Last year saw continuing shifts in legislative policy, with some crystallization of the uncertainties that plagued the energy industry throughout 2018. On last year’s Top 10 list, we identified several proposed policy and legislative changes that were ultimately implemented in 2019, along with some that have since been abandoned as a result of political transitions.
After several years of volatility that had a significant impact on the Canadian energy industry, political shifts in Western Canada have resulted in new attempts to stimulate growth in some areas of the energy industry, with a particular focus on Alberta’s oil and gas industry.
In this article, we review key legislative and policy developments important to the Canadian oil and gas industry from the previous year. This list sets out some items worth following in the coming year. BLG continues to monitor developments in the oil and gas industry closely.
1. Alberta’s Bill 1: An Act to Repeal the Carbon Tax
The first bill introduced to the Alberta Legislature by the newly elected United Conservative Party was on June 3, 3019, when the government passed Bill 1: An Act to Repeal the Carbon Tax.1 This act retroactively repealed the Climate Leadership Act2 to May 30, 2019. BLG previously wrote an article on this development, available here.
Most favourably, this had the effect of reducing energy costs for many Albertans by eliminating the tax on fuel purchases. The change also eliminated the carbon tax rebates that were previously received by many Albertans. It also reduced the amount of government funding available in the province to stimulate research and development of renewable energy technologies.
These changes were short-lived for many Alberta consumers, as the repeal led to the federal government adding Alberta as a “listed province” under the federal Greenhouse Gas Pollution Pricing Act,3 which is discussed in more detail below.
2. Alberta’s Bill 19: Technology Innovation and Emissions Reduction Implementation Act, 2019
Alberta’s Bill 19: Technology Innovation and Emissions Reduction Implementation Act, 2019,4 or TIER, received royal assent on November 22, 2019. Together with its accompanying regulations, Technology Innovation and Emissions Reduction Regulation5 (TIER Regulation) varied Alberta’s system of managing pollution caps and taxes on large emitters. Previously, large emitters were subject to a cap and trade system under the Carbon Competitiveness Incentive Regulation,6 which was enacted pursuant to the former Climate Change and Emissions Management Act7(CCEMA). Following the implementation of TIER, CCEMA was renamed the Emissions Management and Climate Resilience Act (EMCRA).8
Beyond the name change, the most significant change brought by TIER is the easing of certain restrictions on the government’s use of funds collected pursuant to the EMCRA, and a means of allowing certain transfers out of the TIER Fund and into the General Revenue Fund.
The more substantial changes appear in the TIER Regulation, which implements a variation of a cap and trade system for large emitters. Large emitters to whom the EMCRA applies, are required to meet certain emissions targets per unit of production on a per facility basis. Targets are set to be reduced 1 per cent per year after 2020. If facility emissions exceed the target, the facility may purchase emission credits from other facilities that have beat their targets, purchase emissions offsets from organizations that are not regulated by TIER but have reduced their emissions, or purchase fund credits from the TIER Fund at $30 per credit. Credits can be used to reduce the facility’s net emissions by one tonne of CO2 emissions.
The TIER Regulation will also allow more facilities to participate in the large emitter regulatory scheme by allowing certain facilities that do not meet the 100,000 tonne of CO2e/year emission threshold to opt-in. Additionally, persons responsible for conventional oil and gas facilities can apply to aggregate two or more facilities so that they can be included in the scheme as well. This will allow most large emitters of greenhouse gasses to avoid the federal fuel surcharge system.
3. Federal Backstop for Carbon Tax
The Canadian government passed the Greenhouse Gas Pollution Pricing Act (the Federal Backstop) as part of the Budget Implementation Act, 2018, No 1. The Federal Backstop sets a minimum level of tax on fuel sales and industrial emitters. Provinces that do not implement legislation that meet these requirements will be subject to the Federal Backstop.
The Federal Backstop consists of two parts. Part one is a charge on fossil fuels paid by registered distributors. This took effect in Ontario, Saskatchewan, Manitoba, and New Brunswick on April 1, 2019, and in Alberta on January 1, 2020. Part two is a tax on large industrial facilities, and uses a production output-based pricing system for emission-intensive trade-exposed industries. This took effect in Ontario, Saskatchewan, Manitoba, and New Brunswick in January 2019. Part two will not be implemented in Alberta, as the similar TIER discussed above satisfies the federal requirements.
An appeal to the Supreme Court of Canada on the constitutionality of the Federal Backstop is scheduled to be heard on March 24 and 25, 2020. Watch for more updates on this issue from BLG in the coming year.
4. Bill C-48: Oil Tanker Moratorium Act
The Oil Tanker Moratorium Act9 (OTMA) came into effect on June 21, 2019. The OTMA prohibits oil tankers that are carrying more than 12,500 metric tons of crude oil or persistent oil as cargo from stopping or unloading crude or persistent oil at ports or marine installations located along British Columbia’s north coast, from the northern tip of Vancouver Island to the Alaska border.
Notably, the OTMA does not prohibit tanker traffic in the area. It only prohibits stopping, loading, and unloading. It also does not ban all tankers, only those that carry crude and persistent oil. Tankers carrying LNG and certain other refined fuels are not covered by the statute. This means the LNG facilities planned for and under construction in Kitimat, BC will be able to export LNG as planned. The OTMA also makes an exception to allow oil tankers to moor or anchor at a port or marine installation “to ensure the safety of the oil tanker.”
Certain First Nations, such as the Lax Kw’alaams Nation, who seek to benefit from the proposed Eagle Spirit Energy pipeline and energy corridor along its traditional territory, are expected to challenge the legislation on the grounds that Canada has failed to discharge its duty to consult and are frustrating their ability to benefit from their traditional lands. BLG will follow closely developments in this area in the coming year.
5. Bill C-68: An Act to amend the Fisheries Act
Canada’s Bill C-68: An Act to amend the Fisheries Act and other Acts in consequence10 received royal assent on June 21, 2019. Bill C-68 amended the Fisheries Act11 to enhance protections for fish and fish habitats. BLG previously published an article on the proposed amendments. The proposed amendments not only reverse changes made by the former Conservative government, but also create additional requirements for project approval and management. The amendments provide several provisions aimed at creating more safeguards for fisheries and increase transparency, including establishing a public registry, a permitting mechanism and standards, and codes of practice.
Bill C-68 incorporates several provisions relating to Indigenous rights and knowledge. The amendments include a provision recognizing and affirming the rights of Indigenous peoples, as enshrined in section 35 of the Constitution Act, 198212. The Minister must consider any adverse effects a decision may have on the rights of the Indigenous peoples. Subject to certain exceptions (including procedural fairness), any Indigenous knowledge provided to the Minister is confidential and cannot be disclosed without written consent. The Minister is also authorized to enter into agreements with any Indigenous governing bodies to further the purpose of the Fisheries Act. Prior to making decisions under the Fisheries Act, the Minister may also take into consideration Indigenous knowledge, scientific information, community knowledge, social, economic, and cultural factors, and gender considerations.
6. Bill C-69: An Act to enact the Impact Assessment Act and the Canadian Energy Regulator Act, to amend the Navigation Protection Act and to make consequential amendments to other Acts
Bill C-6913 received Royal Assent on June 21, 2019 and the majority of the bill came into force on August 28, 2019. It implements changes to the federal environmental review process for designated projects. The changes include introducing the Impact Assessment Act14 (IAA) and the Impact Assessment Agency of Canada (the Agency) to replace the Canadian Environmental Assessment Act, 201215 and the Canadian Environmental Assessment Agency, respectively. Bill C-69 also creates the Canadian Energy Regulator Act16 (CERA) in replacement of the National Energy Board Act.17 A previous article outlining the proposed changes in detail can be found here.
The IAA gives the Minister broad discretion to determine by regulation or order which physical activities are designated projects thereunder. The Minister then has discretion to refer designated projects to a review panel. The Minister is to refer all designated projects that involve physical activities that are regulated by the Nuclear Safety and Control Act,18 the Canadian Energy Regulator Act, the Canada-Nova Scotia Offshore Petroleum Resources Accord Implementation Act,19 and the Canada-Newfoundland and Labrador Atlantic Accord Implementation Act.20
In turn, the Agency's assessment must account for, among other things, the impact on any Indigenous group, Indigenous knowledge, the extent to which the project contributes to sustainability and Canada's ability to meet its climate change commitments, and the intersection of sex and gender with other identity factors. Projects currently under review may be transitioned to the IAA if the necessary information or studies required by the former statute have not been collected before the IAA comes into force.
The CERA established the Canadian Energy Regulator (the Regulator). The Regulator’s mandate is to make transparent decisions with respect to pipelines, power lines, off-shore renewable projects and abandoned pipelines. The Regulator will have a board of directors and a Commission (which will replace the National Energy Board), each with at least one Indigenous person. The new CERA will also include provisions governing the operation and abandonment of regulated facilities. Although the administrative structure of the energy regulator will change, final decision-making authority remains with the Cabinet.
Bill C-69 expands the scope of considerations that regulators must take into account when conducting impact assessments. Like Bill C-68, Bill C-69 includes broad implementation of considerations for the rights of the Indigenous peoples in both the IAA and the CERA. Bill C-69 requires that the review process account for environmental, gender, and Indigenous considerations. An impact assessment must take into account some considerations that have not been well considered by courts in Canada, including “the intersection of sex and gender with other identity factors” and “Canada's ability to meet its environmental obligations and its commitments in respect of climate change.” The final factor to be considered in an impact assessment is “any other matter relevant to the impact assessment that the Agency requires to be taken into account.” This means that factors may be added on a case by case basis, which adds flexibility to the process together with some additional uncertainty.
7. British Columbia’s Comprehensive Liability Management Plan
The BC Oil and Gas Commission introduced mandatory timelines for oil and gas site cleanups through the new Dormancy and Shutdown Regulation21 (the Dormancy Regulation) and the Comprehensive Liability Management Plan (CLMP). These changes took effect on May 31, 2019 and introduced mandatory timelines for decommissioning, assessing and restoring inactive oil and gas liabilities. The legislation aims to require closure on all current inactive sites by 2036 and to ensure that 100 per cent of the costs for site cleanups and closures are incurred by the oil and gas industry, rather than the general public.
A well becomes dormant if, for five calendar years, one of the following events has not occurred: production from, or injection or disposal into, the well for a total of 720 hours or more in a calendar year; the completion of a zone; a drilling event; or, in the case of an observation well, the well is active for at least one day. It is possible to avoid a well becoming dormant by requesting a two-year extension for wells that will likely become active within a reasonable time after considering the available reserves, economic factors and safety factors, including the well integrity. A site does not become dormant if any of the wells on a multi-well pad are not dormant and the surface facilities can remain in place as long as they service at least one well that is not dormant.
The regulations create certain deadlines for the decommissioning (plugging and removal of surface equipment), assessment, and restoration of sites based on when they become dormant. There are three different site categories: those that became dormant in 2018 (Type A Sites), those that become dormant after 2018, but before 2024 (Type B Sites), and those becoming dormant in 2024 or later (Type C Sites).
Certain proportions of Type A sites must be decommissioned, assessed, and restored by certain deadlines, with all sites restored by the end of 2036. Type B Sites must be restored within 13 calendar years after the year they become dormant, and Type C Sites must be restored within 10 calendar years after the year they become dormant.
The Dormancy Regulation and CLMP now also mandate certain annual planning and reporting requirements for permit holders in the form of annual work plans describing sites that will be decommissioned, assessed, and restored, the timelines for completing the work and factors that may cause deviations from the plan. By March 31 of each year, permit holders are also required to submit reports describing the work actually completed for the prior year.
As part of the CLMP, the BC Oil and Gas Commission now considers a company’s past conduct when deciding to issue, suspend, transfer, cancel or amend a permit. Additionally, funding for the Orphan Site Reclamation Fund has shifted from a fixed tax on production to a new liability levy. Permit holders will be required to pay a proportion of the total amount to be raised in the year based on the proportion of the total estimated restoration liability for all oil and gas sites in the province. The intention is to avoid taxpayer liability for the costs of abandoning orphaned oil and gas wells.
BLG will continue to monitor the progress of the implementation of the CLMP into 2020 as a planned integration of the liability model and corporate health test into the decision making process is rolled out. Considering the growing number of orphan wells in Alberta awaiting abandonment (3406 as of November 1, 201922), the Alberta government may consider new funding models for the Orphan Well Fund.
8. BC’s Bill 41: Declaration on the Rights of Indigenous Peoples Act
On November 28, 2019, BC’s Bill 41: Declaration on the Rights of Indigenous Peoples Act23 (DRIPA) came into force. As described in its purpose section, DRIPA’s purpose is to “affirm the application of [UNDRIP] to the laws of BC; to contribute to the implementation of [UNDRIP]; to support the affirmation of, and develop relationships with, Indigenous governing bodies.”
The BC government appears to have attempted to be clear that DRIPA does not create a new requirement to obtain the consent of Indigenous peoples before passing laws or approving new forestry, mining, and oil and gas projects. If there is a treaty or comprehensive agreement already in place that requires consent, then consent will have to be obtained. The BC government retains authority for making decisions in the public interest.
BLG will carefully follow the outcome of future BC court decisions that consider the effect of DRIPA.
9. Alberta’s Oil Production Curtailment
Effective January 1, 2019, the Alberta government implemented the Curtailment Rules24 to force oil and gas producers in the province to limit production volumes. The goal was to help bring the total supply in the province in line with the total demand and export capacity in the hopes of reducing the steep discount of the Western Canada Select (WCS) spot price relative to Brent Crude and West Texas Intermediate (WTI). This was critical for the province, as the benchmark crude price impacts the amount of royalties it receives, as well as the revenue received and profit earned by Alberta’s oil and gas producers. This further impacts the province’s tax revenue.
The curtailment order has proven to be a bit of a double-edged sword for the province. The WCS-WTI differential was successfully reduced from a high of around $46 US/bbl to a low around $8 US/bbl. However, the curtailment may have also played a role in limiting capital investment in Alberta’s oil industry. Since producers were restricted in the amount of new capacity that they could bring online, it made expensive drilling programs difficult to justify.
The curtailments were in place all through 2019, and the Alberta government has announced that they will likely continue through to the end of 2020. A number of variations to the scheme were made as 2019 progressed, including increases in production limits, special production allowances for oil shipped out of the province using additional rail capacity and exempting newly drilled conventional oil wells from the production limits.
10. Alberta’s Oil by Rail Policy Reversal
On February 19, 2019, the Alberta government announced a deal with Canadian National and Canadian Pacific to lease 4,400 rail cars to move oil to markets outside of Alberta. After the province implemented the oil production curtailments discussed above, the benefits of shipping oil out of Alberta by rail were substantially diminished, as the cost of doing so does not exceed the pricing differential.
While it would not be directly profitable to do so, the province recognized its unique position of being able to capture a portion of the profit and production from all of Alberta’s oil and gas production, and predicted that the increased price Alberta producers could get for their oil from increased export capacity would more than make up for the cost of leasing the rail capacity.
Following the election of a new provincial government, Alberta has been searching for purchasers for its oil-by-rail contracts.
Alberta’s Preserving Canada’s Economic Prosperity Act was proclaimed into force. British Columbia almost immediately filed a constitutional challenge to the act in federal court, following which it made a motion for, and was granted, an injunction preventing the Minister from exercising her powers under the act.
Alberta’s lower corporate tax rates: In 2019, the new United Conservative Party government announced a reduction in the provincial corporate tax rate, dropping 1 per cent per year until the rate reaches 8 per cent in 2022.
Trans Mountain Pipeline approved – again. On June 18, 2019, the federal government approved the expansion of the Trans Mountain Pipeline for the second time, subject to 156 conditions. Terminal and pumping station construction resumed August 22, 2019, and work on the first section of the pipeline began December 3, 2019.
1 Bill 1: An Act to Repeal the Carbon Tax, SA 2019, c 1.
2 Climate Leadership Act, SA 2016, c C-16.9
3 Greenhouse Gas Pollution Pricing Act, SC 2018, c 12, s 186.
4 Technology Innovation and Emissions Reduction Implementation Act, 2019, SA 2019, c 16.
5 Technology Innovation and Emissions Reduction Regulation, AR 133/2019.
6 Carbon Competitiveness Incentive Regulation, AR 255/2017.
7 Climate Change and Emissions Management Act, SA 2003, c C-16.7.
8 Emissions Management and Climate Resilience Act, SA 2003, c E-7.8.
9 Oil Tanker Moratorium Act, SC 2019, c 26.
10 An Act to amend the Fisheries Act and other Acts in consequence, SC 2019, c 14.
11 Fisheries Act, RSC 1985, c F-14.
12 The Constitution Act, 1982, Schedule B to the Canada Act 1982 (UK), 1982, c 11.
13 Bill C-69: An Act to enact the Impact Assessment Act and the Canadian Energy Regulator Act, to amend the Navigation Protection Act and to make consequential amendments to other Acts, 2019, c 28.
14 Impact Assessment Act, SC 2019, c 28, s 1.
15 Canadian Environmental Assessment Act, 2012, SC 2012, c 19, s 52.
16 Canadian Energy Regulator Act, SC 2019, c 28, s 10.
17 National Energy Board Act, RSC 1985, c N-7.
18 Nuclear Safety and Control Act, SC 1997, c 9.
19 Canada-Nova Scotia Offshore Petroleum Resources Accord Implementation Act, SC 1988, c 28.
20 Canada–Newfoundland and Labrador Atlantic Accord Implementation Act, SC 1987, c 3.
21 Dormancy and Shutdown Regulation, BC Reg 112/2019.
23 Bill 41: Declaration on the Rights of Indigenous Peoples Act, SBC 2019, c 44.
24 AR 214/2018.