greenhouse gas emissions management plan

Greenhouse Gas Emissions Management Plan CGL4703-CGP-ENV-PLN-011

March 10, 2016 Revision 1

Coastal GasLink Pipeline Project Greenhouse Gas Emissions Management Plan

Contents

TABLE OF CONTENTS

1.0 INTRODUCTION ....................................................................................................................... 1

1.1 Purpose ...............................................................................................................1 1.2 Objective ............................................................................................................1 1.3 Scope ..................................................................................................................2 1.4 Consultation .......................................................................................................2 1.5 Project Background ............................................................................................2

2.0 REGULATORY CONTEXT ....................................................................................................... 5

3.0 BEST AVAILABLE TECHNOLOGY ECONOMICALLY ACHIEVABLE .................................. 7

3.1 Stationary Combustion Sources .........................................................................8 3.2 Venting .............................................................................................................10 3.3 Fugitive emissions ...........................................................................................10

4.0 ASSET MANAGEMENT SYSTEM.......................................................................................... 13

5.0 MITIGATION AND MAINTENANCE ACTIVITIES .................................................................. 15

5.1 TransCanada Procedures and Programs...........................................................16 5.2 Performance Monitoring ..................................................................................17

6.0 GHG MANAGEMENT SYSTEM ............................................................................................. 19

7.0 GHG REPORTING AND VERIFICATION ............................................................................... 21

8.0 REFERENCES ........................................................................................................................ 23

LIST OF APPENDICES

Appendix A Glossary Appendix B Construction Air Emission Management Plan Appendix C Combustion Equipment Manufacturer Specifications

Revision 1 March 10, 2016

CGL4703-CGP-ENV-PLN-011 Page i

Contents


LIST OF FIGURES

Figure 1-1: Natural Gas Transmission Line Schematic of Greenhouse Gas Sources .............. 3 Figure 6-1: GHG Management System .................................................................................. 19

LIST OF TABLES

Table 2-1: Regulations, Guidelines and Acts ........................................................................... 5 Table 6-1: GHG Management Document List........................................................................ 20

CGL4703-CGP-ENV-PLN-011 Page ii



Section 1 Introduction

1.0 INTRODUCTION

Coastal GasLink Pipeline Ltd. (Coastal GasLink) has developed a Greenhouse Gas 1 (GHG) Emissions Management Plan (the Plan) that provides an outline of GHG 2 emission monitoring that will be conducted once construction has finished. 3

Coastal GasLink applied to the BC Environmental Assessment Office (EAO) for an 4 Environmental Assessment Certificate (EAC) under the BC Environmental 5 Assessment Act (EAA) for the proposed Project. In October 2014, BC EAO issued an 6 EAC for the Coastal GasLink Pipeline Project (Project) that includes a Table of 7 Conditions. 8

1.1 PURPOSE

The purpose of this Plan is to describe a framework of how Coastal GasLink plans to 9 manage GHG emissions for the Project during the Operations Phase. The Plan is 10 premised on TransCanada PipeLines Limited’s (TransCanada’s) existing GHG 11 emissions management program. The Plan will build on discussions related to GHG 12 emissions during operations presented in Section 6 of the Application for an EAC 13 (EAC Application). Discussion related to construction phase air emissions 14 management is included in Appendix A. 15

1.2 OBJECTIVE

The objective of this Plan is to satisfy Condition #3 of the Coastal GasLink EAC (BC 16 EAO 2014), which states: 17 18 The Holder must develop and implement a Greenhouse Gas Emissions Management Plan in consultation with MNGD and CAS, that:

• demonstrates adherence to mitigation proposed in the Application Section 6.7.2, Table 6-24 and the Greenhouse Gas Emissions Technical Memo provided by CGL, to EAO, dated May 13, 2014;

• demonstrates that mitigation proposed in the Plan is consistent with MNGD’s Guidance Best Available Techniques Economically Achievable and does not inadvertently increase the effect on air contaminant emissions predicted in the Application; and

• identifies the specific GHG emissions reporting requirements the Holder must complete in order to meet applicable regulatory requirements.

In order to allow for 30 days review and comment, the Holder must provide the Plan to EAO no less than 60 days prior to the Holder’s planned date to commence Construction. Once the Plan is complete, the Holder must provide the Plan to OGC.


CGL4703-CGP-ENV-PLN-011 Page 1 of 23



1.3 SCOPE

The Plan describes design factors, best management practices, preventive 1 maintenance activities and project-specific mitigation to avoid, mitigate, manage and 2 track GHG emissions anticipated from the Project’s operation. 3

1.4 CONSULTATION

A draft copy of the Plan was provided to the Ministry of Natural Gas Development 4 (MNGD) and the Climate Action Secretariat (CAS) for review and comment. 5 Generally the items raised during consultation related to the need for the level of 6 detail required for the best available technology economically achievable (BATEA) 7 analysis for the Project to be consistent with the MNGD BATEA Guidance document, 8 which was being drafted simultaneous to the development of this Plan. 9

1.5 PROJECT BACKGROUND

Coastal GasLink is proposing to construct and operate a natural gas pipeline from the 10 area near the community of Groundbirch (about 40 km west of Dawson Creek, British 11 Columbia [BC]) to the proposed LNG Canada Development Inc. (LNG Canada) 12 liquefied natural gas (LNG) export facility (LNG Canada export facility) near Kitimat, 13 BC. 14

The proposed Coastal GasLink Pipeline Project (Project) involves the construction 15 and operation of: 16

• approximately 670 km of 48 inch (NPS 48) (1,219 mm) diameter pipeline 17

• metering facilities at the receipt and delivery points at up to three locations 18

• compressor stations at up to eight locations 19

The proposed Project will have an initial capacity of about 2 to 3 billion cubic 20 feet/day (bcf/d) (56 million cubic metres per day [mmcm/d] to 85 mmcm/d), with the 21 potential for expansion up to about 5 bcf/d (142 mmcm/d). The expansion scenarios 22 do not involve the construction of additional pipeline; only the number of compressor 23 stations would change. 24

Depending on the final design, the compressor station(s) will operate two to four 25 natural gas-fired turbine compressors, each with an output rating of 34 MW for 26 compression, as well as heaters and generators. The metering stations will include 27 metering runs, yard piping, isolation and control valves, and separators, which could 28 be minor sources of GHG emissions. 29

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As demonstrated in Section 6 of the Application, the majority of GHG releases will 1 originate from the compressor stations; however, venting and fugitive emissions will 2 be considered in this Plan. 3

To illustrate how the Project emission sources relate to one another, the following 4 simplified process flow diagram has been prepared. 5

Figure 1-1: Natural Gas Transmission Line Schematic of Greenhouse Gas Sources




Section 2 Regulatory Context

2.0 REGULATORY CONTEXT

The Government of Canada has set a target of reducing Canada’s total GHG 1 emissions by 17% from 2005 levels by 2020 (EC 2013). Within this context, the 2 Government of BC legislated a provincial GHG reduction target of 33% below 2007 3 emission levels by 2020, and 80% below 2007 levels by 2050. 4

With these targets in mind, the provincial and national governments have 5 implemented regulations, plans, guidelines and policies. Those considered relevant to 6 the Project are presented in Table 2-1. 7

Table 2-1: Regulations, Guidelines and Acts

Regulation, Guideline or Policy

Project Activity(s) Applicable Brief Description

Environment Canada Greenhouse Gas Reporting Program

Annual Operations

A facility emitting more than 50,000 tonnes CO2e/year is required to report annual GHG emissions.

British Columbia Greenhouse Gas Reporting Regulation

Annual Operations

• Oil and gas facilities that emit more than 10,000 tonnes CO2e/year are required to report annual GHG emissions.

• Those emitting above 25,000 tonnes CO2e/year are required to have their GHG emissions report verified by an independent third-party auditor.

Carbon Tax Act Fossil Fuel Combustion Sources

This revenue neutral tax applies to the purchase or use of fossil fuels. Current tax rate is based on $30/tonne CO2e for combustion related GHGs.

Flaring and Venting Reduction Guideline

Flaring and Venting

The guideline provides a decision tree to evaluate flaring and venting decisions for pipelines and compressor station facilities. Permit holders should consider alternatives and reduce or eliminate flaring and venting. All monthly flared and vented volumes must be reported separately on a Monthly Disposition BC-S2 form.




Section 3 Best Available Technology Economically

Achievable

3.0 BEST AVAILABLE TECHNOLOGY ECONOMICALLY ACHIEVABLE

The Project has considered BATEA principles when designing the pipeline and 1 associated facilities. These BATEA principles are intended to minimize GHG 2 emissions while not inadvertently increasing Criteria Air Contaminants (CAC) to a 3 point where regulatory thresholds are exceeded. BATEA discussed in this section 4 primarily relate to GHG emission sources. CACs are included, but are not the focus 5 of this discussion. 6

Section 6 of the Application presented emission inventories, which showed that 7 approximately 95% of the Project’s GHG emissions are from stationary fuel 8 combustion sources, predominantly associated with the combustion of natural gas in 9 the turbines, which then drive the compressors. Other stationary combustion sources 10 include power units, heaters and boilers. Fugitive and venting emissions comprise the 11 remaining emissions from the Project. GHG emission totals presented in Section 6 of 12 the Application were conservative in approach and assumptions, although refinements 13 will be made to these emission inventories during Project operation using recorded 14 data. 15

The design of the Project considered various options that would effectively be best 16 available technology for reducing GHG emissions. The main factors considered are 17 listed below: 18

• The proposed pipeline route balances the requirements for the shortest length of 19 pipeline (for efficient transport of gas) while managing the potential for adverse 20 environmental effects and constructability issues. 21

• The pipeline internal coating reduces pressure losses during transmission of the 22 gas. This will result in a reduction of the total energy required to move gas, which 23 in turn reduces the generation of GHGs. 24

• Through the correct sizing of equipment and ongoing operator training, the 25 operating pressure will be managed to provide the most efficient operation of the 26 pipeline throughout the anticipated flow rates. 27

• Station locations were chosen to maximize the distance between compressor 28 stations, reducing the number of aboveground facilities and reducing the 29 generation of GHGs. 30

• Aftercoolers will cool the gas once it has passed through the turbines to help 31 protect the pipe coating and help reduce the need for additional compression. 32

• Turbine unit selection is expected to minimize the number of units required 33 overall. 34

TransCanada has demonstrated that it supports the concept of waste heat recovery 35 (WHR) and has implemented WHR systems at several facilities in North America. 36



Section 3 Best Available Technology Economically Achievable


When evaluating BATEA for this Project, the uses of energy recovery mechanisms to 1 take advantage of the gas turbine waste heat were considered. 2

Activities and sources of GHG emissions during the operation of the Project, which 3 were designed considering BATEA, are described in sections 3.1 to 3.3 and, where 4 applicable, manufacturer specifications are provided in Appendix B. BATEA will be 5 maintained to the level outlined by the manufacturer or better, as described in 6 Section 5. 7

This Plan considers the BATEA for the 2 to 3 bcf/d initial build scenario; future 8 expansions may merit the re-evaluation of the BATEA. The expansion case for the 9 Project has a capacity of up to approximately 5 bcf/d. 10

3.1 STATIONARY COMBUSTION SOURCES

Turbine Driven Compressors

Natural gas-fired gas turbine selection for pipeline operation in the unique Canadian 11 environment requires consideration of several factors, including system design 12 requirements, regulatory guidelines for emissions, cold-weather operation, shutdown 13 and start-up conditions, and operating below maximum power. 14

Electric units were not considered a BATEA because of the limited or lack of 15 availability of grid power at the compressor station locations; as well, potential 16 electric transmission failures (i.e., weather events) could shut down a compressor 17 station creating unacceptable system reliability. The reduced reliability of an electric 18 powered system has prevented it from being considered a BATEA. 19

Natural gas-fired gas turbines are powered by clean airflow (which is heated by gas 20 fuel), and these highly efficient systems provide significant overall clean energy 21 benefits while balancing the combination of GHGs, air pollutants (primarily CACs) 22 and air contaminants. Generally, emissions of concern from natural gas-fired turbines 23 include nitrogen oxides (NOX), carbon monoxide (CO), fine particulate matter (PM) 24 and carbon dioxide (CO2) emissions. 25

These emissions are interconnected, and often, by minimizing one of these emission 26 types, the result is an increase in another emission type. For example, environmental 27 decisions that weigh too heavily on low- NOX releases will likely cause higher 28 emissions of GHGs and air contaminants because of increased energy and chemical 29 consumable requirements of these systems. As such, the best technologies for 30 managing specific air issues (such as NOX) can create other environmental issues, 31 such as increased CO2, CO and PM emissions. Examples include: 32





Achievable

• NOX emissions versus GHG emissions: Low- NOX emissions at part load 1 operations (<90%) are achieved on the majority of low- NOX dry low emissions 2 (DLE) turbines through bleeding air, resulting in less efficient combustion 3 (i.e., higher fuel use and GHG emissions). While low- NOX units might make 4 sense for full load operations, applying a limit for partial-load units will generate 5 an increase in GHG emissions. 6

• NOX emissions versus PM2.5 emissions: selective catalytic reduction (SCR) 7 control systems are used to reduce NOX emissions, but they can result in higher 8 PM2.5 emissions (ammonium sulphate). 9

• NOX emissions versus ammonia (NH3) emissions: SCRs are used to reduce NOX 10 emissions, but they result in ammonia slip. SCR requires precise control of 11 ammonia; an injection rate that is too high results in release of ammonia to the 12 atmosphere, or NH3 slip. 13

The use of SCR control systems for additional reductions of NOx emissions was not 14 considered to be BATEA for the following reasons: 15

• The sources of NH3 (anhydrous, aqueous urea) also introduce potential local and 16 transportation hazards. Ammonia transport poses a risk of exposure to the 17 surrounding population as a result of an accidental release caused by an accident 18 involving the delivery vehicle. 19

• Application of SCR systems to achieve increased level of NOX reductions are best 20 suited to base load operations within a narrow temperature band, and do not 21 respond well to the variable operations on pipeline systems and in BC’s wide 22 range of ambient temperatures. 23

• The limitation of SCR for pipelines has been documented in a former BC Air 24 Quality Criteria, Section 4, Table 2 (b), which states that “… gas pipeline 25 application and other installations where SCR is demonstrated to be 26 inappropriate….” 27

• Compressor stations will be unmanned and located in more remote areas, making 28 the storage and use of ammonia at these sites undesirable from a safety and 29 security perspective. 30

The BATEA for turbine-driven compressors has been determined to be aero-31 derivative DLE units, such as the GE LM2500+, RR RB211 or equivalent unit. 32 Reasons for this determination include: 33

• DLE combustion systems have progressed to the point that they prevent 80 to 34 90% of the NOX emissions compared with previous uncontrolled units. 35

• Turbine units using these systems have seen performance improvements 36 unmatched by almost any other energy industry technology, with adequate 37 reliability and efficiency, and no other collateral adverse environmental effects. 38



Section 3 Best Available Technology Economically Achievable


• Low maintenance and manning requirements as compared to SCR systems. 1

Heaters and Generators

The magnitude of emissions estimated to originate from heaters and generators 2 involved in the Project should be considered. When compared to the total emissions 3 from stationary combustion sources, heaters and generators together only contribute 4 approximately 3 to 6% of the emissions, depending on the scenario. As well, when 5 considering the various makes and models commercially available, emission profiles 6 are comparable. Therefore, the difference in emissions between available 7 technologies is minimal. 8

When considering BATEA for small emitting sources, Coastal GasLink considered 9 removing direct emissions entirely by incorporating electric drive units. However, in 10 the case of heaters and generators, because of factors such as equipment purpose, 11 proximity to the grid and reliability, electric drive units were not considered a 12 BATEA. When considering possible fuel sources, the use of natural gas driven units 13 instead of any other type of fossil fuel was considered to be the BATEA. Reasons for 14 this determination are related to reliability, emissions and availability of the fuel 15 source. 16

3.2 VENTING

Non-continuous venting sources are limited to stations; there will be no material 17 sources of continuous venting. Stations will be designed to be partitioned into 18 individual plants to permit separate independent blowdowns (controlled release of 19 natural gas from a section of pipeline), and piping volumes between unit valves will 20 be kept to a minimum to reduce the vented emissions in the event a blowdown is 21 required. Minimizing the number of blowdowns reduces GHG emissions. As well, 22 with the reduced number of blowdowns, timing required for emergency venting and 23 smaller volumes per event, it is not practical to include a flare in the design of a 24 station. 25

3.3 FUGITIVE EMISSIONS

Station pipeline components will be chosen to reduce pressure losses within the 26 piping systems and enhance pipeline efficiency. This may include the use of 27 ultrasonic meters, straightening vanes, full bore valves and contoured fittings. 28

All pipeline high-pressure gas valves will use a double block and bleed design, which 29 reduces the number of valve connections, thereby reducing the number of fugitive 30 sources. As well, the use of process air for pneumatic control valves and seal gas 31





Achievable

inside compressor stations, instead of natural gas, where practical, is expected to 1 reduce fugitive GHG emissions. 2




Section 4 Asset Management System

4.0 ASSET MANAGEMENT SYSTEM

TransCanada has a comprehensive Asset Management System (AMS), which consists 1 of processes, techniques and tools that provide an integrated and scalable approach to 2 decision-making, enabling assets to meet performance requirements. The AMS is a 3 “plan, do, check and act” system, and includes measures of portfolio performance. 4 TransCanada has established the framework of 17 elements for the AMS based on the 5 British Standards Institution’s publicly available Specification 55 to optimize 6 management of physical assets. 7

Within the AMS, TransCanada Operating Procedures (TOPs) outline the work 8 requirements to be undertaken in the preventive maintenance of the Project (refer to 9 Section 5). Monitoring, measuring and associated records of asset performance and 10 condition are used to evaluate the implementation and effectiveness of the AMS 11 (refer to Section 5.2). A GHG Management System uses FileNET and other 12 automated systems to retain GHG related data from the Project (refer to Section 6). 13

Design, implementation, performance measurement and continuous improvement of 14 the system are overseen by TransCanada’s senior executives. 15




Section 5 Mitigation and Maintenance Activities

5.0 MITIGATION AND MAINTENANCE ACTIVITIES

Within the AMS, TransCanada establishes and updates maintenance and operational 1 practices related to the safe, reliable and efficient operation of its assets. Many of 2 these directives are expected to reduce GHG emissions through improved efficiency 3 of equipment and systems, decreased leakage rates, and a reduction in equipment 4 failures or systems upsets, resulting in a decrease in venting or accidental release of 5 methane and, potentially, other sources. These procedures are reviewed regularly and 6 may be modified, added to or removed based on new information that arises that 7 indicates safety, equipment, health or other concerns. The optimal operation of the 8 BATEA defined above will serve to not meet regulatory requirements, but will 9 support efficient operation of the Project. 10

TransCanada implements a maintenance program to ensure that equipment is 11 operating in accordance with vendor specifications. Ensuring efficient operation 12 through the life of the equipment will consequently minimize GHG emissions. 13 TransCanada’s preventive maintenance program mitigates the risks when operating 14 and maintaining TransCanada’s facilities and equipment, as well as protecting people, 15 equipment, processes and the environment. Work requirements undertaken in its 16 preventive maintenance program are outlined in TOPs. Official TOPs are housed and 17 controlled in FileNET, TransCanada’s electronic document management system. 18 TOPs are accessible via a web-based database and an operational team is accountable 19 for ensuring that TOPs are managed and feedback is addressed using the TOPs 20 document control processes, as defined by the TOPs program framework. 21

Three types of documents make up the TOPs document class: 22

• Task packages identify the scope of work for maintaining a facility or piece of 23 equipment, usually associated with maintenance tasks and often attached to work 24 orders. Task packages may reference several procedures to perform the task in a 25 safe and efficient manner. 26

• Procedures provide sequential steps for a specific activity within a larger scope of 27 work. 28

• Forms capture information about the work performed; when complete, the form 29 becomes a record. 30

Any changes to the AMS or its components (including TOPs) are subject to 31 management of change procedures, which include a reason for the change, the 32 authority for approving changes, an analysis of implications, the acquisition of any 33 required work permits, the documentation required for the change, communication of 34 change to affected parties, any time limitations related to the change and 35 qualifications of personnel related to the change. 36





A description of some of the TOPs applicable to this Project that relate to GHG 1 emissions are presented in Section 5.1. 2

5.1 TRANSCANADA PROCEDURES AND PROGRAMS

Turbine Blade Wash

The purpose of this procedure is to prevent contamination of the compressor blades 3 by atmospheric pollutants that can result in loss of compressor efficiency, reduced 4 performance and increased fuel consumption. Increased fuel consumption will result 5 in increased combustion-related GHG emissions, mainly CO2 with minute amounts of 6 methane and nitrous oxides. Regular compressor cleaning can optimize gas generator 7 efficiency and component life while managing GHG emissions by optimizing fuel 8 consumption. The standard maintenance practice and frequencies for completing soak 9 wash inspections may be adjusted based on unique equipment requirements and other 10 considerations. 11

Gas Turbine Fuel Control System Inspections

Operating the fuel control system as per design and installation helps to maintain the 12 efficiency of fuel combustion and, therefore, reduce GHG emissions, which would 13 occur with inefficient fuel system controls. Maintenance programs on the fuel control 14 system for the units will be tested within the frequencies specified. General 15 requirements of inspections include verifying the fuel control average exhaust gas 16 temperature against individual combustor exhaust gas temperatures while the unit is 17 running. The air intake temperature will be verified against the station ambient 18 temperature while the unit is running. If the fuel valve has feedback, then the fuel 19 valve position will be checked to ensure it is not oscillating. Further, all fuel control 20 pressure transmitters will be checked per specified procedures, and visual checks of 21 the condition and security of the equipment connections on control equipment will be 22 performed. Intervals for gas turbine fuel control system inspections may be adjusted 23 based on unique equipment requirements and other considerations. 24

Calibrations

Meter verifications and calibrations are conducted to meet custody transfer and 25 internal management requirements, as well as Measurement Canada specifications. 26 Whether the meter is redundant or for custody transfer purposes determines the 27 frequency of verifications and calibrations. 28

Fugitive Emissions Management Program

The Project will adopt TransCanada’s Fugitive Emissions Management Program to 29 manage fugitive emissions; the Program has received international recognition by 30





industry groups and government. TransCanada has rigorously managed fugitive 1 emissions from its Canadian pipeline system for over a decade. The TransCanada 2 Fugitive Emissions Management Program involves identifying leaks on pipeline and 3 compressor station components, such as valves, flanges and fittings, and conducting 4 repairs. The frequency of leak detection activities and timely repair are paramount to 5 the Fugitive Emissions Management Program. Compressor stations are monitored on 6 an annual basis, whereas meter stations are monitored every two years. 7

As part of this system-wide effort, TransCanada has been influential in developing 8 and implementing leak detection technologies. These technologies are first evaluated 9 at the industry association level and validated by regulators. In BC, methods and 10 technologies deemed acceptable for leak detection would be identified in the most 11 recent version of the Western Climate Initiatives (WCI) Reporting Requirements, 12 Section WCI.354. 13

Pull-Down Compressors

Coastal GasLink will use pull-down compressors, where practical, during 14 maintenance activities to conserve natural gas, reduce emissions and ensure a safe 15 worksite. A pull-down compressor is a mobile semi-trailer, which is transported to the 16 worksite and enables the pressure to be lowered and the natural gas to be diverted 17 from the section of the pipeline while the maintenance work is occurring. Once the 18 work is complete, natural gas is returned to the affected area of the pipeline and 19 pressure is restored, and the pull-down compressor is removed from the site. 20

5.2 PERFORMANCE MONITORING

Monitoring, measuring and associated records of asset performance and condition are 21 used to evaluate the implementation and effectiveness of the AMS, constituent 22 programs and the organization’s ability to maximize the long-term value of its assets. 23 Such performance measures include completion of TOPs (e.g., blade wash, 24 calibrations and reporting). 25

The day-to-day operational performance of assets and programs is monitored as a line 26 management function in accordance with specific management plans. Internal audits 27 of the AMS, programs and processes are regularly conducted to determine the degree 28 to which requirements and expectations of the system are met and to determine 29 whether the system is effectively implemented and maintained. 30

31




Section 6 GHG Management System

6.0 GHG MANAGEMENT SYSTEM

TransCanada integrates GHG emissions information in a GHG management system 1 that organizes documents and data, and coordinates the process for developing, 2 revising, tracking and distributing items through a facility life cycle. A flow diagram 3 (Figure 6-1) depicts the system and inputs into this system. 4

Table 6-1 outlines key documents to be developed as part of the GHG management 5 system to provide working level guidance to TransCanada staff on quantification and 6 activity data management. 7

8

Figure 6-1: GHG Management System

Automatic On-Site Fuel Usage Measurement

Data Storage -Gas Measurement System

Data Transfer to Air Emission Data

Management System

Data Storage- Air Emissions Data

Natural Gas Sample Analysis

Data QA/QC Gas Quality and

Measurement Integrity

Data QA/QC & GHG Calculations

Data Summary & QA/QC Records

Annual Reporting

Automatic On-site Equipment Running Hours Measurement

Data Storage - Production System

Reporting Requirement Updates and Previous

Year Records



Section 6 GHG Management System


Table 6-1: GHG Management Document List

Filename Description BC GHG Quantification Methodology This methodology document describes the Western Climate

Initiative (WCI) methodologies and data management applicable to this Project and used for BC GHG reporting.

Quality Assurance and Quality Control Procedures

These procedures describe TransCanada’s QA/QC practices, including periodic data reviews, monthly gas measurement and production accounting, annual production system audits and data verification.




Section 7 GHG Reporting and Verification

7.0 GHG REPORTING AND VERIFICATION

In BC, currently reporting requirements are described in the Reporting Regulation of 1 the Greenhouse Gas Reduction (Cap and Trade) Act. However, this Act will be 2 repealed when the new reporting regulation takes effect under the authority of the 3 recently enacted Greenhouse Gas Industrial Reporting and Control Act. Coastal 4 GasLink has been advised that reporting and verification obligations are expected to 5 stay similar with enactment of the new legislation. Depending on the total annual 6 GHG emissions, oil and gas facilities in BC will need to report and possibly be third-7 party verified, as described in Table 2-1. This Project will meet the requirements to 8 report and will need to undergo verification as outlined in Table 2-1. Once the Project 9 is operational, a report will need to be submitted to the BC MOE via the Single 10 Window Information Manager and be verified by the specified deadlines, respectively, 11 after each reportable year. 12

Canadian facilities under the authority of Section 46 of the Canadian Environmental 13 Protection Act (EC 1999), are required to report annual GHG emissions to 14 Environment Canada via the Single Window Information Manager. The deadline to 15 report is June 1 after each reporting year. There is currently no verification 16 requirement for GHG reporting to Environment Canada. Activities and sources 17 included in this reporting program are captured in the BC Reporting Regulation and, 18 therefore, do not have to be re-quantified. 19

When quantifying GHG emissions in BC, applicable WCI requirements are followed. 20 WCI requirements are more stringent than methods recommended by Environment 21 Canada. Therefore, methodologies defined in WCI.20 and WCI.350 will be used for 22 emission quantification. Project-specific emission quantification requirements, 23 policies and procedures will be prepared once the Project is operational. 24

Verification requirements will be defined in the Reporting Regulation and are further 25 explained in the most recent version of BC MOE’s document called Reporting 26 Regulation Guidance Document: Verification. Coastal GasLink understands the 27 reporting regulation and guidance document will be used to determine level of 28 assurance, conflict of interest, standards, criteria, materiality and more verification 29 requirements. 30




Section 8 References

8.0 REFERENCES

British Columbia Oil and Gas Commission (BC OGC). February 2013. Flaring and 1 Venting Reduction Guideline. Available at: 2 http://www.bcogc.ca/node/5916/download. [Accessed: January 2014]. 3

Environment Canada (EC). 1999. Canadian Environmental Protection Act. Available 4 at: http://www.ec.gc.ca/lcpe-cepa/default.asp?lang=En&n=26A03BFA-1. 5 [Accessed: January 2014]. 6

Environment Canada (EC). 2013. Canada’s Emission Trends. Environment Canada. 7 October 2013. 8

Government of British Columbia (BC). 2007. Bill 44 – 2007 Greenhouse Gas 9 Reduction Targets Act. Available at: 10 http://www.leg.bc.ca/38th3rd/1st_read/gov44-1.htm. [Accessed: January 11 2014]. 12

Government of British Columbia (BC). 2008. Carbon Tax Act. Available at: 13 http://www.bclaws.ca/EPLibraries/bclaws_new/document/ID/freeside/00_08014 40_01. [Accessed: January 2014]. 15

Government of British Columbia (BC). 2010. Greenhouse Gas Reduction (Cap and 16 Trade) Act. Reporting Regulation. Available at: 17 http://www.bclaws.ca/EPLibraries/bclaws_new/document/ID/freeside/272_2018 09. [Accessed January 2014]. 19

Government of British Columbia (BC). 2014. Greenhouse Gas Industrial Reporting 20 and Control Act. Available at: https://www.leg.bc.ca/40th3rd/1st_read/gov02-21 1.htm. [Accessed October 2014]. 22



Coastal GasLink Pipeline Project Greenhouse Gas Emissions Management Plan Appendices


Issued for Review CGL4703-CGP-ENV-PLN-011

Appendices

Coastal GasLink Pipeline Project Greenhouse Gas Emissions Management Plan Appendices



Coastal GasLink Pipeline Project Greenhouse Gas Emissions Management Plan Appendix A



Appendix A

Glossary

Coastal GasLink Pipeline Project Greenhouse Gas Emissions Management Plan Appendix A



LIST OF ABBREVIATIONS AMS Asset Management System BATEA best available technology economically achievable BC British Columbia bcf/d billion cubic feet per day CAC criteria air contaminant CAS Climate Action Secretariat cfh cubic feet hour Coastal GasLink Coastal GasLink Pipeline Ltd. CO carbon monoxide CO2 carbon dioxide DLE dry low emissions EAC Environmental Assessment Certificate EC Environment Canada FEILR fugitive emission inspection and leak repair GHG greenhouse gases LiDAR leak detection and repair LNG liquefied natural gas MNGD Ministry of Natural Gas Development NH3 ammonia NOx nitrogen oxides Plan Greenhouse Gas Management Plan PM particulate matter Project Coastal GasLink Pipeline Project and associated facilities SCR selective catalytic reduction TCPL TransCanada PipeLines Limited TOPS TransCanada Operating Procedures WCI Western Climate Initiative WHR waste heat recovery

Coastal GasLink Pipeline Project Greenhouse Gas Emissions Management Plan Appendix B



Appendix B

Construction Air Emission Management Plan




INTRODUCTION

The construction of the Project will result in CAC and GHG emissions to the atmosphere. The construction phase will take approximately three years with annual construction emissions totalling less than 23% of a given year of operation at full build out. These emissions have been quantified and assessed in Section 6 of the Application. Coastal GasLink has prepared the following plan to mitigate emissions from construction mobile equipment and land clearing activities.

BEST AVAILABLE TECHNOLOGY ECONOMICALLY ACHIEVABLE

During construction BATEA will be implemented. The following list builds on techniques and mitigation listed in the Application.

Mobile Construction Equipment

Correct sizing of equipment. Coastal GasLink will assess the capacity of the equipment being considered and will use equipment meeting the minimum size requirements in an effort to reduce unnecessary fuel consumption.

Planning ahead. During construction and operations, Coastal GasLink will devise a plan in advance of project activities to reduce the project footprint, and restrict activities to the designated work areas.

Driver behaviour. Employees will be educated on how to effectively use equipment. The proper driving technique can help reduce fuel consumption and required maintenance activities. As well, speed restrictions will be implemented to reduce the load placed on the mobile equipment and improve site safety.

Vehicle maintenance. On-road and off-road equipment will be diligently serviced and properly tuned on a regular bases to increase fuel consumption efficiency.

Modernizing fleet and equipment. In addition to vehicle maintenance, newer and more efficient equipment will be considered in the attempt to modernize the fleet and reduce fuel consumption.

Reduce idling. Employees will be encouraged to reduce idling times and turn off equipment when not in use or when safe to do so. As well, idling reduction equipment will be implemented where practical 1 (i.e., battery powered units, or automatic shutdown systems)

Regulatory standards: Heavy and light duty equipment will adhere to and meet all relevant regulatory emission standards.

Alternative fuels. The most common fuels used by mobile equipment are gasoline and diesel. However, in some instances propane or compressed natural gas might be used. The efficiency of the fuel will be assessed when selecting the type of equipment to use. As well, when considering the fuel type, effort will be made to




combust fuel grades with low sulphur contents. Where practical, equipment capable of using renewable fuels (such as biofuels) will be introduced.

Land Clearing and Biomass Burning

Timber will be salvaged in accordance with the Timber Salvage Strategy and the fibre utilization plan. To the extent practical, non-marketable timber will be considered for rollback, bio-stabilization or other uses. If warranted, unusable timber may be chipped and dispersed in specific locations.

Compressor station locations will be chosen to improve the spread between sites. This reduces the amount of above grade facilities and land clearing.

Provincially accepted guidelines will be followed for controlled open burning to increase burning efficiency. These guidelines may include the Open Burning Smoke Control Regulation of the Environmental Management Act, the Wildfire Act, and the Wildfire Regulation.

The ROW will be reclaimed following construction and vegetation will be allowed to regrow, leaving space for maintenance and safety activities.

Alternatives to counteract the permanent removal of GHG sinks for station footprints will be assessed post construction, but may be related in planting additional vegetation in the areas surrounding the stations to increase the capacity of the surrounding GHG sinks.

Coastal GasLink Pipeline Project Greenhouse Gas Emissions Management Plan Appendix C



Appendix C

Combustion Equipment Manufacturer Specifications




Appendix C presents the manufacturer information of the planned compressor packages, generators and heaters.

LM2500+ Compressor Package

Table B-1 LM 2500+ DLE Emissions Guarantee Summary Power Range [%] 50-100

NOx [ppm] 24.4 CO [ppm] 25

UHC [ppm] 15 Note: Guarantees valid for T2 range of -12.2 to 37.8°C Appropriate mapping was completed (includes bleed restriction, proper model selection)

Generator

Specifications to be provided upon generator final selection.

Heaters/Boilers

The following pages summarize the specification of the AAA3000 Super Hot boiler/heater from Allied Engineering Company. The total exhaust from the boiler is 199,024 cubic feet per hour (cfh). This includes 58,537 cfh from combustion and 140,487 cfh from dilution air. Table B-2 lists the emissions per combustion before the dilution air is added to the exhaust flow.

Table B-2 AAA3000 Emissions Summary Species Emissions per 58,537 cfh

CO 30 [ppm] NOx 80 [ppm] CO2 7.8 %

Key features of the AAA3000 boiler include:

85% Combustion Efficiency

2012 DOE & NRCAN Compliant

Natural Gas or Propane

480M to 3,000M BTU

H.P. 76.2

greenhouse gas emissions management plan

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