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Top energy issues of 2021, with implications for 2022 and beyond

In 2021, the Canadian energy sector continued to encounter structural change: in energy transition, pricing, government policy, and regulatory review, which will have implications well into the future. This past year, BLG noted several positive trends influencing change across the sector, including a significant increase in M&A activity that could facilitate long-term growth, a greater focus on the energy transition and decarbonisation, and increased Indigenous participation in energy project development.

BLG’s energy lawyers have taken a closer look at many of the changes and developments that took place in 2021 that will influence trends, business decisions and the future growth of Canada’s energy industry in 2022 and beyond.

Growing Indigenous participation in energy projects

(Rick Williams, Tim Pritchard and Chris Roine)

Proposed energy projects in Canada are often located within the asserted traditional territory of at least one Indigenous nation. Indigenous participation in these projects continues to grow, whether through partnerships, joint ventures or, increasingly, equity stakes and direct ownership. This has been encouraged, at least in a part, by economic incentives and funding programs through provincial and federal levels of government as well as increased pressure by shareholders and investors for positive environmental, social and governance reporting.

2021 saw a number of proposed and announced partnerships with First Nations on large-scale energy development, both conventional and renewable, including:

  • The Fort Nelson First Nation’s announced Geothermal Energy project near Fort Nelson, British Columbia. The project plans to limit its surface disturbance by using existing natural gas wells, which would be repurposed for geothermal energy.
  • Fortescue Future Industries’ deal with three Indigenous groups located in British Columbia, Manitoba, and Newfoundland and Labrador, exploring the viability of large scale green hydrogen projects, utilizing hydroelectric dams and wind farms.
  • Kanata Clean Power and Climate Technologies proposed partnership with the Frog Lake First Nation (located east of Edmonton) to build a net-zero natural gas electricity power plant in Alberta.
  • The sale of the Northern Courier Pipeline System in Alberta to a partnership of three First Nations and five Métis communities, which was facilitated in part with funding from the Alberta Indigenous Opportunities Corporation (AIOC).
  • The Wataynikaneyap Transmission Project, a partnership of 24 First Nations and Fortis Inc., to provide electrical power to remote First Nations’ communities in northwestern Ontario. This project was supported by a grant of $1.6 million from the federal government.

Many of these projects and others were able to benefit from favourable government funding programs, such as British Columbia's First Nations Clean Energy Business Fund or the federal Emerging Renewable Power Program. Announcements in the past year included:

  • In December 2021, the B.C. government announced its Indigenous Clean Energy Initiative, which will provide funding to 10 First Nations across the province to “develop alternative energy projects and advance energy efficiency in their communities”. The funding is targeted towards supporting development of clean-energy generation projects (i.e. run of river, wind, biomass, solar, marine and geothermal).
  • On March 25, 2021, the Province of British Columbia’s Renewable Energy for Remote Communities Program announced it had provided $1.8 million to three remote Indigenous communities, Kwadacha First Nation, Lhoosk'uz Dené, and Hesquiaht First Nation, to fund the installation of solar panels and reduce these communities’ reliance on diesel energy.
  • On March 12, 2021, the Government of Canada announced the investment $40.5 million from its Emerging Renewable Power Program into the Indigenous owned Clark Lake Geothermal Development Project.
  • On April 27, 2021, the AIOC announced it had provided a $27 million loan to Frog Lake First Nation to support long-term ownership of the Lindbergh’s cogeneration facility.
  • On September 16, 2021, AIOC announced it had provided up to a $40 million guarantee loan to eight Indigenous communities to help finance investment in the Northern Courier Pipeline System.

Support of Indigenous communities is increasingly required for regulatory approvals in Canada. The trend toward Indigenous partnered resource development reveals a shift away from project proponents relying solely upon impact benefit agreements to earn that support. “These partnership-based models offer potentially broader benefits to both proponents and Indigenous communities; they also require careful consideration of key drivers around financing, governance, and operational requirements.”

Readers may also be interested in the BLG webinar discussing “Perspectives on First Nations Issues and Canadian Energy Projects.

Carbon tax and decarbonisation

(Karen Salmon and Jonathan Cocker)

In 2021, there were a number of developments on climate action, which will no doubt continue to take shape in 2022 and beyond. While the Supreme Court of Canada gave the final word on the carbon tax in upholding the federal Greenhouse Gas Pollution Pricing Act, the Government of Canada continued to push forward with a combination of regulatory and incentive measures to accelerate Canada’s progress toward its net-zero emissions target, and reaffirmed its commitments in advance of COP 26. Both the federal government and the Alberta government announced significant investment in carbon capture use and storage (CCUS) developments, a critical tool in reaching those targets. While we can expect that 2022 will almost certainly be the year that a national low carbon fuel regime becomes law.

The Canadian Net-Zero Emissions Accountability Act and COP 26

In June of 2021, in advance of the COP 26 meetings and Canada’s obligation to state its 2021 National Determined Contribution under the Paris Agreement, the federal government enacted the Canadian Net-Zero Emissions Accountability Act, the first of its kind federally in Canada in setting legal requirements on the government to plan for and report on its efforts to achieve net-zero emissions.

The Canadian Net-Zero Emissions Accountability Act mandates national targets for the reduction of greenhouse gas emissions in Canada, with a net-zero emissions objective by 2050, as well as reduction plans, progress reports and assessment reports to hold the federal government accountable. At present, the act sets a 2030 target of 40-45 per cent below 2005 levels. The due dates for the minister to set the remaining GHG emissions reduction targets are as follows:

  • 2035 target due by December 1, 2024
  • 2040 target by December 1, 2029
  • 2045 target by December 1, 2034

The Government of Canada subsequently affirmed the target as its Nationally Determined Contribution in July 2021. In advance of COP 26, the government has continued to promote a combination of regulatory and incentive measures aimed at accelerating Canada’s progress towards these ambitious targets.

Carbon capture use and storage (CCUS) developments

“World wide, carbon capture use and storage (CCUS) technologies are gaining recognition as a valuable tool in GHG emission reductions and climate action. In Canada, CCUS is expected to play a significant role in meeting net zero targets.” To that end, the federal government is developing a federal CCUS strategy that recognizes the importance of CCUS and growth of the CCUS industry as not only a climate change action but also an economic opportunity. Further, in its 2021 budget, the federal government announced a significant investment into research, development and demonstrations to advance the commercial viability of CCUS technologies as part of the Energy Innovation Program. At the same time, the Government of Alberta is investing heavily in new CCUS projects.

Carbon capture storage projects have been operating in Alberta for several years including the Alberta Carbon Trunk Line System and Shell’s Quest project, which together represent an Alberta government investment of $1.24B through 2025. In addition, new CCUS projects are being funded through a $131 million investment under the Industrial Energy Efficiency and Carbon Capture Utilization and Storage Grant Program, seven of which were announced in November. 2021 also saw a number of announcements of private investment in CCUS projects, including the planned Alberta Carbon Grid project announced in June by Pembina Pipeline Corporation and TC Energy Corporation and Shell’s planned Polaris project announced in July.

Currently Alberta’s CCUS regulatory regime is based largely on the existing oil and gas framework as amended, and includes the 2011 Carbon Sequestration Tenure Regulation. The Alberta government signalled in May 2021 that it was not contemplating changes to the existing legislation and regulations at that time, but it may in the future if necessary. Looking ahead, as the CCUS industry and technologies continue to develop and expand, we can expect additional regulation to support this growing technology.

Clean Fuel Standard

The landmark federal Clean Fuel Standard (CFS) remains at the proposed regulation stage with an expectation that the final regulations will be released in spring 2022 with a compliance start date of December.

In anticipation of the final regulations, Environment and Climate Change Canada has finally released the Life Cycle Assessment Tool, which will allow all participants in the CFS to better understand the crediting opportunities associated with various activities and the related financial returns.

While some last minute adjustments to the overall CFS program may occur, 2022 will almost certainly be the year that a national low carbon fuel regime is implemented in Canada.

GHG emissions reference cases

In March 2021, the Supreme Court of Canada released its decision in the three reference cases brought by Saskatchewan, Ontario and Alberta challenging the constitutionality of the Greenhouse Gas Pollution Pricing Act, S.C. 2018, c. 12, s. 186 (the GGPPA). In a 6-3 decision, the Supreme Court upheld the GGPPA as a valid exercise of the federal government’s power to legislate for the peace, order and good government of Canada (the POGG power). For a detailed analysis, please see our earlier article here.

In summary, the court found the true subject matter of the GGPPA as “establishing minimum national standards of GHG price stringency to reduce GHG emissions.” The court classified the GGPPA as a matter of national concern and thus subject to federal legislation under the POGG power. It found that the matter was of sufficient national concern; that there was a provincial inability to deal with the matters at the core of the GGPPA and finally that the impacts by the GGPPA on provincial jurisdiction was acceptable.

This decision provided clarity with respect to federal and provincial jurisdiction over climate policy and may have implications in future disputes in relation to division of powers in the energy space. Further, the court’s reasoning may have impacts on the decision of the Alberta Court of Appeal in relation to the Government of Alberta’s challenge to the federal Impact Assessment Act, a reference case heard by the Alberta Court of Appeal in February 2021.

Enbridge application for mainline contracting

(Alan Ross, Laurie Ziola and Bradon Willms)

On November 26, 2021, the Canada Energy Regulator (CER) released its reasons for decision denying an application by Enbridge Pipelines Inc. (Enbridge) to contract up to 90 per cent of the available transportation capacity on its Canadian Mainline oil pipeline for firm transportation service. The CER found that the proposal was contrary to Enbridge’s common carrier obligations, was unjustly discriminatory, and would result in unjust and unreasonable tolls. As a result, the largest export oil pipeline in Canada will continue to provide service on a 100 per cent uncommitted basis.

Enbridge’s Canadian Mainline pipeline is the single largest crude oil pipeline in Canada, accounting for approximately 70 per cent of total oil transportation capacity. Historically, the Canadian Mainline provided uncommitted transportation service on a strictly common carriage basis, without any long-term contractual service rights. The application proposed largely fixed tolls over long-term contracts that locked in volumes for up to 20 years. The application represented the first time Enbridge applied for approval of firm service on the Canadian Mainline. It was unique from other firm service applications on major Canadian oil pipelines, in that it was not brought in conjunction with a major proposed new investment by the pipeline. The Enbridge application was made in the context of a significantly constrained market, with energy producers having difficulty securing enough transportation to meet their needs. The application was hotly contested, with support from refiners and opposition from upstream oil producers and industry associations.

“The CER was of the view that the application had serious and broad-ranging implications for the oil industry.” In denying Enbridge’s application, the CER found that certain elements of the application provided a justification for some firm service on the Canadian Mainline, but the proposed offering would have “dramatically and suddenly changed, and likely diminished, overall access to the Canadian Mainline, without a compelling justification.” In essence, the application did not provide sufficient access to uncommitted transportation on a common carriage basis and the proposed package of tolls, terms and conditions would result in unjust discrimination and tolls that could be unjust and unreasonable. Ultimately, the application was not in compliance with Enbridge’s common carrier duties under subsection 239(1) of the CER Act, and raised concerns in relation to the requirement in section 230 to charge just and reasonable tolls and the prohibition against unjust discrimination under section 235.

As a result of the decision, existing interim tolls and conditions of service for the Enbridge Mainline remain in effect until new tolls are approved by the CER. The CER decision does not preclude future proposals to contract firm service on the Canadian Mainline in appropriate circumstances. The CER also raised the prospect of a cost of service application respecting the Canadian Mainline, but this is generally a lengthy and expensive proceeding.

In a press release issued shortly after the decision, Enbridge stated that it would consult with its stakeholders to establish a process for negotiating a new commercial framework for the Canadian Mainline, which could include alternatives such as a modified and extended version of the existing toll settlement agreement, a new incentive rate-making agreement, or a cost of service rate-making structure. A negotiated settlement with substantial broad support from producers, shippers and refining sectors would be the most cost-efficient and expedient process for all parties, but substantial broad support is hard to achieve, as demonstrated by the 2021 proceeding. Enbridge and its stakeholders will need to carefully consider all of the concerns raised in the 2021 proceeding, as well as the CER’s comments in its decision, to collaborate and develop a new proposed commercial framework, whatever form it may take. Stay tuned for the next chapter of the Enbridge Mainline story.

Pipelines and energy trading

(Peter Bryan)

In 2021, pipelines continued to be lightning rods for a range of social, economic and political debates. These public controversies, and the associated delays, costs and uncertainties, are expected to persist as disputes are addressed by regulators, courts and corporations in 2022 and beyond.

Pipeline politics continue

The year commenced with the new Biden administration’s revocation of a previously granted Presidential Permit to construct and operate the Keystone XL Pipeline. Although construction of the Canadian portion of the 1,897 kilometer, 830,000 bbl/d pipeline had commenced and Alberta had recently invested $1.5 billion in the project, the Biden administration determined that the Presidential Permit “would not be consistent with [the new] Administration's economic and climate imperative.” The project was terminated as a result, but in July, the proponent, TC Energy commenced a $15 billion claim against the U.S. government under the Chapter 11 NAFTA rules, which is ongoing.

Similar cross-border disputes also plagued Enbridge’s 540,000 bbl/d Line 5 crude and products pipeline. Following Michigan Governor Whitmer’s November 2020 revocation of a required easement that had been in place since 1953, Enbridge and Michigan pursued negotiations and then wrangled over the appropriate court to resolve the dispute. In October 2021, the Government of Canada stepped in by invoking the negotiation and potential arbitration process under the 1977 Transit Pipelines Treaty with the Government of the United States. The treaty prohibits a public authority from instituting measures intended to, or having the effect of, impeding, diverting, redirecting or interfering with the transmission of hydrocarbon in transit, but it provides for exceptions such as an actual or threatened natural disaster. Whether the matter is determined in the federal court or pursuant to the treaty, the outcome will establish important precedents affecting cross border energy infrastructure, and the security of international transit.

The impact of short term election cycles on long term energy infrastructure projects, as well as the friction between project specific regulation (such as Presidential Permits and regulatory permits) and international treaties (such as trade or environmental treaties) is expected to persist into 2022.

In British Columbia, controversy continued to follow the 640 km, 2.1 bcf/d Coastal GasLink natural gas pipeline as demonstrations and a blockade by Wet’suwet’en heredity chiefs and their supporters continued into 2021. These protests, stemming from Indigenous groups’ land title disputes, internal governance conflicts, and broader environmental concerns, culminated in arrests by the RCMP and enforcement of a court ordered injunction barring protesters from blocking an access road. The myriad of legal issues, including aboriginal rights and title, enforcements of injunctions, freedom of expression, and the application of federal, aboriginal and international law, amongst others, are expected to continue for the foreseeable future.

Aside from the political and social issues, pipelines also attracted significant commercial attention in 2021. The $12 billion TransMountain crude oil pipeline (the costs of which substantially escalated) fought to protect the identity of its insurers in regulatory filings, and joined other pipelines who had to respond to public statements from certain insurers, banks and investors that had announced policies to divest away from the petroleum industry. However, pipelines also attracted interest from new investors, including new and potential Indigenous investors in the Northern Courier pipeline and TransMountain Pipeline, as well as private equity investors in Inter Pipeline. This shifting of investors and stakeholders is expected to continue into 2022.

Debates about the commercial structures of pipeline contracts also came to the fore in 2021, when the CER issued its November decision refusing Enbridge’s proposal to reserve approximately 90 per cent of the space in its three million bbl/d crude mainline pipeline for long term firm contracts (versus monthly access). The highly contested proceedings provided a deep analysis into market access issues, common carrier obligations and the Mainline’s commercial framework. This will have ongoing implications for the Mainline toll and may set a precedent for negotiations on other pipelines.

BLG anticipates that the commercial risk and reward, and needs and impacts of pipelines will continue to draw significant attention in 2022.

Climate change litigation in Canada

(Matti Lemmens)

The prospect of climate change litigation continues for Canadian companies and, in particular, oil and gas companies in Canada. Milieudefensie et al. v. Royal Dutch Shell is a recent case raising novel legal risks for oil and gas companies around the world. However, the impact of this decision may be tempered in Canada given the fundamental differences in our judicial systems.

In May 2021, the Hague District Court ordered Shell to reduce its CO2 emissions to 45 per cent by 2030 compared to 2019 levels. The basis of the decision was rooted in a breach of an “unwritten duty of care”, found in the Dutch Civil Code. The court interpreted this “unwritten duty of care” with reference to international human rights treaties, and held that Shell had an obligation to protect the human rights of Dutch citizens. Although Shell has indicated an intention to appeal this decision, this precedential case raises uncertainty and risks for energy companies, regardless if they have policies in place to reduce their environmental impacts.

A Canadian example of climate-related litigation that has yet to be determined is the Reference re Impact Assessment Act. The main question before the Alberta Court of Appeal in this reference is whether the federal Impact Assessment Act (IAA), which imposes a more stringent approval process for major energy projects, is unconstitutional because it attempts to govern matters falling under provincial legislation. For instance, the act introduces more factors to consider during assessment, an additional planning phase, and greater penalties for breaches, much with a view to reducing climate change. However, given the discretionary nature of the assessment, it is difficult to predict whether project approval rates will ultimately suffer. If the IAA is upheld, it could significantly increase the hurdles for getting an energy project approved.

“In summary, both Dutch Shell and the IAA Reference have the potential to increase environmental regulatory obligations on energy companies.” The impact of Dutch Shell is yet to be seen in Canada, although the case may inspire environmental groups to sue companies in Canada. Canadian law may ultimately be too different for Dutch Shell to have much application in the Canadian context. Nevertheless, the highly anticipated IAA Reference may result in a more onerous approval process for major energy companies if the court finds the IAA constitutional.

M&A trends and energy consolidation

(Miles Pittman and Xiaodi Jin)

After six years of low commodity prices, characterized by tepid recoveries followed by devastating price setbacks, 2021 saw sustained price increases in both oil and natural gas. Wary of continued volatility and the sustainability of these gains, the response from producers has been mixed. Some are eyeing consolidation opportunities; others taking the opportunity to exit the sector or at least divest of non-core assets which, even a year ago, would have gone no-bid in a sale process; and a few smaller new entrants willing to bet that the recovery this time will hold.

“In general, however, 2021 saw the mega consolidation trends from 2020 continue. Based on the state of the market, 2022 promises to be a different story.”


One of the year’s marquee deals was the closing of the C$6.07 billion merger between Husky Energy and Cenovus Energy (effectively a takeover by Cenovus). This was followed by the sale of Husky’s retail stations to Parkland Corporation and Federated Co-operatives. The main transaction was an all-share deal, with Husky shareholders receiving a fractional Cenovus share and a fractional Cenovus share purchase warrant for each Husky share; and Parkland and Federated paid a total of $420MM in cash for the retail stations. In addition to consolidating its position as a premier oil sands producer, Cenovus now has exposure to Canada’s east coast, as a result of Husky’s involvement in White Rose and exploration in the Flemish Pass.

Inter Pipeline/Brookfield

Brookfield Infrastructure Partners successfully acquired Inter Pipeline Ltd. after an extended bidding process that became hostile before being resolved amicably. The Brookfield acquisition is based on the consistent return presented by Inter Pipeline, an entity which has grown over the last 15 years to be one of the premier Canadian pipeliners.

Other notable consolidations

The ARC/Seven Generations, CNRL/Storm, Tourmaline/Black Swan/Jupiter, PrairieSky/Heritage, Spartan/Velvet, Whitecap/TORC, and Tamarack/Anegada deals highlight the magnitude and breadth of the consolidation trend among Canadian upstream midcap issuers. We anticipate 2022 to be characterized by further and potentially more numerous consolidations albeit at a smaller scale, as producers of all sizes look to higher prices as an opportunity to offload non-core or high liability assets, and end-of-mandate private companies that have waited through/survived the downturn now seek liquidity at more reasonable metrics. We anticipate these opportunities to be plentiful throughout the year but balanced on the purchaser side by new entrants and the increased buying power afforded by higher commodity prices and significantly reduced capital expenditure budgets.

Hydrogen in Canada

(Kristyn Annis)

In 2021, the tremendous interest and momentum in the hydrogen economy continued at an accelerated pace, while government policies and incentives emerged in tow. Although there are formal strategies in place in at least three provinces in Canada and at the national level, funding and policy development and implementation remains patchwork nationwide.

Below we provide a summary of the current federal and provincial policies related to hydrogen.


The federal Hydrogen Strategy for Canada, released in December 2020, reflects many of the priorities of the numerous provincial hydrogen initiatives already announced.

The federal plan is unique in both its recognition of the need for regional adoption strategies and the sheer magnitude of the undertaking – the national strategy seeks to vault Canada into a top three hydrogen producer globally and has included a number of industry and sector-specific goals to achieve this lofty goal. The strategy includes 32 recommendations across eight pillars in promoting investment and collaboration across sectors. It sets out near-term (2020-2025), mid-term (2025-2030) and long-term (2030-2050) objectives. On April 9, 2021, the federal government launched the Hydrogen Strategy Steering Committee to establish priorities, guide actions, share knowledge and track results to deliver on recommendations outlined in the strategy. The committee has not published anything to date.


On November 19, 2020, the Ontario government released a discussion paper titled Ontario Low-Carbon Hydrogen Strategy, which is part of its climate strategy. Ontario’s Environment Plan, released in November 2018, commits the province to reducing greenhouse gas emissions to 30 per cent below 2005 levels by 2030, in line with Canada’s 2030 target. Ontario is focused on ‘low-carbon’ hydrogen as opposed to green hydrogen. Per the Ontario government’s publications, this includes hydrogen that is made through electrolysis from Ontario’s relatively clean grid, biomass and steam and natural gas and steam with CCUS (commonly referred to as blue hydrogen). Following the close of the consultation period last year, Ontario established a new Hydrogen Strategy Working Group to help inform the development of its hydrogen strategy. The purpose of the working group is to build on the input the government received through the public consultation process and discussion paper. Members of the working group will also provide advice on how to use hydrogen across various sectors and help Ontario compete in the global hydrogen market.


Alberta’s Hydrogen Roadmap, updated as recently as November 5, 2021, is focused on building a provincial hydrogen economy and accessing global markets. Already the largest grey hydrogen producer in Canada, the province’s stated 2030 goal is to integrate “clean hydrogen” at-scale into Alberta’s domestic energy system for use in transportation, heat, power generation and renewable energy storage. Alberta currently produces more than 2.4 million tonnes of grey hydrogen annually. “Clean hydrogen” is defined by the Alberta government as hydrogen produced with minimal emissions.

British Columbia

B.C.’s hydrogen strategy was developed in order to help the province meet its CleanBC goal of net zero GHG emissions by 2050. The BC Hydrogen Strategy, published in July 2021, includes 63 actions to undertake, categorized using the same categories identified in the national strategy: short term (2020-2025), medium term (2025-2030) and long term (2030-beyond).

The Government of British Columbia provided $10 million to the construction and operation of 10 hydrogen-fuelling stations in the province in 2020, as well as three years of support for Hydrogen BC, which is affiliated with the Canadian Hydrogen Fuel Cell Association (CHFCA). British Columbia currently has the largest hydrogen-fuelling network in Canada, including a public hydrogen fuelling station.


Although the Québec government does not have a stand-alone hydrogen strategy in place, the element is seen as essential to meet the province’s climate goals of carbon neutrality by 2050 and a reduction in GHGs of 37.5 per cent reduction compared with 1990 levels. Two of the province’s climate plans, the 2030 Plan for a Green Economy and the Green Economy Implementation Plan 2021 – 2026, identify various areas in which hydrogen can and should be used. The implementation plan also sets out an investment schedule to support innovation in the field of green hydrogen and bioenergy. In addition to government strategy, the private sector has identified Québec as a potential resource for green hydrogen due to the province’s abundant supply of renewable, low cost electricity.

“In 2022 and beyond, both industry and the commercial sector will need to keep the government’s feet to the fire in order to ensure that the hydrogen economy gets the support that it needs to properly develop.”

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