification services, or, if you are eligible, participating in “batch certification” through the Registry;

• Negotiating your contract with your selected certifier; and

• Assembling relevant materials needed by the certifier to certify your emissions data.

Use of Registry-Approved Certifiers. You must choose your certifier from the list of approved certifiersmaintained by the Registry. Information about Registryapproved certifiers is provided on the Registry website at www.climateregistry.org/serviceproviders.


### Request for Bids for Certification Services Options for Soliciting Bids. The Registry recommends that those participants with complex GHG emission reports solicit competitive bids for certification services from at least three Registry-approved certifiers. If your organization has prepared a simpler GHG emission report and does not seek, or is not eligible for, “batch certification,” you may wish to either secure competitive bids or to sole-source the certification contract in order to reduce costs and expedite the certification process.

Non-Disclosure Agreements. When preparing to send out a request for bids from certifiers, you should review the list of approved certifiers and select some or all as prospective bidders. The Registry recommends that you send the contact person from each prospective bidder a non-disclosure agreement prior to requesting bids or releasing potentially proprietary information.

The Request for Bids. In order to obtain the most competitive bids and ensure that you will receive the most effective certification services, your request for bids should include as much detailed information about your organization and its emission report as possible. The Registry recommends that participants include the following information in their requests for bids from certifiers:

1. The expected contract duration;

2. A general description of the participant’s organization;

3. The geographic boundaries of the participant’s report;

4. The number and locations of facilities and operations;

5. The GHGs reported in the participant’s emission report;

6. The emission source categories (and possibly emission sources) in the participant’s report; and

7. A copy of the participant’s emission report from CARROT. You should request bids and negotiate terms and conditions for a complete certification, including:

• A review of your management systems (required in year one and recommended at least every third year thereafter);

• A review of your underlying activity data;

• Confirmation of emissions estimates:

• A final Certification Report;

• A Certification Opinion submitted to the Registry. The Registry suggests that participants request Commercial and Technical Proposals from potential certifiers that include the following components:

Commercial Proposal

1. History and Description of Company

2. Explanation of Core Competencies

3. Proposed Price for Certification Services

4. Proposed Staff

5. Statement of Certifier Liability

6. Confidentiality Policy

7. Duration of Contract
Technical Proposal

1. Approach to Preparing for Certification

2. Approach for Completing Core Certification Activities

3. Approach for Completing the Certification Process


### Negotiating a Contract with the Certifier After you have selected from the approved certifiers from which you receive bids, you should negotiate complete contract terms. This contract must be for direct services between the participant and an approved certifier; a certifier cannot sub-contract for certification services. However, contracts for certification services typically include the following components: Scope of the Certification Process. This component of the contract will outline the exact geographic and organizational boundaries of the participant’s emissions inventory to be examined. This should, but may not necessarily, match the boundaries used in the GHG emission report to the Registry. This scope will indicate whether California-only emissions are included or if both California and U.S. emissions are included. It will also include whether the participant has used the management control, equity share, or other method based on contractual relationships to determine organizational boundaries.

Confirmation of Approved Certifier Status. This is a simple statement that the certifier has been approved by both the State and the Registry to certify emission reports74 Part IV Chapter 1 4 covering the scope listed above.

Certification Standard. Approved certifiers must certify participants’ GHG emission reports against the Registry’s General Reporting Protocol using the process outlined in this Certification Protocol. However, if a participant is reporting process or fugitive emissions, a separate industry specific protocol may also be used and cited. Some participants may wish to use their GHG emission report for additional purposes such as, registering in another registry, participating in an emissions trading scheme or crediting program, etc., and thus may add additional standards for certification.

Non-disclosure Terms. The certifier and the participant should agree in advance on methods for identifying and protecting proprietary and business confidential data that may be revealed during certification.

Site Access. The certifier and the participant should agree in advance to the time, place, and conditions of certifier’s site visits, if any are required.

Documentation and Data Requirements. The certifier and participant should agree on how and when the participant will provide emissions data to the certifier. The range of required documentation will largely be determined by the size and complexity of participant operations, and whether the participant has used the online calculation tools available through CARROT.

Period of Performance. The period of performance for certification services will typically be for three years, given that the certification process required by the Registry is more streamlined in Year 2 and Year 3, if participant operations do not change. However, there may be instances where contracts are negotiated for a single year, pending renewal.

Performance Schedule. Participants and certifiers may wish to agree on a schedule to complete the certification process and for the certifier to deliver a Certification Report and Certifier’s Opinion. Certification should be initiated in time to meet the December 31 emissions registration deadline, and should be completed within one calendar year of when the emission report was submitted. Payment Terms. Typical payment terms include total value, schedule of payments, and method of payment (e.g., electronic funds transfer).

Re-certification Terms. If the certifier identifies material discrepancies, the participant may choose to revise its GHG emission report. At that time, the participant may ask the certifier to re-certify the report or seek certification from another provider. The certifier may not provide guidance, technical assistance, or implementation work on the remediation of material misstatements, as this would be viewed as consulting services and result in a conflict of interest. Liability. All certifiers are subject to the minimum liability associated with completing the certification per the terms of the certification contract. The participant may require and the certifier may agree to additional liability under this contract.

Contacts. The contract should identify technical leads for the participant and certifier, as well as responsible corporate officials of each party.


### Certifier Requirement to Notify State of Certification After you have completed and submitted your uncertified emission report and at least two weeks (10 business days) prior to beginning of certification activities, the certifier is required to notify the State of any and all planned certification activities. This notification period is necessary to allow the State the opportunity to occasionally accompany certifiers on visits to participants’ sites. The State is required to observe, evaluate, and report on the quality and consistency of certification activities. A certifier that does not provide proper notification to the Registry and the State may be disqualified as an approved certifier.


### Kick-off Meeting After the certifier has notified the Registry and the State of planned certification activities, certifiers should host a kick-off meeting with participants. Meetings can be conducted in person or by telephone. The agenda for that meeting should include:

1. Introduction of the certification team;

2. Review and confirmation of certification process and scope;
3. Transfer of background information and underlying activity data (See Table 13-1); and

4. Review and confirmation of the certification process schedule; Based on the information provided in agenda items 2 and 3, the certifier should determine the most effective, efficient, and credible detailed certification approach tailored to the particular characteristics of the participant.



## IV.14.11 The Certification Cycle While certification is required annually, in some instances it can be thought of as a three-year process. In Year 1, a certifier will need to form a detailed understanding of a participant’s operations and consequential GHG emissions. Assuming that there have been no significant75 Part IV Chapter 1 4 changes in the geographic and organizational boundaries of a participant’s operations, a certifier is likely to have identified all emission sources and gained a sufficient understanding of the participant’s GHG emissions management systems in Year 1 to streamline and expedite the certification activities to focus on verifying emissions estimates in Year 2 and Year 3. To ensure data integrity, all of the core certification activities should be completed in Year 4. Thus, the core certification activities each year will likely be as follows:
Year 1: Identify Emission Sources, Review Management Systems, Verify Emissions Estimates
Year 2: Verify Emissions Estimates
Year 3: Verify Emissions Estimates
Year 4:	 Same as Year 1 The Registry assumes that certifiers will use their best professional judgment when conducting certification activities, and thus, will modify the suggested annual process described above as necessary. Each certifier is also required to complete a number of steps in their review, and to evaluate every participant against a number of criteria. These steps and criteria are listed in the Certification Activities Log, provided in the Certification Protocol. When you have specified a baseline, each year your certifier will need to identify changes to your direct emissions, review the cause of the changes, and assess if you have reached the baseline change threshold of 10%, and if you have adjusted your baseline appropriately.



## IV.14.12 Online Reporting If a participant chooses to use the Registry’s on-line calculation tool (CARROT) and the certifier’s document review suggests that data have been collected properly and entered accurately, the certifier will not need to re-calculate the emissions, as the calculations will be automatic. Due to the time savings, this should result in a less expensive and expedited certification process.



## IV.14.13 Documentation for Review The documents that will need to be reviewed during certification will also vary depending on the nature of the emission sources contained in your GHG emission report to the Registry. Table IV.14.1 on the following page, provides a list of recommended documents to have ready to provide a certifier for conducting the certification process.76 Part IV Chapter 1 4 

### Activity or Emissions Source Documents Identifying Emission Sources

Emission Source Inventory Facility inventory
Emission source inventory Stationary source inventory Mobile source inventory Fuel inventory

Understanding Management Systems and Methodologies Responsibilities for Implementing GHG Management Plan Organization chart, greenhouse gas management plan, documentation and retention plan Training Training manual, procedures manual, consultant quals statement Methodologies Protocols used (if in addition to the Registry’s General Reporting Protocol) Verifying Emission Estimates

Indirect Emissions from Electricity Use Monthly electric utility bills, emission factors (if not default)

Direct Emissions from Mobile Combustion Fuel purchase records, fuel in stock, vehicle miles traveled, inventory of vehicles, emission factors (if not default)

Direct Emissions from Stationary Combustion Monthly utility bills, fuel purchase records, CEMs data, inventory of stationary combustion facilities, emission factors (if not default)

Indirect Emissions from Cogeneration Monthly utility bills, fuel and efficiency data from supplier, emission factors (if not default)

Indirect Emissions from Imported Steam Monthly utility bills, fuel and efficiency data from supplier, emission factors (if not default)

Indirect Emissions from District Cooling Monthly utility bills, fuel and efficiency data from supplier, emission factors (if not default)

Direct Emissions from Manufacturing Processes Raw material inputs, production output, calculation methodology, emission factors Refrigeration Systems Refrigerant purchase records, refrigerant sales records, calculation methodology, emission factors

Landfills Waste in place data, waste landfilled, calculation methodology, emission factors

Coal Mines Coal production data submitted to EIA, quarterly MSHA reports, calculation methodology, emission factors

Natural Gas Pipelines Gas throughput data, calculation methodology, emission factors

Electric Transmission and Distribution Sulfur Hexafluoride purchase records, calculation methodology, emission factors 

### Table IV.14.1: Documents to be Reviewed During Certification Activities77 Part IV Chapter 1 4 

## IV.14.14 Batch Certification

In an effort to minimize the transaction costs of certification for small organizations with relatively simple emissions, the Registry will contract with an approved certifier to undertake the certification work for interested participants with limited GHG emissions. The Registry calls this Batch Certification. Emissions reports certified under Batch Certification must meet the same standards as non-batch reports. Eligible participants include those with:

• less than 500 metric tons of CO 2 e emissions per year,

• no significant process or fugitive emissions;

• indirect emissions from purchased electricity at four or fewer sites; and/or

• direct emissions from five or fewer passenger vehicles only; and/or

• direct emissions from stationary combustion at one site. Upon the recommendation of the Batch Certifier, the Registry reserves the right to deem a participant’s GHG emissions inventory too complex for batch certification. The Registry also reserves the right to grant batch eligibility on a case by-case basis.



### Batch Certification Process Overview The following is a summary of the steps of the batch certification process. Participants interested in batch certification will notify the Registry. After confirming the participant’s eligibility, the Registry will keep track of interested participants until a sufficient number have reported their emissions in CARROT and submitted the data for certification. Each year, the Registry will solicit competitive bids for batch certification services from at least three approved certifiers. On behalf of batch participants, the Registry will select one certifier to perform all eligible certifications for that calendar year of emissions.

1. Batch Certifier & Batch Participants Sign Contracts : Each participant signs a standardized contract with the certifier. Any participant requiring non-standard contract language cannot participate in batch certification.

2. Batch Certifier Receives Documentation: After the entities participating in batch certification have completed their reports, the Registry will collect the necessary supporting documentation from the participants and forward it to the certifier. Batch certification will not require a site visit, but will consist of document review and telephone interviews.

3. Certifier Conducts Certification Activities: The certifier will follow the guidance in the Certification Protocol to evaluate a participant’s GHG emission report. The certifier will contact each participant to understand their operations.

4. Certifier Provides Batch Certification Report, Opinion and Activities Log to Participant: The certifier prepares and discusses a summary (Certification Report) of the certification activities with the participant. The certifier also provides original copies of the Batch Certification Opinion and Checklist to the participant. Once authorized by a participant, the certifier completes the Certification Form via CARROT. The participant notifies the Registry once the certifier has submitted its Certification Form in CARROT, and forwards original copies of the Certification Opinion and Batch Certification Activities Log to the Registry. The Registry will review the Certification Opinion and Batch Certification Activities Log and evaluate the participant’s emission report. Once accepted by the Registry, a participant’s aggregated entity-level emissions become available to the public via CARROT.



## IV.14.15 Certification Report and
Opinion The certifier will prepare a detailed Certification Report for each Emissions Report. The Certification Report is a confidential document that is shared between a certifier and a participant—it is not available to the Registry or the public unless a participant chooses to share it.


### Certification Report The Certification Report should include the following elements:

• The scope of the certification process undertaken;

• The standard used to certify emissions (this is the Registry’s General Reporting Protocol, but may also include other protocols or methodologies for those sources for which the Registry has yet to provide detailed guidance);

• A description of the certification activities, based on the size and complexity of the participant’s operations;

• A list of emissions sources identified;

• A description of the sampling techniques and risk assessment methodologies employed for each source;

• An evaluation of the participant’s emission report compliance with the Registry’s General Reporting Protocol;

• A comparison of the participant’s overall emission estimates with the certifier’s overall emission estimates;78 Part IV Chapter 1 4 • A list of material discrepancies, if any;

• A list of immaterial discrepancies, if any; and

• A general conclusion to be reflected in the Certification Opinion forwarded to the Registry. A participating organization should be provided up to 30 days to review and comment on the certification report. At the end of that review, the certifier and the participating organization should hold a meeting to discuss the nature of any material or immaterial discrepancies.


### Certification Opinion The Certification Opinion is a simple confirmation of the certification activities and outcomes for all stakeholders (participants, certifiers, the Registry, and the public). The Certification Opinion must also follow the same internal review process as the Certification Report, and consequently must be reviewed and signed by the certification firm and the participating organization.


### Exit Meeting Certifiers should prepare a brief summary presentation of their certification findings for the participant’s key personnel. At the exit meeting certifiers and participants might exchange lessons learned about the certification process and share thoughts for improving the certification process in the future. Certifiers and participants may wish to consider joint feedback to the Registry. The goals of this meeting should be: • Acceptance of the Certification Report and Opinion (unless material discrepancies exist and can be remediated, in which case the certification contract may need to be revised, and a recertification scheduled). If the participant does not wish to retain the certifier for the re-certification process, the certifier shall turn over all relevant documentation to the participant within 30 days. • Authorization for the certifier to complete the certification form in the CARROT.



## IV.14.16 Submitting a Certified Emission Report to the
Registry Once a participant authorizes the Certification Opinion, the certifier must complete the electronic certification form in the CARROT and send the original Certification Opinion to the participant. The participant must forward original copies of the Certification Opinion and the Certification Activities Log to the Registry. Once the electronic certification form is completed and the Registry receives a hardcopy of the Certification Opinion, the participant’s report will be formally accepted into the Registry database, and the annual certification process will be completed. Participants are not required to submit their Certification Opinions to the Registry for the first two years of their participation. However, a participant’s emissions data will not be considered accepted by the Registry unless the Registry receives a Certification Opinion indicating a “certified without qualification” assessment.



## IV.14.17 Record Keeping and
Retention You should maintain any relevant records from which emissions results have been calculated. Such records may include, but not be limited to, utility bills, fuel consumption records, emissions data, process data and schedules, and past reports. Although it is not possible to predict what any future regulatory regime may require regarding record keeping and retention, it is inadvisable for you to dispose of relevant records immediately after filing emission reports. This would hinder any future certification or review activities, placing you at a disadvantage in case of some need to re-estimate the emissions results. In addition, your baseline inventory data is the key to determining temporal trends in GHG emissions



## IV.14.18 Correcting or Revising your GHG Emissions Report After you have submitted your certified GHG emission report to the Registry, you will still be able to make corrections if you have determined an error in your report, have identified new emissions sources, or would like to utilize more thorough calculation methodologies to estimate your emissions. You should note that the Registry’s reporting system is designed to retain all original reports and records it receives as archives, even after a GHG emission report has been corrected or updated. Should you update your GHG emission report, theupdated portion will need to be certified by a Registryapproved certifier, following the process described in this chapter. Note that if the specific changes you have made to your report influence or affect the estimations of other elements of your report, you will again need to have the certifier review and certify all relevant sections of your GHG Emission Report. Where your overall corrections result in an insignificant change in emissions from your previous GHG Emission Report, certification should require only verifying your emissions estimates. Once a79 Part IV Chapter 1 4 revision is initiated in CARROT, the information is not publicly available until all additions to the report are certified.



## IV.14.19 Dispute Resolution There may be instances where a certifier and a participant cannot agree on identification of material discrepancies and/or the findings of the Certification Opinion. In such instances, both parties can request the Dispute Resolution Committee, composed of qualified representatives from the CEC, the Registry, the California Air Resources Board (CARB) and one non-voting certifier, who serves pro bono on an annual, rotating basis. Members of the Registry’s Technical Advisory Committee may also be consulted for additional technical assistance. The participant and the certifier will each pay a filing fee equal to 5% of the participant’s annual Registry membership fee to submit the matter to the Dispute Resolution Committee. The Dispute Resolution Committee will interview the participant and the certifier, review the area of dispute and reach a unanimous, binding decision concerning certifiability. The Registry will notify the certifier and Registry participant of the Committee’s decision. Thus, as part of contract negotiations, each Registry participant and certifier will need to sign a form agreeing to this Dispute Resolution policy.



## IV.14.20 Key Certification Questions

Certification Deadlines: What is the deadline for completing the certification process? Emissions should be reported to the Registry no later than August 31 following the emissions year. Certification should be completed by December 31 following the emissions year. For instance, 2006 emissions should be reported by August 31, 2007 and certified by December 31, 2007.



### Costs: What will it cost to have my GHG Emission Reports certified? Because certifiers will review GHG emission reports with more scrutiny every fourth year (barring significant changes to your geographic or organizational boundaries), costs associated with certification are likely to be higher in the first year than in years two or three of the reporting process. In order to obtain an estimate for certification, you will need to convey information about your: industrial sector, organization size (annual revenue and number of employees), number of facilities, estimated number and type of direct emissions sources, types of indirect emission sources (e.g., electricity from a utility, or electricity or heat from co-generation), the types of gases you are reporting, and the methodologies you are using to estimate and report your emissions (e.g., CARROT). You may contact the Registry for information about the costs associated with certifying your GHG emission report. In addition, you may contact Registry-approved certifiers listed on the Registry’s website at www. climateregistry.org for information about the estimated costs associated with certification.



### Batch Certification: What is it? How does it work? How will it affect bidding, contracting, and the overall certification process? In an effort to minimize transaction costs, eligible Registry participants may request to participate in “batch certification” with similar organizations through the Registry. Eligible participants have relatively simple GHG emission sources and no more than 500 tons of CO 2 e from only indirect emissions from electricity consumption at four or fewer sites, direct emissions from stationary combustion at a single site, and/or direct emissions from five or less vehicles. In that situation, bidding, contract negotiations, and the kick-off meeting will take place between the certifier and the Registry. Standard terms and conditions are expected to apply for all contract elements. The Registry will initiate the procurement process for batch certification.



### Certification and Remediation: What if my GHG emission report is not certified? At the completion of the certification process, the certifier will prepare a Certification Report and forward it to the responsible official representing the Registry participant. (The responsible official includes anyone authorized by the participant to approve the GHG emission report for submission to the Registry and will typically be a corporate official or the technical manager of the certification contract.) If the certifier identifies material discrepancies that prevent a favorable Certification Opinion, those material misstatements should be listed and described in the Certification Report. If possible, the participant may correct those material discrepancies and resubmit the Emission Report for certification within a reasonable amount of time. The participant may hire technical assistance to correct material discrepancies but the certifier may not provide such technical assistance as it would create a conflict of interest. If the participant is unable to correct the material discrepancies, the Registry will retain the participant’s8 0 Part IV Chapter 1 4 data in the Registry database for up to two years pending certification. Participants who have submitted a report and undergone certification as part of a “learning by doing” process may wish to retain a pending status for their emission report for up to two years while the report is enhanced. After that time, the data will be deleted from CARROT. The participant may re-enter the data at a later date with the same conditions.


### Certification Report, Certification Opinion, and Certification Activities Log: What are these documents and how are they different? The Certification Report is a detailed report that a certifier prepares for a participant. The report should describe the scope of the certification process, standards used, emissions sources identified, sampling techniques, evaluation of the participant’s compliance with the General Reporting Protocol, and list material and immaterial discrepancies, if any. The Certification Report is a confidential document between a certifier and participant, and is not shared with the Registry or the public. The Certification Opinion is a brief, one-page summary of a certifier’s findings that simply states if a participant’s Emission Report is certifiable or not. The Certification Opinion is submitted to both the participant and the Registry. A majority of the contents of the Certification Opinion will be available to the public. The Certification Activities Log is a form that the certifier must complete that asks them to demonstrate consistency in their professional judgments. The form asks them to respond to a series of yes and no questions, and to provide the dates they have performed certification activities. This information is provided to the participant to submit to the Registry, and is not shared with the public.


### Confidentiality: Are the results of the certification kept confidential? Is emissions data kept confidential? The Registry will make public the Certification Opinion as well as the identity of your certifier, but not your Certification Report. All aggregated entity-level emissions data and metrics reported to the Registry will be available to the public. However, the Registry intends to keep confidential all reported emissions, activity data, methodologies, and emissions factors with a higher granularity (at facility, project, or source levels). Confidential information will only be accessible to the participant, the Registry, and the certifier, unless the participant allows others access to such information or wishes to have it available to the public. 

### Certification Protocol Revision Policy: Will the Certification Protocol change over time? How can participants provide feedback to the Registry? The Registry expects to regularly review, revise, update, and augment the Certification Protocol. The Registry invites all parties, certifiers, Registry participants, California State agencies, and the public to provide insights and experiences that will help improve the Certification Protocol. Anyone with suggestions or concerns is encouraged to contact the Registry at any time. Stakeholders will also be able to present suggestions directly to the Registry’s Board of Directors for consideration at their meetings. All suggestions and requests for modifications must be made by utilizing the “Protocol Comment Form” available on the Registry’s website at www.climateregistry.org . Responses to any comments can also be submitted through a “Protocol Comment Response Form,” also available on the Registry’s website.8 1 

# Appendix A: Glossary

Barrel (bbl) Commonly used to measure quantities of various petroleum products, a volumetric measure for liquids equal to 42 U.S. gallons at 60 degrees Fahrenheit.



### Baseline For the purposes of this Protocol, a datum against which to measure GHG emissions performance or change over time, usually annual emissions in a selected base year.



### British Thermal Unit (Btu) The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit at about 39.2 degrees Fahrenheit.



### Carbon Dioxide (CO 2 

### ) The most common of the six primary GHGs, consisting of a single carbon atom and two oxygen atoms, and providing the reference point for the GWP of other gases. (Thus, the GWP of CO 2 is equal to 1.)



### CO 2 

### equivalent (CO 2 

### e) A measure for comparing carbon dioxide with other GHGs (which generally have a higher global warming potential (GWP)), based on the amount of those other gases multiplied by the appropriate GWP factor; commonly expressed as metric tons of carbon dioxide equivalents (MTCO 2 e). CO 2 e is calculated by multiplying the metric tons of a gas by the appropriate GWP.



### Carbon Intensity The relative amount of carbon emitted per unit of energy or fuels consumed.



### Certification For the purposes of this Protocol, the method used to ensure that a given participant’s GHG emissions inventory (either the baseline or annual result) has met a minimum quality standard and complied with an appropriate set of Registry-approved procedures and protocols for submitting emissions inventory information.



### Certifier For the purposes of this Protocol, an organization approved by the Registry and the California Energy Commission to provide certification services for Registry participants. 

### Cogeneration The generation of two forms of energy such as heat and electricity from the same process with the purpose of utilizing or selling both simultaneously.



### Datum A reference or starting point.



### De Minimis For the purposes of this Protocol, the GHG emissions from one or more sources, for one or more gases which, when summed, equal less than 5% of an organization’s total emissions.



### Direct Emissions For the purposes of this Protocol, emissions from applicable sources that are owned or controlled by the reporting organization.



### Emission Factor A unique value for determining an amount of a GHG emitted for a given quantity of activity data(e.g., million metric tons of carbon dioxide emitted per barrel of fossil fuel).



### Equity Share According to the calculated share.



### Fugitive Emissions The unintended or incidental emissions of greenhouse gases from the transmission, processing, or transportation of fossil fuels or other materials, such as HFCs from refrigeration leaks, SF6 from electrical power distributors, methane emissions from solid waste landfills, and other

sources.



### Global Warming Potential (GWP) The ratio of radiative forcing that would result from the emission of one kilogram of a GHG to that from the emission of one kilogram of carbon dioxide over a fixed period of time.



### Higher Heating Value (HHV) The amount of heat released from the complete combustion of a fuel including water vapor produced in the process.82 

### Hydrocarbons Chemical compounds containing only carbon and hydrogen, including fossil fuels and a variety of major air pollutants.



### Hydrofluorocarbons (HFCs) One of the six primary GHGs primarily used as refrigerants, consists of a class of gases containing hydrogen, fluorine, and carbon, and possessing a range of high and very high GWP values from 120 to 12,000.



### Indirect Emissions Emissions that occur because of a participant’s actions, but are produced by sources owned or controlled by another entity.



### Intergovernmental Panel on Climate Change (IPCC) An organization established jointly by the United Nations Environment Programme and the World Meteorological Organization in 1988 to assess information in the scientific and technical literature related to all significant components of the issue of climate change, and providing technical analysis of the science of climate change as well as guidance on the quantification of GHG emissions.



### Joule A measure of energy, representing the energy needed to push with a force of one Newton for one meter.



### Lower Heating Value (LHV) The amount of heat released from the complete combustion of a fuel after netting out the heat that is released with the water vapor produced in the process.



### Management Control The ability of an entity to govern the operating policies of another entity or facility so as to obtain benefits from its activities.



### Material Any emission of GHG that is not de minimis in quantity.



### Kilowatt Hour (KWh) The electrical energy unit of measure equal to one thousand watts of power supplied to, or taken from, an electric circuit steadily for one hour. (A Watt is the unit of electrical power equal to one ampere under a pressure of one volt, or 1/746 horsepower.)



### Methane (CH 4 

### ) One of the six primary GHGs, consisting of a single carbon atom and four hydrogen atoms, possessing a GWP of 21, and produced through the anaerobic decomposition of waste in landfills, animal digestion, decomposition of animal wastes, production and distribution of natural gas and petroleum, coal production, and incomplete fossil fuel combustion.



### Metric Ton Common international measurement for the quantity of GHG emissions, equivalent to about 2,204.6 pounds or 1.1 short tons.



### Nitrous Oxide (N 2 

### O) One of the six primary GHGs, consisting of a two nitrogen atoms and a single oxygen atom, possessing a GWP of 310, and typically generated as a result of soil cultivation practices, particularly the use of commercial and organic fertilizers, fossil fuel combustion, nitric acid production, and biomass burning.



### Perfluorocarbons (PFCs) One of the six primary GHGs, consists of a class of gases containing carbon and fluorine (represented by the chemical formula CNF(2N+2)), originally introduced as alternatives to ozone depleting substances and typically emitted as by-products of industrial and manufacturing processes, and possessing GWPs ranging from 5,700 to 11,900.



### Short Ton Common measurement for a ton in the U.S. and equivalent to 2,000 pounds or about 0.907 metric tons.



### Sulfur Hexafluoride (SF 6 

### ) One of the six primary GHGs, consisting of a single sulfur atom and six fluoride atoms, possessing a very high GWP of 22,000, and primarily used in electrical transmission and distribution systems.



### Therm A measure of one hundred thousand (105) Btus.83 

# Appendix B: Common Conversion Factors

Energy

1 quadrillion Btu = 1.0551 x 10 18 joules

= 1.0551 exajoules

= 10 9 MMBtu

1 MMBtu (million Btu) = 1.0551 x 10 12 joules

= 1.0551 x 10 -6 exajoules

= 10 Therm

1 joule = 947.9 x 10 -21 quadrillion Btu

1 exajoule = 10 18 joules

= 0.9479 quadrillion Btu

1 GJ (gigajoule) = 947,817 Btu

= 277.8 kilowatt hours (kWh)

= 0.2778 Megawatt hours (MWh)

1 Therm = 10 5 Btu


### Mass

1 short ton (U.S. ton) = 2,000 pounds (lbs)

= 0.9072 metric tons

= 9.072 x 10 -4 grams

1 kilogram = 2.20462 pounds (lbs)

1 metric ton = 1.1023 short tons

= 1.1023 tons (U.S.)

= 2,204.62 pounds (lbs)

= 1,000 kg

= 10 -3 kilotons

= 10 -6 megatons 

### Volume

1 cubic centimeter = 3.531 x 10 -5 cubic feet

1 cubic meter (m 3 ) = 35.3115 ft 3 (cubic feet)

= 1,000 liters

= 264.2 U.S. gallons

= 6.29 barrels

= 1.308 yd 3 (cubic yards)

1 barrel = 42 gallons

= 5.6139 ft 3 (cubic feet)

= 0.15898 m 3

= 158.98 liters84 

### Area

1 acre = 0.40468724 hectare (ha)

= 4,047 m 2

1 hectare (ha) = 35.3115 ft 3 (cubic feet)

= 10,000 m 2

= 2.47 acres


### Distance

1 kilometer = 0.6214 miles 

### Density
1,000 cubic feet of methane (CH 4 ) = 42.28 pounds

= 1,000 cubic feet carbon dioxide (CO 2 )

= 115.97 pounds

1 metric ton natural gas liquids = 11.6 barrels

1 metric ton unfinished oils = 7.46 barrels

1 metric ton alcohol = 7.94 barrels

1 metric ton liquefied petroleum gas = 11.6 barrels

1 metric ton aviation gasoline = 8.9 barrels

1 metric ton naphtha jet fuel = 8.27 barrels

1 metric ton kerosene jet fuel = 7.93 barrels

1 metric ton motor gasoline = 8.53 barrels

1 metric ton kerosene = 7.73 barrels

1 metric ton naphtha = 8.22 barrels

1 metric ton distillate = 7.46 barrels

1 metric ton residual oil = 6.66 barrels

1 metric ton lubricants = 7.06 barrels

1 metric ton bitumen = 6.06 barrels

1 metric ton waxes = 7.87 barrels

1 metric ton petroleum coke = 5.51 barrels

1 metric ton petrochemical feedstocks = 7.46 barrels

1 metric ton special naphtha = 8.53 barrels

1 metric ton miscellaneous products = 8.00 barrels


### Metric Prefixes

Abbreviation Prefix Multiple

k kilo- 10 3 or 1,000

M mega- 10 6 or 1,000,000

G giga- 10 9 or 1,000,000,000

T tera- 10 12 or 1,000,000,000,000

P peta- 10 15 or 1,000,000,000,000,00085 

# Appendix C: Calculation References

Converting to CO 2 

### Equivalent To incorporate and evaluate non-CO 2 gases in your GHG emissions inventory, the mass estimates of these gases will need to be converted to CO 2 equivalent. To do this, multiply the emissions in units of mass by the GHG’s global warming potential (GWP). The table below lists the 100-year GWPs to be used to express emissions on a CO 2 equivalent basis. The equation below provides the basic calculation required to determine CO 2 e from the total mass of a given GHG using the GWPs published by the IPCC.



### Greenhouse Gas GWP (SAR, 1996) GWP (TAR, 2001)

CO 2 1 1

CH 4 21 23

N 2 O 310 296

HFC-23 11,700 12,000

HFC-125 2,800 3,400

HFC-134a 1,300 1,300

HFC-143a 3,800 4,300

HFC-152a 140 120

HFC-227ea 2,900 3,500

HFC-236fa 6,300 9,400

HFC-43-10mee 1,300 1,500

CF 4 6,500 5,700

C 2 F 6 9,200 11,900

C 3 F 8 7,000 8,600

C 4 F 10 7,000 8,600

C 5 F 12 7,500 8,900

C 6 F 14 7,400 9,000

SF 6 23,900 22,000 

### Comparison of GWPs from the IPCC’s Second and Third Assessment Reports

Source: U.S. Environmental Protection Agency, U.S. Greenhouse Gas Emissions and Sinks: 1990-2000 (April 2002). Converting Mass Estimates
to Carbon Dioxide Equivalent

Metric Tons of CO 2 e = Metric Tons of GHG x GWP86 

## Emission Factors for Electricity Use

eGRID Subregion Acronym eGRID Subregion Name CO 2 

### Output Emission Rate (lbs/MWh)

AKGD ASCC Alaska Grid 1,399.95
AKMS ASCC Miscellaneous 757.81

ECMI ECAR Michigan 1,632.06
ECOV ECAR Ohio Valley 1,966.53

ERCT ERCOT All 1,408.27

FRCC FRCC All 1,390.04
HIMS HICC Miscellaneous 1,702.93
HIOA HICC Oahu 1,721.69
MAAC MAAC All 1,097.56
MANN MAIN North 1,761.09
MANS MAIN South 1,237.29
MAPP MAPP All 1,838.83
NYLI NPCC Long Island 1,659.76
NEWE NPCC New England 897.11
NYCW NPCC NYC/Westchester 1,090.13
NYUP NPCC Upstate NY 843.04
OFFG Off-Grid 1,706.71

SRMV SERC Mississippi Valley 1,331.34
SRSO SERC South 1,561.51

SRTV SERC Tennessee Valley 1,372.70

SRVC SERC Virginia/Carolina 1,164.19
SPNO SPP North 2,011.15
SPSO SPP South 1,936.65
CALI WECC California 804.54

NWGB WECC Great Basin 852.31

NWPN WECC Pacific Northwest 671.04
ROCK WECC Rockies 1,872.51

WSSW WECC Southwest 1,423.95 

### Table C.1: EPA eGRID Carbon Dioxide Electricity Emission Factors by Subregion (Year 2000)

Source: EPA eGRID2002 Version 2.01 Location (Operator)-Based eGRID Subregion File (Year 2000 Data) Reporters for years prior to April 2005 (GRP 2.0)used adjusted, state-specific electricity emission factors (EIA) tocalculate GHGs. These historical factors can be referenced at www .climateregistry.org/protocols.87 

### Region/State Methane (lbs/MWh) Nitrous Oxide (lbs/MWh)

Pacific Contiguous 0.0053 0.0037
California 0.0067 0.0037 Oregon 0.0033 0.0034 Washington 0.0037 0.0040

Pacific Non-Contiguous 0.0161 0.0149
Alaska 0.0068 0.0089

Hawaii 0.0214 0.0183

Mountain 0.0108 0.0236
Arizona 0.0068 0.0154
Colorado 0.0127 0.0289
Idaho 0.0080 0.0033

Montana 0.0108 0.0227
Nevada 0.0090 0.0195

New Mexico 0.0131 0.0296
Utah 0.0134 0.0308 Wyoming 0.0147 0.0338

West-North Central 0.0127 0.0269
Iowa 0.0138 0.0298

Kansas 0.0112 0.0254

Minnesota 0.0157 0.0247

Missouri 0.0126 0.0288
Nebraska 0.0095 0.0219
North Dakota 0.0147 0.0339
South Dakota 0.0053 0.0121

West-South Central 0.0087 0.0153
Arkansas 0.0125 0.0203

Louisiana 0.0094 0.0112
Oklahoma 0.0110 0.0223

Texas 0.0077 0.0146

East-North Central 0.0123 0.0257
Illinois 0.0082 0.0180
Indiana 0.0143 0.0323 Michigan 0.0146 0.0250
Ohio 0.0130 0.0288

Wisconsin 0.0138 0.0260 

### Table C.2: Methane and Nitrous Oxide Electricity Emission Factors by State and Region (Average Years 2001-2003)88 

### Region/State Methane (lbs/MWh) Nitrous Oxide (lbs/MWh)

East-South Central 0.0128 0.0240
Alabama 0.0137 0.0223 Kentucky 0.0140 0.0321 Mississippi 0.0132 0.0165

Tennessee 0.0105 0.0212

New England 0.0207 0.0146

Connecticut 0.0174 0.0120

Maine 0.0565 0.0270
Massachusetts 0.0174 0.0159 New Hampshire 0.0172 0.0141
Rhode Island 0.0068 0.0047

Vermont 0.0096 0.0039

Mid Atlantic 0.0093 0.0145 New Jersey 0.0077 0.0079
New York 0.0081 0.0089 Pennsylvania 0.0107 0.0203

South Atlantic 0.0127 0.0207
Delaware 0.0123 0.0227
Florida 0.0150 0.0180
Georgia 0.0129 0.0226 Maryland * 0.0118 0.0206
North Carolina 0.0105 0.0203
South Carolina 0.0091 0.0145 Virginia 0.0137 0.0192 West Virginia 0.0137 0.0316

United States 0.0111 0.0192 

### Table C.2: Methane and Nitrous Oxide Electricity Emission Factors by State and Region (Average Years 2001-2003)

- continued

* Includes the District of Columbia. Note: All emission factors for electricity generation were derived based on higher heating values (HHV). Source: Emission factors are derived from: U.S. Department of Energy, Revised/Updated State-level Greenhouse GasEmission Factors for Electricity (February 2000), http://www.eia.doe.gov/oiaf/1605/e-factor.html. Note: These statelevel electricity generation emission factors represent average emissions per kWh or MWh generated by electric utilities for the 1997-1999 time period. They do not include emissions from pow er produced by non-utility generators. EIA’s Voluntary Reporting of Greenhouse Gases (1605(b)) Program believes these factors provide reasonably accurate default values for power generated in a given state. However, reporters should use these state- and regional-level factors only if utility-specific or power pool-specific emission factors are not available.89 

## Emission Factors for Mobile Emissions

Fuel kg CO 2 

### /gallon Aviation gasoline 8.24

Biodiesel 9.52

CA Low Sulfur Diesel 9.96 CA Reformulated gasoline, 5.7% ethanol 8.55

Crude Oil 10.14
Non-CA Diesel/Diesel No.2 10.05
Ethanol (E85) 6.10 Fischer Tropsch Diesel 9.13
Jet Fuel, Kerosene (Jet A or A-1) 9.47 Jet Fuel, Naphtha (Jet B) 9.24

Kerosene 9.67 Liquefied Natural Gas (LNG) 4.37 Liquefied Petroleum Gas (LPG) 5.92
Methanol 4.10

Motor Gasoline (Non CA and off-road) 8.78
Propane 5.67

Residual Oil 11.67

Fuels With Other Units Of Measure Natural Gas (CNG) per therm 5.28 Natural Gas (CNG) per gasoline gallon equivalent 6.86

Hydrogen per kg 0.0 

### Table C.3: Carbon Dioxide Emission Factors for Transport Fuels (kg CO 2 

### /gallon)

Note: Emission factors are based on complete combustion and high heating v alue (HHV). Source: California Energy Commission, Inventory of California Greenhouse Gas Emissions and Sinks: 1990-1999 (November 2002); Energy Information Administration, Emissions of Greenhouse Gases in the United States 2000, (2001), Table B1, page 140, see http://www.eia. doe.gov/oiaf/1605/ggrpt; propane and butane emission factors and fractions oxidized fromU.S. Environmental Protection Agency, Compilation of Air Pollutant Emission Factors, AP42, Fifth Edition, see http://www.epa.gov/ttn/chief/ap42/index.html. Methanol emission factor is calculated from the properties of the pure compounds; the fraction oxidized is assumed to be the same as for other liquid fuel.9 0 

### Vehicle Types/Model Years CH 4 

### (g/mile) N 2 

### O (g/mile)

Passenger Cars

- Gasoline
Model Year 1966-1972 0.22 0.02
Model Year 1973-1974 0.19 0.02

Model Year 1975-1979 0.11 0.05
Model Year 1980-1983 0.07 0.08
Model Year 1984-1991 0.06 0.08
Model Year 1992 0.06 0.07
Model Year 1993 0.05 0.05
Model Year 1994-1999 0.05 0.04
Model Year 2000– present 0.04 0.04 Passenger Cars

- Alternative Fuels and Diesel

CNG Model Year 2000– present 0.04 0.04 LPG Model Year 2000– present 0.04 0.04
E85 Model Year 2000– present 0.04 0.04 Diesel all model years 0.01 0.02 Light Duty Truck (<5750 GVWR*)

- Gasoline
Model Year 1966-1972 0.22 0.02
Model Year 1973-1974 0.23 0.02
Model Year 1975-1979 0.14 0.07
Model Year 1980-1983 0.12 0.13
Model Year 1984-1991 0.11 0.14
Model Year 1992 0.09 0.11
Model Year 1993 0.07 0.08
Model Year 1994-1999 0.06 0.06
Model Year 2000– present 0.05 0.06 

### Table C.4: Methane and Nitrous Oxide Emission Factors for Mobile Sources by Vehicle and Fuel Type (g/mile)9 1 

### Vehicle Types/Model Years CH 4 

### (g/mile) N 2 

### O (g/mile)

Light Duty Truck

- Alternative Fuels and Diesel

CNG Model Year 2000– present 0.05 0.06

LPG Model Year 2000– present 0.05 0.06

E85 Model Year 2000– present 0.05 0.06

Diesel all model years 0.01 0.03 Heavy-Duty Vehicle (>5751 GVWR)

- Gasoline

Model Year 1981 and older 0.43 0.04

Model Year 1982-1984 0.42 0.05

Model Year 1985-1986 0.20 0.05

Model Year 1987 0.18 0.09

Model Year 1988-1989 0.17 0.09

Model Year 1990-present 0.12 0.20 Heavy Duty Trucks

- Diesel and Alternative Fuels

Model Year 1966-1982 0.10 0.05

Model Year 1983-1995 0.08 0.05

Model Year 1996 to present 0.06 0.05
CNG, LNG 3.48 0.05
FTD, Biodiesel 0.06 0.05 Motorcycles

Model Year 1966-1995 0.42 0.01

Model Year 1996-present 0.09 0.01

*GVWR = Gross Vehicle Weight Rating Note: Emission factors are based on complete combustion and high heating v alue (HHV). Source: Derived from California Energy Commissions, Inventory of California Greenhouse Gas Emissions and Sinks: 1990-1999 (November 2002). 

### Table C.4: Methane and Nitrous Oxide Emission Factors for Mobile Sources by Vehicle and Fuel Type (g/mile)

- continued92 

## Emission Factors for Stationary Combustion

Table C.5:	 Carbon Dioxide Emission Factors and Oxidation Rates for Stationary Combustion (kg/MMBtu or kg/gallon)

Fuel kg CO 2 

### / MMBtu (CA.) kg CO 2 

### / MMBtu (U.S.) kg CO 2 

### / gallon Fraction of Carbon Oxidized Adjusted kg CO 2 

### / MMBtu (CA.) Adjusted kg CO 2 

### / MMBtu (U.S.) Adjusted kg CO 2 

### / gallon

Coal and Natural Gas

Residential Coal 92.77 95.33 NA 99.0 % 91.84 94.38 NA

Commercial Coal 92.77 95.33 NA 99.0 % 91.84 94.38 NA Industrial Coking Coal NA 93.72 NA 99.0 % 92.78 NA

Industrial Other Coal 93.00 93.98 NA 99.0 % 92.07 93.04 NA

Utility Coal NA 94.45 NA 99.0 % 93.51 NA
Natural Gas NA 53.05 NA 99.5 % 52.78 NA
Petroleum
Distillate Fuel (Diesel) NA 73.15 10.15 99.0 % 72.42 10.15

Kerosene NA 72.31 9.77 99.0 % 71.59 9.77 Liquefied Petroleum Gas (LPG) NA 62.30 5.95 99.0 % 61.68 5.95

Motor Gasoline NA 70.91 8.87 99.0 % 70.20 8.87
Reformulated Gasoline 69.73

Residual Fuel NA 78.80 11.79 99.0 % 78.01 11.79 Propane NA NA 5.70 99.5 % NA 5.70

Butane NA NA 6.52 99.5 % NA 6.52
Methanol (neat) NA NA 4.11 99.0 % NA 4.11
Crude Oil NA 74.18 10.24 99.0 % 73.44 10.24
Still Gas NA 64.20 NA 99.5 % 63.88

Note: Emission factors are based on complete combustion and high heating v alue (HHV). Emission factors for coking and utility coals are not given for California because they are not consumed in the state. Sources: Emission factors are derived from: California Energy Commission, Inventory of California Greenhouse Gas Emissions and Sinks: 1990-1999 (November 2002); and Energy Information Administration, Emissions of Greenhouse Gases in the United States 2000 (2001), Table B1, page 140. Propane and butane emission factors and fractions oxidized from U.S. Environmental Protection Agency, Compilation of Air Pollutant Emission Factors, AP-42, Fifth Edition, Methanol emission factor is calculated from the properties of the pure compounds; the fraction oxidized is assumed to be the same as for other liquid fuels.93 

### NON-PETROLEUM FUELS
Sector Fuel kg CH 4 

### /MMBtu kg N 2 

### O/MMBtu

Industrial Coal 0.0111 0.0016
Petroleum 0.0022 0.0007

Natural Gas 0.0059 0.0001

Wood 0.0351 0.0047

Commercial/Institutional Coal 0.0111 0.0016

Petroleum 0.0111 0.0007

Natural Gas 0.0059 0.0001

Wood 0.3514 0.0047



### PETROLEUM FUELS

Sector Fuel kg CH 4 

### /gallon kg N 2 

### O/gallon

Industrial Distillate Fuel 0.0003 0.0001

Kerosene 0.0003 0.0001 Liquefied Petroleum Gas (LPG) 0.0002 0.0001

Residual Fuel 0.0003 0.0001

Commercial/ Institutional Distillate Fuel 0.0014 0.0001

Kerosene 0.0014 0.0001 Liquefied Petroleum Gas (LPG) 0.0010 0.0001

Motor Gasoline 0.0013 0.0001

Residual Fuel 0.0015 0.0001

Residential Distillate Fuel 0.0014 0.0001

Kerosene 0.0014 0.0001 Liquefied Petroleum Gas (LPG) 0.0010 0.0001

Motor Gasoline 0.0013 0.0001 Propane 9.1 x 10-5 4.1 x 10-4

Butane 9.1 x 10-5 4.1 x 10-4 

### Table C.6: Methane and Nitrous Oxide Emission Factors for Stationary Combustion by Sector and Fuel Type (kg/MMBTu)

Note: All emission factors have been converted to higher heating value (HHV), assuming LHV is 95% of HHV for coal and petroleum and is 90% of HHV for natural gas and wood. Sources: Emission factors are derived from: U.S. EPA, “Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000” (2002), Table C-2, page C-2. EPA obtained original emission factors from the Intergovernmental Panel on Climate Change, Revised IPCC Guidelines for National Greenhouse Gas Inventories: Reference Manual (1996), Tables 1-15 through 1-19, pages 1.53-1.57.94 

# Appendix D: Electricity Emission Factors –All Fuels (lbs. CO 2 

# / kWh) for Non–U.S. CountriesTableD.1:1990–2003CO2EmissionsperkWhfromElectricityandHeatGeneration*Country19901991199219931994199519961997199819992000200120022003Albania296174113176187825346408610813512866Algeria15331475145814381502154114801504155715281513151515411544Angola756573397287399390419536448754845842781823Argentina864902829745725600811719756803745589569606Armenia......882240278472485580569496520536337326Australia17881795181017771724171118151813184818171802185719671914Austria540556461432472479512492459434412426430494Azerbaijan......171618901063111111511175119513581436123910831155Bahrain23402373232619631932179717881689181318791914185218411947Bangladesh12221184123313081286132512501288129713051226132713321261Belarus......772734772739684675664646664651664648Belgium767754732763805789750686695613628600587604Benin26482419249626701458209716161755149714531327200419891903Bolivia7237288347859721065853937995684657112210361006Bosnia-Herzegovina......189630253663995581297167414861504153913411394Brazil117121130119110119124135135179192229190172BruneiDarussalam20372018201820572165194018831885190718321753176218041773Bulgaria10179481076110010459979661032105499299010329641041Cameroon2929272024222222332422356068Canada426410430384375386373419479459479501472494Chile9926314044085545767678499221012730576578615People’sRepublic ofChina16601674168516411625170017181821180617241663161616321700ChineseTaipei9921056108111161109113311491213123512791332135813361396Colombia448476640470395428302432437309346370337337Congo130152022201515202540000*CO2emissions from fossil fuels consumed for electricity, combined heat and power and main activity heat plants divided by the output ofelectricity and heat generated from fossil fuels, nuclear, hydro (excluding pumped storage), geothermal, solar and b.Source: International Energy Agency Data Services, 2005. “CO2Emissions from Fuel Combustion (2005 Edition).”95Country19901991199219931994199519961997199819992000200120022003DemocraticRepublic ofCongo997799991199999CostaRica44110309216379344192751504618313344Côte d’Ivoire4545405426337066067509261140913836869902847Croatia...569717721551602558657712673666688785836Cuba17881786202023242430239023532337237923462335220523312205Cyprus18571835182118321846183918571877189218991863171616711839CzechRepublic12861394139612831288128312771219122412371255123512041107Denmark105011161036100810369461028926858796743737728785DominicanRepublic18631993165815961859193216411716183218741676145116191420Ecuador412507613430379692501651633520474600587582Egypt1149116911691109102897795595010231014920873851922ElSalvador157595556651838889567825814602635666684701Eritrea......336930783312322829332214152415521581165814581535Estonia......143113671365151914971499158815551535150814801592Ethiopia30037514112697938857552224201813Finland507518456512593556640591468459465529558655FYR ofMacedonia18651905182817951793185017621607165615101502171615941449France243273218152152170172159214190185150168181Gabon595615626659461562695695759719719600622675Georgia......8097036021076366337357340426293115119Germany12591288121912131208117311581140112010921094111411491100Ghana00079709509412172284468657Gibraltar17181698171317131665169816671713169816981682166916851671Greece21852075211520602020192318261916189618131795183517971713Guatemala1541926516206516755675279927458649281067891Haiti90010016864761987218781252838637763750882706Honduras272088139304721520587840576617725622776Hong Kong,China18211841180618961921187917751510155914911495151515331711Hungary103410141069101297598395595094291390987186492896Country19901991199219931994199519961997199819992000200120022003Iceland20022422792222India19051932200020531976207721742110205320532079207520442011Indonesia15461548142915901367129013451464140714531418163215791711IslamicRepublicof Iran13271310123712901301133413191305123912831252127512351153Iraq10121014130513741594153915391528149514951612179317052044Ireland16871663166716141599159615991583156315351409148814181305Israel18261806180818131810181018241813168916911678170518151804Italy12661200118211511144121311641142114010981111106911221155Jamaica16692015196927341843195818261826183218151810181517711751Japan942917933889922882873842823867871873920972Jordan17971918197418961835183917881764177916471561154816341411Kazakhstan......274726923255241524762298249624612355260025272461Kenya1191281481591921702102406539551310842593428Dem. People’sRepublic ofKorea12461215119511111118105811471228110012171286128312501195Korea112912111270122811951169116012021085105410981100924964Kuwait12941394146013631420143614311491143315171550150214001462Kyrgyzstan......340236172267273293236221223221227185Latvia......703554562525580476432474441417408399Lebanon40462262144015521471144215571522172717971616165615921563Libya17181669162316011936249423622340235923292256225821632159Lithuania......419417483390393377395408373333282267Luxembourg56565398542453854595290625911731503525514487714717Malaysia14241438131912681160115311581028111410741050110312151085Malta35082470225830692567212121592077206620041914177918081795Mexico11951195113811291246112211201155129412771290128612811270Morocco17271795182119671861191615551519160716711698168516871623Mozambique531578470331143141121647721177Myanmar1125105697210061067112012721155132512641008893717811Namibia1046039557382106126996646646462Nepal064110128157575516116175271542Netherlands132712881259126611861169110510961032102898110171010102897Country19901991199219931994199519961997199819992000200120022003NetherlandsAntilles15811577158315831588158115811585158115851588158815851585New Zealand234256329258207192251331271326304390313393Nicaragua792803975873988106710981184139413341345135212411233Nigeria9287788479067376977127548698719379661010983Norway711991111131313139131120Oman16801709188518721874183217331669165617841755180218301883Pakistan9009138678478628939771001906103210581021977816Panama375578814655664699498617983494509882595785Paraguay00000400000000Peru406337474393344410450463430377335265315326Philippines959948106510561144112211331257130311051098116910631014Poland14471436144014111418148814661471146414661482145514601460Portugal11401144137212041096125794610301023118910589771131913Qatar23752547223622932381249423182238190718151700172217241718Republic ofMoldova......156113561275113315661610151913981638170516431667Romania118612379048471006970979849774794871909909995Russia......679642653644754723721721708710721725SaudiArabia18701841182118351821182617931808181918131808174016801652Senegal20511956200920712130199119381996199820682101154116851310Serbia/Montenegro......164516711539184317621799177114931630156616271689Singapore19851764185422142152206819401696170714991499142212901239Slovak Republic72867775612861107110510761193955931814531485562Slovenia776653774787703703662807823759739752816800South Africa18741837188519431905193619121956208819911993179917991881Spain93593510639249201006792862823948893836946840Sri Lanka4121419163141113512578450505942895959897Sudan717748662113877810251065112710289441175117813941638Sweden1041171101131211081591061171018690110130Switzerland5762645562647564756668687366Syria12191178120612351281129212991303131413191288126612521286Tajikistan......1941438811013510199909090606098Country19901991199219931994199519961997199819992000200120022003UnitedRepublicof Tanzania33530030035349062842386093278419247170210Thailand13801486142413891374133613781398134113141244123911861164Togo93174354548593740847282710018316371301450386TrinidadandTobago15611645161016691572156815171495156315611524153017021612Tunisia14361535151014931420129713271341134113191266128812441222Turkey12971303128311621286118011861213123012721323136511841094Turkmenistan......75011111819205316101389134517441753175317531753Ukraine......792798772774712714734721743723725752UnitedArabEmirates16471647164516471647163416381658156115461583161616561722UnitedKingdom14971460142712591195120611331052105695599010309971043Uruguay952071961482711722915473412126794FormerUSSR9191003754717725703781752754754745750756765Uzbekistan......1155117510479579831017107210581010103210301032Venezuela712518501534490483439490523481463622613540Vietnam11848366685586446487039001032875926864935827Yemen16451960195417002020208421212051219420312051205120261951FormerYugoslavia14661396139414311180134512501385142012221292128112991327Zambia2422292420151522221515131313Zimbabwe1574207122712284240820291938173520021791163418721581113899 

# Appendix E: Industry-Specific Metrics for Determining Emission Intensity

The following table provides industry-specific metrics that may be used to measure energy and GHG emissions. It was compiled by researchers at the Lawrence Berkeley National Laboratory (LBNL).



### SIC Code Description Energy Metric Emissions Metric Source

13 Oil and Gas Extraction

131 Crude petroleum and natural gas Production Energy Intensity Production Carbon Intensity (PCI) = CO 2 eq./cubic meter oil eq. CAPP, 2000

132 Natural gas liquids Production Energy Intensity Production Carbon Intensity (PCI) = CO 2 eq./cubic meter oil eq. CAPP, 2000

138 Oil and gas field services Production Energy Intensity Production Carbon Intensity (PCI) = CO 2 eq./cubic meter oil eq. CAPP, 2000

29 Petroleum and Coal Products Energy Intensity Index (EII) Solomon Associates, 2001 Energy/$ gross output GHG/$ gross output Nyboer and Laurin, 2001a Energy/GDP GHG/GDP Nyboer and Laurin, 2001b

291 Petroleum refining Energy efficiency index Ministry of Economic Affairs, 1998 Energy/cubic meter fossil fuels GHG/cubic meter fossil fuels Nyboer and Laurin, 2001a Energy/$ gross output GHG/$ gross output Nyboer and Laurin, 2001b Energy/GDP GHG/GDP

295 Asphalt paving and roofing materials N/A

299 Misc. petroleum and coal products N/A 

### Table E.1: Industry-Specific Metrics, Ranked by California Industrial Combined Electricity and Natural Gas Consumption (Listed by Largest to Smallest Subsector)100 

### SIC Code Description Energy Metric Emissions Metric Source

20 Food and Kindred Products

201 Meat products Energy efficiency index Ministry of Economic Affairs, 1998 Energy/tonne GHG/tonne Institute for Energy Technology, 1998

202 Dairy products Energy efficiency index Ministry of Economic Affairs, 1998 Energy/liter weighted production GHG/liter weighted production Institute for Energy Technology, 1998 Energy/tonne milk and

cream GHG/kiloliter milk and

cream Nyboer and Laurin, 2001a Energy/$ gross output GHG/$ gross output Nyboer and Laurin, 2001b Energy/GDP GHG/GDP

203 Preserved fruits and vegetables Energy efficiency index Ministry of Economic Affairs, 1998 Energy/$ gross output GHG/$ gross output Nyboer and Laurin, 2001a Energy/GDP GHG/GDP Nyboer and Laurin, 2001b

204 Grain mill products N/A

205 Bakery products Energy/kg bread GHG/kg bread Institute for Energy Technology, 1998 Energy/$ gross output GHG/$ gross output Nyboer and Laurin, 2001a Energy/GDP GHG/GDP Nyboer and Laurin, 2001b

206 Sugar and confectionery products Energy efficiency index Ministry of Economic Affairs, 1998

207 Fats and oils Energy efficiency index Ministry of Economic Affairs, 1998101 

### SIC Code Description Energy Metric Emissions Metric Source

20 Food and Kindred Products

208 Beverages Energy/$ gross output GHG/$ gross output Nyboer and Laurin, 2001a Energy/GDP GHG/GDP Nyboer and Laurin, 2001b
Soft Drinks Energy efficiency index Ministry of Economic Affairs, 1998 Energy/$ gross output GHG/$ gross output Nyboer and Laurin, 2001a Energy/GDP GHG/GDP Nyboer and Laurin, 2001b Brewery Products Energy/hectoliter of beer equiv GHG/hectoliter of beer equiv Institute for Energy Technology, 1998 Energy/hectoliter of beer GHG/hectoliter of beer Nyboer and Laurin, 2001a Energy/$ gross output GHG/$ gross output Nyboer and Laurin, 2001b Energy/GDP GHG/GDP

209 Misc. food and kindred products N/A

32 Stone, Clay, and Glass Products Glass and glass products Energy efficiency index Ministry of Economic Affairs, 1998 Energy/$ gross output GHG/$ gross output Nyboer and Laurin, 2001a Energy/GDP GHG/GDP Nyboer and Laurin, 2001b

321 Flat glass N/A

322 Glass & glassware, pressed or blown N/A

323 Products of purchased glass N/A

324 Cement, hydraulic Energy efficiency index Ministry of Economic Affairs, 1998 Energy/tonne clinker GHG/tonne clinker Nyboer and Laurin, 2001a Energy/$ gross output GHG/$ gross output Nyboer and Laurin, 2001a Energy/GDP GHG/GDP

325 Structural clay products (bricks, tile) Energy efficiency index Ministry of Economic Affairs, 199810 2 32 Stone, Clay, and Glass Products

326 Pottery Energy Efficiency Index Ministry of Economic Affairs, 1998

327 Concrete, gypsum & plaster products N/A

328 Cut stone and stone products N/A

329 Misc nonmetallic mineral products N/A

28 Chemicals and Allied Products Energy/$ gross output GHG/GDP Ministry of Economic Affairs, 1998 Energy/GDP Nyboer and Laurin, 2001a Energy/GDP Nyboer and Laurin, 2001b

281 Industrial inorganic chemicals Energy/tonne inorganic chemicals GHG/tonne inorganic chemicals Nyboer and Laurin, 2001a Energy/$ gross output GHG/$ gross output Nyboer and Laurin, 2001b Energy/GDP GHG/GDP

286 Industrial organic chemicals Energy/$ gross output GHG/$ gross output Nyboer and Laurin, 2001a Energy/GDP GHG/GDP Nyboer and Laurin, 2001b

287 Agricultural chemicals Energy/tonne chemical fertilizers GHG/tonne chemical fertilizers Nyboer and Laurin, 2001a Energy/$ gross output GHG/$ gross output Nyboer and Laurin, 2001b Energy/GDP GHG/GDP
Chemical fertilizers Energy/tonne fertilizers GHG/tonne fertilizers Nyboer and Laurin, 2001a Energy/$ gross output GHG/$ gross output Nyboer and Laurin, 2001b Energy/GDP GHG/GDP

36 Electronic and Other Electric Equipment Energy/$ gross output GHG/$ gross output Nyboer and Laurin, 2001a Energy/GDP GHG/GDP Nyboer and Laurin, 2001b 

### SIC Code Description Energy Metric Emissions Metric Source10 3 

### SIC Code Description Energy Metric Emissions Metric Source

33 Primary Metal Industries Energy/$ gross output GHG/$ gross output Nyboer and Laurin, 2001a Energy/GDP GHG/GDP Nyboer and Laurin, 2001b

331 Blast furnace and basic steel Energy efficiency index Ministry of Economic Affairs, 1998 Energy/tonne steel GHG/tonne steel Nyboer and Laurin, 2001a Energy/$ gross output GHG/$ gross output Nyboer and Laurin, 2001b Energy/GDP GHG/GDP

332 Iron and steel foundries Energy efficiency index Ministry of Economic Affairs, 1998 Energy/$ gross output GHG/$ gross output Nyboer and Laurin, 2001a Energy/GDP GHG/GDP Nyboer and Laurin, 2001b
Non-ferrous Metal Smelters & Refineries Energy efficiency index Ministry of Economic Affairs, 1998

Energy/$ gross output GHG/$ gross output Nyboer and Laurin, 2001a Energy/GDP GHG/GDP Nyboer and Laurin, 2001b Primary Production of Aluminum Energy/tonne aluminum GHG/tonne aluminum Institute for Energy Technology, 1998

3335 Aluminum rolling and drawing Energy/$ gross output GHG/$ gross output Nyboer and Laurin, 2001a Energy/GDP GHG/GDP Nyboer and Laurin, 2001b Copper/Alloy Roll, Cast & Extrude Energy/$ gross output GHG/$ gross output Nyboer and Laurin, 2001a Energy/GDP GHG/GDP Nyboer and Laurin, 2001b

26 Paper and Allied Products Energy efficiency index Ministry of Economic Affairs, 1998 Energy/$ gross output GHG/$ gross output Nyboer and Laurin, 2001a Energy/GDP GHG/GDP Nyboer and Laurin, 2001b10 4 

### SIC Code Description Energy Metric Emissions Metric Source

26 Paper and Allied Products

261 Pulp mills Energy/tonne pulpwood GHG/tonne pulpwood Institute for Energy Technology, 1998 Energy/tonne thermomechanical pulp GHG/tonne thermomechanical pulp Nyboer and Laurin, 2001a

Energy/tonne chemical pulp GHG/tonne chemical pulp Nyboer and Laurin, 2001b Energy/tonne market pulp GHG/tonne market pulp Energy/$ gross output GHG/$ gross output Energy/GDP GHG/GDP

262 Paper mills Energy/tonne paper GHG/tonne paper Institute for Energy Technology, 1998 Energy/tonne pulp and paper GHG/tonne pulp and paper Nyboer and Laurin, 2001a Energy/$ gross output GHG/$ gross output Nyboer and Laurin, 2001b Energy/GDP GHG/GDP

263 Paperboard mills Energy/tonne paperboard GHG/tonne paperboard Nyboer and Laurin, 2001a

34 Fabricated Metal Products Energy/$ gross output GHG/$ gross output Nyboer and Laurin, 2001a Energy/GDP GHG/GDP Nyboer and Laurin, 2001b

37 Transportation Equipment Energy/$ gross output GHG/$ gross output Nyboer and Laurin, 2001a Energy/GDP GHG/GDP Nyboer and Laurin, 2001b

371 Motor vehicles and equipment Energy/1000 cars and trucks GHG/1000 cars and trucks Nyboer and Laurin, 2001a Energy/$ gross output GHG/$ gross output Nyboer and Laurin, 2001b Energy/GDP GHG/GDP

3714 Motor vehicle parts and accessories Energy/$ gross output GHG/$ gross output Nyboer and Laurin, 2001a Energy/GDP GHG/GDP Nyboer and Laurin, 2001b10 5 

### SIC Code Description Energy Metric Emissions Metric Source

35 Industrial Machinery and Equipment Energy/$ gross output GHG/$ gross output Nyboer and Laurin, 2001a Energy/GDP GHG/GDP Nyboer and Laurin, 2001b

30 Rubber and Miscellaneous Plastics Products Energy efficiency index Ministry of Economic Affairs, 1998 Energy/tonne of rubber products GHG/tonne rubber products Nyboer and Laurin, 2001a Energy/$ gross output GHG/$ gross output Nyboer and Laurin, 2001b Energy/GDP GHG/GDP

22 Textile Mill Products Energy/$ gross output GHG/$ gross output Nyboer and Laurin, 2001a Energy/GDP GHG/GDP Nyboer and Laurin, 2001b Energy efficiency index Ministry of Economic Affairs, 1998

227 Carpets and rugs N/A

24 Lumber and wood products N/A

14 nonmetallic mineral, except fuels N/A

38 Instruments and related products N/A

27 Printing and publishing N/A

15 General building
contractors N/A

2 Agriculture production - livestock N/A

39 Miscellaneous manufacturing industries N/A

23 Apparel and other textile products N/A

25 Furniture and fixtures N/A

10 Metal mining N/A

31 Leather and leather products N/A10 6 

# Appendix F: References

Alliance for Responsible Atmospheric Policy, Global comparative analysis of HFC and Alternative Technologies for Refrigeration, Air Conditioning, Foam, Solvent, Aerosol Propellant, and Fire protection Applications, Final Report (March 2002). American Petroleum Institute, Compendium of Greenhouse Gas Emission Estimation Methodologies for the Oil and Gas Industry, Pilot Test Version (April 2001). Australian Greenhouse Office, Progress Report’ Reporting Template (1999). California Energy Commission, Inventory of California Greenhouse Gas Emissions and Sinks: 1990-1999: (2002). Canada’s Climate Change Voluntary Challenge & Registry Inc., Registration Guide 1999 (1999). California Energy Commission, Committee Report: Guidance to the California Climate Action Registry: General Reporting Protocol, P500-02-005F (June 2002). California Energy Commission, Committee Report: Guidance to the California Climate Action Registry: Certification Protocol, P500-02-030F (June 2002). Gas Technology Institute, GRI-GHGCalcTM Computer Program, Version 1.0, GRI-99/0086 (December 1999). Intergovernmental Panel on Climate Change, Good Practice Guidance and Uncertainty Management in National Greenhouse Gas Inventories (2000). Intergovernmental Panel on Climate Change, Revised 1996 IPCC Guidelines for National Greenhouse Gas Inventories, Greenhouse Gas Inventories Reference Manual, Reference Manual, Chapter 1 (1996). Phylipsen, K., et al., Handbook on International Comparisons of Energy Efficiency in the Manufacturing Industry, Department of Science, Technology, Society, Utrecht University, Netherlands (1998).

World Resources Institute and World Business Council for Sustainable Development, The Greenhouse Gas Protocol: A Corporate Accounting and Reporting Standard (2001), www.ghgprotocol.org. United Kingdom Department for Environment, Food & Rural Affairs (DEFRA), Draft Framework Document for the UK Emissions Trading Scheme (2001). United Kingdom Department for Environment, Food & Rural Affairs (DEFRA), Guidelines for the Measurement and Reporting of Emissions in the UK Emissions Trading Scheme (2001). U.S. Department of Energy, Energy Information Administration, Annual Energy Review 2000, Appendix A, DOE/EIA-0384 (2001). U.S. Department of Energy, Energy Information Administration, Emissions of Greenhouse Gases in the United States (2000). U.S. Department of Energy, Energy Information Administration, Instructions for Form EIA-1605 Voluntary Reporting of Greenhouse Gases for Data Through 2000 (2001). U.S. Department of Energy, Energy Information Administration, Voluntary Reporting of Greenhouse Gases under Section 1605(b) of the Energy Policy Act of 1992, General Guidelines (1994). U.S. Department of Energy, Energy Information Administration, Updated State-level Greenhouse Gas Emission Factors for Electricity Generation (2001). U.S. Environmental Protection Agency, Estimating Greenhouse Gas Emissions, Volume VIII of the Emissions Inventory Improvement Program (EIIP) Technical Report Series (October 1999). U.S. Environmental Protection Agency, ClimateWise (1999), http://www.epa.gov/climatewise. U.S. Environmental Protection Agency, Composition of Refrigerant Blends (May 1998), http://www.epa.gov/ozone/ title6/snap/lists/refblend.html. U.S. Environmental Protection Agency, Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000, EPA-236- R-02-003 (April 2002). U.S. Environmental Protection Agency, Methods for Estimating Methane Emissions from Natural Gas and Oil Systems. Emissions Inventory Improvement Program, Volume VIII, Chapter 3 (1999). U.S. Environmental Protection Agency, U.S. Methane Emissions 1990-2020: Inventories, Projections, and Opportunities for Reductions, EPA-430-R-99-013 (September 1999).