2018 saw continuing shifts and uncertainty in legislative and policy developments for the oil and gas industry. On last year’s Top 10 list, found here, we identified several proposed changes to energy regulation across Canada. 2018 further provided us with numerous policy changes, with implications uncertain and complicated by potential political transitions in this new year.
After several years of commodity price freefalls marked with significant price volatility and declining capital investment, the Canadian oil and gas industry faces potential regulatory impediments to industry recovery. In 2018, the trend towards increasingly rigorous approval processes persisted with a focus on environmental impacts and climate change. With elections scheduled for the federal and Alberta governments in the coming months, 2019 may emerge as an inflection point for oil and gas policy-making.
In this article, we consider ten legislative, regulatory and policy developments of import to the Canadian oil and gas industry from the past year. This list sets out some items that bear close monitoring in the coming year. BLG continues to monitor developments in the oil and gas industry closely.
1. Bill C-68: Enhanced Protections for Canada’s Fish and Fish Habitats
Canada’s Bill C-68 introduces amendments to the federal Fisheries Act to enhanced protections for fish and fish habitats. BLG previously published an article on the proposed amendments, found here. The proposed amendments not only reverse changes made by the former Prime Minister Harper’s government but also created additional requirements for project approval and management. The amendments provide several provisions aimed at creating more safeguards for fisheries and increase transparency, including the establishment of a public registry, a permitting mechanism and standards and codes of practice.
Bill C-68 incorporates several provisions relating to Indigenous rights and Indigenous knowledge. The amendments include a provision recognizing and affirming the rights of the Indigenous peoples as enshrined in section 35 of the Constitution Act, 1982. The Minister must consider any adverse effects a decision may have on the rights of the Indigenous peoples. Subject to certain exceptions (including as relates to 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 Act, the Minister may also take into consideration Indigenous knowledge, scientific information, community knowledge, social, economic and cultural factors, and gender considerations.
Bill C-68 has received second reading in the Senate and has been submitted to the Standing Senate Committee on Fisheries and Oceans for consideration.
2. Bill C-69: Changes to Canada’s Environmental Legislation
Bill C-69 is Canada’s bill to overhaul the federal environmental review process for designated projects. The changes include the introduction of the Impact Assessment Act (the “IAA“) and the Impact Assessment Agency of Canada (the “Agency“) to replace the Canadian Environmental Assessment Act, 2012 and the Canadian Environmental Assessment Agency, respectively. Bill C-69 also creates the Canadian Energy Regulator Act (“CERA“) in replacement of the National Energy Board Act. A previous article outlining the proposed changes in detail can be found here.
The proposed IAA gives the Minister broad discretion, including the designation of a physical activity as a “designated physical activity” which in turn requires an impact assessment. 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 has not been collected before the IAA comes into force.
The CERA will establish the Canadian Energy Regulator (the “Regulator“); the Regulator’s mandate is to make transparent decisions with respect to pipelines, powerlines, 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.
The proposed legislation include significant changes to the federal regulatory regime; most significantly, 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 CERA. The Bill has been referred to the Standing Senate Committee on Energy, the Environment and Natural Resources for review.
In its current form, Bill C-69 stands to create greater challenges for the industry to meet the approval requirements. Bill C-69 expressly requires that the review process must account for environmental, gender and Indigenous considerations, but does not place similar emphasis on the economic benefits of the proposed project. To the extent that the review must consider “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”, Bill C-69 creates uncertainty with respect to how these considerations will apply in practice. Further, Bill C-69 provides little clarity as to how the government may exercise its veto power to require a reconsideration of the application or a dismissal of the application entirely.
3. Pipeline Developments: Canada Purchases the Trans Mountain Pipeline and Requests Evaluation of Existing Pipeline Capacity
Pipeline development has received significant public attention in recent years as many projects have been cancelled after a protracted regulatory process. One of the most significant policy decisions of 2018 is the Government of Canada’s purchase of the Trans Mountain pipeline. In May, the federal government announced its plans to buy the pipeline for $4.5 billion. This announcement was made as the Trans Mountain saga continued in court, with the B.C. government’s reference case and the Federal Court of Appeal judicial review. BLG represented the Government of Canada in this transaction, click here to view the media update.
A further development for the midstream sector is the federal Minister of Natural Resources Amarjeet Sohi’s request to the NEB for advice on options to optimize pipeline capacity out of Western Canada. This request has led to National Energy Board’s report on Western Canadian Crude Oil Supply, Markets, and Pipeline Capacity (the “Report“). The Report identifies increase in oil production, lack of additional pipeline capacity, and refinery maintenance in the U.S. Midwest as factors that contributed to the backlog and lower price for Canadian crude oil. The estimated available pipeline takeaway capacity from Western Canada as of September 2018 was 3.95 million barrels per day (bpd), but crude oil production had increased by over 2.7% over the first nine months of 2018 to 4.3 million bpd in September 2018. Though one million bpd of nameplate pipeline capacity was added between 2013 and 2016, no additional capacity has been added since then.
Of note, the Report also identifies the practice of nominating “air barrels” as a factor leading to inflated apportionment of pipeline capacity. NEB-regulated pipelines generally provide two types of services: committed (contracted) and uncommitted (uncontracted). Apportionment refers to the pro rata curtailment of the shippers’ nominated volumes; this occurs when the supply of oil nominated for transportation exceeds available capacity or where capacity is otherwise disrupted. Apportionment has led some shippers to nominate more barrels than they intend to ship such that the volume after apportionment may be closer to their desired capacity. This practice is also known as the nomination of “air barrels” and can result in shippers being allocated more capacity than they require. The regulations on air barrels have been light so far, but we anticipate that this will be an emerging issue in 2019.
4. USMCA: the New and Improved North American Trade Deal?
2018 saw international trade at the forefront of international policy-making. The Trump Administration had placed the renegotiation of NAFTA among its priorities, and a significant portion of 2018 was spent on attempts to preserve the trade alliance in North America. The new United States-Mexico-Canada Agreement – what would become known as the USMCA – was reached on September 30, 2018. BLG has previously discussed the key provisions in a number of articles, including preliminary insights for business, and more detailed analysis on automotive rules of origin, intellectual property, dispute settlement, and customs administration. The Resource Blog has also published a blog post on the potential implications of the elimination of investor-statement dispute settlement on the energy industry.
Two changes that are directly aimed at the oil and gas industry are the elimination 605 of the NAFTA and changes to the oil and gas rules of origin. Article 605 (also known as the proportionality rule) sets out conditions under which Canada may restrict energy exports; in particular, Canada can restrict its energy exports if: (1) exports as a percentage of Canadian supply do not fall; (2) Canada does not charge the U.S. and Mexico a higher price; and (3) restrictions cannot result from a disruption of normal supply channels. Under the USMCA, the so-called proportionality rule no longer exists. Whether or not the removal of the proportionality clause will result in an expansion of Canadian oil and gas exports to areas beyond the U.S. remains to be seen. Under the NAFTA, oil and gas producers must prove origin of the products at the wellhead in order to obtain duty-free status at the border. However, because Canadian oil was often mixed and traded multiple times, it became increasingly difficult to prove Canadian origin of the oil exports. Under the USMCA, oil exports are allowed up to 40% of diluent without paying the tariff.
Another change of interest for the oil and gas energy is the elimination of the investor-state dispute settlement mechanism found in Chapter 11 of NAFTA as between Canada and the U.S. With respect to these two countries, investors will no longer be able to protect their foreign investment from expropriation through the investor-state dispute settlement procedure. Foreign investors will be limited to seeking remedies through causes of action that exist in the local law.
5. Bill 12: Alberta’s Restriction on Oil and Gas Exports
In 2018, we saw Alberta and British Columbia at odds over the expansion of the Trans Mountain pipeline, which carries crude and refined oil from Alberta to coastal B.C. The project has received support from the federal and Alberta governments, while B.C. opposes the project on the basis of environmental concerns. Disputes over the project have led to a number of court challenges, as well as B.C. proposed regulations against increasing bitumen shipments across the province and Alberta’s two-week embargo against B.C. wine. Alberta’s Bill 12, which allows the province to limit its export of oil and gas, is designed to respond to B.C.’s resistance against the Trans Mountain project.
Serious discussions of proposed energy export legislation from Alberta and Saskatchewan have been ongoing since the spring of 2018. In Alberta, Bill 12 – or the Preserving Canada’s Economic Prosperity Act (the “PCEPA“) – has received royal assent and will come into force on proclamation. The PCEPA confers the Government of Alberta authority to the quantity of oil and gas exports from the province by giving the Minister of Energy the discretion to require a person wishing to export natural gas, crude oil or refined fuels from Alberta to obtain a licence. The licence may be subject to any terms and conditions, including the point at which the licensee may export oil and gas products from Alberta, and the method by which they may be exported.
The B.C. government has already indicated that it would seek a constitutional challenge against the PCEPA. In support of Alberta, Saskatchewan introduced The Energy Export Act (the “EEA“), which uses a permitting mechanism similar to that of the PCEPA. Saskatchewan’s position is that it would bring the EEA into effect if Alberta decided to do so with the PCEPA. At this point, the constitutional validity of the Alberta and Saskatchewan statutes, and the exercise of export licensing powers thereunder, is uncertain. Indeed, whether the Alberta government will bring the PCEPA into force remains unclear.
6. Alberta Announces Mandatory Production Cuts
One of the most significant developments in the Canadian oil and gas industry came at the end of 2018, with the Government of Alberta’s announcement that it would implement mandatory cuts of crude oil and bitumen production by 8.7% (325,000 barrels) per day by January 1, 2019. The production cut was implemented as a temporary measure to raise the price of Alberta’s crude oil, which was then selling at a steep discounted price of $10 per barrel compared to the global price of $50 per barrel. On December 3, 208, Alberta implemented the curtailment plan by establishing the Curtailment Rules.
The Curtailment Rules allow the Minister of Energy to establish issue monthly curtail orders setting out the combined provincial crude oil and crude bitumen production volume, and pro-rate the volume among the operators. Exemptions include a three-month exemption period for operators who did not begin production until after August 31, 2018, operators whose baseline production during a specified period is less than 10,000 barrels per day, and the first 10,000 barrels per day for all operators.
Although the Curtailment Rules include some measure of flexibility through its exemption and allocation-sharing features, there are areas of concern that have been left unaddressed. Notably, the Curtailment Rules do not consider whether the production cuts may render more wells inactive or orphaned. We have considered the potential implications of the curtailment plan in our previous updates (here and here). The effectiveness of the curtailment plan will become clearer as implementation goes under full swing.
7. Bill 13: Capacity Market Development in Alberta
The Government of Alberta’s legislative agenda for 2018 tackled not only issues directly related to the oil and gas industry, but also the energy market as well. In June, Alberta passed Bill 13, An Act to Secure Alberta’s Electricity Future. Bill 13 amended a number of existing legislation and established a capacity market to Alberta’s energy supply system, which currently has an “energy only market” with some ancillary services. In a “capacity market”, generators are paid to keep generation capacity to meet the demand, separate from the energy actually produced.
A capacity market is designed to bring greater stability to the supply system by ensuring that resources are available to meet the energy demands of the market at all times. Recognizing that Alberta’s coal phase-out plan has brought significant changes to the province’s power system, the AESO recommended the transition toward a capacity market to ensure the reliability of energy supply during coal retirement. In Alberta, the AESO is responsible for administering the requisite capacity contracts. Among other things, Bill 13 obliges the AESO to make rules to establish and operate the capacity market as soon as practicable, and such rules do not take effect unless they are approved by the Alberta Utilities Commission. According to the provincial government, Alberta’s capacity market is expected to be operational by 2021.
8. Lack of New Regulations on Oil Sands Emissions Cap
A notable development in 2018 is the lack of development in Alberta’s plan to move towards an oil sands emission cap. In our Top Ten list for 2015, we considered the Government of Alberta’s November 2015 announcement of its Climate Leadership Plan; in our 2016 list, we recognized Alberta’s Bill 25 – the Oil Sands Emissions Management Act. Alberta’s Climate Leadership Plan includes a 100 megatonne cap on oil sands emissions. In a previous article published in The Resource Blog, our preliminary assessment of Bill 25 noted that there were several details to be filled out through regulations. To date, however, the Government of Alberta has not implemented its proposed emissions cap. It appears that the provincial government is waiting until after the spring election to address this item. We continue to monitor the situation and will provide updates accordingly.
9. Bill 15: B.C.’s New Orphan Well Legislation
In the spring of 2018, the Government of British Columbia introduced Bill 15 to improve the province’s orphan well restoration and prevention regime. Bill 15 – the Energy, Mines and Petroleum Resources Statute Amendment Act, 2018 – would make several amendments to B.C.’s Oil and Gas Activities Act and the Petroleum and Natural Gas Act to create a liability-based regulatory framework for orphan well sites. This Bill can be viewed as B.C.’s response to Alberta’s Redwater decision, which confirmed that receivers and trustees may disclaim uneconomic assets, such as those subject to reclamation and restoration obligations. BLG has discussed the implications of Bill 15 in a previous post (found here) and Redwater (for example, see here and here).
One of the main features of Bill 15 is the replacement of current orphan site reclamation fund paid by permit holders with a levy. Producers currently pay $0.03 per 1,000 cubic metres of marketable gas produced and $0.06 per cubic metre of petroleum produced each month. The new levy would be determined from a formula based on a producer’s pro rata share of the total forecast total liabilities (i.e. reclamation and restoration costs) estimated by the B.C. Oil and Gas Commission. The Bill also expands the Commission’s powers to order site restoration, including orders against former permit holders and former authorization holders, as well as initiating formal enforcement proceedings to recover outstanding amounts owing under the Act.
10. Ontario’s New Energy Policy
As Alberta continued to contend with changes in the energy market from the provincial government’s coal phase-out plan, the Government of Ontario took several significant steps directed at the renewable energy sector. In 2018, Ontario enacted the White Pines Wind Project Termination Act to cancel the White Pine’s feed-in-tariff contract which Ontario’s IESO. This move followed the spring electoral victory of the Ontario Progressive Conservative party, whose campaign platform included the cancellation of renewable energy contracts and the cap-and-trade system. Ontario next announced that it was cancelling 758 renewable energy contracts and pledged that the decision would save Ontario ratepayers $790 million.
Notably, the White Pines Wind Project Termination Act expressly provides that “[n]o cause of action arises” against the Ontario government or the IESO as relates to the legislation. This clearly signifies the Ontario government’s intent to prevent litigation such as those arising after Alberta’s cancellation of power-purchase agreements. The Act further provides a formula for calculating compensation payable to White Pines and requires that any dispute in relation to compensation be determined by a binding arbitration. It is likely that Ontario intends to replicate this scheme in further legislation dealing with the cancellation of the renewable energy contracts, thereby limiting the project owners’ remedies to arbitral resolution of the amount payable under the stipulated formula.
The Government of Ontario has also introduced Bill 34, the Green Energy Repeal Act, 2018. Bill 34 is known as the bill that would reverse the Green Energy Act, which was introduced by the province in 2009 and created multiple levels of tariffs for various renewable generation. Among other things, Bill 34 empowers the Lieutenant Governor in Council to make a broad range of designations, including the designation of goods, services and technologies as energy efficient and the designation of certain renewable energy projects for specified purposes. These designations can allow such goods, services and technologies to be used, or such projects to proceed notwithstanding any restrictions established by any municipal bylaw, condominium bylaw, encumbrance or agreement.