California Climate Action Registry

General Reporting Protocol

Reporting Entity-Wide Greenhouse Gas Emissions 

Version 2.2 March 2007

California Climate Action Registry

515 S. Flower Street, Suite 1640

Los Angeles, CA 90071

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 CO2 Equivalent 85

 Emission Factors for Electricity Use 86

Table C.1: EPA eGRID Carbon Dioxide Electricity Emission Factors by

Subregion (Year 2000–2003) 86
Table 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 CO2/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. CO2 / 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-CO2 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 CO2 Emissions from Mobile Combustion 37

Equation III.7d Vehicle Miles Travelled 38

Equation III.7e Total CH4 or N2O Emissions from Mobile Combustion 38

Equation III.8a Annual Consumption of Fuels 43


Equation III.8b Total CO2 Emissions (Fuel Consumption is in MMBtu) 44

Equation III.8c Total CO2 Emissions (Fuel Consumption is in gallons) 44

Equation III.8d Total CH4 or N2O Emissions (Fuel Consumption is in MMBtu) 44

Equation III.8e Total CH4 or N2O 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

CH4 methane

COP coefficient of performance

CO2 carbon dioxide

CO2e 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 

N2O 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 Acronyms
10

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). 

CO2-equivalent* (CO2e) 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 CO2. 

Greenhouse Gases (GHG) For the purposes of the Registry, GHGs are the six gases identified in the 

Kyoto Protocol: Carbon Dioxide (CO2), Nitrous Oxide (N2O), Methane (CH4), 

Hydrofluorocarbons (HFCs), Perfluorocarbons (PFCs), and Sulphur Hexafluoride 

(SF6). 

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 Terms
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 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 have 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 emission 

accounting 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 as 

a 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 CO2

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 

(CO2, CH4, N2O, HFCs, PFCs, SF6). 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 provides 

a 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 CO2 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 (CO2)

• Methane (CH4)

• Nitrous Oxide (N2O)

• Hydrofluorocarbons (HFCs)

• Perfluorocarbons (PFCs)

• Sulfur Hexafluoride (SF6)

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 (CO2) 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 CO2 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 CO2 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 CO2/year, and finds that this amount falls 

below the de minimis threshold of 5% or 50 metric tons 

CO2/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 CO2. 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 CO2 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 

CO2 emissions

2008 Participant tracks 2008/reports 2007 

CO2 emissions

2009 Participant tracks 2009/reports 2008 

CO2 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 Registry 

database, 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.1.1Reporting 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 cover 

the 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.
12 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 would 

report the emissions associated with the 350 Californiaregistered vehicles, and separately report the emissions 

associated with the 650 non-California based vehicles.
13 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.
14 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 Control
15 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, 2004
16 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 Share
17 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.
18 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%
19 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. 
20 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 context 

to 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. 
21 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., CO2/ft2 of 

office space, CO2/customer, CO2/kWh, CO2/$ 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%

Your

Co.

100%

Yr. 1

Baseline

Year 1

M

30%

Your

Co.

100%

Updated

Baseline

Year 2

M 7%

Your

Co.

100%

Yr. 1

Baseline

Year 1

M 7%

Your

Co.

100%

Same

Baseline

Year 2

GHGs Raised Less Than 10%:

Same Baseline

GHGs Raised Over 10%:

Updated Baseline

GHGs Reduced by More Than 10%:

Updated Baseline

Z 4%

Rest

of

Co.

88%

Same

Baseline

Year 2

Y 4%

96%

Z 4%

Rest

of

Co.

88%

Same

Baseline

Year 3

92%

Rest

of

Co.

88%

Adjusted

Baseline

Year 4

88%

Z 4%

Rest

of

Co.

88%

Yr. 1

Baseline

Year 1

Y 4%

X 4% 100%

II.4.4 Example: Updating Your Baseline
23 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 CO2 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 CO2/year, and finds that this amount falls below the de 

minimis threshold of 5% or 50 tons CO2/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-CO2

gases as de minimis since non-CO2 gas emissions are not 

significant for many operations. On the other hand, some 

companies where the majority of emissions are of non-CO2

gases—such as gas transmission and distribution firms—

are not likely to simply consider non-CO2 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 CO2e. Therefore, the 5% de minimis threshold is 5,000 metric tons CO2e. 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 CO2 equivalent and 650 metric tons of CO2 e of 

methane, for a total of 2,000 metric tons of CO2e

2%

2%

1%

Source B

2,000

Source A

1,000

Source C

2,000

Source D

20,00 0 MT

CO 2e

Source E

19,00 0 MT

CO 2e

Source F

21,00 0 MT

CO 2e

Source G

35,00 0 MT

CO 2e

De Mini mis Emissions

The sum of Source A, B, and C

is equal to or le ss than 5% of

the total o f all G HG em ission

sou rc es.

CH4

650 MT

CO 2e

CO2

1,350 M T

CO 2e

Each sou rc e is a summa tion

of all G HGs emi tted by that

sou rc e in CO 2 equ ivalents

(CO 2e).

Source C

2,000 M T CO2e

5,000 is 5% of the total

emiss ions of 1 00,0 00 metric

tons of C O2e.

2,500

5,000

7,500

0

20,00 0

21%

35%

20%

19%

Signi ficant Em issions

The sum of Sou rces E through G com prise 95% of the

total.

III.5.7 Example: Determining De Minimis
29 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 CO2e. Therefore, your 5% 

threshold is 10,000 metric tons of CO2e. 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 CO2 and CH4 	 	 	 	

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 CO2e. The emissions from the four sources are as 

follows:

34%

33%

Source C

9,000 MT

CO 2e

Source D

50,00 0 MT

CO 2e

Source E

68,00 0 MT

CO 2e

Source F

66,00 0 MT

CO 2e

4.5%

25%

Signi ficant Em issions

The sum of Sou rces C through F compr ise 96. 5% of

the total.

De Mi nimis Em issions

The sum of Source A and B is

equal to or l ess than 5 % of the

total of al l GH G em ission

sou rc es.

1.5%

2% Source A

4,000

Source B

3,000

10,00 0 is 5% of the total

emiss ions of 2 00,0 00 metric

tons of C O2e.

5,000

10,00

15,00 0

Source CO2 Emissions 

(metric tons)

CH4 Emissions 

(metric tons CO2e)

Total Source Emissions

(metric tons CO2e)

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 = 96,700
30 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-CO2 gases to carbon dioxide equivalent 

(CO2e); and

5. Total the sum of all CO2 and CO2e 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 electricity 

bills. 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. 
31 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 CO2, CH4, and N2O 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 CO2

Emissions

(metric tons)

= Electricity 

Use (kWh) x

Electricity 

Emission Factor 

(lbs CO2/kWh)

÷ 2,204.62

lbs/metric ton

Total CH4

Emissions

(metric tons)

= Electricity 

Use (kWh) x

Electricity 

Emission Factor 

(lbs CH4/kWh)

÷ 2,204.62

lbs/metric ton

Total N2O 

Emissions

(metric tons)

= Electricity 

Use (kWh) x

Electricity 

Emission Factor 

(lbs N2O/kWh)

÷ 2,204.62

lbs/metric ton

Step 4: Convert Non-CO2 Emissions to CO2e and sum

the total.

To incorporate non-CO2 gases in your GHG emissions 

inventory, the mass estimates of these gases will need to 

be converted to CO2 equivalent. To do this, multiply the 

non-CO2 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 CO2 equivalent 

basis. Equation III.6c shows the calculation to determine 

CO2e from the total mass of a given non-CO2 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 CO2 + CO2e emissions (see 

Equation III.6d).

If non-CO2 gases are de minimis when converted to 

CO2e, you do not need to report them to the Registry (see 

Chapter 5). Also, you are not required to report non-CO2

gases until the fourth year that you report emissions to the 

Registry.

Greenhouse 

Gas

GWP

(SAR, 1996)

GWP

(TAR, 2001)

CO2 1 1

CH4 21 23

N2O 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-CO2 GHGs to

Carbon Dioxide Equivalent

Metric Tons of 

CO2e = Metric Tons of non COe GHG x GWP (SAR, 1996)

Equation

III.6d

Total GHG Emissions from Electricity Use

Total CO2e 

Emissions 

(metric tons)

= Total CO2 Emissions 

(metric tons) + Total CO2

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-CO2 Emissions to CO2e 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 information 

will 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 transparency 

in 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-CO2 emissions to CO2e, 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-CO2 emissions to CO2e. Add together the CO2e “emissions” from the 

two types of purchases to determine total “emissions.”

Step 5: Subtract the total “emissions” from renewable 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) ÷ 2,204.62lbs/mt = 583.89mt CO2

Portland, OR = 600 

MWh x 671.04 (lbs/MWh) ÷ 2,204.62lbs/mt = 182.63mt CO2

Tucson, AZ = 800 

MWh x 1,423.95 (lbs/MWh) ÷ 2,204.62lbs/mt = 516.71mt CO2

Subtotal = 1,283.23

mt CO2

Los Angeles, 

CA = 1,600 

MWh x 0.0037 (lbs/MWh) ÷ 2,204.62lbs/mt = 0.00269 mt N2O

Portland, OR = 600 

MWh x 0.0034 (lbs/MWh) ÷ 2,204.62lbs/mt = 0.00093mt N2O

Tucson, AZ = 800 

MWh x 0.0154(lbs/MWh) ÷ 2,204.62lbs/mt = 0.00559mt N2O

Subtotal = 0.00921

mt N2O

Los Angeles, 

CA = 1,600 MWh x 0.0067 

(lbs/MWh) ÷ 2,204.62lbs/mt = 0.00486 mt CH4

Portland, OR = 600 

MWh x 0.0033 

(lbs/MWh) ÷ 2,204.62lbs/mt = 0.00090mt CH4

Tucson, AZ = 800 

MWh x 0.0068

(lbs/MWh) ÷ 2,204.62lbs/mt = 0.00247mt CH4

Subtotal = 0.00823

mt CH4

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)

CO2 lbs/

MWh

CH4 lbs/

MWh

N2O 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-CO2 Emissions to CO2e and sum

the total. Use Equation III.6c and III.6d

Equation

III.6c

Convert Non-CO2 GHGs to Carbon Dioxide

Equivalent and Sum Total

Metric Tons of 

CO2e = Metric Tons of GHG x GWP (SAR, 1996)

Metric Tons of CO2 = 1,283.23 

metric tons CO2

CH4 Tons of CO2e =

0.00823 

metric tons 

N2O

x 21 (GWP) = 0.17283

metric tons CO2e

N2O Tons of CO2e =

0.00921

metric tons 

N2O

x 310 (GWP) = 2.8551

metric tons CO2e

Total = 1,286.28

metric tons CO2e
36 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 CO2 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 CO2 emission factor from 

Appendix C, Table C.2; and

3. Multiply fuel consumed by the emission factor to 

calculate total CO2 emissions and convert kilograms to 

metric tons.

If you have fuel consumption information, CARROT can 

calculate your CO2 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 CO2 emissions and convert to

metric tons.

Multiply your fuel use from Step 1 by the CO2 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 CH4 and N2O emissions 

and convert grams to metric tons;

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

6. Convert CH4 and N2O Emissions to CO2e 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 CO2 Emissions from Mobile Combustion

Total Emissions

(metric tons) = Fuel Consumed(gallons) x Emission Factor(kg CO2/gallon) x 0.001metric tons/kg
38 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 CH4 and N2O

emissions and convert to metric tons.

Use Equation III.7e to calculate total emissions for CH4 and 

N2O 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 CH4 and N2O Emissions to CO2e 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-CO2 gases are de 

minimis after they are converted to CO2e and metric 

tons, you do not need to report them to the Registry.

Step 7 	 Total CO2e 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 CO2e 

emissions from mobile combustion. 

Equation

III.7e

Total CH4 or N20

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 CH4 or N20

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 + 20,000gallons - 10,000gallons = 245,000gallons

Total Diesel 

Consumption = 5,000

gallons + 500gallons - 1,000gallons

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 CO2 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 CO2 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 (CO2)

Emissions Contribution of Each Fuel

CO2 from 

Motor 

Gasoline

= 8.55

kg/gallon x 245,000gallons x

0.001

metric 

tons/kg

=

2,094

metric 

tons CO2

CO2 from 

Diesel Fuel = 9.96

kg/gallon x 4,500gallons x

0.001

metric 

tons/kg

=

45

metric 

tons CO2

Total =

2,139

metric 

tons CO2

Carbon Dioxide

Emission Factor

Fuel kg CO2/

MMBtu

kg CO2/

gallon

CA Gasoline NA 8.55

CA Diesel Fuel NA 9.96

Carbon Dioxide Emission Factors

for Transport Fuels
40 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 EconomyHighway (mpg) x 45% )

Total Mileage –passenger 

(mi.) = 225,000gallons 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 CH4 and N2O

emissions and convert to metric tons.

Equation

III.7e

Passenger Cars:

Total CH4 and N2O Emissions

CH4 Emissions

(metric tons) = 0.04 g/mi x 2,647,750 (mi) x

0.000001 

metric 

tons/g

=

.1324

metric 

tons CH4

N2O Emissions

(metric tons) = 0.04 g/mi x 2,647,750 (mi) x

0.000001 

metric 

tons/g

=

.106

metric 

tons N2O

Equation

III.7e

Light-Duty Trucks:

Total CH4 and N2O Emissions

CH4 Emissions

(metric tons)

= 0.05 g/mi x 362,250 

(mi)

x 0.000001 

metric 

tons/g

= .0163

metric 

tons CH4

N2O Emissions

(metric tons)

= 0.06 g/mi x 362,250 

(mi)

x 0.000001 

metric 

tons/g

= .0217

metric 

tons N2O
41 Part III Chapter 7

Step 6: Convert CH4 and N2O Emissions to CO2e and

sum the subtotals using the GWPs in Table 

III.6.1.

GHG metric tons CO2e

CO2 2,139.00

CH4 4.62

N2O 69.12

Total 2,212.74 metric tons CO2

e

Total CO2e Emissions from Mobile Combustion

Vehicle Type Fuel Model Year CH4 (metric tons) N2O (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 CO2e

(metric tons)

= Total Emissions

(metric tons) x GWP factor

= .02199

metric tons CH4

21 (GWP) = 4.62 metric tons 

CO2e

= .223

metric tons N2O x 310 (GWP) = 69.12 metric tons CO2e

Step 5: Sum the methane and nitrous oxide emissions 

for each vehicle and fuel type. 

Equation

III.7f

Heavy-Duty Trucks:

Total CH4 and N2O Emissions

CH4 Emissions

(metric tons) = 0.06 g/mi x 40,050 (mi) x

0.000001 

metric 

tons/g

=

.0024

metric 

tons CH4

N2O Emissions

(metric tons) = 0.05 g/mi x 40,050 (mi) x

0.000001 

metric 

tons/g

=

.0020

metric 

tons N2O
42 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 CO2 are emitted, 

along with trace levels of other GHGs like CH4 and N2O. 

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 CO2 emissions and convert to 

metric tons;

5. Calculate each fuel’s CH4 and N2O emissions and 

convert to metric tons; and

6. Convert CH4 and N2O emissions to CO2e 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 CO2, CH4, or N2O emitted per unit of fuel 

consumed (either in kilograms per MMBtu of fuel, or 

kilograms per gallon of fuel). CO2 emission factors depend 

almost completely on the carbon content of the fuel. CH4

and N2O emission factors also depend on the type of 

combustion device and the combustion conditions. 

Carbon Dioxide. Appendix C, Table C.5 provides 

CO2 emission factors for the most common fuel types 

in kilograms of CO2 per million Btu (MMBtu) and in 

kilograms of CO2 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 CO2 emission factors provided in Appendix C, 

Table C.5 already incorporate a factor for the fraction of 

carbon oxidized. The CO2 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 End
44 Part III Chapter 8

combusted. 

Methane and Nitrous Oxide. Appendix C, Table C.6 

presents CH4 and N2O emission factors by activity sector 

and fuel type. For petroleum products, emission factors 

for CH4 and N2O 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 CO2 Emissions

(Fuel Consumption is in MMBtu)

Total Emissions 

(metric tons) = Emission Factor(kg CO2/Btu) x Fuel Consumed(MMBtu) x 0.001metric tons/kg

Equation

III.8c

Total CO2 Emissions

(Fuel Consumption is in Gallons)

Total Emissions

(metric tons) = Emission Factor(kg CO2/gallon) x Fuel Consumed(gallon) x 0.001metric 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-CO2 gases may be de minimis.

Equation

III.8d

Total CH4 or N2O Emissions

(Fuel Consumption is in MMBtu)

Total 

Emissions

(metric tons)

= Emission Factor

(kg CH4 or N2O /MMBtu) x

Fuel 

Consumed

(MMBtu)

x

0.001

metric 

tons/kg

Equation

III.8e

Total CH4 or N2

O Emissions

(Fuel Consumption is in Gallons)

Total 

Emissions

(metric tons)

= Emission Factor

(kg CH4 or N2O /gallon) x

Fuel 

Consumed

(gallon)

x

0.001

metric 

tons/kg

Step 6: Convert CH4 and N2O Emissions to CO2e and

sum all subtotals.

Use the IPCC global warming potential factors from Table 

III.6.1 to convert CH4 and N2O to CO2 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 drives 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

EH =

H

/eH

H/eH + P/eP

x E

T

and EP =

 ET - EH

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 CO2 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:

EH = Emissions allocated to steam production

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

eH = Efficiency of steam (or heat) production

P = Total electricity output (MMBtu)

eP = Efficiency of electricity generation

ET = Total direct emissions of the CHP system

EP = 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 CO2 per kg CH4 per kg N2O 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 two 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 year 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 gallons
47 Part III Chapter 8

Carbon Dioxide Emissions from Distillate Fuel

(Gallons)

Total 

Emissions

(metric tons)

=

10.05 

kg CO2 

/gallon

x 9,996

gallons x

0.001

metric 

tons/kg

= 100.5 metric 

tons CO2

Total CO2 from All Sources = 128,810.5

metric tons CO2

Carbon Dioxide Emissions from

Natural Gas (MMBtu)

Total Emissions

(metric tons) =

52.78

kg CO2/

MMBtu

x 788,400

MMBtu x

0.001

metric 

tons/kg

=

41,611.8

metric tons 

CO2

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 CO2/

MMBtu

x 946,000

MMBtu x

0.001

metric 

tons/kg

=

87,098.2 

metric tons 

CO2

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 CH4/

MMBtu

x 788,400

MMBtu x

0.001

metric 

tons/kg

=

4.652

metric tons 

CH4

Step 6:	 Convert CH4 and N2O Emissions to CO2e 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 N2O/

MMBtu

x 788,400

MMBtu x

0.001

metric 

tons/kg

=

0.0788

metric tons 

N2O

Methane Emissions from Coal

(MMBtu)

Total Emissions

(metric tons) =

0.0111

kg CH4/

MMBtu

x 946,000

MMBtu x

0.001

metric 

tons/kg

=

10.501

metric tons 

CH4

Nitrous Oxide Emissions from Coal

(MMBtu)

Total Emissions

(metric tons) =

0.0016

kg N2O/

MMBtu

x 946,000

MMBtu x

0.001

metric 

tons/kg

=

1.514

metric tons 

N2O

Nitrous Oxide Emissions from Distillate Fuel

(Gallons)

Total 

Emissions

(metric tons)

=

0.0001

kg N2O

/gallon

x 9,996

gallons x

0.001

metric 

tons/kg

= 0.0010 metric 

tons N2O

Total N2O from All Sources = 1.594

metric tons N2O

Converting Mass Estimates to Carbon Dioxide

Equivalent

Metric Tons 

of CO2e =

Metric 

Tons of 

GHG

x GWP

(SAR, 1996) = 128,810.5 metric tons CO2

e

CH4 Tons of 

CO2e =

15.17

metric tons 

CH4

x 21 (GWP) = 318.6 metric tons CO2e

N2O Tons of 

CO2e =

1.594 

metric tons 

CH4

x 310 (GWP) = 494.2 metric tons CO2e

Total = 129,623.3 metric tons CO2e

Methane Emissions from Distillate Fuel

(Gallons)

=

0.0014

kg CH4/ 

gallon

x 9,996

gallons x

0.001

metric 

tons/kg

= 0.014 metric 

tons CH4

Total CH4 from All Sources = 15.17 metric 

tons CH4
48 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-CO2 emissions to carbon dioxide 

equivalent, as applicable; and

5. Sum CO2e.

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 purchase 

electricity, 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-CO2 emissions to CO2e, 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 212OF 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. 
50 Part III Chapter 9

from imported steam or hot water.

Step 5: Convert any CH4 and N2O Emissions to CO2e

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/kg
51 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 0.001metric 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

Performance
52 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 CO2 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, Tables C.5 and C.6

Equation

III.9k

Total Emissions

Total Carbon Dioxide (CO2) Emissions (kg) = 750.94 MMBtu x 52.78 kg/MMBtu x 0.001 metric tons/kg = 39.63 metric tons CO2

Total Methane (CH4) Emissions (kg) = 750.94 MMBtu x 0.0059 kg/MMBtu x 0.001 metric tons/kg = .0044 metric tons CH4

Total Nitrous Oxide (N2O) Emissions (kg) 750.94 MMBtu x 0.0001 kg/MMBtu x 0.001 metric tons/kg = 0.000075 metric tons N2O

Equation

III.9f

Energy Input

Energy Input

(MMBtu) = 600MMBtu ÷ [ 0.85 (boiler

efficiency) x ( 1 - 0.06 ) ] = 750.94

MMBtu

Step 5:	 Convert CH4 and N2O Emissions to CO2e 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 

CO2e

Metric Tons of 

GHG x GWP (SAR, 1996)

Metric Tons 

of CO2

= = 39.63 metric 

tons CO2e

CH4 Metric 

Tons of CO2e = 0.0044 metric 

tons CO2e x 21 (GWP) = 0.0924 metric tons CO2e

N2O Metric 

Tons of CO2e

0.000075

metric tons N2O x 310 (GWP) = 0.0233 metric tons CO2e

Total = 39.746 metric 

tons CO2e

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 CO2 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 N2O Emissions from the Production of 

Adipic Acid

 ̇ Calculating CO2 and PFC Emissions from the 

Production of Aluminum

 ̇ Calculating CO2 Emissions from the Production of 

Ammonia

 ̇ Calculating HFC-23 Emissions from the Production of 

HCFC-22

 ̇ Calculating CO2 Emissions from the Production of 

Iron and Steel

 ̇ Calculating CO2 Emissions from the Production of 

Lime

 ̇ Calculating N2O 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 CO2 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: 

 ̇ CO2 emissions from lime production: Appendix B 

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

 ̇ CO2 emissions from limestone and dolomite 

consumption: Appendix B page B-12;

 ̇ N2O from nitric acid production: Appendix B page 

B-16, Appendix C page C-7;

 ̇ FC-23, CF4, C2F6, and SF6 emissions from 

semiconductor manufacturing: Appendix B page 

B-18, Appendix C page C-9;

 ̇ CO2 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 CO2e.

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 

(ft2)

R404A,R507

Secondary Loop System 15 % 1.5% of floor area 

(ft2)

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 Blends
58 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 

CO2e 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 to 

accurately 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 Changes
59 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 CO2e (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 fugitive 

GHG 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: 

 ̇ CH4 emissions from coal mining: Appendix B page 

B-5, Appendix C page C-3;

 ̇ CH4 emissions from natural gas systems: Appendix B 

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

 ̇ CH4 emissions from petroleum systems: Appendix B 

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

 ̇ SF6 emissions from electricity transmission and 

distribution equipment: Appendix B page B-6, 

Appendix C page C-4;

 ̇ N2O emissions from wastewater: Appendix B page 

B-9;

 ̇ CH4 emissions from wastewater: Appendix B page 

B-15;

 ̇ CH4 emissions from landfills: Appendix B page B-10;

 ̇ N2O emissions from agricultural soil management: 

Appendix B page B-2;

 ̇ CH4 emissions from livestock as a result of enteric 

fermentation: Appendix B page B-7;

 ̇ CH4 and N2O emissions from manure management: 

Appendix B page B-13;

 ̇ CH4 emissions from rice cultivation: Appendix B page 

B-18. 
60 Part III Chapter 11

Equation

III.6c

Converting Mass Estimates to

Carbon Dioxide Equivalent

HFC-23 metric 

tons of CO2e = 1.286 metric tons HFC-23 x 11,700 (GWP) = 15,046.2 metric tons CO2e

HFC-134a metric 

tons of CO2e = .001 metric tons HFC-134a x 1,300 (GWP) = 1.3 metric tons CO2e

Total = 15,047.50 

metric tons CO2e

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 vegetable 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 CO2e, using Equation III.6c
61 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 

CO2e =

Metric 

tons of 

GHG

x GWP

(SAR, 1996)

HFC-23

metric tons of 

CO2e

=

132.2

kg 

HFC-23

x 11,700

(GWP) x

0.001

metric 

tons/kg

=

1.5467

metric tons 

CO2e

Total =

1.5467

metric tons 

CO2e

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 several 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 Table 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 CO2e and convert to

metric tons.
62 Part III Chapter 12

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 12

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 CO2/ft2 of office space, lbs CO2/customer, 

lbs CO2/kWh, lbs CO2/$ 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_CO2Guide.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.cfm 
64 Part III Chapter 10 Chapter 12

• 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 13

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 13

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 CO2e/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 13

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 140641 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.org
69 Part IV Chapter 14

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 CO2e 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 CO2 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 (CO2, CH4, N2O, 

HFCs, PFCs, SF6). 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.
70 Part IV Chapter 14

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 the 

guidance 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

Verifying

Emission Estimates

Identifying

Emission Sources

Risk Analysis &

Uncertainty

Assessment

Reviewing

Methodologies &

Management

Systems
71 Part IV Chapter 14

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 must 
72 Part IV Chapter 14

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 31
73 Part IV Chapter 14

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 certifiers 

maintained 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 reports 
74 Part IV Chapter 14

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 significant 
75 Part IV Chapter 14

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 14

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 Activities
77 Part IV Chapter 14

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 CO2e 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 14

• 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, the 

updated 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 a 
79 Part IV Chapter 14

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 CO2e 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’s 
80 Part IV Chapter 14

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.
81

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 (CO2) 

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 CO2 is equal to 1.) 

CO2 equivalent (CO2e)

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 (MTCO2e). CO2e 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 (CH4) 

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 (N2O) 

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 (SF6) 

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 1018 joules

= 1.0551 exajoules

= 109 MMBtu

1 MMBtu (million Btu) = 1.0551 x 1012 joules

= 1.0551 x 10-6 exajoules

= 10 Therm

1 joule = 947.9 x 10-21 quadrillion Btu

1 exajoule = 1018 joules

= 0.9479 quadrillion Btu

1 GJ (gigajoule) = 947,817 Btu

= 277.8 kilowatt hours (kWh)

= 0.2778 Megawatt hours (MWh)

1 Therm = 105

 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 (m3) = 35.3115 ft3

 (cubic feet)

= 1,000 liters

= 264.2 U.S. gallons

= 6.29 barrels

= 1.308 yd3 (cubic yards)

1 barrel = 42 gallons

= 5.6139 ft3 (cubic feet)

= 0.15898 m3

= 158.98 liters
84

Area

1 acre = 0.40468724 hectare (ha)

= 4,047 m2

1 hectare (ha) = 35.3115 ft3

 (cubic feet)

= 10,000 m2

= 2.47 acres

Distance

1 kilometer = 0.6214 miles

Density

1,000 cubic feet of methane (CH4) = 42.28 pounds

= 1,000 cubic feet carbon dioxide (CO2)

= 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- 103

 or 1,000

M mega- 106

 or 1,000,000

G giga- 109

 or 1,000,000,000

T tera- 1012 or 1,000,000,000,000

P peta- 1015 or 1,000,000,000,000,000
85

Appendix C: Calculation References 

Converting to CO2 Equivalent

To incorporate and evaluate non-CO2 gases in your GHG emissions inventory, the mass estimates of these gases will 

need to be converted to CO2 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 CO2 equivalent basis. The 

equation below provides the basic calculation required to determine CO2e from the total mass of a given GHG using the 

GWPs published by the IPCC. 

Greenhouse 

Gas

GWP

(SAR, 1996)

GWP

(TAR, 2001)

CO2 1 1

CH4 21 23

N2O 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

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 CO2e = Metric Tons of GHG x GWP
86

Emission Factors for Electricity Use

eGRID Subregion

Acronym

eGRID Subregion 

Name

CO2 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 Gas 

Emission 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 power 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 CO2/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 CO2/gallon)

Note: Emission factors are based on complete combustion and high heating value (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 from 

U.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.
90

Vehicle Types/Model Years CH4 (g/mile) N2O (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)
91

Vehicle Types/Model Years CH4 (g/mile) N2O (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 value (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) - continued
92

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 CO2/

MMBtu

(CA.)

kg CO2/

MMBtu

(U.S.)

kg CO2/

gallon

Fraction 

of 

Carbon 

Oxidized

Adjusted

kg CO2/

MMBtu

(CA.)

Adjusted 

kg CO2/

MMBtu

(U.S.)

Adjusted

kg CO2/

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 value (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 CH4/MMBtu kg N2O/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 CH4/gallon kg N2O/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. CO2 / kWh) 

for Non–U.S. Countries

Table D.1: 1990

– 2003 CO2 Emissions per kWh from Electricity and Heat Generation*

Country 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003Albania 296 174 113 176 187 82 53 46 40 86 108 135 128 66Algeria 1533 1475 1458 1438 1502 1541 1480 1504 1557 1528 1513 1515 1541 1544Angola 756 573 397 287 399 390 419 536 448 754 845 842 781 823Argentina 864 902 829 745 725 600 811 719 756 803 745 589 569 606Armenia

...

... 882 240 278 472 485 580 569 496 520 536 337 326

Australia 1788 1795 1810 1777 1724 1711 1815 1813 1848 1817 1802 1857 1967 1914Austria 540 556 461 432 472 479 512 492 459 434 412 426 430 494Azerbaijan

...

... 1716 1890 1063 1111 1151 1175 1195 1358 1436 1239 1083 1155

Bahrain 2340 2373 2326 1963 1932 1797 1788 1689 1813 1879 1914 1852 1841 1947Bangladesh 1222 1184 1233 1308 1286 1325 1250 1288 1297 1305 1226 1327 1332 1261Belarus

...

... 772 734 772 739 684 675 664 646 664 651 664 648

Belgium 767 754 732 763 805 789 750 686 695 613 628 600 587 604Benin 2648 2419 2496 2670 1458 2097 1616 1755 1497 1453 1327 2004 1989 1903Bolivia 723 728 834 785 972 1065 853 937 995 684 657 1122 1036 1006Herzegovina Bosnia-

...

... 1896 3025 366 399 558 1297 1674 1486 1504 1539 1341 1394

Brazil 117 121 130 119 110 119 124 135 135 179 192 229 190 172DarussalamBrunei 2037 2018 2018 2057 2165 1940 1883 1885 1907 1832 1753 1762 1804 1773Bulgaria 1017 948 1076 1100 1045 997 966 1032 1054 992 990 1032 964 1041Cameroon 29 29 27 20 24 22 22 22 33 24 22 35 60 68Canada 426 410 430 384 375 386 373 419 479 459 479 501 472 494Chile 992 631 404 408 554 576 767 849 922 1012 730 576 578 615ChinaRepublic of People’s 1660 1674 1685 1641 1625 1700 1718 1821 1806 1724 1663 1616 1632 1700Chinese Taipei 992 1056 1081 1116 1109 1133 1149 1213 1235 1279 1332 1358 1336 1396Colombia 448 476 640 470 395 428 302 432 437 309 346 370 337 337Congo 13 0 15 20 22 20 15 15 20 254 0 0 0 0

*CO2 emissions from fossil fuels consumed for electricity, combined heat and power and main activity heat plants divided by the output of Source: International Energy Agency Data Services, 2005. “COelectricity and heat generated from fossil fuels, nuclear, hydro (excluding pumped storage), geothermal, solar and b.

2 Emissions from Fuel Combustion (2005 Edition).”
95

Country 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003CongoRepublic of Democratic 9 9 7 7 9 9 9 9 11 9 9 9 9 9Costa Rica 44 110 309 216 379 344 192 75 150 46 18 31 33 44Côte d’Ivoire 454 540 542 633 706 606 750 926 1140 913 836 869 902 847Croatia ... 569 717 721 551 602 558 657 712 673 666 688 785 836Cuba 1788 1786 2020 2324 2430 2390 2353 2337 2379 2346 2335 2205 2331 2205Cyprus 1857 1835 1821 1832 1846 1839 1857 1877 1892 1899 1863 1716 1671 1839Czech Republic 1286 1394 1396 1283 1288 1283 1277 1219 1224 1237 1255 1235 1204 1107Denmark 1050 1116 1036 1008 1036 946 1028 926 858 796 743 737 728 785RepublicDominican 1863 1993 1658 1596 1859 1932 1641 1716 1832 1874 1676 1451 1619 1420Ecuador 412 507 613 430 379 692 501 651 633 520 474 600 587 582Egypt 1149 1169 1169 1109 1028 977 955 950 1023 1014 920 873 851 922El Salvador 157 595 556 651 838 889 567 825 814 602 635 666 684 701Eritrea ... ... 3369 3078 3312 3228 2933 2214 1524 1552 1581 1658 1458 1535Estonia ... ... 1431 1367 1365 1519 1497 1499 1588 1555 1535 1508 1480 1592Ethiopia 300 375 141 126 97 93 88 57 55 22 24 20 18 13Finland 507 518 456 512 593 556 640 591 468 459 465 529 558 655MacedoniaFYR of 1865 1905 1828 1795 1793 1850 1762 1607 1656 1510 1502 1716 1594 1449France 243 273 218 152 152 170 172 159 214 190 185 150 168 181Gabon 595 615 626 659 461 562 695 695 759 719 719 600 622 675Georgia ... ... 809 703 602 1076 366 337 357 340 426 293 115 119Germany 1259 1288 1219 1213 1208 1173 1158 1140 1120 1092 1094 1114 1149 1100Ghana 0 0 0 7 9 7 0 9 509 412 172 284 468 657Gibraltar 1718 1698 1713 1713 1665 1698 1667 1713 1698 1698 1682 1669 1685 1671Greece 2185 2075 2115 2060 2020 1923 1826 1916 1896 1813 1795 1835 1797 1713Guatemala 154 192 651 620 651 675 567 527 992 745 864 928 1067 891Haiti 900 1001 686 476 198 721 878 1252 838 637 763 750 882 706Honduras 27 20 88 139 304 721 520 587 840 576 617 725 622 776ChinaHong Kong, 1821 1841 1806 1896 1921 1879 1775 1510 1559 1491 1495 1515 1533 1711Hungary 1034 1014 1069 1012 975 983 955 950 942 913 909 871 864 928
96

Country 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003Iceland 2 0 0 2 2 4 2 2 7 9 2 2 2 2India 1905 1932 2000 2053 1976 2077 2174 2110 2053 2053 2079 2075 2044 2011Indonesia 1546 1548 1429 1590 1367 1290 1345 1464 1407 1453 1418 1632 1579 1711Islamic Republicof Iran

1327 1310 1237 1290 1301 1334 1319 1305 1239 1283 1252 1275 1235 1153

Iraq 1012 1014 1305 1374 1594 1539 1539 1528 1495 1495 1612 1793 1705 2044Ireland 1687 1663 1667 1614 1599 1596 1599 1583 1563 1535 1409 1488 1418 1305Israel 1826 1806 1808 1813 1810 1810 1824 1813 1689 1691 1678 1705 1815 1804Italy 1266 1200 1182 1151 1144 1213 1164 1142 1140 1098 1111 1069 1122 1155Jamaica 1669 2015 1969 2734 1843 1958 1826 1826 1832 1815 1810 1815 1771 1751Japan 942 917 933 889 922 882 873 842 823 867 871 873 920 972Jordan 1797 1918 1974 1896 1835 1839 1788 1764 1779 1647 1561 1548 1634 1411Kazakhstan ... ... 2747 2692 3255 2415 2476 2298 2496 2461 2355 2600 2527 2461Kenya 119 128 148 159 192 170 210 240 653 955 1310 842 593 428KoreaRepublic of Dem. People’s 1246 1215 1195 1111 1118 1058 1147 1228 1100 1217 1286 1283 1250 1195Korea 1129 1211 1270 1228 1195 1169 1160 1202 1085 1054 1098 1100 924 964Kuwait 1294 1394 1460 1363 1420 1436 1431 1491 1433 1517 1550 1502 1400 1462Kyrgyzstan ... ... 340 236 172 267 273 293 236 221 223 221 227 185Latvia ... ... 703 554 562 525 580 476 432 474 441 417 408 399Lebanon 4046 2262 1440 1552 1471 1442 1557 1522 1727 1797 1616 1656 1592 1563Libya 1718 1669 1623 1601 1936 2494 2362 2340 2359 2329 2256 2258 2163 2159Lithuania ... ... 419 417 483 390 393 377 395 408 373 333 282 267Luxembourg 5656 5398 5424 5385 4595 2906 2591 1731 503 525 514 487 714 717Malaysia 1424 1438 1319 1268 1160 1153 1158 1028 1114 1074 1050 1103 1215 1085Malta 3508 2470 2258 3069 2567 2121 2159 2077 2066 2004 1914 1779 1808 1795Mexico 1195 1195 1138 1129 1246 1122 1120 1155 1294 1277 1290 1286 1281 1270Morocco 1727 1795 1821 1967 1861 1916 1555 1519 1607 1671 1698 1685 1687 1623Mozambique 531 578 470 331 143 141 121 64 7 7 2 11 7 7Myanmar 1125 1056 972 1006 1067 1120 1272 1155 1325 1264 1008 893 717 811Namibia 104 60 395 573 82 106 126 99 66 46 64 64 62Nepal 0 64 110 128 157 57 55 161 161 75 27 15 4 2Netherlands 1327 1288 1259 1266 1186 1169 1105 1096 1032 1028 981 1017 1010 1028
97

Country 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003AntillesNetherlands 1581 1577 1583 1583 1588 1581 1581 1585 1581 1585 1588 1588 1585 1585New Zealand 234 256 329 258 207 192 251 331 271 326 304 390 313 393Nicaragua 792 803 975 873 988 1067 1098 1184 1394 1334 1345 1352 1241 1233Nigeria 928 778 847 906 737 697 712 754 869 871 937 966 1010 983Norway 7 11 9 9 11 11 13 13 13 13 9 13 11 20Oman 1680 1709 1885 1872 1874 1832 1733 1669 1656 1784 1755 1802 1830 1883Pakistan 900 913 867 847 862 893 977 1001 906 1032 1058 1021 977 816Panama 375 578 814 655 664 699 498 617 983 494 509 882 595 785Paraguay 0 0 0 0 0 4 0 0 0 0 0 0 0 0Peru 406 337 474 393 344 410 450 463 430 377 335 265 315 326Philippines 959 948 1065 1056 1144 1122 1133 1257 1303 1105 1098 1169 1063 1014Poland 1447 1436 1440 1411 1418 1488 1466 1471 1464 1466 1482 1455 1460 1460Portugal 1140 1144 1372 1204 1096 1257 946 1030 1023 1189 1058 977 1131 913Qatar 2375 2547 2236 2293 2381 2494 2318 2238 1907 1815 1700 1722 1724 1718MoldovaRepublic of ... ... 1561 1356 1275 1133 1566 1610 1519 1398 1638 1705 1643 1667Romania 1186 1237 904 847 1006 970 979 849 774 794 871 909 909 995Russia ... ... 679 642 653 644 754 723 721 721 708 710 721 725Saudi Arabia 1870 1841 1821 1835 1821 1826 1793 1808 1819 1813 1808 1740 1680 1652Senegal 2051 1956 2009 2071 2130 1991 1938 1996 1998 2068 2101 1541 1685 1310MontenegroSerbia/ ... ... 1645 1671 1539 1843 1762 1799 1771 1493 1630 1566 1627 1689Singapore 1985 1764 1854 2214 2152 2068 1940 1696 1707 1499 1499 1422 1290 1239Slovak Republic 728 677 756 1286 1107 1105 1076 1193 955 931 814 531 485 562Slovenia 776 653 774 787 703 703 662 807 823 759 739 752 816 800South Africa 1874 1837 1885 1943 1905 1936 1912 1956 2088 1991 1993 1799 1799 1881Spain 935 935 1063 924 920 1006 792 862 823 948 893 836 946 840Sri Lanka 4 121 419 163 141 113 512 578 450 505 942 895 959 897Sudan 717 748 662 1138 778 1025 1065 1127 1028 944 1175 1178 1394 1638Sweden 104 117 110 113 121 108 159 106 117 101 86 90 110 130Switzerland 57 62 64 55 62 64 75 64 75 66 68 68 73 66Syria 1219 1178 1206 1235 1281 1292 1299 1303 1314 1319 1288 1266 1252 1286Tajikistan ... ... 194 143 88 110 135 101 99 90 90 90 60 60
98

Country 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003United Republicof Tanzania

335 300 300 353 490 628 423 860 93 278 419 247 170 210

Thailand 1380 1486 1424 1389 1374 1336 1378 1398 1341 1314 1244 1239 1186 1164Togo 931 743 545 485 937 408 472 827 1001 831 637 1301 450 386Trinidad andTobago

1561 1645 1610 1669 1572 1568 1517 1495 1563 1561 1524 1530 1702 1612

Tunisia 1436 1535 1510 1493 1420 1297 1327 1341 1341 1319 1266 1288 1244 1222Turkey 1297 1303 1283 1162 1286 1180 1186 1213 1230 1272 1323 1365 1184 1094Turkmenistan ... ... 750 1111 1819 2053 1610 1389 1345 1744 1753 1753 1753 1753Ukraine ... ... 792 798 772 774 712 714 734 721 743 723 725 752United ArabEmirates

1647 1647 1645 1647 1647 1634 1638 1658 1561 1546 1583 1616 1656 1722

United Kingdom 1497 1460 1427 1259 1195 1206 1133 1052 1056 955 990 1030 997 1043Uruguay 95 207 196 148 27 117 229 154 73 412 126 7 9 4Former USSR 919 1003 754 717 725 703 781 752 754 754 745 750 756 765Uzbekistan ... ... 1155 1175 1047 957 983 1017 1072 1058 1010 1032 1030 1032Venezuela 712 518 501 534 490 483 439 490 523 481 463 622 613 540Vietnam 1184 836 668 558 644 648 703 900 1032 875 926 864 935 827Yemen 1645 1960 1954 1700 2020 2084 2121 2051 2194 2031 2051 2051 2026 1951YugoslaviaFormer 1466 1396 1394 1431 1180 1345 1250 1385 1420 1222 1292 1281 1299 1327Zambia 24 22 29 24 20 15 15 22 22 15 15 13 13 13Zimbabwe 1574 2071 2271 2284 2408 2029 1938 1735 2002 1791 1634 1872 1581 1138
99

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) = 

CO2eq./cubic meter oil 

eq.

CAPP, 2000

132 Natural gas liquids Production Energy 

Intensity

Production Carbon 

Intensity (PCI) = 

CO2eq./cubic meter oil 

eq.

CAPP, 2000

138 Oil and gas field 

services

Production Energy 

Intensity

Production Carbon 

Intensity (PCI) = 

CO2eq./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, 1998
101

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, 1998
102

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 Source
103

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, 

2001b
104

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, 

2001b
105

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/A
106

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).