Navigating Canada's greenhouse gas policy landscape: a comparison of carbon market mechanisms in the oil and gas sector

Abstract

Canada has the third largest oil reserves in the world and its production is expected to grow to 4.9 million barrels per day by 2020. As energy production and greenhouse gas (GHG) emissions grow, Canada's provincial governments are implementing policies that utilize market-based mechanisms to mitigate GHG emissions. The oil and gas sector should seek to understand this fragmented policy landscape as there is significant business risk that the policy and legal environment will change quickly, imposing incremental costs to regulated emitters. Market-based regulations also give oil and gas producers the opportunity to gain a competitive advantage by developing new forms of revenue from commoditizing GHG emission reduction projects. This research compares carbon market mechanisms across and within jurisdictional boundaries using seven criteria: facility type, project type, baseline, additionality, crediting period, measurement, monitoring and verification, and credit value. These criteria are used to compare existing and emerging carbon market mechanisms in the provinces of Alberta, British Columbia, and Saskatchewan, as well as GHG fuels standards. Results show variability in rules for commoditizing GHG emission reduction projects. The study highlights significant differences between carbon market mechanisms and offers key design features for effective market-based GHG policy in Canada's oil and gas sector.

Keywords:

• Canadian greenhouse gas policy
• carbon markets
• oil and gas

1. Introduction

Canada has the third largest oil reserves in the world with 173.6 billion barrels of proven oil reserves, 98% (170 billion barrels) of which is unconventional oil from oil sands deposits (Energy Information Administration [EIA], 2012). Of the 3.24 million barrels per day of crude produced in Canada in 2012, 1.80 million barrels per day were derived from the oil sands of Alberta (Canadian Association of Petroleum Producers [CAPP], 2013a). According to industry projections, Canada's total oil production is expected to be 4.85 million barrels per day by 2020 (CAPP, 2013a). While the oil sands industry has reduced its per-unit of production emissions by 26% below 1990 levels, emissions from the oil and gas sector as a whole have increased 61% above 1990 levels as total production grows and as more greenhouse gas (GHG)-intensive sources replace easily removable reserves of conventional crude oil (Environment Canada, 2013a). To curb growing emissions, Canada's provincial governments are implementing policies that utilize market-based mechanisms to mitigate GHG emission growth. Carbon pricing is considered to be a more efficient management policy than command-and-control regulations given its flexibility and cost-effectiveness for attainment of policy goals (Aldy & Stavins, 2011).

As a result of the division of jurisdictional power between federal and provincial governments over environmental matters and the lack of a cohesive national approach to climate change, Canada's GHG policy landscape has become very fragmented (Belanger, 2011; Boyle, 2008). Various GHG policies are emerging across sub-national jurisdictions with a federal sector by sector regulatory approach emerging (Sawyer, 2011). The ranging policy commitments and regulatory frameworks reflect the considerable diversity of each region's economic, geographic, and resource endowment, as well as the region's politics (Klein & Walshe, 1999). These coexisting carbon markets each have their own approach regarding eligible project types, developing baseline methodologies, monitoring emissions, and verification procedures (Michalowa, 2011). This type of fragmented environmental policy is expected to lead to increased mitigation costs for regulated sectors (Hof, den Elzen, & van Vuuren, 2009). When compared to unified carbon policy across Canada, a fragmented approach whereby each province acts in isolation is expected to increase GHG mitigation costs by 25% (International Institute for Sustainable Development, 2013; National Round Table on the Environment and the Economy [NRTEE], 2009).

Multiple market-based policies across jurisdictional boundaries present both risks and opportunities (Coria et al., 2010). As major emitters, facilities in the oil and gas sector should seek to understand this fragmented policy landscape for two reasons: (1) There is significant business risk stemming from the likelihood that the policy and legal environment will change quickly, imposing costs to large emitters (Hsu, 2011). Risk does not just include regulations that are directly imposed on facilities, but also reputational risk. Recent opposition to proposed Canadian oil export pipelines demonstrates the importance of public perception to oil sands expansion (Lynch & Sendall, 2012); (2) Oil and gas producers can gain a competitive advantage by developing new forms of revenue from commoditizing GHG emission reduction projects (Lash & Wellington, 2007). Carbon compliance instruments can be traded on carbon markets or used to reduce regulatory compliance costs.

Given the current risks and opportunities of carbon pricing policies in Canada's oil and gas sector, and the likelihood that market mechanisms will become increasingly important as governments move to further regulate GHG emissions, it is important to outline the various rules and approaches that guide the creation of these compliance instruments. To date, there has been no comprehensive analysis of carbon market mechanisms in the oil and gas sector in Canada. This comparison is intended to inform key industry stakeholders, but may also be useful for policy-makers and regulators seeking a detailed comparative analysis of carbon market mechanisms across Canada.

2. Methodology for comparison

This analysis uses seven unique criteria to compare carbon market mechanisms across regulatory systems. Each of these criteria was identified as being fundamental to the development and commercialization of GHG emission reduction activities. A description of each criterion and the rationale for its inclusion are provided below.

(1) Facility type: Carbon credit generation may be limited to specific geographic locations or facility types. Facilities outside of the jurisdiction where the emission reduction regulation has been enacted may not be eligible to generate eligible credits unless efforts are made to link GHG programmes (Haites & Mehling, 2009). The emissions output of a facility may also limit its ability to participate in certain emission-trading schemes. In a cap and trade system, facilities that exceed a programme's emission threshold will require emission permits precluding their ability to generate offsets, which are generated from emission reductions at facilities not covered by the cap (World Resources Institute [WRI], 2005).

(2) Project type: Typically only specific GHG emission reduction project types can qualify within a given GHG programme. While performance credits may include any emission reduction activity at a regulated facility, offset projects generated at facilities not subject to regulatory emission reduction obligations are often limited to only select project types. Offset protocols are documents often used to define the quantification methodology with respect to a specific project type; however under some programmes, general GHG accounting standards, such as the World Resources Institute and World Business Council for Sustainable Development Protocol for Project Accounting or the International Organization for Standardization (ISO) Standard 14064 Part 2, may be used to quantify emission reductions (Kollmuss, Lazarus, Lee, LeFranc, & Polycarp, 2010). Common offset project types include renewable energy generation, forestry/land management, energy efficiency, and methane/industrial gas management.

(3) Baseline: The baseline scenario is a reference case for the GHG project activity. It is a hypothetical description of what would most likely have occurred in the absence of any considerations about climate change mitigation (WRI, 2005). The baseline year against which emission reductions are calculated can vary across jurisdictions, thereby affecting the volume of calculated emission reductions. Approaches for calculating baseline emissions include historic benchmark, performance standard, comparison approach, projection-based, and adjusted baseline approach (Alberta Environment [AENV], 2011).

(4) Additionality: Often projects that reduce GHG emissions are undertaken regardless of GHG considerations. In these cases, the project activity and its baseline scenario are effectively identical and the project does not actually represent any emission reduction activity (WRI, 2005). Additionality tests attempt to establish whether an offset project would have happened anyway (Kollmuss, Zink, & Polycarp, 2008). There are several methods for demonstrating if a project is additional to business as usual. Common methods include regulatory surplus, implementation barriers (including investment, technological, and institutional barriers), common practice, performance benchmarking, and technology benchmarking (Verified Carbon Standard, 2011).

(5) Crediting period: The duration that a GHG emission reduction project is eligible to generate credits often varies with project type and jurisdiction. It is common for regulators to define a set crediting period to provide a stable period for investments and commercial planning (AENV, 2011). A crediting period can also be retroactive. The ability to commercialize historic emission reduction activities often serves to reward early-movers of GHG mitigation technologies or practices (Michaelowa & Rolfe, 2001).

(6) Measurement, Monitoring and Verification (MMV): MMV methods vary greatly between projects and programmes. A GHG mitigation programme often stipulates unique approaches for dealing with baseline adjustments, data measurement and tracking, accuracy requirements, and independent verification (Efficiency Valuation Organization, 2010). Under some GHG programmes excessive measurement and verification requirements can increase project monitoring costs making commercialization uneconomic (Tarnoczi, 2011). Verification can be done to a limited or reasonable level of assurance. The level of assurance dictates the nature of the verification statement and the level of effort required by the verification body to determine if there are any material errors, omissions, or misrepresentations in the GHG assertion. Verifications conducted to a limited level of assurance generally involve fewer verification activities, such as inquiry, analytical procedures, and discussion, reducing the risk of an inappropriate conclusion to a moderate level (Environment Canada, 2010).

(7) Credit value: Price formation in carbon markets varies from system to system and depends on a complex interplay between policy targets, dynamic technology costs, and market rules (Blytha, Bunnb, Kettunenb, & Wilsonc, 2009). A strong price signal creates a greater economic incentive for GHG mitigation projects. On the other hand, the financial liability due to regulatory exposure for larger emitting facilities increases with carbon market price. In some emission-trading systems, price floors are used to guarantee minimum abatement efforts while price ceilings are used to manage cost uncertainty (Philibert, 2009).

3. Results: overview of carbon market mechanisms

For the purpose of this analysis carbon market mechanisms are defined as regulatory instruments that encourage GHG emission reductions through market signals without mandating specific emission control methods (Stavins, 2002). Examples of carbon market mechanisms include a carbon tax or per tonne emission charge, renewable portfolio standards with certificate trading, low-carbon fuel standards (LCFSs) with certificate trading, cap and trade, and baseline and credit systems (Boyle, 2008; Litz & Hamel, 2007).

This section provides an overview of the various carbon market mechanisms that are applicable to the oil and gas sector in Canada. The analysis focuses on existing regulations in the provinces of Alberta and British Columbia (BC), as well as emerging regulations in BC and Saskatchewan. LCFSs from other jurisdictions that impact Canada's oil and gas sector are also explored. Where programmes are sufficiently developed, the seven criteria discussed in the previous section are used to guide the comparative analysis.

3.1. Alberta's Specified Gas Emitters Regulation

Alberta is Canada's largest energy producing province with natural gas and liquid hydrocarbon production making up 71% and 78% of Canada's total production, respectively (CAPP, 2013b). As a result of province's intensive oil and gas production, Alberta is the largest GHG emitter in Canada with emissions of 242 MtCO₂e/year (Environment Canada, 2013a). In 2007, Alberta became the first jurisdiction in North America to impose legislated targets for reducing emissions from large industrial facilities (Hogg, 2008). Alberta's Climate Change Strategy committed to a 50 MtCO₂e reduction in GHG emissions by 2020 and a 200 MtCO₂e reduction by 2050 (AENV, 2008). To help achieve this emission reduction goal, the Specified Gas Emitters Regulation (SGER) required large facilities (i.e. those that emit greater than 100,000 tCO₂e/year) across all sectors to reduce their GHG emissions intensity by 12%, as of 1 July 2007 (Province of Alberta, 2007). Emissions intensity, under the Alberta Climate Change and Emissions Management Act, is defined as the quantity of GHGs released by a facility per unit of production (Province of Alberta, 2003). For example, the unit of production for an oil sands facility is defined as tCO₂e/barrel bitumen produced. Companies have four choices to their meet compliance targets under the SGER (Kollmuss et al., 2010): (1) Reduce emissions by improving facility operations; (2) Purchase or use Emission Performance Credits; (3) Purchase Alberta-based offset credits; and (4) Contribute to the Climate Change and Emissions Management Corporation's Fund.

3.1.1. Emission performance credits

Regulated entities under the SGER that have gone beyond the 12% mandatory intensity reduction can generate Emission Performance Credits (EPCs). EPCs can be banked for use in future years or sold to other regulated facilities that need to meet the emission intensity reduction target. Below is an overview of EPCs under the SGER according to information obtained from Alberta Environment's Technical Guidance for Completing Specified Gas Compliance Reports (AENV, 2013a).

• Eligible facility types: EPCs can be generated at Alberta-based facilities that are required to reduce their emission intensity under the SGER (i.e. emit greater than 100,000 tCO₂e/year).

• Eligible project types: Any regulated facilities under the SGER that makes direct, demonstrable improvements beyond their 12% mandatory intensity reduction will generate EPCs. EPCs cannot be generated through changes in reporting methodology, shifting of emissions upstream or downstream of the facility (i.e. increases in indirect emissions), short-term fluctuations in facility production, reductions of industrial process emissions, or CO₂ emissions from combustion and decomposition of biomass. Examples of facility improvements include adapting new technologies, enhanced maintenance procedures, and fuel switching.

• Baseline: Baseline emission intensity for facilities in operation before 1 January 2000 is calculated based on average 2003–2005 emissions. For facilities that have operated less than eight years and began commercial operation after 1 January 2000, the first three years of operation are used to establish the facility's baseline emission intensity. Emission intensity reductions are phased in over a six-year period at a rate of 2% per year beginning in the fourth year of operations. The full 12% annual reduction level is achieved after a new facility's ninth year of operation (AENV, 2012).

• Additionality criteria: There are no additionality criteria for generating EPCs. Any eligible facility improvement that reduces emission intensity beyond the established baseline will generate credits, even if the improvement is considered common practice.

• Crediting period duration: No formal crediting period is defined for the generation of EPCs. Facility improvements will continue to generate EPCs relative to the established baseline so long as the 12% mandatory intensity reduction target is met.

• MMV: Emissions intensity reductions based on facility improvements can be determined using several measurement and calculation options including extrapolation from historic data (AENV, 2012). EPCs require independent verification to a reasonable level of assurance using ISO 14064-3 and additional standards such as the Standards for Assurance Engagements or Canadian Standard on Assurance Engagements 3410. Materiality thresholds for a facility's compliance assertion is set at 2% if annual emissions are >500,000 tCO₂e/year or 5% if annual emissions are <500,000 tCO₂e/year. Approximately 10% of compliance reports are audited on behalf of Alberta Environment after undergoing verification.

• Credit value: Transactions occur through bilateral contracts negotiated between the buyer and seller. The option for a Large Final Emitter to pay C$15/tCOe acts as a price ceiling for EPCs.

3.1.2. Alberta-based offset credits

Facilities regulated under the SGER have the option of using verified emission reductions and/or removals from voluntary actions arising from activities that reduce GHGs in unregulated sectors to meet their compliance obligation. The Alberta-based Offsets Credits System (AOCS) commoditizes emissions reductions from new management practices, technologies, or control systems (C3, 2014a). Alberta Environment's Technical Guidance for Offset Project Developers (AENV, 2013b) was used to assess these market-based instruments.

• Eligible facility types: Alberta-based offset credits can be generated at facilities that are not required to reduce their emission intensity under the SGER (i.e. emit less than 100,000 tCO₂e/year).

• Eligible project types: Projects must have a start date that is on or after 1 January 2002 and have an approved protocol in place. The following protocols are applicable to the oil and gas sector for use under the AOCS (C3, 2014b): Enhanced Oil Recovery; Instrument Gas Conversion to Instrument Air; Engine Fuel Management and Vent Gas Capture; Waste Heat Recovery; Energy Efficiency; Conversion of Drilling Rigs from Diesel-Electric to High-line Electricity Sources; and Solution Gas Conservation. As of January 2013 the Acid Gas Injection Protocol was terminated, but existing projects will continue to generate credits for the duration of the crediting period.

• Baseline: The baseline can be calculated in a number of different ways depending on available information, activity type, and methodology laid out in the approved protocol. Acceptable baseline approaches include historic benchmark, performance standard, comparison approach, projection base, and adjusted baseline. Baselines can be further classified as static or dynamic (AENV, 2011).

• Additionality criteria: 40% uptake of an activity as determined by Alberta Environment is the additionality threshold for determining if an activity is business as usual/sector common practice. Projects do not have to demonstrate financial additionality, but must have alternatives and barriers to the project activity and the project must not be required by law (AENV, 2011).

• Crediting period duration: The crediting period for offsets projects is eight years with a possible five-year extension for most project types. Effective 1 January 2012, retroactive offset credits are no longer accepted in the Alberta offset system. Offset crediting is permitted on a go-forward basis only.

• MMV: Most offset protocols require direct measurement and monitoring. Projects require independent verification to a reasonable level of assurance using ISO 14064-3 and additional standards such as the Standards for Assurance Engagements Canadian Standard on Assurance Engagements 3410. Cumulative error on an absolute basis cannot exceed 5%. Facility compliance submissions (including offset credits) may be selected for government audit which is essentially a second third-party verification.

• Credit value: Transactions occur through bilateral contracts negotiated between the buyer and seller. Contractual terms vary based on project type. Project types where the risk of having credits revoked is low demand a higher market price. The option for Large Final Emitters to pay C$15/tCOe provides a price ceiling for investment in offset projects. This price is expected to increase over time. Typically Alberta-based offset credits trade in the range of C$10–14/tCO₂e (Point Carbon, 2012).

3.1.3. Climate Change Emissions Management Corporation

The Climate Change Emissions Management Corporation (CCEMC) is the entity responsible for investing the funds collected through the SGER. The CCEMC is an arms-length organization that is accountable to Alberta Environment. It has a mandate to reduce GHG emissions by investing in the development of clean technology to support Alberta's 2008 Climate Change Strategy (Climate Change and Emissions Management Corporation [CCEMC], 2013a). In the oil sands, where emission reduction activities involve large capital investments and long time horizons, the CCEMC serves to accelerate technology development and deployment (Tarnoczi, 2013). The seven assessment criteria are discussed in reference to the Climate Change and Emissions Management Corporation 2013–2016 Business Plan (CCEMC, 2013a).

• Eligible facility types: Small-scale demonstration projects receiving funding can be located anywhere as long as the project technology can be transferred to Alberta. For large-scale demonstration projects, only those occurring in Alberta are eligible (CCEMC, 2013b).

• Eligible project types: The CCEMC funds projects at all levels of the innovation chain, from early stage research and development to commercialization. Projects can be categorized into one of three investment areas: energy efficiency, carbon capture and storage (CCS), and greening energy production (including fuel switching, renewable production, and clean energy production and distribution). More recently the CCEMC has also expanded to support climate adaptation and emission reduction projects from biological sources.

• Baseline: Two baseline emission scenarios (project and market) are to be considered for project applications. Project emissions reductions are evaluated against the change from historical conditions and average conditions in Alberta. Market emission reductions are evaluated against the change in average conditions in Alberta (CCEMC, 2012). Baselines can include regulatory requirements; relevant GHG scheme requirements; actual practices; historical practices; alternative practice; best available technology; or emerging technology (CCEMC, 2010).

• Additionality criteria: Projects are considered additional if they overcome one or more barriers. Validation ensures that the baseline represents the most plausible alternative scenario. If the business as usual scenario is eliminated as a potential baseline through a barriers analysis, the project is additional. The barriers analysis should include investment, technological, social, or other barriers (CCEMC, 2010).

• Crediting period duration: Projects do not receive annual crediting, but instead receive upfront project financing. These funds are collected by the project proponent over no more than three years (CCEMC, 2011).

• MMV: Projects must undergo independent validation of the GHG assertion and the technical and financial additionality of the project (CCEMC, 2010). Emissions can be quantified using a variety of methods ranging from design requirements and extrapolations to direct measurement. Uncertainty that affects the GHG claim by more than 50% is considered material. If approved for funding, projects must annually report on GHG reductions and these reductions must be verified by an independent party (AEW, 2011).

• Credit value: No credits are generated for these projects as funding is awarded based on the ability of the project to stimulate the development, application, and commercialization of clean technology, processes, or systems. Based on estimated emission reductions, each tonne of CO₂e emission reductions has been funded an average of C$40 (CCEMC, 2013c).

3.2. BC's Climate Action Plan

BC is Canada's second leading natural gas-producing province accounting for 24% of total production and 47% of Canada's total natural gas reserves (CAPP, 2013b). As technological advances have spurred rapid investment in BC's Montney and Horn River shale gas deposits (EIA, 2011), BC's total GHG emissions increased by 20% between 1990 and 2011 from 49.4 MtCO2e to 59.1 MtCO2e, with the greatest growth resulting from fossil fuel production and fugitive emissions from oil and natural gas (Environment Canada, 2013a).

BC's Greenhouse Gas Reduction Targets Act (GGRTA) was passed in November 2007 and came into force on 1 January 2008 (Government of British Columbia, 2007). The GGRTA establishes targets for reducing provincial GHG emissions in BC to 33% below 2007 levels by 2020 and 80% below 2007 levels by 2050. To meet these targets BC has passed a number of pieces of legislation that define the province's approach to reducing GHG emissions (Government of British Columbia, 2008a). Regulations applicable to the oil and gas sector include:

• Carbon Tax Act;

• Greenhouse Gas Reduction (Cap and Trade) Act;

• GGRTA, Carbon Neutral Government Regulation; and

• Greenhouse Gas Reduction (Renewable and Low Carbon Fuel Requirements) Act.

The following section will overview BC's carbon tax, its emerging cap and trade system, and its carbon neutral government regulation. BC's low carbon fuel requirements are discussed in reference to other fuel regulations in a later section.

3.2.1. Carbon Tax

Theory suggests the simplest and most efficient approach to carbon pricing is through a carbon tax (Aldy, Ley, & Parry, 2008; International Monetary Fund, 2012; Metcalf, 2007). A carbon tax provides a clear price signal, requires less bureaucracy, reduces costs, accrues revenue straight to the government that collects it, and does not place an upper limit on emissions reductions (Whiteman, 2011). Unlike cap and trade, a carbon tax does not provide for emission reduction certainty, but does provide cost certainty to regulated emitters (Avi-Yonah & Uhlmann, 2009).

Since 2008, BC has had a revenue neutral carbon tax as part of its plan to reduce provincial GHG emissions. The economy-wide carbon tax began at a rate of C$10/tCO₂e in 2008, and increased by C$5 per year peaking at C$30/tCO2e in 2012 (Aldy et al., 2008). In June 2013, BC confirmed tax rates would not be increased beyond C$30/tCO2e (British Columbia Ministry of Finance [BCMF], 2013a). The tax is collected upstream at the fuel distribution level and is based on the carbon content of fuels. Oil and gas operators are required to pay for GHG emissions from fossil fuel combustion. Emissions from industrial processes, which vary depending on production processes and are administratively challenging to measure, are excluded from the tax. It is expected that these emissions will be subject to a cap and trade system or other future GHG reduction measures (Duff, 2008). An overview of the BC Carbon Tax according to information obtained from the Carbon Tax Act (Government of British Columbia, 2008b) is provided below. Some of the seven criteria used in the comparison are not applicable to the BC Carbon Tax given that the market mechanism is not a tradable credit.

• Eligible facility types: The carbon tax is intended to be an economy-wide tax on the purchase or use of fossil fuels within the province. The tax is applied and collected at the wholesale level in the same way that motor fuel taxes are currently applied and collected, except for natural gas which is collected at the retail level. Any facility that reduces fossil fuel combustion will reduce their exposure to the tax.

• Eligible project types: The tax does not apply to all GHG emissions, only to emissions from the combustion of fossil fuels and other specified combustibles. Emissions from industrial processes such as the production of oil and gas are not subject to the tax.

• Baseline: No baseline is used in a carbon tax approach. All eligible emissions are subject to the tax.

• Additionality criteria: Additionality is not applicable to a carbon tax. Tax exposure is reduced even if emission reduction activities are business as usual.

• Crediting period duration: The BC carbon tax does not allow for the generation of tradable or bankable emission credits.

• MMV: The carbon tax is applied upstream at the wholesale level (fuel distributors) based on the carbon content of fuels to simplify administration. Carbon tax rates by fuel type are defined by the Ministry of Finance (BCMF, 2013b).

• Credit value: The tax rate on 1 July 2012 increased to C$30/tCO₂e. No further increases to the carbon tax are planned.

3.2.2. Carbon Neutral Government Regulation

Under BC's GGRTA, the Carbon Neutral Government Regulation and the Emission Offsets Regulation requires all public sector organizations (PSOs) (including core government, school boards, universities, colleges, health authorities, and Crown corporations) to measure their GHG emissions, reduce emissions where possible, and apply emission offsets to cover remaining emissions so that the requirement of zero net carbon emissions is met (Government of British Columbia, 2008c). The Emission Offsets Regulation originally required that GHG reductions be acquired by the Pacific Carbon Trust (PCT) (Carbon Offset Research and Education, 2011). In November 2013, following a report from the Auditor General of BC that was highly critical of the PCT for failing to source offset credits that were additional to business as usual (Auditor General of British Columbia, 2013), it was announced that the PCT will be transitioned into government (BCMEM, 2013a). Guidance documents and protocols developed by the PCT are expected to carry forward under the Carbon Neutral Government Regulation.

To date, six different offset projects from the oil and gas industry have been acquired under the Carbon Neutral Government Regulation. Below is an overview of the requirements for generating offsets according to the PCT's Guidance Document to the BC Emission Offset Regulation (Pacific Carbon Trust [PCT], 2012). The seven criteria used to compare the requirements of developing PCT offsets with other carbon market mechanisms are provided below.

• Eligible facility types: To develop an offset project under the PCT, projects must have a start date after 29 November 2007 and occur in BC.

• Eligible project types: The oil and gas-related protocols that have been approved for use under the PCT include Blowdown Protocol for Pipeline Systems; Electrification; Engine Fuel Management; High-Bleed to Low-Bleed; Instrument Gas to Air; Pump Conversion; Vent Gas Capture; and Waste Heat Recovery (PCT, 2014). The PCT also allows for aggregation projects and programmes of activities for small-scale projects that are too small on their own to generate enough emission reductions to justify project development costs.

• Baseline: While the baseline quantification is unique to each protocol, the PCT outlines seven general areas that can be used to derive baseline scenarios. These can be placed into two categories, historical and prospective. Historical baselines are developed from past practices and extrapolated into the future. Prospective baselines model future behaviour, usually when past practices are not available.

• Additionality criteria: Additionality is proven by meeting three criteria. First, the project must have begun commercial operation after 29 November 2007. Second, the project must be surplus to regulatory requirements. The third criterion for determining additionality is for the project developer to address financial, technical, or other barriers (including technical expertise, infrastructure, institutional/political, and social barriers). The developer must show that revenue from generating offsets overcomes or partially overcomes these barriers.

• Crediting period duration: All offset projects have a 10-year crediting period unless otherwise ordered by the Director of the Climate Change Branch of the Ministry of Environment. At the end of the 10-year period, proponents can apply to renew the offset project under a new validated project plan. Projects can receive historic credits back to 29 November 2007 (Point Carbon, 2013).

• MMV: The quantification approach for the creation of PCT offsets vary according to protocol. Where multiple quantification methods are available, the final choice must be justified. When there is significant uncertainty in the quantification methodology, conservativeness of the emission reduction claim must be maintained. Conservativeness may be ensured through the application of a discount factor or through the use of worst-case project assumptions. BC regulation requires that project plans first be validated to a reasonable level of assurance by an independent third party that is ISO 14065 accredited. There is no explicit materiality threshold at the validation stage. At the verification stage, an independent verification body must assess the report to a reasonable level of assurance in conformance with the principles and requirements of ISO 14064-3. Cumulative uncertainties must not overstate emission reduction by more than 5%. Conservative assumptions that understate the emission reduction claim by greater than 5% are permitted.

• Credit value: The PCT enters into various types of contractual relationships with project developers depending on the status of their project. PCT documents state that the crown corporation purchases offsets wholesale in the range of C$10 to C$20/tCO₂e and resells to the public sector at a fixed price of C$25/tCO₂e (PCT, 2010).

3.2.3. Cap and trade credits

An emerging area of BC's Climate Action Plan is its provincial cap and trade system. Although BC has the legislation in place to implement a cap and trade system and had initially said it would launch the programme in 2012, the Liberal government under leader Christy Clark has not committed to carrying out the plan and is currently reviewing whether a cap and trade model is the best way to meet the provincial target (Point Carbon, 2011). If implemented, it is expected that the cap and trade programme will be linked through the Western Climate Initiative (WCI) with existing systems in California and Quebec and planned systems in Ontario and Manitoba (World Bank Carbon Finance Unit, 2013). The province's plans have not addressed how the carbon tax and cap and trade system will be coordinated (Aldy et al., 2008). BC does not intend to double regulate emission sources, but may continue to apply the carbon tax on emissions from the residential, commercial, and transportation sectors rather than expand the coverage of its cap and trade system (British Columbia Ministry of Environment [BCME], 2010a; Western Climate Initiative [WCI], 2010a).

3.2.3.1. Cap and trade allowances

Using the seven criteria for comparison, the following section gives an overview of allowance credits under BC's planned cap and trade programme according to the BC Ministry of Environment's Emission Trading Regulation – Consultation Paper (BCME, 2010a).

• Eligible facility types: If an operation is regulated and emits greater than 25,000 tCO₂e a year it is covered by the cap and is eligible to sell excess allowance credits resulting from its emission reduction activities. Oil and gas extraction and gas processing activities are considered Linear Operated Facilities meaning each individual well site is regulated regardless of emissions (Government of British Columbia, 2010).

• Eligible project types: Covered emission activities applicable to oil and gas operations include general stationary combustion, flaring, venting, and fugitive emissions from oil and gas extraction, processing, transmission, distribution, and storage.

• Baseline: Allowances are expected to be issued based on historic emissions from regulated operations informed by emissions reported through BC's Reporting Regulation (Government of British Columbia, 2010). The baseline year is not stated, but provisions for allowance allocation will take into account population growth, economic growth (including new and shut-down sources), and voluntary and mandatory emission reductions.

• Additionality criteria: Any activity that reduces emissions at a regulated facility is considered additional and will decrease the quantity of allowances required for compliance. Allowance credits can be transferred, banked, or sold.

• Crediting period duration: Emission reduction actions that reduce a facility's compliance obligation will generate credits relative to the baseline indefinitely. BC may designate allowances for regulated operations as an incentive for early reductions back to 2008. Early reduction allowances (ERAs) will be designed to reward facilities that can demonstrate emission reductions beyond business as usual activities.

• MMV: Emissions accounting under the cap and trade system, including the generation of allowance and ERAs, will comply with BC's Reporting Regulation which refers to the WCI's Final Essential Requirements for Mandatory Reporting – Amended for Canadian Harmonization (WCI, 2011, 2013). Emissions are calculated based on a combination of measured values, emission factors, manufacturer's specifications, and engineering estimates. The WCI's quantification methodologies are generally flexible with regard to calculation options and missing data. Reported facility emissions are to be verified by an accredited member of the International Accreditation Forum, in accordance with ISO 14065 through a programme developed under ISO 17011. Verification must occur to a reasonable level of assurance in compliance with the requirements specified in the standard ISO 14064-3. The verification must conclude that reported emissions are no less than 95% accurate (BCME, 2012a).

• Credit value: BC would have the ability to set a minimum reserve price for the allowances it offers for sale at any particular auction. Forecast modelling by the WCI suggests allowance prices in 2020 will be US$33/tCO₂e (WCI, 2010b).

3.2.3.2. Cap and trade offsets

The section below provides information on the seven criteria for offset credits under BC's proposed cap and trade programme according to the BC Ministry of Environment's Cap and Trade Offsets Regulation under the Greenhouse Gas Reduction (Cap and Trade) Act – Consultation Paper (BCME, 2010b).

• Eligible facility types: A BC offset or an Emission Reduction Unit (ERU) stemming from verified emission reductions can be created at non-regulated facilities (i.e. those emitting less than 25,000 tCO2e/year). It is expected that WCI Partner jurisdictions will accept offset certificates issued by other WCI Partner jurisdictions and may also accept offset certificates from outside North America (WCI, 2010c).

• Eligible project types: BC would issue ERUs for registered projects with protocols approved by the programme authority and by cap and trade partner jurisdictions. Currently BC and its cap and trade partners in the WCI are evaluating protocols in the areas of agriculture, forestry, and waste management (BCME, 2010b; Det Norske Veritas, 2010). There are no offset project types applicable to the oil and gas sector under consideration as these will likely be covered as Linear Operated Facilities under the programme cap.

• Baseline: The baseline for offsets is to be set using a sector-specific or an activity-specific performance standard. Project-specific baselines may be used under some circumstances. Modelling or other methods of developing the baseline must be transparent to provide the assurance that GHG reductions or removals from a project are not over-estimated.

• Additionality criteria: Additionality criteria for offset projects will be evaluated against a baseline that reflects conservative assumptions. Criteria would be developed under approved protocols. The WCI states that offset certificates will be awarded only for the portion of GHG emission reductions or removals that would not have happened under a baseline scenario (WCI, 2010c).

• Crediting period duration: Offsets would only be issued for projects that have a project start date after 1 January 2007 which is the beginning of the year in which the original WCI Memorandum of Understanding was signed. The crediting period for non-sequestration offset projects would be 10 years and could possibly be renewed for an additional 10 years as specified in the applicable protocol.

• MMV: Quantification approaches will be developed under individual protocols. Offset credits would have to obtain a positive validation and verification opinion from separate accredited independent bodies approved by the programme authority. Projects are to be verified by an accredited member of the International Accreditation Forum, in accordance with ISO 14065 through a programme developed under ISO 17011. Verification must occur to a reasonable level of assurance in compliance with the requirements specified in the standard ISO 14064-3. Material misstatement in the reported GHG reductions or assertion must not exceed +5%. For a WCI offset, the verifier must be able to state, with reasonable assurance, that total reported reductions or removals are free of material misstatement (WCI, 2010c). Conservative assumptions that understate the emission reduction claim by greater than 5% are permitted.

• Credit value: Offsets under a BC cap and trade system would likely trade at a discount to the projected WCI allowance price given the inherent risk associated with offset projects.

3.3. Saskatchewan's management and reduction of GHGs regulation

Saskatchewan is Canada's second largest producer of oil accounting for 13% of the country's total liquid hydrocarbon production (CAPP, 2013b). Saskatchewan's relative emissions have grown more than those of any other province since 1990, increasing by 67% as a result of the development in the province's oil and gas sector (Environment Canada, 2013a). In 2010, Saskatchewan passed the Management and Reduction of Greenhouse Gases Act (Government of Saskatchewan, 2009) establishing a GHG emission reduction programme for the province. Bill 126 sets the province's GHG emission reduction target to reduce emissions by 20% below 2006 levels by 2020 (Saskatchewan Ministry of Environment [SME], 2010a). Regulated emitters are required to reduce emissions by 2% per year over the baseline emission level from 2010 to 2019 in order to achieve the net emission reduction targets (SME, 2010b).

3.3.1. Cap and trade credits: performance credits and offsets

Like the Alberta system, regulated entities in Saskatchewan will be permitted to meet compliance through payments to a technology fund or through the use of carbon compliance instruments. Given the nascent nature of Saskatchewan's cap and trade rules, few details regarding offset and performance credits have been announced. The following examines both offset and allowance credits according to the Summary of Management and Reduction of GHG Regulation published by Saskatchewan's Ministry of Environment (SME, 2010b). Distinctions between offsets and allowance credits are detailed where possible.

• Eligible facility types: Performance credits can be earned by regulated emitters when annual emissions are less than permitted. Performance credits can be carried forward or sold to other parties. The emission threshold for a regulated facility is 50,000 tCO₂e/year. New facilities constructed after 2006 that have emissions in excess of the emissions threshold will also be required to achieve emission reduction targets. Offset credits can be generated at unregulated facilities that are under the 50,000 tCO₂e/year emission threshold.

• Eligible project types: Any activity at a regulated facility that reduces emissions below the prescribed level of emissions can generate performance credits. Pre-certified Investment Credits may be awarded to regulated emitters that have implemented large-scale, transformative emission reduction projects constructed on or after 1 January 2006. Early Action Credits may be provided to regulated emitters for actions that occurred on or after 1 January 2004. Qualifying offset activities have not yet been determined. The province may adopt existing protocols from the AOCS rather than develop an entirely new system.

• Baseline: Regulated emitters can calculate their baseline emission levels on a facility or aggregated facility basis. The baseline for emission reductions is 2006, although if 2006 is not reflective of a typical year, an alternate three-year average calculation that includes the year 2006 may be used. Rules for establishing facility baselines for qualifying offset activities have not yet been finalized.

• Additionality criteria: Performance credits do not have additionality requirements. For Pre-certified Investment Credits and Early Action Credits, additionality is determined on a case-by-case basis. Eligible offset activities must have occurred on or after 1 January 2006. Further guidance documents and policies have yet to be established regarding additionality criteria.

• Crediting period duration: Performance credits are generated indefinitely relative to the baseline. Pre-certified Investment Credit and Early Action Credit duration will likely be judged based on individual applications. A crediting period for offset credits has not yet been defined.

• MMV: For both performance credits and offsets, monitoring and verification procedures will be announced when the programme is brought into force.

• Credit value: Credit value will be effectively capped according to the carbon compliance price. The carbon compliance price gives regulated facilities the option to make a payment to the Saskatchewan Technology Fund Corporation for emissions that exceed regulatory requirements. Given that Saskatchewan is aligning their provincial initiatives with Alberta (Taylor, 2010) a price cap of C$15/tCOe is likely. Offsets will likely trade at a slight discount to this.

3.4. GHG fuel standards

The intention of a GHG fuel standard is to reduce carbon intensity (CI) of fuels based on measured and calculated life cycle emissions associated with individual fuels (IHS Cambridge Energy Research Associates, 2010). Often fuel standard regulations can be met through market-based compliance options, thereby ensuring that access to markets for fuel exporters is not hindered (Sperling & Yeh, 2009). Fuel standards are typically applied to downstream fuel suppliers and blenders and are therefore not a regulation directly related to oil and gas producers. However, because GHG fuel standards are calculated from life cycle emissions, including upstream production, products exported by Canadian oil and gas producers may be subject to fuel standard regulation. In theory, life cycle emissions include all the carbon emitted in the production, transportation, and use of the fuel; however, accurately tracking emission sources is difficult given the variability and uncertainty in life-cycle assessment (LCA) models (Brandt, 2012). California was the first to implement a GHG fuel standard, while the European Union (EU) and BC have similar regulations in place. Other states have been considering low carbon regulation including Oregon, Washington, as well as several states in the Northeast and Midwest (Yeh et al., 2012). California, BC, and the EU have made the most progress with their regulatory systems and are discussed here in greater detail.

3.4.1. California – LCFS

The California Air Resources Board (ARB) implemented the LCFS in January 2010. The regulation calls for at least a 10% reduction in emissions per unit of energy by 2020 (Government of California, 2009). The regulation measures transportation emissions using an LCA and permits emission reduction targets to be met using market-based mechanisms. If a fuel provider exceeds the target, they can receive credits that may be used towards future obligations or traded to other providers not meeting the LCFS target (Government of California, 2007). According to Sperling and Yeh (2009), in order to meet the compliance obligation under the LCFS, regulated parties can meet their compliance obligation under the LCFS by using three strategies: (1) blend low-GHG fuels such as biofuels into gasoline and diesel; (2) purchase low-GHG emitting fuels such as natural gas, biofuels, electricity, and hydrogen; or (3) purchase credits from other refiners or use banked credits from previous years.

In December 2011, the LCFS regulation was amended to revise the treatment of crude oil (California Air Resources Board [CARB], 2012). Originally crudes that formed the majority of California imports were designated a default CI value. If crude was considered High Carbon Intensity Crude Oil (HCICO) they would be assigned a higher CI. Fuels given the HCICO classification had the opportunity to file a detailed application demonstrating that innovative production methods were used resulting in a lower CI (Government of California, 2009). Under the new ‘California Average' approach, if the average crude intensity across California refineries is less than or equal to the baseline then there is no impact beyond meeting programme targets of a 10% reduction by 2020 (CARB, 2011). If the average CI of crude is greater than the baseline, the resulting deficit must be accounted for in addition to the programme target. Also included is a provision for creating credits from purchasing crudes produced using innovative production methods (CARB, 2013a). Below is an overview of California's LCFS according to the Government of California's Final Regulation Order, Sub-article 7, LCFS (CARB, 2013a).

• Eligible facility types: The LCFS applies to producers and importers of transportation fuels in California. For the purposes of generating credits for low CI fuel, emission reductions can be achieved upstream of the refinery gate. As such, the regulation impacts upstream oil and gas facilities including those in Canada which export crude to California.

• Eligible project types: Any regulated party can generate credits where the reported CI is less than the mandated CI requirement for either gasoline or diesel. For crude oil, an ‘innovative method' that reduces a crude oil's production and transport carbon-intensity value below the California average will be eligible to generate credits. Currently only crude production using CCS or solar steam generation are considered to be ‘innovative methods'.

• Baseline: The baseline CI is determined from the total pool of crude oil supplied to California refiners in 2010. If ‘innovative methods' are used to reduce fuel CI, they must be implemented no early than 2010 to be eligible to generate credits. The ‘innovative method' production credits are determined relative to the relevant crude pathway under the Oil Production Greenhouse Gas Emissions Estimator (OPGEE), the model used to calculate CI for crude oil production and transport to California refineries.

• Additionality criteria: Any action deemed by the Executive Officer to be an ‘innovative method' that reduces CI by at least 1.00 gCO₂e/MJ or greater may generate credits.

• Crediting period duration: There is no defined crediting period for California's LCFS. Credits may be generated up to 2020 relative to the annual California average crude CI and the LCFS compliance schedule which stipulates an overall 10% reduction in emissions.

• MMV: Credits are determined by the California-modified Greenhouse gases, Regulated Emissions, and Energy use in Transportation (GREET) pathway, OPGEE model, or an approved custom pathway. Default CI of crude oil production and transportation values are provided in lookup tables. The OPGEE model aims to establish GHG estimates for various crudes from all over the world, while also setting an average California baseline to determine whether specific crudes are above or below the California average. The model includes five general categories of emission sources including direct combustion and associated fugitives from on-site combustion; electricity consumed; venting, flaring and fugitive emissions; emissions embodied in materials; and land-use emissions, resulting from land clearing. Credits generated for oil production using ‘innovative methods' are subject to approval from the Executive Officer. Producers must provide schematic flow charts, a description of all chemical inputs and outputs, a list of all combustion equipment, thermal and electrical consumption, and a description of transportation model used in the crude production life cycle.

• Credit value: California LCFS market activity has been volatile and transactional activity has been thin. In 2013, LCFS credits traded in the range of US$29 to US$54/MtCO₂e (CARB, 2013b). Credits traded significantly higher than the 2012 average price of US$13.50/MtCO₂e as a result of high demand for low carbon feedstock under the Federal Renewable Fuel Standard (RFS2) (Yeh, Wicover, & Kessler, 2013).

3.4.2. BC – Renewable and Low Carbon Fuel Requirements Regulation

BC's Renewable and Low Carbon Fuel Requirements Regulation (RLCFRR) commits the province to a 10% reduction in the CI of BC's transportation fuel blends by 2020 supporting the province's goal to lower GHG emissions 33% by 2020 (BCME, 2012b). Like the California LCFS, a fuel supplier may bank emission credits for use in future compliance years or trade credits to other fuel suppliers (Government of British Columbia, 2008d). An overview of BC's Low Carbon Fuel Requirements is provided with reference to the Government of BC's Renewable and Low Carbon Fuel Requirements Regulation (Government of British Columbia, 2008e), regulatory requirements published by the BC Ministry of Energy, Mines and Petroleum Resources (BCMEM, 2013b), and Part 3 Agreements Consultation Paper (BCMEM, 2013c).

• Eligible facility types: Low carbon fuel requirements apply to all fuel suppliers in BC. For the purposes of generating credits for low CI fuel, credits can be generated by (1) reducing the CI of supplied fuels; (2) acquiring credits from other fuel suppliers; or (3) entering into Part 3 Agreements. Like the California LCFS, the regulation tracks life cycle GHG emissions and therefore has an impact on upstream oil and gas facilities.

• Eligible project types: Credits can occur from emission reductions in the upstream fuel production process while Part 3 Agreements are to support the development and increased market penetration of renewable and low carbon fuels. As a compliance option, Part 3 Agreements are limited to 25% of the total debits from previous compliance periods (Government of British Columbia, 2008d).

• Baseline: The RLCFRR commits the province to a 10% reduction in the CI of BC's transportation fuel blends by 2020. The default level of CI for gasoline based on fuel mixtures is calculated to be 87.29 g/MJ while diesel fuel is assigned an average CI of 93.55 g/MJ. Under this approach, all gasoline and diesel receive the same CI value regardless of crude source.

• Additionality criteria: There are no defined additionality criteria for credits. Any action that reduces CI on a life cycle basis can generate credits. Part 3 Agreements must reduce emissions through the use of low carbon fuel in a way that is additional to what would occur in the absence of the proposed project.

• Crediting period duration: There is no defined crediting period for emission reductions that reduce fuel CI. Credits may be generated relative to the mandated fuel CI set out in the compliance schedule which requires a 10% overall reduction by 2020. Part 3 Agreements are not to generate credits on multi-year contracts; project applications must be submitted each year.

• MMV: The Regulation allows fuel suppliers to use one of three methods to determine the CI of each supplied fuel: (1) Choose the default CI as set forth in the Regulation; (2) Use an approved version of GHGenius to calculate a unique CI; or (3) Use an alternative method approved by the Director. If CI is determined by Method 2 or Method 3, fuel suppliers must meet ISO standards and Director requirements (BCMEM, 2013d). Credits generated under Part 3 Agreements are also to be determined using an approved version of GHGenius.

• Credit value: There has yet to be any reported credit transaction between fuel suppliers. Beginning on 1 July 2013, fuel suppliers were required to ensure that the CI is below the specified threshold. Credit trading will likely become more active as the market matures. The first application deadline for Part 3 Agreements is January 2014.

3.4.3. EU –Fuel Quality Directive

The EU Fuel Quality Directive (EU FQD) was adopted by the EU Council and Parliament in 2009 with the goal of reducing GHG intensity of transportation fuels by up to 10% by 2020 (European Parliament, 2009). The 10% reduction target is made up of a 6% reduction in GHG intensity of fuels by 2020, with intermediate targets of 2% by 2014 and 4% by 2017. The 6% reduction is to be met through the use of biofuels, alternative fuels, and reductions in flaring and venting at production sites. An additional 2% reduction may be required as new technologies such as CCS and electric vehicles become available. A further 2% reduction is to come from the purchase of Clean Development Mechanism (CDM) credits. The GHG intensity of fuels is to be calculated on a life cycle basis using a 2010 baseline of fossil fuel GHG intensity.

Under Article 7a of the Directive, a method for calculating GHG emissions of fuels from fossil sources and baseline fossil fuel GHG intensity is to be developed (European Parliament, 2009). The draft implementing measure for Article 7a requires fuel suppliers to use default GHG intensity values rather than the actual GHG intensity of the upstream fuel production (European Commission, 2011). Although a methodology for calculating actual GHG intensity for fuels was considered (European Commission, 2009), the use of average default values was deemed to strike a balance between the required level of accuracy and administrative burden associated with reporting. Petrol fuel from conventional crude, natural bitumen, and oil shale are assigned life cycle GHG intensities of 87.5, 107, and 108.5 gCO₂e/MJ, respectively (European Commission, 2011). These default values were derived from work carried out by the JEC (JRC, EUCAR and CONCAWE) consortium (JEC, 2007). Baseline fuel CI is derived from consumption data from the Member States’ reporting to the UNFCCC in 2007 (European Commission, 2011). The European Commission is expected to finish drafting implementation measures for the Fuel Quality Directive in 2014 (EurActiv, 2014).

4. Discussion

4.1. Comparing market-based mechanisms

As Canada's crude oil production increases from 3.24 million barrels per day to 4.85 million barrels per day by 2020 (CAPP, 2013a), national emissions are expected to increase 5% to 734 Mt CO₂e (Environment Canada, 2013b). Canada's leading oil and gas-producing provinces of Alberta, BC, and Saskatchewan are also leading the development of GHG market-based policy. Table 1 provides a summary of the GHG market-based mechanisms overviewed in this research. While provincial governments have enacted climate change regulation implementing market mechanisms, the policy landscape is fragmented. This comprehensive overview of carbon market mechanisms applicable to the oil and gas sector shows variation in rules for commercializing GHG emission reduction projects. This section focuses on the significant variations between each of these market-based mechanisms.

Table 1. Summary of carbon market mechanism attributes applicable to Canada's oil and gas industry.

Market mechanism	1. Facility types	2. Project types	3. Baseline	4. Additionality	5. Crediting period	6. MMV	7. Credit value
Alberta’s SGER
EPCs	Alberta-based; >100 kCO2e/y	Any improvements	Average 2003–2005 for existing facilities; first three years of operation for new facilities	None	Indefinite	Verification; cumulative error cannot exceed 5% if <500 ktCO2e/year or 2% if >500 ktCO2e/year	C$15/tCO2e
AOCS	Alberta-based; <100 ktCO2e/y	Limited to approved protocols	Approach varies according to protocol	Project is additional if technology uptake is <40%	8 years plus possible 5-year extension; no historic credits	Verification; cumulative error cannot exceed 5%	C$10–14/tCO2e
CCEMC	Alberta-based for large-scale projects	Limited to CCEMC priority areas	Project and market scenarios must be considered	Project must overcome an investment, technological, social, or other barrier	Projects receive upfront funding, not credits	Validation and verification; cumulative error cannot exceed 50%	Maximum one-to-one funding match
BC's Climate Action Plan
Carbon tax	Any BC-based project that reduces fossil fuel combustion	Applies only to combustion emissions	n/a	n/a	n/a	Tax is calculated according to carbon content of fuel	C$30/tCO2e
Carbon neutral government offsets	Any BC-based project	Limited to approved protocols	Approach varies according to protocol	Start date after 29 November 2007; is surplus to regulation; and has overcome financial, technical or other barriers	10 years plus possible extension subject to regulatory additionality; historic credits back to November 2007	Validation and verification; assertions cannot be overstated by >5%	C$10–20/tCO2e
Cap and trade: allowances	BC-based; >25 kCO2e/y	Includes combustion, flaring, venting, and fugitive emissions	Likely to be based on historic reporting	None	Indefinite	Verification; cumulative error cannot exceed 5%	US$33/tCO2e by 2020
Cap and trade: offsets	BC-based; <25 kCO2e/y	Unknown, but may include agriculture, forestry, and waste management	Approach will vary according to protocol	Likely to be defined by each offset protocol	10 years plus possible 10-year extension; historic credits back to 2007	Validation and verification; assertions cannot be overstated by >5%	Will trade at a discount to predicted allowances price
Saskatchewan's management and reduction of GHGs
Performance credits	Saskatchewan-based; >50 kCO2e/y	Any improvements	Emissions from 2006 or a 3-year average that includes 2006	None	Indefinite; historic credits back to 1 January 2004 or 1 January 2006	In development	C$15/tCO2e if programme is aligned with Alberta
Offsets	Saskatchewan-based; <50 kCO2e/y	Qualifying offset activities	In development	In development; start date after 1 January 2006	In development; historic credits back to 1 January 2006	In development	C$10–14/tCO2e if programme is aligned with Alberta
GHG fuel standards
CA LCFS credits	Credits from innovative methods in upstream production	Any innovative method; includes CCS and solar steam generation	Upstream projects can generate credits relative to fuel CI in 2010	Must be approved by the regulator and reduce emissions by >1.00 gCO2e/MJ	Credits generated annually until 2020	OPGEE quantification tool; subject to approval by the regulator	US$29–54/MtCO2e
BC RLCFRR credits	Credits can be from upstream emission reductions or projects	Any project that reduces a fuel's CI value	Upstream projects can generate credits relative to fuel CI in 2010	Additionality is only required for Part 3 Agreement credits that support low-carbon fuels	Credits generated annually until 2020	GREET quantification tool; subject to approval by the regulator	No market activity

Alberta's SGER highlights the variability around GHG emission reduction commoditization rules within a single provincial programme. From a project development perspective, the CCEMC has the most flexibility with respect to project type, additionality requirements, and MMV. Any emission reduction activity that falls under one of the CCEMC priority areas of greening energy production; renewable and non-renewable energy; conserving and using energy efficiently; and CCS are eligible to receive financing. Unlike CCEMC-funded projects that place no restriction on facility size, EPCs can only be generated at SGER-regulated facilities while offsets credits can only be generated at unregulated facilities where there is an approved protocol in place.

Additionality criteria under the Alberta SGER are most stringent for offset credit generation which requires the technology uptake to be less than 40% across the industry. If an offset project does not meet this requirement, it is considered to be a business as usual activity. The CCEMC requires that some project barriers must be overcome, while EPCs have no additionality requirement so long as the activity reduces emissions below the 12% emission reduction threshold. With respect to MMV, projects seeking financing from the CCEMC have the most flexibility regarding quantification approaches since these emission reduction claims are projections made before the project has actually been implemented. Offsets and EPCs have much more stringent measurement and quantification guidance with strict materiality thresholds in place.

Despite less rigorous quantification methodologies and additionality requirements, EPCs are less subject to criticism than Alberta-based offset credits. Unlike offset projects that require a project plan (a document disclosing how the project will meet the requirements of the SGER and the relevant quantification protocol) to be publicly posted, the creation of EPCs is less transparent. A facility's emission intensity, and consequently compliance obligation, can be significantly impacted by ambiguous accounting, allocation, and credit procedures of oil production by-products and co-products (e.g. coke, sulphur, cogenerated electricity surplus) (Charpentier, Bergerson, & MacLean, 2009). However, unlike the AOCS which has been criticized over the rigour of its quantification procedures (Auditor General of Alberta, 2011), little attention has been directed towards the ambiguity in EPC credit development and quantification methodologies.

BC's Climate Action Plan consists of a suite of market-based mechanisms including a carbon tax, a carbon neutral offset programme, and a planned cap and trade system. The BC carbon tax has been well received by environmental groups (Sustainable Prosperity, 2012); however there are concerns whether the price is stringent enough to substantially reduce emissions. It is expected that the programme will result in only 3 MtCO₂e of reductions by 2020, which is equivalent to just 1% the required 239 MtCO₂e in reductions that Canada will need to meet its 2020 emission target under the Copenhagen Accord (Sawyer, 2011). The carbon tax essentially acts as an indefinite incentive to reduce or avoid GHG emissions and is not subject to rules around baseline, additionality, or crediting. In this way, avoided emissions under a carbon tax regime more closely resemble allowances under a cap and trade system.

Offset credits under BC's existing carbon neutral offset programme and planned cap and trade systems in both BC and Saskatchewan are considerably more flexible than those generated in Alberta. Offset additionality for BC and Saskatchewan credits is not tested against a 40% technology uptake threshold and historic crediting is permitted. Perhaps most importantly to stimulating credit development, BC offsets place a materiality threshold at less than 5%. Permitting GHG assertions to be understated by greater than 5% allows project developers to use conservative quantification methodologies when direct measurement is not available. This is particularly important for commoditizing historic emission reductions where data may not meet protocol requirements with respect to measurement and monitoring. Data limitations are common for development of historic credits where data is collected before the offset system is established.

Historic crediting is characteristic of programmes in their early stages as regulators seek to ensure there is sufficient offset supply to meet compliance obligations. Under Alberta's SGER over 82% of the offsets purchased to comply with Alberta's SGER between 2008 and 2010 were from projects with a start date before the SGER existed (Bramley, Huot, Dyer, & Horne, 2011). After the provincial Auditor General criticized Alberta Environment's administration of the AOCS regarding its transparency, additionality, and its ability to achieve emission reductions (Auditor General of Alberta, 2011), historic credits were no longer permitted in the system. As BC and Saskatchewan's cap and trade systems mature, it can be expected that rules governing offset credit development will eventually become more stringent and historic credits will be restricted.

Fuel standards offer regulated entities the option of purchasing credits in order to meet mandated GHG intensity targets. Renewable or low carbon fuel credits are similar to performance credits under the Alberta SGER in that credits are generated on an intensity basis (i.e. per unit of product or per MJ). Like EPCs, surpluses are created when the fuel CI is below the mandated target for a given year. Also like EPCs, the methodologies for qualifying upstream oil and gas activities are subject to approval by the regulator making them less transparent than offsets under the AOCS where offset project reports are published annually. Generally, life cycle GHG regulations are viewed as inefficient since they fail to target lowest-cost GHG emission reductions across the entire economy and instead limit GHG emission reductions to the transportation fuel supply chain (Bergerson, Kofoworola, Charpentier, Sleep, & MacLean, 2012).

In 2012, compliance with the California LCFS was met largely by blending of ethanol and biodiesel. Credits generated by natural gas and other transportation fuels (e.g. hydrogen, electricity) accounted for only 13% of credits generated (Yeh et al., 2013). The LCFS has been criticized as ethanol's availability may limit refiners' ability to meet the LCFS (Zhang, Joshi, & MacLean, 2012) and because biofuels' production can result in land-use changes and soil carbon releases impacting the effectiveness of the policy (Melillo et al., 2009). Given the dearth of new transportation fuel technologies, California is considering a credit price ceiling and technology fund payment option to keep compliance costs under control (Lade & Lin, 2013). The LCFS also presents incentives for crude shuffling (a form of carbon leakage) whereby production and sales will move to meet the requirements of the regulation without any net GHG benefit (Sperling & Yeh, 2009). The complexity of using an LCA approach to regulate GHG emissions is further highlighted by the nascent BC RLCFRR. The programme has been criticized for favouring Canadian crude by not including indirect land use in its life cycle analysis (Shaw, 2010). For oil sands, land-use conversion can add 1.5–3.1 gCO₂e/MJ for surface-mining compared to 0.025–1.4 gCO₂e/MJ to a fuel's life cycle CI (Yeh, Jordaan, & Brandt, 2009). The RLCFRR has also been criticized for regulatory overlap with emission reductions that are already being regulated under the Carbon Tax and the planned Emission Offset Regulation (Business Council of British Columbia, 2013).

4.2. Design features for effective market-based regulation

The focus of this research has been to compare and highlight differences between market-based mechanisms across several GHG emission reduction programmes. Here, we suggest key policy design features for successful GHG emission reduction measures in Canada's oil and gas sector. Given that sector output will continue to grow, it is important that policies provide flexible compliance options. Limiting resource development through an absolute emissions cap would forego a massive economic opportunity. The Canadian Energy Research Institute estimates cumulative economic benefits of up to $2.8 trillion to Canada over the period of 2011–2035 as a result of oil sands development (Canadian Energy Research Institute, 2012). To strike a balance between resource sector growth and emission reductions, GHG policy needs to promote three key elements: jurisdictional harmonization, administrative simplicity, and technology development.

Jurisdictional harmonization: Given the division of jurisdictional power between federal and provincial governments over environmental matters and the lack of a cohesive national approach to climate change, Canada's GHG policy landscape has become very fragmented (Belanger, 2011). This type of fragmented environmental policy is expected to lead to increased mitigation costs for regulated sectors (Hof et al., 2009). The National Round Table on the Environment and the Economy estimates that Canada's fragmented GHG policy landscape could increase mitigation costs by 25% compared to unified carbon policy across Canada (NRTEE, 2009). Encouraging flexible compliance though increased market linkages would allow emission reductions to be sourced across jurisdictions where it is most efficient on a dollar-per-tonne CO₂e basis. A harmonized nation offset system could also incent clean technology investments in provinces and sectors without comprehensive GHG regulation.

Administrative simplicity: Reducing the administrative burden of GHG credit development increases the volume of credits available for compliance. For example, under the Alberta SGER, to generate offset credits at an unregulated facility, developers must first navigate several levels of protocol review and then adhere to inflexible quantification procedures. Such methodologies do not exist for GHG projects at regulated facilities that generate EPCs. To increase flexibility, Alberta Environment could develop performance standards for baseline emission reduction activities rather than rely on speculative facility-based projections. For offset projects where established quantification protocols do not exist, project developers could be given the flexibly to follow ISO 14062-2 standards as set out under the Canadian Standard Association's GHG CleanProjects Registry (Canadian Standard Association, 2014). To reduce administrative burden associated with credit development, GHG programmes should seek to adopt best practices from international emission trading in the CDM market. The CDM system was previously criticized for its complex procedure for credit generation. As a result, project developers overlooked low-cost mitigation opportunities resulting in an overall negative impact on the cost-effectiveness of the CDM system. To enhance simplicity, programme administrators introduced reforms to standardize baselines, consolidate rules for validation and verification, and introduced materiality thresholds (World Bank, 2014).

Technology Development: Policy should stimulate investment in the transformative technologies necessary for significant reductions in GHG emissions in Canada's oil and gas sector. A study evaluating technology developments for reducing GHGs from oil sands development found that GHG mitigation options in the near and medium terms are limited, amounting to reductions of only 2–9% across in-situ and mining projects below business as usual activity (Jacobs, 2012). In contrast, long-term GHG emission reduction technologies (defined as those that with a greater than 10-year time horizon) have significant potential to reduce GHG emissions (20% for in-situ and 30% for mining). Since new technologies have the greatest potential to significantly reduce GHG emissions, policy-makers should seek to build on the success of Alberta's technology funding model. To encourage innovation across the sector, a portion of the fund may be allocated to emission reduction technologies developed through industry-led collaborations such as the Canadian Oil Sands Innovation Alliance.

Climate change policy should aim to minimize environmental impacts in a way that is cost-effective and does not put Canada's industries at a competitive disadvantage. For regulated facilities, a GHG mitigation programme should provide certainty, consistency, and flexibility in compliance options. This requires that market mechanisms be fungible, encourage development of low-cost reductions, and incent long-term technology development.

5. Conclusion

This study highlights the importance of regulatory understanding for mitigating risk and capitalizing on GHG emission reduction activities. Significant business risk exists for oil and gas producers as GHG regulation can impose substantial compliance costs. Regulation can also change very rapidly leaving large industrial emitters financially exposed. This work also seeks to aid in the successful navigation of regulatory risk and highlight opportunities stemming from GHG regulations. Oil and gas producers may have opportunities to capitalize on carbon markets by commercializing credits through emission reduction activities. It is important that industry track the evolving GHG policy landscape in order to effectively navigate risk and opportunities. Further changes to the GHG policy landscape are expected as the Canadian federal government develops new emission regulations for the oil and gas industry. In the future, individual GHG emission programmes may seek linkage, but in the near term, fragmented regulation will remain the norm.

This work provides a comprehensive analysis that details in-depth credit development requirements for projects originating from Canada's oil and gas sector. This work reviews policy approaches to regulating GHG emissions through market-based mechanisms and may guide similar analysis in other sectors or jurisdictions. Policy options outlined here might inform future GHG regulations for the oil and gas sector being developed federally. This comparison may also highlight key components of credit development that require alignment in order to progress towards harmonization across provincial GHG programmes.