Ministry of Environment Victoria, B.C. August 2011 Version 1.0

BRITISH COLUMBIA REPORTING REGULATION GUIDANCE DOCUMENT Victoria, B.C. August 2011 Version 1.0

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British Columbia Reporting Regulation Guidance Document Table of Contents Acknowledgements and Further Information... vi 1. Acronyms, Abbreviations and Index Table... 1 1.1 List of Acronyms... 1 1.2 Index Table... 2 2. Context and Purpose of GHG Reporting in B.C.... 4 2.1 Climate Action and B.C. s Approach to Regulating GHGs... 4 2.2 Purpose of Guidance Document... 5 3. Key Definitions... 6 3.1 General Terms... 6 3.2 Facilities, Emissions and Reporting Operations... 8 4. Simplified Reporting Framework... 11 4.1 Core Requirements... 11 4.1.1 Who is Required to Report... 12 4.1.2 What to Report... 12 4.1.3 New Reporting Operations... 13 4.1.4 Verification Requirements... 14 4.1.5 When to Report... 14 4.2 Excluded Facilities... 15 5. Reporting Requirements... 16 5.1 Responsible Parties... 16 5.1.1 Management and Control of Reporting Operation... 16 5.1.2 Operation Representative... 16 5.1.3 Multiple Operators... 16 5.1.4 Roles of Operation Representative... 17 5.1.5 Person Responsible for Preparing and Submitting Report... 18 5.2 Reporting Operations and Emissions... 18 5.2.1 Operations with Reporting Obligations... 18 5.2.2 Attributable Emissions... 20 5.2.3 Biomass CO 2 Exclusions (Schedule C Biomass)... 22 5.2.4 Coal Combustion... 24 5.2.5 Exclusions... 24 5.2.6 Sample Cases... 24 5.2.7 Reporting Thresholds... 27 5.3 Reporting Period... 28 5.4 Registration of Reporting Operations... 28 5.5 Reporting GHG Emissions... 30 5.5.1 Reporting Timing... 30 5.5.2 Reporting Contents... 30 5.5.3 Historical 2006-2009 Data Reports... 36 5.5.4 Supplementary Reports... 37 Page iii

6. Calculating Emissions... 39 6.1 Emission Quantification Methodology... 39 6.2 Selection of Quantification Methods... 41 6.3 Replacement Quantification Methodologies... 45 6.4 Alternative Measurement Parameter... 46 6.5 Choosing Between Measurement Methodologies... 47 6.6 Instrumentation... 48 7. Data Quality and Document Management... 49 7.1 Data Quality... 49 7.2 Document Management... 49 7.2.1 Records and Record Retention... 49 7.2.2 Public Disclosure and Confidentiality... 51 8. Inspection and Seizure Powers... 54 8.1 Inspectors... 54 8.2 Appeals... 54 9. References... 56 List of Appendices Appendix A Global Warming Potentials (GWP) for Specified Gases Appendix B Sample Process Flow Diagram Page iv

List of Tables Table 1 Guidance Document and Regulation Index Table.... 2 Table 2 Reporting Timeline.... 15 Table 3 Checklist #1: All Reporting Operations.... 32 Table 4 Checklist #2: Additional reporting requirements for single and linear facilities emitting 10,000 t CO 2 e in the current reporting period.... 33 Table 5 Checklist #3: Additional requirements for single or linear facilities operations that emitted < 10,000 t CO 2 e in entirety during the current reporting year that do not have verification obligations from the previous reporting year.... 34 Table 6 Checklist #4: Additional requirements for electricity import reporting operations.... 35 Table 7 Record Retention Requirements.... 50 List of Figures Figure 1 Relationship between Reporting Operations, Activities, Source Types and GHG Types... 10 Figure 2 Core Requirement of the Reporting Framework.... 11 Figure 3 Designating an Operation Representative.... 17 Figure 4 Reporting Operations for Single and Linear Facilities.... 19 Figure 5 Linear Facilities Operation (Sample Case #4).... 20 Figure 6 Single Facility Operation with Multiple Activities and Source Types.... 21 Figure 7 Combustion Emissions and the Reporting Threshold.... 23 Figure 8 Understanding Reporting Thresholds.... 28 Figure 9 Decision Tree for Determining Whether or Not an Operation Must be Registered.... 29 Figure 10 Reporting Due Dates for 2010, 2011 and 2012.... 37 Figure 11 Overview of Emission Quantification Methodology Single or Linear Facilities.... 39 Figure 12 Example of Source Type and GHG Type Determination.... 40 Figure 13 Selecting Approved Methodologies, Facility A (Sample Case #21).... 43 Figure 14 Selecting Approved Methodologies, Facility B (Sample Case #21).... 44 Figure 15 Selection of Replacement Quantification Methods.... 45 Figure 16 Confidentiality Evaluation and Decision Process.... 53 Page v

ACKNOWLEDGEMENTS AND FURTHER INFORMATION Acknowledgements The Reporting Regulation Guidance Document has been prepared by Golder Associates Ltd. and The Delphi Group for the British Columbia (the Ministry) to support the implementation of the Reporting Regulation (B.C. Reg. 272/2009), and subsequent amendments, under the Greenhouse Gas Reduction (Cap and Trade) Act (SBC 2008, c. 32). The contributions of Ministry staff (Dennis Paradine, Christine Woodhouse, Julie-Anne Bathory Frota, Konstantin Zahariev, Megan Hodder, Lee Thiessen and Laura Lapp), ERG (Eastern Research Group) and other personnel are gratefully acknowledged. Further Information Sample cases are provided throughout this Reporting Regulation Guidance Document to provide general responses to some of the more frequent questions from reporting facility owners and operators, consultants and verification bodies. The Ministry also plans to publish a database of Ministry responses to stakeholder inquiries at the Reporting Regulation website. For further information, please e-mail the Ministry at ghgreporting@gov.bc.ca. Page vi

1. ACRONYMS, ABBREVIATIONS AND INDEX TABLE 1.1 List of Acronyms BC BC Hydro CEMS CEPA CH 4 CO 2 CO 2 e FOIPPA GHG GWP HFC HHV ISO NAICS NERC N 2 O OWR PFC SF 6 t WBCSD WCI British Columbia British Columbia Hydro and Power Authority Continuous Emissions Monitoring System Canadian Environmental Protection Act Methane Carbon Dioxide Carbon Dioxide Equivalent Freedom of Information and Protection of Privacy Act Greenhouse Gas Global Warming Potential Hydrofluorocarbon Higher Heating Value International Organization for Standardization North American Industry Classification System North American Electric Reliability Corporation Nitrous Oxide One-window Reporting Perfluorocarbon Sulphur Hexafluoride Metric Tonne World Business Council for Sustainable Development Western Climate Initiative In this guidance document, a reference to ISO and a number refers to a standard made by the International Organization for Standardization, as amended from time-to-time, and named in part by that number. A reference to WCI and a number refers to a standard set out by the Western Climate Initiative s Final Essential Requirements for Mandatory Reporting, as amended from time-to-time. Page 1

1.2 Index Table Table 1 provides an index between the Reporting Regulation Guidance Document and the relevant sections of the Reporting Regulation. Table 1 Guidance Document and Regulation Index Table. Reporting Regulation Guidance Document Reporting Regulation 3 Key Definitions 3.1 General Terms Part 1, Section1. Schedule A 3.2 Facilities, Emissions and Reporting Operations Part 1, Section1. Schedule A 4 Simplified Reporting Framework 4.1 Core Requirements 4.1.1 Who is Required to Report Part 1, Section 3 Part 2, Sections 6 and 7 4.1.2 What to Report Part 2, Sections 5 and 8. Part 3, Section 12 4.1.3 New Reporting Operations Part 2, Section 9 4.1.4 Verification Requirements Part 4 4.1.5 When to Report Part 3, Section 11 4.2 Excluded Facilities Part 1, Sections 3 and 4 5 Reporting Requirements 5.1 Responsible Parties 5.1.1 Management and Control of Reporting Operation Part 3, Section 10 5.1.2 Operation Representative Part 1, Section 1 5.1.3 Multiple Operators Part 1, Section 1 5.1.4 Roles of Operation Representative Part 3, Section 12, Subsection 3 5.1.5 Person Responsible for Preparing and Submitting Report Part 5, Section 28, Subsection 1 (f) 5.2 Reporting Operations and Emissions 5.2.1 Operations with Reporting Obligations Part 1, Section 1 5.2.2 Covered Emissions Part 1, Section 2. Schedule A Covered Emissions Single Facility Operations Covered Emissions Linear Facilities 5.2.3 Biomass CO2 Exclusions (Schedule C Biomass) Part 1, Section 1 Part 2, Section 6 5.2.4 Coal Combustion Part 1, Section 2 5.2.5 Exclusions n/a 5.2.6 Sample Cases n/a Page 2

Reporting Regulation Guidance Document Reporting Regulation 5.2.7 Reporting Thresholds Part 2, Sections 6 and 7 5.3 Reporting Period Part 2, Section 8 5.4 Registration of Reporting Operations Part 2, Section 9 5.5 Reporting GHG Emissions 5.5.1 Reporting Timing Part 3, Section 11 5.5.2 Reporting Contents Part 3, Section 12 5.5.3 Historical 2006-2009 Data Reports Part 3, Section 16 5.5.4 Supplementary Reports Part 3, Section 17 6 Calculating Emissions 6.1 Emission Quantification Methodology Part 3, Section 13, Schedule D 6.2 Selection of Quantification Methods Part 3, Sections 13 and 14 6.3 Replacement Methodologies Part 3, Section 13, subsection 4 6.4 Alternative Measurement Parameter Part 3, Section 13, subsection 5 6.5 Choosing Between Measurement Methodologies Part 3, Section 14 6.6 Instrumentation Part 3 Section 15 7 Data Collection and Document Management 7.1 Data Quality Part 3, Section 15 7.2 Document Management 7.2.1 Records and Record Retention Part 5, Sections 27 and 28 7.2.2 Public Disclosure and Confidentiality Part 5, Section 29 8 Inspection and Seizure Powers 8.1 Inspectors Part 5 Sections 30 and 31 8.2 Appeals Part 5, Section 32 Page 3

2. CONTEXT AND PURPOSE OF GHG REPORTING IN B.C. 2.1 Climate Action and B.C. s Approach to Regulating GHGs In accordance with the Greenhouse Gas Reduction Targets Act, the Province of British Columbia (BC) has legislated commitments to reduce B.C. s Greenhouse Gas (GHG) emissions to at least 33% below 2007 levels by 2020, and at least 80% below 2007 levels by 2050. For large emitters (emitters above 25,000 tonnes (t) of carbon dioxide equivalent (CO 2 e) per year), a market-based cap and trade approach has been proposed as one solution to reducing GHG emissions. The Greenhouse Gas Reduction (Cap and Trade) Act was given Royal Assent on May 29, 2008. This Act provides the statutory basis for setting up a cap and trade framework to reduce GHG emissions from large emitters operating within B.C. The details of the cap and trade system are being worked out in cooperation with partners in the Western Climate Initiative (WCI). The WCI is a collaboration of states (Arizona, California, Montana, New Mexico, Oregon, Utah and Washington) and provinces (BC, Manitoba, Ontario and Quebec), that are working together to identify, evaluate and implement policies to tackle climate change at the regional level 1. The cap in the cap and trade system establishes an overall limit on GHG emissions while the trading provisions allow regulated emitters and others to buy, bank or sell emissions allowances and offset units. Those who can reduce emissions more at lower cost are able to sell their surplus unit to those whose emission reductions are more costly. The responsibility for emission reductions in this system is transferred to the emitters, while market forces help determine the distribution of reductions. The Reporting Regulation (B.C. Reg. 272/2009) (the Regulation) was ordered under the authority of the Greenhouse Gas Reduction (Cap and Trade) Act and was promulgated on November 25, 2009. In brief, the Regulation sets out: Criteria for determining which facilities are required to report; Reporting requirements; Quantification methods for emissions; and Verification requirements. The Regulation was designed based on the WCI s Final Essential Requirements for Mandatory Reporting. It contains provisions for the collection of accurate emissions data of a consistent quality and type essential to a cap and trade system, as well as the measurement of GHG emissions so that they can be effectively managed through mitigation projects and policy design. 1 http://www.westernclimateinitiative.org/ Page 4

2.2 Purpose of Guidance Document This guidance document has been developed to provide clarity of the requirements of the Regulation for reporting facility owners and operators, consultants and verification bodies. In some cases, more conventional terms than those contained in the Regulation are used to help clarify the intention of the statute. At all times the Greenhouse Gas Reduction (Cap and Trade) Act and the Reporting Regulation take precedence over information provided in this guidance material. The Reporting Regulation Guidance Document is not intended to provide detailed information on report templates or submission methodology, as these are being be developed separately and made available through the Reporting Regulation website. Page 5

3. KEY DEFINITIONS This section is meant to accompany the definitions provided in Section 1(1) and Schedule A of the Regulation and provide additional guidance on terms used within this document. 3.1 General Terms Attributable GHG emission Where a GHG is to be reported for facility operations as defined in Schedule A of the Regulation, the GHG is attributable to that reporting operation. Biomass Biomass is defined as: a. non-fossilized plants or parts of plants, animal waste or any product made of either of these and includes, without limitation, biomass derived fuels, wood and wood products, agricultural residues and wastes, biologically derived organic matter found in municipal and industrial wastes, landfill gas, black liquor, kraft pulp fibres and sludge gas, and b. any fuels in respect of which the entire heat generation capacity is derived entirely from biomass described in paragraph (a); this includes biofuels and biomass charcoal. Schedule C Biomass The regulations define certain types of biomass deemed to be treated separately and not contribute towards exceeding the reporting or verification thresholds. Note that emissions of other GHGs (CH 4 and N 2 O) from the biomass defined in Schedule C are not excluded. Biomass CO 2 exclusions are defined as wood biomass, or the wood biomass component of mixed fuels, including: wood residue within the meaning of the Forest Act; wood-derived fuel, red liquor and black liquor from pulp and paper production processes; and woody matter from agricultural trimmings, tree thinning and orchard removals. For the purpose of a cap and trade system, wood biomass that fails to meet the criteria for carbon neutrality established by the jurisdiction in which it was produced would not be considered Schedule C biomass. Also not included in Schedule C biomass is the aerobic digestion of other organic matter, or the combustion of the organic content of waste. Greenhouse Gas (GHG): As the sun heats up the Earth, the Earth radiates energy back into space. Gaseous layers prevent this energy from escaping into space, instead radiating it back down to the Earth s surface. There are many gases that have this greenhouse effect. The term greenhouse gas refers to a set of gases with this greenhouse property that are emitted into the atmosphere, in part, through human activity. Greenhouse gases (GHGs) include carbon dioxide (CO 2 ), methane (CH 4 ), nitrous oxide (N 2 O), hydrofluorocarbons (HFCs), perfluorocarbons (PFCs) and sulphur hexafluoride (SF 6 ). Carbon dioxide and, to a lesser extent, methane are the most common GHGs. Common emission sources of these gases include: CO 2 fossil fuel and biomass combustion, cement production; CH 4 fossil fuel and biomass combustion, landfills (anaerobic biomass digestion), livestock (enteric emissions); Page 6

N 2 O fossil fuel and biomass combustion, nitrogen fertilizer use; HFCs HCFC-22 production, refrigeration and air conditioning, some aerosols; PFCs - aluminum production, semi-conductor manufacture, some refrigeration; and SF6 electrical transmission and distribution, semi-conductor manufacturing. Global Warming Potential (GWP): Not all GHGs have the same effect some have much stronger greenhouse effects than others. To simplify GHG accounting, the greenhouse effect of each of gas is referred to as its global warming potential (GWP) and is expressed as carbon dioxide equivalents (CO 2 e). A GWP of 21 would mean that 1 tonne of the particular GHG emitted (in this case methane) has the same warming effect as 21 tonnes of CO 2 over a 100-year time horizon. A list of GWPs for specified gases is provided in Appendix A. Mobile Equipment: Mobile equipment includes mobile equipment other than aircraft, marine vessel or on-road vehicles, used for the on-site transportation or movement of substances, materials or products, and other mobile equipment such as: tractors; mobile cranes; log transfer equipment; mining machinery; graders; backhoes; bulldozers; and other industrial equipment. Mobile equipment excludes on-road vehicles. The term on-road vehicle refers to a motor vehicle that has features normally associated with safe and practical highway use, safety features required by federal or provincial laws, and can exceed a speed of 40 kilometres per hour on a level paved surface. An on-road vehicle does not have features that render its use on a highway unsafe, impractical or highly unlikely. Electricity Import Operation: An operation that imports electricity, at the time when it is delivered to the first point of delivery in BC. Page 7

3.2 Facilities, Emissions and Reporting Operations Facility: Facilities are defined using the following criteria: All buildings, structures, stationary items and equipment that: a) Are located or used primarily on a single site, contiguous sites or adjacent sites; b) Are managed or controlled by the same person; and c) Function as a single integrated site. In addition, the definition of a facility includes wastewater treatment systems provided they are located on or adjacent to the facility site(s) and are managed or controlled by the same person who also manages or controls the facility. The definition of a facility also includes the storage of petroleum products at a terminal that receives petroleum products from a facility, if the terminal is adjacent to the facility and are managed or controlled by the same person who also manages or controls the facility. A facility also includes mobile equipment that functions as a part of the integrated facility site(s), mobile equipment is defined separately in Section 3.1. The term managed or controlled includes contractor and subcontractor activities. Attributable GHG emissions from these activities must be reported, if required (see Section 5.2.2). Activity: Activities for the purpose of the Regulation are those listed in Table 1 or Table 2 of Schedule A. These activities result in GHG emissions that are deemed attributable essentially these activities result in GHG emissions that are quantified as part of a determination as to whether an operation must report and hence must be reported by a reporting operation. Source Type: A source type is a specific category within an activity that results in GHG emissions. For example, for general stationary combustion (the activity), there are two source types of emissions: with useful energy production and without useful energy production. Greenhouse Gas (GHG) Type: Refers to the specific GHG(s) that is emitted from a Source Type. For further information on GHGs see the definition located within this section. Major Source Category: The Regulation allows the Ministry to publish emissions by major source category. Major source categories are defined by the combination of GHG types (e.g., CO 2, CH 4, N 2 O) by category of emission. The eight categories of emissions are flaring, fugitive, industrial process, on-site transportation, stationary fuel combustion, venting, waste and wastewater. Reporting-only Emissions: For the 2011 and subsequent reporting periods, a category of reporting-only emissions has been created. Reporting-only emissions include CO 2 from biomass listed in Schedule C and GHG emissions associated with fuel combustion by mobile equipment and fugitive methane emissions from coal mining. Reportingonly emissions are not considered in calculating to the quantitative verification threshold. A different Page 8

supplementary report threshold applies for reporting-only emissions (i.e., the lesser of 3% or 3,000 tonnes of the total greenhouse gas emissions attributable to the reporting operation). Reporting Operation: A reporting operation is any operation that satisfies the requirements for GHG reporting as defined in Sections 6 and 7 of the Regulation (and described in Section 5.2). Operations are divided into three (3) categories based on the activities that occur within: 1. Single facility operations A facility and carries out an activity listed in Column 2 in Table 1 of Schedule A of the Regulation. Single facility operations include a range of activities including general stationary combustion, electricity generation and a range of production, manufacturing and refining activities. 2. Linear facilities operations All of the facilities within B.C. that are under management and control of the same person and carry out one or more activities listed in Column 2 in Table 2 of Schedule A of the Regulation. Linear facilities operations incorporate activities such as the transportation or transmission of electricity, natural gas, carbon dioxide and oil, as well as oil and gas extraction and processing activities and the stationary combustion required by these. 3. Electricity import operation An operation that undertakes the business of importing electricity at the time when it is delivered to the first point of delivery in BC. Imported electricity means electricity, not generated in a jurisdiction with a cap and trade program approved by the Minister of Environment, delivered from outside BC to a point of delivery in BC, including electricity imported under an exchange program or swap. Imported electricity does not include electricity that has a final point of delivery outside BC or is owned by the Yukon Electrical Company Limited if the final point of delivery is not connected to the North American electrical transmission grid. The nested relationship between operations of one or more facilities, activities of those facilities and associated major sources of GHG emissions, and attributable GHG emissions for the purpose of reporting is described in Figure 1. Page 9

Figure 1 Relationship between Reporting Operations, Activities, Source Types and GHG Types. Page 10

4. SIMPLIFIED REPORTING FRAMEWORK 4.1 Core Requirements A simplified framework of the reporting requirements of the Regulation is presented in Figure 2. This framework is designed to provide an overview of reporting requirements and to help determine whether a facility is required to report emissions and when that reporting is to occur. More detailed guidance and examples that help describe the reporting requirements are provided in subsequent sections of the document. Where a GHG is to be reported for facility operations as defined in Schedule A of the Regulation, the GHG is attributable to that reporting operation. The Operation Representative (see Section 5.1.2) of a facility is responsible for determining and certifying reporting requirements for a particular facility. Figure 2 Core Requirement of the Reporting Framework. Page 11

4.1.1 Who is Required to Report Part 1 of the Regulation defines which operations are required to report their attributable GHG emissions. Reporting operations include: Operations with attributable GHG emissions 10,000 metric tonnes (t) CO 2 e per reporting period, excluding CO 2 produced from biomass listed in Schedule C of the Regulation; BC Hydro (only attributable GHG emissions 10,000 t CO 2 e per reporting period from electricity generating facilities, electricity transmission facilities or electricity import operations); and Electricity import operations. Reporting requirements for electricity import operations begin in the 2011 reporting period. If an operation has reported emissions under the Regulation, but in a subsequent reporting period emissions fall below 10,000 t CO 2 e per year, the operation must continue to report until the operation emits less than 10,000 t CO 2 e for three consecutive reporting periods. If an operation has reported emissions under the Regulation, but in a subsequent period does not produce any attributable emissions defined in Schedule A of the Regulation, then reporting is no longer required. This situation may occur in the event of the permanent closure of an operation. The operator must notify the director within 90 days if an operation ceases to be a reporting operation. The director is a government employee designated in writing by the Minister of Environment for the purpose of the Greenhouse Gas Reduction (Cap and Trade) Act and associated enabling regulations. Sample Case #1 An operations annual emissions history was as follows: Year 2010: 10,800 t CO 2 e Year 2011: 9,500 t CO 2 e Year 2012: 8,900 t CO 2 e Year 2013: 8,600 t CO 2 e Year 2014: 10,200 t CO 2 e Is the facility required to submit a report for 2013 calendar year emissions in 2014? No, since the attributable emissions fall below 10,000 t CO 2 e for three consecutive reporting periods (2011, 2012 and 2013) an emissions report does not have to be submitted for the 2013 reporting period. However, since emissions in 2014 exceed the 10,000 t CO 2 e threshold, an emissions report for the 2014 period will be required in 2015. 4.1.2 What to Report Schedule A of the Regulation defines which GHG emissions are attributable to a facility for the purpose of reporting. These attributable GHG emissions are based on the activities and associated sources for the Page 12

facility or facilities of a single or linear facilities operation (e.g., acid gas scrubbers and acid gas reagent emissions (source type) from copper or nickel production (activity)). All GHG emissions must be reported in metric tonnes of carbon dioxide equivalent (t CO 2 e). For electricity import operations, for the 2011 and subsequent reporting periods, Schedule D of the Regulation defines the methodology for determining which GHG emissions are attributable for the purpose of reporting. 4.1.3 New Reporting Operations New operations, or an existing operation that may become a reporting operation within a reporting period must forecast emissions and register with the Ministry. Reporting operations that submitted an emissions report for the previous calendar year do not need to re-register. Between January 1 and February 28, operations must forecast whether attributable GHG emissions, not including CO 2 from biomass sources listed in Schedule C, are likely to be 10,000 t CO 2 e. If the forecast exceeds 10,000 t CO 2 e, the operation is required to register before March 31 st. If the facility forecasts less than 10,000 t CO 2 e, but actual emissions then exceed 10,000 t CO 2 e, the facility is required to register within 90 days of the date the attributable GHG emissions for the reporting period meets or exceeds 10,000 t CO 2 e. For the 2011 reporting period, electricity import operations are required to register before March 31 st, 2011. New electricity import operations beginning after January 1 st, 2011 are required to report within 90 days of the day the operation begins. The facility must register with the director detailing the following: Administrative particulars; North American Industry Classification System (NAICS) codes; Facility location(s), a) For a single facility operation, this means street address and geographic coordinates. b) For a linear facilities operation, this means street address and geographic coordinates for each facility within the operation that has attributable GHG emissions during the reporting period of 10 000 t CO 2 e, not including carbon dioxide produced from biomass listed in Schedule C. Statement specifying the type of reporting operation: single facility, linear facilities or electricity import (for the 2011 and subsequent reporting periods); and Identify activities occurring at the facility that are listed in Schedule A, Tables 1 and 2. As part of the registration, if the operation is a single facility operation or liner facility operation, the facility must also forecast which GHG emission range (excluding biomass listed in Schedule C) the facility will fall under: Less than 10,000 t CO 2 e per year (voluntary registration); 10,000 to 25,000 t CO 2 e per year; Page 13

25,000 to 50,000 t CO 2 e per year; 50,000 to 100,000 t CO 2 e per year; or More than 100,000 t CO 2 e per year. 4.1.4 Verification Requirements For the 2010 reporting period, the Regulation required that reporting operations with annual GHG emissions 25,000 t CO 2 e (exclusive of CO 2 from Schedule C biomass) include a verification statement with their emissions report. For the 2011 and subsequent reporting periods, the Regulation requires that reporting operations with annual GHG emissions 25,000 t CO 2 e (exclusive of reporting-only emissions) include a verification statement with their emissions report. For the 2010 and 2011 reporting periods, the verification statement can be submitted by September 1 st of the year following the reporting period (at the same time a supplementary report is submitted). Further information on verification of emission reports is contained in the BC Reporting Regulation Verification Guidance Document. Sample Case #2 An open pit mining operation ships product overseas for refining. An on-site grinding mill operates using a mechanical process run by electricity. Total annual emissions from mobile equipment are approximately 35,000 t CO 2 e. Annual emissions from stationary combustion sources are approximately 1,000 t CO 2 e. Is this operation required to report GHG emissions? The mining operation needs to report emissions since attributable GHG emissions exceed 25,000 t CO 2 e and the facility undertakes the general stationary and mobile equipment combustion activities in Schedule A, Table 1, items 1 and 2 of the Reporting Regulation. Verification is required for 2010 emission reports. Verification is not required for 2011 and subsequent emission reports since mobile equipment are reporting-only sources excluded from calculating the verification threshold. 4.1.5 When to Report Annual reporting periods for existing facilities commenced with the 2010 calendar year. If total GHG emissions during any calendar years 2006 to 2009 exceeded 20,000 t CO 2 e (excluding emissions of CO 2 from biomass sources listed in Schedule C), then the operator was required to submit a historical emissions report at the same time as the emissions report for 2010. For new operations that commence operations part way through a calendar year, the first reporting period commences the day the operation starts to operate and ends on December 31 st of that year. An emissions report must be submitted to the director on or before March 31 st for the previous reporting period. The timeline for GHG reporting is summarized in Table 2. Page 14

Table 2 Reporting Timeline. Reporting Year Year Immediately Following Reporting Year Timeline January 1 st February 28 th Facility That May Become a Reporting Operation in the Current Reporting Period Forecast emissions n/a March 31 st Register if forecast emissions 10,000 t CO2e Throughout the Reporting Year If emissions 10,000 t CO2e during the reporting year then register within 90 days. March 31 st Submission deadline for emissions report. Submission deadline for verification statement (requirement starts with 2012 reporting year) September 1 st Submission deadline for emissions report that includes a verification statement (2010 and 2011 reporting years only) n/a n/a Facility That Reported Emissions in the Previous Calendar Year Submission deadline for emissions report Submission deadline for verification statement (requirement starts with 2012 reporting year) Submission deadline for emissions report that includes a verification statement (2010 and 2011 reporting years only) 4.2 Excluded Facilities An operation does not have to report if: It is a single facility or linear facilities operation with attributable GHG emissions < 10,000 t CO 2 e per year (excluding CO 2 produced from biomass listed in Schedule C of the Regulation), subject to the restrictions in Section 7 of the Regulation. Any activity/emission source/ghg combination not listed in Tables 1 and 2 in Schedule A of the Regulation. For example emissions of hydrofluorocarbons (HFCs) used in fire suppression systems are not covered in Schedule A, therefore do not have to be reported. A public sector organization with the exception of BC Hydro and any of its subsidiaries electricity generation, transmission facilities and electricity import operations. A public sector organization is defined in the Greenhouse Gas Reduction Targets Act as any of the following: a) the Provincial government; b) an organization or corporation that is not part of the Provincial government but is included within the government reporting entity under the Budget Transparency and Accountability Act, unless excluded by regulation under the Greenhouse Gas Reduction Targets Act; and c) any other public organization or corporation included by regulation. Landfill operations do not have to report landfill gas emissions, where landfill gas is defined as a mixture of gases generated by the decomposition of municipal solid waste. Emissions from the combustion or flaring of landfill gas need to be reported if, in combination with other attributable sources at the landfill operation, emissions meet or exceed the 10,000 t CO 2 e reporting threshold. Page 15

5. REPORTING REQUIREMENTS 5.1 Responsible Parties 5.1.1 Management and Control of Reporting Operation Meeting the requirements of the Regulation is the responsibility of the operator of each reporting operation, where the operator is the person or persons who own the operation and manage or control the operation. Where the owner is different from the person who manages or controls the operation (e.g., where management is contracted to a different firm), both groups of persons would be considered operators and would ultimately be responsible for meeting the reporting requirements. Where the operator of a reporting operation changes during a reporting period (e.g., the reporting operation is purchased by another company), the new operator who is the operator on the last day of the reporting period is responsible for submitting the emission report. The exception to this would be if the former operator has not provided sufficient information to the new operator to allow them to submit a complete report. 5.1.2 Operation Representative The Operation Representative acts as a point of contact and signing authority for the operation with respect to the Regulation. Where the operator is one individual, rather than a corporation or other entity, then this individual is automatically the Operation Representative. Where the operator is something other than an individual (e.g., where the operator is a corporation) or there are multiple operators, the Regulation requires that an individual be designated as the Operation Representative. In the case of a single operator, the Operation Representative must either be: a Senior Officer of the corporation (if applicable) who performs a policy-making function and has the ability to influence the direction of the company; or the individual with primary responsibility for the operations and management of the reporting operation. The Operation Representative is a senior-level official. An operational position, such as the Environmental Superintendant or Air Emissions Specialist, does not typically have sufficient authority to be considered an Operation Representative for the purpose of the Regulation. 5.1.3 Multiple Operators Where there are multiple operators, the Operation Representative must be authorized in writing by all of the operators or at least by the operator who manages the operation. Multiple owners can occur where, for instance, multiple companies own the operation or different entities own and manage the operation (e.g., where participants in a joint venture contracts management of an operation to a third company). Options for designating an Operation Representative are illustrated in Figure 3. Page 16

Figure 3 Designating an Operation Representative. Sample Case #3 Company with Multiple Subsidiaries An oil and gas company owns three subsidiaries, each of which owns multiple oil and gas production and processing facilities. Individual facilities are considered to be part of the reporting operation that they are managed and controlled by. Assuming that the subsidiaries are managed and controlled by the parent company (which in most cases they would be), then each of their facilities would be considered as part of their overall linear facilities operation (i.e., the three subsidiaries would report their facilities together under one linear facilities operation to be reported by the parent company). 5.1.4 Roles of Operation Representative The Operation Representative s primary role is to certify in writing for each submitted emissions report that they have examined the report and that it meets the requirements of the Regulation. This certification effectively binds the reporting operation to the contents of the emissions report. All emissions reports are certified, including those submitted under the following circumstances: A report for an operation emitting 10,000 t CO 2 e per year; A report for an operation with verification obligations; Emissions for the reporting year in question fall below 10,000 t CO 2 e per year; and The operation had previously been required to report emissions (e.g., attributable annual emissions were greater than 10,000 t CO 2 e in a previous year) and thus is considered a reporting operation. Page 17

5.1.5 Person Responsible for Preparing and Submitting Report The operator of a reporting operation is ultimately responsible for collecting data and submitting emissions reports. The physical preparation and submission of the emissions report will most likely be conducted by the Operation Representative or delegated to an appropriate staff member or consultant with appropriate skills and experience in preparing emission reports. This person primarily responsible for preparing and submitting an emissions report also needs to be identified in the report. 5.2 Reporting Operations and Emissions Reporting operations and emissions are described in Sections 5.2.1 through 5.2.5, and illustrated through a range of sample cases provided in Section 5.2.6. 5.2.1 Operations with Reporting Obligations Reporting operations are broken down into three (3) types of operations, which are defined by the associated types of GHG emitting activities. 1. Single facility operation an operation that operates in a facility and carries out a covered activity listed in Column 2 in Table 1 of Schedule A of the Regulation. Single facility operations incorporate a range of activities including general stationary combustion, electricity generation and a range of production, manufacturing and refining activities. 2. Linear facilities operations all of the facilities within B.C. that are under the management and control of the same person and carry out one or more activities listed in Column 2 in Table 2 of Schedule A of the Regulation. Linear facilities operations incorporate activities such as the transportation or transmission of electricity, natural gas, carbon dioxide and oil, as well as oil and gas extraction and processing activities and the stationary combustion required by these operations. 3. Electricity import operations operations that import electricity into BC at the first point of delivery into BC. Page 18

Figure 4 Reporting Operations for Single and Linear Facilities. (NOTE: the two single facilities are separate reporting operations even if they are managed and controlled by the same company, whereas each linear facility is part of the same reporting operation provided they are managed and controlled by the same company.) Sample Case #4 Linear facilities operation A company has facilities involved in both oil transportation and natural gas transmission (Figure 5). In this case, all facilities managed or controlled by the company will be included in the same linear facilities operation (i.e., the operation will report as one linear facilities operation). Page 19

Figure 5 Linear Facilities Operation (Sample Case #4). 5.2.2 Attributable Emissions GHG emissions from a facility are defined as either attributable or unattributable. For single facilities and linear facilities operations, emissions are attributable and must be reported if they result from one of the activities listed in Column 2 in Tables 1 (Single Facility Operations) and 2 (Linear Facilities Operations) of Schedule A of the Regulation. An operation may have more than one activity generating attributable GHG emissions, all of which must be reported. For electricity import operations, attributable emissions are defined in Schedule D of the Regulation. If an activity is not listed in Tables 1 and 2 of Schedule A of the Regulation, associated emissions are unattributable and only need to be reported as described in Checklist #2 (Table 4) if it is estimated that these annual emissions exceed 100 t CO 2 e per activity. Attributable emissions from Single Facility Operations Attributable emissions from single facility operations occur as a result of the following activities, listed in Table 1 of Schedule A of the Regulation: 1. General Stationary Combustion 2. Mobile Equipment Fuel Combustion (except for linear facilities, generally on-site, off-road equipment) 3. Aluminum or Alumina Production 4. Ammonia Production 5. Cement Production 6. Coal Mining from Underground Mines 7. Coal Storage at Facilities that Combust Coal 8. Copper or Nickel Smelting or Refining 9. Electricity Generation 10. Electronics Manufacturing Page 20

11. Ferroalloy Production 12. Glass Manufacturing 13. Hydrogen Production 14. Industrial Wastewater Processing 15. Lead Production 16. Lime Manufacturing 17. Magnesium Production 18. Nitric Acid Manufacturing 19. Petrochemical Production 20. Petroleum Refining 21. Phosphoric Acid Production 22. Pulp and Paper Production 23. Refinery Fuel Gas Combustion 24. Zinc Production Emissions sources are listed in Column 3, and associated GHG types in Column 4 of Table 1 of Schedule A. More than one activity can occur at a single facility operation and each activity may have one or more emissions sources, which would emit one or more types of GHGs. For example, general stationary combustion (the activity) may emit CO 2 (the GHG type) during either useful energy production or non-useful energy production (the source). Figure 6 provides an example of multiple activities, sources and GHG types, using the example of a petroleum refinery. Figure 6 Single Facility Operation with Multiple Activities and Source Types. Page 21

Attributable Emissions from Linear Facilities Operations Linear facilities operations include operations where the following Table 2 activities are conducted either in conjunction with, or separately from activities listed in Tables 1 of Schedule A: 1. General Stationary Combustion at any operation or facility that carries out oil and gas extraction, gas processing, electricity transmission, natural gas transmission, natural gas distribution, natural gas storage, oil transmission or carbon dioxide transportation; 2. Oil and gas extraction and gas processing activities; 3. Electricity transmission; 4. Natural gas transmission, distribution or storage; 5. Oil transmission; and 6. Carbon dioxide transportation. These activities may have one or more emissions sources, which would emit one or more types of GHGs. For example, oil and gas extraction and gas processing activities (the activity) may emit CH 4 (the GHG type) during either venting, flaring or from fugitive emissions (the source). Fuel combustion by mobile equipment at a facility carrying out activities listed in Column 2 of Table 2 of Schedule A are not attributable to linear facilities. Attributable Emissions from Electricity Import Operations For the 2011 and subsequent reporting periods, the emissions attributable to an electricity import operation are the emissions associated with the production of the imported electricity. Schedule D of the Regulation provides the methodology for determining attributable emissions from electricity import operations. 5.2.3 Biomass CO 2 Exclusions (Schedule C Biomass) Biomass CO 2 emissions are excluded from the calculation of GHG emissions for wood biomass, or the wood biomass component of mixed fuels, including wood residue within the meaning of the Forest Act; wood-derived fuel, red liquor and black liquor from pulp and paper production processes, and woody matter from agricultural trimmings, tree thinning and orchard removals. The biomass CO 2 exclusion does not extend to: wood biomass that fails to meet the criteria for carbon neutrality established by the jurisdiction in which it was produced, if any; aerobic digestion of other organic matter; or combustion of the organic content of waste. Page 22

CH 4 and N 2 O emissions from all biomass combustion must always be reported and considered to determine whether the facility has exceeded the reporting threshold. CO 2 emissions from wood biomass as defined above must be reported only when other attributable GHG emissions are 10,000 t CO 2 e per year. CO 2 emissions from wood biomass will not cause an operation to exceed the reporting threshold. However, if the operation is required to report due to other attributable GHG emissions, then the Schedule C biomass emissions must also be reported (Figure 7). Fossil Fuel Combustion Non-Schedule C Biomass Combustion Emissions reported separately only if facility exceeds reporting threshold CO 2 CH 4 N 2 O CO 2 CH 4 N 2 O CO 2 Emissions added to determine whether the facility has exceeded the reporting threshold CH 4 N 2 O Schedule C Biomass Combustion Figure 7 Combustion Emissions and the Reporting Threshold. Sample Case #5 Schedule C biomass Two single facility operations both use wood waste for co-generation: Attributable emissions from all activities at Facility A are 20,000 t CO 2 e/year, 15,000 t CO 2 e of which come from wood residue combustion. Attributable emissions from all activities at Facility B are 20,000 t CO 2 e/year, 5,000 t CO 2 e of which come from wood residue combustion. Subtracting Schedule C biomass emissions that come from wood residue combustion from the emissions of both facilities, Facility A has remaining emissions of 5,000 t CO 2 e and Facility B has remaining emissions of 15,000 t CO 2 e. Therefore, Facility A does not need to report emissions, but Facility B will have to report 20,000 t CO 2 e of emissions, 15,000 t CO 2 e from non-schedule C biomass emissions and 5,000 t CO 2 e from Schedule C biomass emissions. Page 23

5.2.4 Coal Combustion Facilities that combust coal are responsible both for emissions occurring from the combustion of coal (activities in Column 2 of Tables 1 and 2 in Schedule A) and for fugitive emissions from coal storage (and any other attributable activities). The methodology reference for quantifying fugitive emissions from coal storage is provided in row 7, Column 5 in Table 1 of Schedule A. The coal storage quantification method assigns responsibility to the facility that combusts coal for fugitive emissions occurring during the transportation and storage of coal to the associated combustion facility. Responsibility of the facility for fugitive emissions begins once the coal is mined. This includes fugitive emissions during handling, processing and transport to the facility. 5.2.5 Exclusions Emissions reporting is limited to activities, sources and GHG types listed in Tables 1 and 2 of Schedule A. This is not an exhaustive list of all possible emissions that could occur at a reporting operation. There are some emissions that are not included as attributable (i.e., exclusions). Rather than consider all of the emissions sources that are excluded from reporting, reporting operations should refer to Tables 1 and 2 in Schedule A of the Regulation and only treat the emissions found therein as attributable. Sample cases #6 and #7 describe situations where emissions sources would be excluded. Sample Case #6 HFC emissions from cooling units HFC emissions from cooling units in a facility that generates electricity are attributable for a single site facility. However, HFC emissions from cooling units associated with any other activity are unattributable. Sample Case #7 Grounds maintenance Operation of mobile equipment involved in grounds maintenance would be attributable. GHG emissions associated with fertilizer application or changes in the amount of biomass sinks located on facility property would be unattributable. 5.2.6 Sample Cases Subcontractor emissions Sample Case #8 On-site contractor emissions A coal mine contracts all of the above-ground transportation of coal occurring on-site to a contractor who owns a fleet of off-road mobile equipment. In this case, since the mobile equipment functions as part of the integrated facility site, the activities of the contractor would be included as part of the facility. Page 24

Sample Case #9 Off-site contractor emissions A pulp and paper mill is provided with raw materials from contractors operating at a variety of different logging sites. What equipment is included as part of the reporting operation? Forestry operations are single facility operations. The reporting operation includes those pieces of equipment used on-site and/or at a site that was either adjacent or contiguous. The operation would not include any activities such as Mobile Equipment Fuel Combustion occurring at the various sites where contractors were harvesting wood. What emissions are attributable? The operation is responsible only for the emissions occurring at the facility, or at a site contiguous or adjacent to the facility that result from the activities listed in Table 1 of Schedule A of the Regulation. Mobile emissions Sample Case #10 Mobile emissions from a single facility A cement producer operates a fleet of forklifts on-site as well as a fleet of delivery trucks to transport the finished product to market. What mobile equipment is included as part of the reporting operation? Only mobile equipment that is not an on-road vehicle (i.e., cannot exceed 40 km/h and is not considered practical for highway use) is included as part of a single facility operation. The emissions from the fleet of forklifts would therefore be attributable. The delivery trucks would be unattributable since they meet the definition of on-road vehicles. Sample Case #11 Mobile emissions from a linear facilities operations An oil and gas extraction and processing operation includes a large facility with a number of truck mounted construction cranes as well as a mobile drilling rig. What mobile equipment is included as part of the reporting operation? Oil and gas extraction is attributable to a linear facilities operation. Mobile equipment is not found in Table 2 of Schedule A and is excluded from the reporting operation. Therefore, the truckmounted construction cranes are not included within the operation. However, the linear facilities operation including each individual facility emitting more than 1,000 t CO 2 e and carrying out either oil and gas extraction and processing, oil transmission, or carbon dioxide transportation activities (Schedule A, Table 2, rows 2, 5, and 6) have to report emissions from mobile drilling rigs (while in use at the facility, but not while moving from site to site) as considered in the general stationary combustion definition in the Regulation and prescribed in the WCI quantification methods. Page 25

Landfill gas Sample Case #12 Emissions from a landfill The single facility operation is a landfill where 50% of the landfill gas is captured, half of which is flared on-site and half is supplied to a company that uses it for cogeneration at a greenhouse. What is included as part of the reporting operation? The operation is responsible for the landfill gas that is flared on-site, but is not responsible for the landfill gas that is supplied downstream off-site to another company (the other company would be responsible for these emissions). What emissions are attributable? All GHGs emitted from the flaring of landfill gas are covered as they are considered to occur from the activity General Stationary Combustion. Any emissions from other activities found in Table 1 of Schedule A are also covered, which may include Mobile Equipment Fuel Combustion, depending on how the waste is managed on-site. Landfill gas emissions that are not captured do not need to be reported by the operation as they are not covered by an activity in either Table 1 or Table 2 of Schedule A of the Regulation. These emissions are regulated under the Landfill Gas Management Regulation. Oil transmission Sample Case #13 Oil transmission to Vancouver Island A linear facilities operation includes a terminal for oil transmission on Vancouver Island that is serviced by barge from the BC Lower Mainland. What is included as part of the reporting operation? Schedule A defines a terminal as occurring at the end of a pipeline. Since the terminal on Vancouver Island is reached by barge and not by pipeline, the terminal does not fall within an activity in Table 2 of Schedule A and is not attributable. However, if other activities listed in Table 2 of Schedule A occurred at the terminal, then the terminal would be included in the linear facilities operation (as explained in Sample Case #6, more than one activity can be included in the same linear facilities operation provided it is controlled or managed by the same company) What emissions are attributable? Assuming that the Vancouver Island terminal does not carry out any activity listed in Column 2 of Table 2 of Schedule A, it might be a single facility operation separate from the linear facilities operation if it carries out an activity listed in Column 2 of Table 1 of Schedule A. The Vancouver Island terminal would, for instance, be a single facility operation if the facility engages in General Stationary Combustion or petroleum refining (see definitions in Section 1 of Schedule A). Whether the facility was required to report would then be determined by whether it exceeded the reporting threshold (see Section 5.2.7). Note that fugitive emissions from oil and refined petroleum product storage are not attributable emissions for a single facility, while venting emission are attributable. Page 26

5.2.7 Reporting Thresholds Figure 8 provides a flow diagram which can be used to determine if a single facility or linear facilities operation will need to report its emissions 2. There are two groups of operations that will need to report: 1. All operations with attributable emissions greater than or equal to 10,000 t CO 2 e from sources other than biomass emissions described in Schedule C within the reporting period. 2. Operations with attributable emissions less than 10,000 t CO 2 e from sources other than biomass emissions described in Schedule C within the reporting period, but that had emissions greater than or equal to 10,000 t CO 2 e from sources other than biomass emissions described in Schedule C within the last 3 reporting periods, unless: a) The operation is a single facility operation that did not carry out any of the activities listed in Table 1 of Schedule A in the most recent reporting period, other than industrial wastewater treatment or the use of mobile equipment for the purpose of decommissioning the operation; or b) The operation is a linear facilities operation that did not carry out any activities listed in Table 2 of Schedule A in the most recent reporting period. For electricity import operations that are required to report for the 2011 and subsequent reporting periods, no reporting threshold applies. 2 A similar mechanism is used to determine if the 25,000 t CO 2e verification threshold has been exceeded is described in the Ministry s Verification Manual. Page 27

Figure 8 Understanding Reporting Thresholds. 5.3 Reporting Period The annual emissions reporting period covers the calendar year, from January 1 to December 31 inclusive, starting in 2010 for single and linear facilities operations, and 2011 for electricity import operations. For facilities that begin operating part way through a calendar year, their first reporting period begins on the first day of operation and ends on December 31 of that year. If a reporting operation permanently ceases to operate prior to the end of a calendar year, then the last day of operation would be considered the end of the reporting period. 5.4 Registration of Reporting Operations Becoming a Reporting Operation Operations that are required by the Regulation to report their emissions must first register their operation with the Ministry. Other operations may also register on a voluntary basis. Page 28

The first step in this process is for the operator of an operation that did not submit an emissions report in the previous year, but that may become a reporting operation during the current reporting period (i.e., current calendar year), to forecast the attributable emissions for the operation for that reporting period. Forecasting is intended to be a simplified process, and does not require the use of particular approved methodologies. If forecasted emissions, excluding CO 2 from biomass listed in Schedule C of the Regulation, are greater than or equal to 10,000 t CO 2 e, then the operation is required to register by March 31 of the reporting year. Where emissions are forecasted to be less than 10,000 t CO 2 e, but the operation s emissions nonetheless exceed this threshold at some point during the reporting period, the operation would need to register within 90 days of the date on which emissions equalled or exceeded the 10,000 t CO 2 e threshold. These requirements are illustrated in Figure 9. Operations that have previously registered do not need to register in subsequent years. Figure 9 Decision Tree for Determining Whether or Not an Operation Must be Registered. Registrations must be completed for each individual reporting operation (i.e., separate registration forms for each single facility operation or for a complete linear facilities operation). Comprehensive Page 29

GHG Reporting Registration Instructions have been prepared by the Ministry and are available online. Sample Case #14 A new industrial facility is slated to become operational on May 1, 2011. The operator of this facility prepares a forecast of attributable emissions for the 2011 reporting period (May 1 to Dec 31, 2011 in the case of this particular facility) on February 1, 2011. Forecasted emissions are expected to be 50,000 t CO 2 e over that period, and thus this facility will become a reporting operation in 2011. The operator must therefore register the facility as a reporting operation by March 31, 2011. Sample Case #15 A small oil & gas company owns a limited number of gas wells. On January 15, 2010 an emission forecast for this linear facilities operation is made by the operator, and shows that emissions are expected to be below the 10,000 t CO 2 e reporting threshold. As a result, the operation is not registered. However, on July 15 of that year, the company acquires a number of additional gas wells from a different company, such that on August 10 the total attributable emissions for this linear facilities operation since Jan 1, 2010 first exceed the 10,000 t CO 2 e threshold. The operator of the linear facilities operation then has 90 days in which to register the operation as a reporting operation. Ceasing to be a Reporting Operation There are two cases where the operator of a reporting operation is required to notify the director that the operation has ceased to be a reporting operation: Single facility operation: it did not carry out any of the activities listed Column 2 of Table 1 of Schedule A of the Regulation for an entire reporting period, except for industrial wastewater treatment or the use of mobile equipment for the purpose of decommissioning the operation; and Linear facilities operation: it did not carry out any of the activities listed Column 2 of Table 2 of Schedule A of the Regulation for an entire reporting period. The director must be notified with 90 days of one of the above conditions being satisfied. 5.5 Reporting GHG Emissions 5.5.1 Reporting Timing Reports must be submitted by March 31 for the preceding calendar year. For example, reports for the 2011 reporting period must be submitted by March 31, 2012. 5.5.2 Reporting Contents Reports must be submitted to the one-window reporting (OWR) system which is designed to meet the requirements of both the Regulation and Environment Canada s Section 46 notice. The OWR interface includes data entry fields for all information required to be reported. In a few instances Page 30

template files will be provided to reporters for submitting specific information. These files would then be attached to the emissions report. Further guidance on the OWR interface, including training materials, are available to operators on the s OWR website. The specific information that is required to be reported is outlined in Section 12 of the Regulation. Checklist 1 (Table 3) is provided here to guide operators in the information that will need to be compiled for reporting by all reporting operations. Single site and linear facilities operations with attributable emissions greater or equal to 10,000 t CO 2 e excluding CO 2 emissions from Schedule C biomass in the current reporting year would, in addition to the information noted in Checklist 1, include the information specified in Checklist 2 (Table 4). Single site and linear facilities operations that are required to report but have attributable emissions lower than 10,000 t CO 2 e excluding CO 2 from Schedule C biomass in the current reporting period would include the information specified in Checklist 3 (Table 5) in addition to that in Checklist 1 (Table 3). Electricity import operations would include additional information specified in Checklist 4 (Table 6). Single site and linear facilities operations Checklists 1, 2 and 3 Electricity import operations Checklists 1 and 4 For the 2012 and subsequent reporting periods, single site and linear facilities operations are required to provide process flow diagrams that show, to a reasonable level of detail, the processes that result in GHG emissions. For a linear facilities operation, more than one process flow diagrams may be required to show multiple facilities. Process flow diagram(s) should include all individual sources of emissions over 100 t CO 2 e (e.g., generators or boilers). Source types that cumulatively exceed 250 t CO 2 e should also be included. For example, for the source type emissions from fuel combustion, emissions from an individual vehicle may not exceed 100 t CO 2 e in a reporting period. However, a facility with numerous vehicles that cumulatively exceed 250 t CO 2 e should be included in the process flow diagram. A sample process flow diagram is provided in Appendix B. Page 31

Table 3 Checklist #1: All Reporting Operations. Requirement 1. The trade name, if any, of the reporting operation (for the 2011 and subsequent reporting periods). 2. Legal name of the parent companies of the operator, their head office mailing address and their percent ownership of the operation (applicable for both Canadian and non- Canadian parent companies). 3. Name and head office mailing address of the operator. 4. Name and contact information for both the operation representative and the person responsible for preparing the report. 5. Unique B.C. identification number of the reporting operation (if the operation has been provide with one). 6. The name, street address and geographical coordinates of a single facility operation or of each facility in a linear facilities operation with attributable emissions (not including Schedule C biomass) greater or equal to 1,000 t CO2e. 7. The National Pollutant Release Inventory (NPRI) identification number(s) assigned to the operation by Environment Canada. Single and Linear Facilities Operations - Included? Electricity Import Operations - Included? N/A N/A 8. NAICS code(s) of the reporting operation. N/A 9. The business number of the reporting operation, as defined in the Income Tax Act (for the 2011 and subsequent reporting periods). 10. The Dun and Bradstreet (DUNS) number of the operator (for the 2011 and subsequent reporting periods). N/A N/A 11. Identification of the reporting period and the date of submission (automatically generated). 12. The current permit numbers of the reporting operation issued under Section 14 of the Environmental Management Act, if any. N/A 13. The amount of CO2 captured for on-site storage or use, or transportation off-site. N/A 14. A certification statement signed by the operation representative asserting that they have read the report and that it conforms to the Regulation. 15. Historical data reports if required (see Section 5.5.3). N/A 16. Process flow diagram showing the process that result in GHG emissions (for the 2012 and subsequent reporting periods) (See Appendix B Sample Process Flow Diagram). N/A 17. A verification statement if required (see Section 4.1.4). For single facilities and linear facilities operations with emissions 10,000 t CO 2 e in the current reporting year, the report must also contain information specified in Checklist 2 (Table 4). Page 32

Table 4 Checklist #2: Additional reporting requirements for single and linear facilities emitting 10,000 t CO 2e in the current reporting period. Row Requirement Explanation Additional Guidance for Linear Facilities Included? 1 The total GHG emissions attributable to the reporting operation during the reporting period 2 Emissions of each GHG from each source type A sum of all of the attributable emissions occurring at the operation. Attributable emissions are calculated from the sources (Column 3) and activities (Column 2) provided in Tables 1 and 2 of Schedule A. GHGs that must be included for each source are listed in Column 4 and must be reported separately. Must be reported separately for each of the following: All facilities aggregated Each facility with attributable emissions 10,000 t CO2e excluding Schedule C biomass Aggregated facilities not identified in the bullet immediately above Each facility with attributable emissions 1,000 t CO2e but < 10,000 t CO2e excluding Schedule C biomass Same as above Unattributable emissions exceeding 100 t CO2e do not need to be quantified, but must be listed separately and accompanied by a description of associated activities and sources as well as the type of GHGs that are emitted from each source. 3 The GHG emissions divided by categories of emissions All attributable reported emissions must be aggregated and categorized as per the categories provided in Column 2 of the table in Schedule B. Categorization is accomplished by referring to Column 3 of the same table which attributes each source found in Tables 1 and 2 of Schedule A to a category. Each reported unattributable emission must be categorized as per the categories provided in Column 2 of the table in Schedule B separately, using the source types categorized in Column 3 of Schedule B as guidance. Same as above. Page 33

Row Requirement Explanation Additional Guidance for Linear Facilities Included? 4 Identification of methodology used to quantify each source type Quantification methods for attributable emissions can be found in the rules, codes and standards referenced in Column 5 of Tables 1 and 2 of Schedule A. Replacement methodologies can be used in specific instances as per Section 6.3 of this guidance document, but a description of the methodology must be included. Replacement methodologies that have not been pre-approved must be accompanied by an explanation why it is impracticable to use the prescribed methodology and how the alternate methodology is as practicable as possible. If more than one methodology has been used for a single source, then the emissions quantified by each method must be reported separately. Must be reported separately for each of the following: All facilities aggregated Each facility with attributable emissions 10,000 t CO2e excluding Schedule C biomass Aggregated facilities not identified in bullet above 5 Additional information required by standards, codes and rules The standards, codes and rules listed in Column 5 of Tables 1 and 2 of Schedule A may require additional information for each activity occurring at the facility (Column 2). This must be included in the report. Same as above For a single facility or linear facilities operation that has emitted < 10,000 t CO 2 e (in entirety) during the current reporting year, the report must also contain the information specified in Checklist 3 (Table 5). Table 5 Checklist #3: Additional requirements for single or linear facilities operations that emitted < 10,000 t CO 2e in entirety during the current reporting year that do not have verification obligations from the previous reporting year. Requirement Explanation Included? The total GHG emissions attributable to the operation during the reporting period An assertion/certification that the reported GHG emission are complete and accurate An explanation why emissions are lower A sum of all attributable emissions occurring at the operation The assertion must be in the form provided by the director and must be made by the operation s representative. The report must contain an explanation of why the emissions (excluding emissions from Schedule C biomass) are now lower than 10,000 t CO2e. Possible explanations could include a switch to a less GHG intensive fuel, decrease in production at the operation, efficiency measures etc. Page 34

Table 6 Checklist #4: Additional requirements for electricity import reporting operations. Requirement Explanation Included? The total GHG emissions attributable to the operation during the reporting period Reporting requirements referred to in Section 4 of Schedule D of the Regulation A sum of all attributable emissions occurring at the operation A list of reporting requirements specific to electricity import operations is provided in Schedule D Sample Case #16 Reporting single facility operation A pulp and paper facility has total attributable emissions of 40,000 t CO 2 e in the current year not including schedule C biomass. Reporting Requirements: The facility operation will have to report using the OWR system form provided by the director and must include the information described in Checklists 1 and 2. Sample Case #17 Reporting linear facilities operation Linear facilities operations with total attributable emissions of 60,000 t CO 2 e: Facility #1 with attributable emissions of 30,000 t CO 2 e, no emissions from Schedule C biomass. Facility #2 with attributable emissions of 20,000 t CO 2 e, 15,000 t CO 2 e of which are from Schedule C biomass combustion. Facilities #3-#7 (5 in total) with attributable emissions of 1,500 t CO 2 e each, no emission from Schedule C biomass. Various other facilities with attributable emissions totalling 2,500 t CO 2 e, no emission from Schedule C biomass and none exceeding 1,000 t CO 2 e. Reporting Requirements: The facility operation will have to report using the form provided by the director and must include the information described in Checklists 1 and 2. Checklist #1 - Row 6 of Checklist #1 will require that Facilities #2-#7 include the name, street address and geographic coordinates. Checklist #2 - Reporting will be as follows: All facilities aggregated report rows 1-5. Facility #1 reports rows 1-5, as it is above 10,000 t CO 2 e not including Schedule C biomass. All facilities except Facility #1 aggregated report rows 1-5. Facilities #2-#7 report rows 1-3 individually, as each of these facilities is above 1000 t CO 2 e not including Schedule C biomass. Page 35

Sample Case #18 Single facility operation with decreasing emissions A single facility operation emitted 15,000 t CO 2 e (excluding emissions from Schedule C biomass) in the previous reporting period, but only 7,500 t CO 2 e in the current reporting period. Reporting Requirements: Since the facility has emitted greater than 10,000 t CO 2 e (excluding emissions from Schedule C biomass) in one of the three previous reporting periods, the facility must still report. The single facility operation will have to report using the form provided by the director and must include the information described in Checklists #1 and #3. 5.5.3 Historical 2006-2009 Data Reports Historical data reports, if applicable, must be submitted by March 31, 2011 along with the first emissions report (see Figure 10). They are required for each individual year of operation between 2006 and 2009 where attributable emissions excluding emissions from Schedule C biomass are greater than or equal to 20,000 t CO 2 e. Sample Case #19 Historical Reports Historical emissions from an operation were as follows: Year Emissions, t CO2e 2006 19,500 2007 20,600 2008 23,500 2009 15,600 Is the facility required to submit a historical data report? Yes, the facility is required to submit a historical data report for 2007 and 2008 only. Emissions for 2006 and 2009 do not need to be reported since they fall below the 20,000 t CO 2 e threshold. Data reports should contain the information specified in rows 1, 2 and 3 of Checklist #2 in Section 5.5.2 with the following amendments: The total GHG emissions attributable to the reporting operation during the reporting period (row 1) must be reported without Schedule C biomass emissions. Categorized emissions (row 3) and emissions by source (row 2) must include Schedule C biomass emissions as a separate item. Linear facilities are only required to report as an aggregated whole. Quantification methods referred to in column 5, Tables 1 and 2 should be used if practical, based on information that the operator has control of, custody of or can reasonably obtain. Should information not be available, the operator may use an alternate quantification Page 36

methodology (such as that for data submitted to Environment Canada under section 46 or section 71 of the Canadian Environmental Protection Act (CEPA)) that is as accurate as possible. Figure 10 Reporting Due Dates for 2010, 2011 and 2012. 5.5.4 Supplementary Reports A supplementary report must be prepared if the operator becomes aware that a previous report did not completely and accurately disclose the required information, or information required to be reported in a previous report has changed. For the 2011 and subsequent reporting periods, a supplementary report is required if: An inaccuracy, omission or change increases the total GHG emissions attributable to the reporting operation during that reporting period to an amount that is greater than or equal to 25,000 t CO 2 e, not including reporting-only emissions; or The total GHG emissions attributable to the reporting operation from reporting-only emissions within the reporting period changes by more than the lesser of 3% or 3,000 tonnes of the total GHG emissions attributable to the reporting operation during the reporting period. A supplementary report is not required if the inaccuracy, omission or changes results a difference in total attributable GHG emissions (not including reporting only emissions) that does not exceed the lesser of 1% or 1,000 tonnes of attributable GHG emissions (not including reporting-only emissions). The supplementary report must contain: A revised emissions report meeting all of the same criteria as the original emissions report, but containing the revised or updated information; and An annex with the following information: Page 37

o A description of the differences between the revised report and the original emissions report; and o An explanation of why any inaccuracies or omissions occurred. If a supplementary report is submitted due to inaccuracies or omissions, and the original report required a verification statement, then the percent difference between the updated attributable GHG emissions and the attributable GHG emissions reported in the original emissions report must be calculated and reported as follows: % Adjustment = (Attributable GHG emissions from original emissions report Attributable GHG emissions from revised report) / (Attributable GHG emissions from original emissions report) x 100% Supplementary reports must be submitted using the OWR system within 60 days if the operator becomes aware of errors, omissions or changes required to the emissions report 3. 3 For the 2010 and 2011 reporting periods, the operator must submit a supplementary report by September 1 of the year in which the report was due in order to append a verification report, if applicable. For these first two reporting periods, the verification statement can be submitted at a date later than the emissions report, but must be attached to a supplementary report. Page 38

6. CALCULATING EMISSIONS 6.1 Emission Quantification Methodology The Regulation requires the use of approved methodologies for calculating emissions. For single site and linear facilities, Column 5 in Tables 1 and 2 of Schedule A of the Regulation specifies the GHG emission quantification method for each activity and source type, and refers to an approved WCI quantification methodology. For example, for the General Stationary Combustion activity at a single facility operation, Schedule A, Table 1, Column 5 refers to quantification methodology WCI.020. An electricity import operation must quantify emissions using the methodology provided in Schedule D of the Regulation. Figure 11 provides an overview of the stages of emission quantification for a single or linear facilities operation. Figure 11 Overview of Emission Quantification Methodology Single or Linear Facilities. Page 39

Figure 12 provides an example of facility type, activity, source type and GHG type identification for a single facility operation (cement facility). Figure 12 Example of Source Type and GHG Type Determination. Sample Case #20 The WCI finalized an update to their quantification methodology for a particular emission source. When does the change take effect? In this situation the revised WCI quantification methodology should be used at the beginning of the next calendar year. For example, if the WCI quantification methodology is updated in June 2011, the updated version would be required to be used starting on January 1, 2012. Generally, the quantification methodologies contain the following: One or several different quantification methodologies, and the criteria to assess whether a specific methodology applies to a particular reporting operation; Specific supporting information that has to be included in the emissions report (e.g. annual fuel combustion, average carbon content of each fuel); Page 40

Equations and default emission factors; and Sampling, analysis and measurement requirements. 6.2 Selection of Quantification Methods The two fundamental approaches to quantifying emissions are direct measurement and mass-balanced based approaches: Direct measurement involves the measurement of GHG emissions. An example of direct measurement is a Continuous Emissions Monitoring System (CEMS) used to measure CO 2 (or O 2 ) stack emissions. Mass-balance method refers to the quantification of emissions by applying the conservation of mass principle. With this method, the feedstock, fuel or other substances consumed by a process are related to the emissions resulting from a process through applying a suitable emissions factor (default or sampled) to a volume or mass of fuel or feedstock. The WCI emissions quantification methodologies typically provide a number of different quantification methodologies for use in different situations. Where a choice exists with respect to approved methods, the WCI quantification methods should be referenced to clarify under what situations different methodologies may be used. Under the Regulation the operator of the reporting operation must use the methodology appropriate to the circumstances. Sample Case #21 and associated Figure 13 and Figure 14 provide an example of emissions quantification and quantification method selection. Page 41

Sample Case #21 Selecting Approved Methodologies Facility A operates a landfill which captures and combusts landfill gas to generate steam for a district heating application, and also exports some landfill gas to nearby Facility B, which uses the gas along with natural gas from a local distributor to produce electricity. Both sources of gas are metered for billing purposes. Facility A s annual emission are estimated at 80,000 t CO 2 e, facility B s emissions are estimated at 20,000 t CO 2 e. Neither facility currently uses a CEMS. What protocol should each facility use? Facility A Facility A is covered under the Regulation as it is combusting landfill gas on site (note that under Part 1, Section 4 of the Regulation, landfill gas generation emissions (i.e., methane) are not required to be reported, however combustion of landfill gases over the reporting threshold are covered). As per Table 1 in Schedule A, WCI.020 for General Stationary Combustion applies. WCI.023(a) lists 4 possible methodologies, subject to the restrictions of WCI.023(e). Based on WCI.023(e), Facility A is subject to verification requirements, so is excluded from choosing option 1 or 2. Since the facility does not currently employ a CEMS, Methodology 3 is the appropriate choice (if the gas were of pipeline quality it would be possible to use either Methodology 1 or 2 and default emission factors, instead of Methodology 3). Facility B Facility B s operations are classified as electricity generation so WCI.040 applies, as per Table 1 in Schedule A. As per WCI.043(7), the facility should quantify the landfill gas and natural gas sources separately. a) Landfill gas: WCI.043(4) states that Facility B must use either WCI.023(c) or WCI.023(b) (as the facility is not subject to verification requirements). Facility B elects to use the WCI.023(b) to calculate emissions based on the higher heating value (HHV) and default emission factor to account for the landfill gas portion. b) Natural gas: In this case the HHV is between 36.3 and 40.98 MJ/m 3. WCI.043(1) states that Facility B must use WCI.23(c) or WCI.023(b) (as the facility is not subject to verification requirements). Facility B elects to use the HHV supplied by the Gas distributor and the default emission factor to calculate emissions using WCI.023(b). Page 42

Figure 13 Selecting Approved Methodologies, Facility A (Sample Case #21). Page 43

Figure 14 Selecting Approved Methodologies, Facility B (Sample Case #21). Page 44

6.3 Replacement Quantification Methodologies Replacement quantification methodologies to those referenced in Schedule A may be used when: Total emissions quantified using replacement methodologies do not exceed the lower of: o 20,000 t CO 2 e; or o 3% of GHG emissions attributable to the reporting operation during the reporting period (not including CO 2 from biomass sources); and The use of a replacement methodology will not lead to a bias in the amount of GHG emissions quantified. Replacement methodologies cannot be used for electricity import operations. A general outline of the replacement methodology selection process is provided in Figure 15. Figure 15 Selection of Replacement Quantification Methods. Page 45

Sample Case #22 Replacement Methodologies A facility is quantifying a source under the 3%/20,000 limit and is considering two replacement measurement methods. Method 1 will result in an uncertainty of +/-5%, and method 2 will result in an uncertainty of +/- 10%. What are the considerations which apply in determining which replacement methodology should be used? Method 1 will result in a more accurate estimation of emissions. Method 2 should only be used if method 1 is not practicable, or will incur a significant amount of time or cost, sufficient that the added uncertainty associated with Method 2 is justified. Reporting entities should seek guidance from consultants or the Ministry if questions arise when replacement methodologies are being considered. 6.4 Alternative Measurement Parameter For the 2010 reporting period, where a quantification methodology specifies measurement of a parameter and it was not possible or practicable to measure such a parameter, an alternative parameter measurement was permitted to be used, if approved by the Ministry. Use of alternative measurement parameters is not applicable to electricity import operations. If the quantification methodology referenced in Schedule A is new or revised, and this results in a change to the methodology for measuring a parameter from the previous reporting period, an operator may use an alternative measurement parameter for the first reporting period after the methodology change if: It is not practicable to use the specified parameter measurement methodology because the operator has not been able to establish systems necessary to use that methodology within the time necessary to use the methodology for the reporting period; The alternative parameter measurement methodology is as accurate as is practicable; and For an alternative parameter measurement methodology used after March 31 of the reporting period, the methodology has been approved by the Ministry. For quantification of emissions from January 1 to March 31 of the reporting period, no Director approval is necessary. For the 2011 and subsequent reporting periods an application for use of an alternative measurement parameter must be submitted to the Ministry on or before February 1 of the reporting period, including the following information: Explanation of why it is not practicable to use the specified parameter measurement methodology; Justification for why the alternative parameter measurement methodology is as accurate as practicable; An estimate of the level of uncertainty associated with the alternative parameter measurement methodology; and An estimate of the percentage of operation emissions to be calculated using the alternative methodology. Page 46

An Alternative Parameter Measurement Methodology Approval Request Form is available through the Reporting Regulation website. In response to the request, the Ministry may request further information, approve or reject the request. If the Ministry has not taken action by March 3 of the reporting period, the request is deemed to be approved. 6.5 Choosing Between Measurement Methodologies There may be an option, under a specific quantification methodology, to choose between two or more measurement methodologies to quantify GHG emissions. Once a specific measurement methodology has been selected for an operation, the operator must continue to use that methodology, regardless of whether the owner or operator changes, unless: A change in measurement methodology is approved in advance by the Ministry; The change in measurement methodology is to accommodate a higher numerically-rated quantification method; The change in measurement methodology is to a more accurate quantification method; The GHG emissions calculated using the measurement methodology are less than the lower of: 20,000 t CO 2 e; 3% of the reporting operation s total emissions for the reporting period (not including CO 2 produced by biomass); or There is no longer a choice of measurement methodology because of the following situations: Quantification methodologies listed in Schedule A have been amended or added to; Emissions exceed the threshold for the use of replacement methodologies (described in Section 6.3); and An alternative parameter measurement methodology has not been approved for use for the reporting period. Sample Case #23 Choice between Measurement Methodologies Suppose that Facility B in Sample Case #21, after reporting emissions during its first reporting year, wished to alter the methodology used to report the natural gas portion of its fuel consumption. Specifically, the facility wishes to use the average carbon content (which it is now able to receive from its distributor) instead of the HHV and default emission factor (this represents a methodology change from WCI.023(b) to WCI.023(c), both which are eligible). The facility s emissions last year were 21,500 t CO 2 e, with the portion due to natural gas representing 11,000 t CO 2 e. It is expected that using the alternate quantification methodology the same emissions would be slightly lower, at 10,500 t CO 2 e. Is the facility able to alter its emission measurement methodology? As the emissions calculated using the altered methodology are not less than 3% of total emissions, Facility B would not be able to alter its emissions quantification methodology for the next reporting year unless the facility has prior approval of the Ministry. Page 47

6.6 Instrumentation Instrumentation may be used in the measurement of GHG emissions or to gather data used in the quantification of emissions attributable to a reporting operation. The requirements for this instrumentation are given in Section 15 of the Regulation. Examples of instrumentation that may be used include CEMS, samplers, gas analyzers and flow meters. The Regulation requires that all instrumentation used in emissions quantification: Meet the requirements of the quantification methodology, standards, code or rules referred to in Column 5 of Tables 1 or 2 in Schedule A of the Regulation; and Must be calibrated and maintained in accordance with manufacturer s specifications (or other relevant standards or written procedures which will result in the same accuracy level or better) with a record of calibration. Page 48

7. DATA QUALITY AND DOCUMENT MANAGEMENT 7.1 Data Quality Data used for the preparation of an emissions report must: Be of sufficient quality to allow a verification body to determine that reported emissions are materially correct and are a fair and accurate representation of emissions; Meet the requirements of a ministry inspection; Be unbiased, complete and sufficient to meet the data requirements of the quantification protocol used; and Be consistent with the sampling, measurement, calibration and instrumentation requirements of the quantification protocol used. Further guidance regarding data quality is provided within the Verification Guidance Document. 7.2 Document Management The process, document and record retention requirements are outlined in Section 27 and 28 of the Regulation. The operator of a reporting operation must establish processes and maintain records that: Accurately and fairly reflect the GHG emissions attributable to the reporting operation; Allow an inspector or verification body to determine that emission reports are materially correct and are a fair and accurate representation of the GHGs attributable to the reporting operation; Allow preparation of emission reports as required under the Regulation; and Prevent, or provide timely detection of errors, omissions or misrepresentations. Generally good document management (i.e., data controls and audit trail) will result in a more efficient verification process. 7.2.1 Records and Record Retention Records must be retained in paper or electronic format for a period of not less than 7 years from the date the emission report or supplementary report is submitted to the Ministry. All records used to quantify GHG emissions and supporting information such as fuel purchase records, utility bills, and monitoring data must be retained. The records that are required to be retained and examples of such data are summarized in Table 7. Note the examples provided are not intended to provide a complete list, and will vary for different operations. Page 49

Table 7 Record Retention Requirements. Records To Be Retained Examples Fuel data Utility bills Monthly fuel purchase records, fuel meter reading data, record of mileage Documentation of biomass fraction of specific fuels Other fuel data used for emission quantification Activity data Scheduled maintenance, Emergency shut down System capacity addition or reduction Other activities affecting reporting and verification Emission data Output from Continuous Emission Measurement Systems Annual stack emission test data Periodic stack emission measurement data Data used to estimate emission using mass balance -based methodology Records of calculation GHG emission inventory Databases containing calculations Documentation on quantification methodologies, choices made, database design, etc. Emission category Emission categories listed in Column 2 of Schedule B Quantification methodologies Reference to the quantification methodologies used to quantify emissions. Description of methodology if it is not referred to in standards, codes or rules listed in Column 5 of Schedule A Ministry approval to use an alternative parameter measurement methodology for the reporting period. Ministry approvals to move to a different quantification methodology from that used for the previous year. Emission Factors Records of all emission factors used to quantify GHG emissions Reference for emission factors Information submitted to the Ministry Reporting operation registration Emissions report Any supplementary/corrected reports Correspondence regarding emissions report, for example requests to use an replacement quantification methodology Records related to any calculations and methods used to substitute the data that has been lost or missing Previous reporting period data that has been used to substitute missing data from current reporting period Meter calibration records Equipment nameplate specifications Process flow diagrams Page 50

Records To Be Retained Name, job title, contact information of a) operation representative, b) the person responsible for preparing and submitting the emissions report, and c) other facility personnel involved in quantifying emissions and/or quality assurance. Examples May include people from various departments within an organization such as environmental engineers, accounts manager, production manager, environmental system manager. Records must indicate what task was performed by each of the identified groups and/or individuals. Log of changes in calculations, methods and instrumentation for each reporting period Documentation relating to new instruments that have replaced existing instruments Documents related to any revisions, reasons for such changes to emission reports Verification Process Documents Verification findings report For electricity import operations, additional information to be retained include NERC energy tags, power contracts, settlements data, and all other information needed to confirm the transactions and emissions. If an operator uses a direct measurement methodology, all records related to the methodology must also be kept in paper or electronic format for a period no less than 7 years from the date the emissions report or supplementary report is submitted to the Ministry. For direct measurement documents and records include, but are not limited to the following: List of all data sources monitored; Detailed technical description of the direct measurement system; Raw and aggregated data from the direct measurement system; Log book of systems down times, calibration, servicing and maintenance of the direct measurement system; and Documentation of any changes in the direct measurement system that occurred during the reporting period. 7.2.2 Public Disclosure and Confidentiality Section 29 of the Regulation contains provision for the Ministry to publish information submitted within an emissions report including, but not limited to: Name of reporting operation; Name and head office mailing address; Location information; Page 51

Total GHG emissions; GHG emissions broken down by major source category; Subtotals of two or more emissions from major source categories; Whether information has been verified; and Information regarding the verification outcome. An operator can include within an emissions report a claim that disclosure of the information on GHG emissions broken down by major source category and subtotals of two or more emissions from major source categories be prohibited under Section 21(1) of the Freedom of Information and Protection of Privacy Act (FOIPPA). The operator may also request that information within the emissions report be kept confidential. The claim for data confidentiality must provide details on the specific information considered to be confidential, and how publication of the material would result in revelation of material and cause effects referred to under Section 21 (1) of FOIPPA. Data may still be published if the Ministry determines that disclosure of information would not be contrary to FOIPPA. The request for confidentiality process in summarized in Figure 16. Page 52

Figure 16 Confidentiality Evaluation and Decision Process. Should a reporter want to publically report that their emissions report complies with any relevant standards such as ISO 14064-1, The Climate Registry General Reporting Protocol, or the World Business Council for Sustainable Development/World Resources Institute (WBCSD/WRI) GHG protocol, then the reporter must ensure that they have met the requirements of those standards. Where the Regulation has different requirements to other standards, the Regulation takes precedence for the purposes of submitting an emissions report to the Ministry, and publishing of emissions report data by the Ministry as outlined under the Regulation. Page 53

8. INSPECTION AND SEIZURE POWERS 8.1 Inspectors Although the Ministry is taking a compliance promotion approach to the early stages of implementing the Regulation, inspection and seizure powers exist. An inspection of a facility may be carried out to ensure compliance with Greenhouse Gas Reduction (Cap and Trade) Act and the Regulation. Under the Regulation, an inspector(s) can be designated and may enter land or premises and inspect processes, activities, places associated with the reporting operation. The inspector can take along persons and equipment relevant to the inspection, and must provide proof of identity upon request. During an inspection, the inspector may: Undertake inspection and analysis; Measure, sample or test anything; Take samples off site from the reporting operation; and Make or take away copies of records. During an inspection, at the request of the inspector, the reporting facility must: Produce any record relating to the Greenhouse Gas Reduction (Cap and Trade) Act without charge or unreasonable delay; and Provide relevant information to the inspector during an inspection. Section 112 (Seizures and prevention orders) of the Environmental Management Act applies to the Greenhouse Gas Reduction (Cap and Trade) Act, and the Regulation. If, in the course of an inspection, an inspector has reasonable grounds to believe that a person has contravened/is contravening the act or regulations, then the inspector may: Order a person to do anything to stop the contravention or prevent another contravention; and Seize anything the inspector believes on reasonable grounds that was used/is being used in the contravention, or will afford evidence of the contravention (e.g., documentation of processes and procedures). 8.2 Appeals A person aggrieved by a decision of the director, related to specific provisions within the Greenhouse Gas Reduction (Cap and Trade) Act and Environmental Management Act, may appeal the decision to Environmental Appeal Board within 30 days after notice of the decision is given. The specific provisions relating to appeals include: Provisions of the Greenhouse Gas Reduction (Cap and Trade) Act: Section 13 (7) [approval of replacement methodology for 2010]; and Section 14 (2) [approval of change of methodology]. Page 54

Provisions of the Environmental Management Act: Section 101 [time limit for commencing appeal]; Section 102 [procedure on appeals]; Section 103 [powers of appeal board in deciding appeal]; and Section 104 [appeal does not operate as stay]. An appeal must be commenced by notice of appeal in accordance with the prescribed practice, procedure and forms. The commencement of an appeal does not operate as a stay or suspend the operation of the decision being appealed unless the Environmental Appeal Board orders otherwise. Page 55

9. REFERENCES Budget Transparency and Accountability Act, SBC 2000, Chapter 23. Canadian Environmental Protection Act, SC 1999, Chapter 33. Environmental Management Act, SBC 2003, Chapter 53. Environmental Management Act, Environmental Appeal Board Procedure Regulation, B.C. Reg. 1/82. Environmental Management Act, Landfill Gas Management Regulation, B.C. Reg. 391/2008. Freedom of Information and Protection of Privacy Act, RSBC 1996, Chapter 165. Forest Act, RSBC 1996, Chapter 157. Greenhouse Gas Reduction (Cap and Trade) Act, SBC 2008, Chapter 32. Greenhouse Gas Reduction (Cap and Trade) Act, Reporting Regulation, B.C. Reg. 272/2009. Greenhouse Gas Reduction Targets Act, SBC 2007, Chapter 42. Greenhouse Gas Reduction Targets Act, Carbon Neutral Government Regulation, B.C. Reg. 392/2008. B.C., July 2011, British Columbia Reporting Regulation, Verification Guidance Document, Version 1.1. Western Climate Initiative, July 2009, Final Essential Requirements for Mandatory Reporting. Western Climate Initiative, July 2010, Design for the WCI Regional Program. Western Climate Initiative, December 2010, Final Essential Requirements of Mandatory Reporting for Canadian Jurisdictions (Overview). Western Climate Initiative, December 2010, Final Harmonization of Essential Reporting Requirements in Canadian Jurisdictions (Quantification Methods). World Business Council for Sustainable Development (WBCSD)/World Resources Institute (WRI), 2004, The Greenhouse Gas Protocol, A Corporate Accounting and Reporting Standard, Revised Edition. Page 56

Appendix A Global Warming Potentials (GWP) for Specified Gases Specified Gas Chemical Formula Global Warming Potential (100 year time horizon) Carbon dioxide CO2 1 Methane CH4 21 Nitrous oxide N2O 310 HFC-23 CHF3 11,700 HFC-32 CH2F2 650 HFC-41 CH3F 150 HFC-43-10mee C5H2F10 1,300 HFC-125 C2HF5 2,800 HFC-134 C2H2F4 (CHF2CHF2) 1,000 HFC-134a C2H2F4 (CH2FCF3) 1,300 HFC-143 C2H3F3 (CHF2CH2F) 300 HFC-143a C2H3F3 (CF3CH3) 3,800 HFC-152 C2H4F2 43 HFC-152a C2H4F2 (CH3CHF2) 140 HFC-161 C2H5F 12 HFC-227ea C3HF7 2,900 HFC-236cb C3H2F6 1,300 HFC-236ea C3H2F6 1,200 HFC-236fa C3H2F6 6,300 HFC-245ca C3H3F5 560 HFC-245fa C3H3F5 950 HFC-365mfc C4H5F5 890 Perfluoromethane CF4 6,500 Perfluoroethane C2F6 9,200 Perfluoropropane C3F8 7,000 Perfluorobutane C4F10 7,000 Perfluorocyclobutane c-c4f8 8,700 Perfluoropentane C5F12 7,500 Perfluorohexane C6F14 7,400 Sulphur hexafluoride SF6 23,900 Page 57

Pulp and Paper Production Appendix B Sample Process Flow Diagram Page 58