Top energy issues of 2021, with implications for 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.”

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.

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.

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.

Canada

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.

Ontario

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

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.

Québec

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.”