The future of Canadian energy: A review of 2023's top energy issues and what to expect in 2024

Canada’s carbon pricing system is really a collection of systems. There is the federal output-based pricing system (OBPS).  Under any OBPS, like the federal one, large emitters generally pay a federally set price per tonne of emissions that they generate in excess of the emissions thresholds applicable to the facilities that they own. These emitters can also generate carbon credits if they emit less than these emissions thresholds and then sell those carbon credits to other emitters who fail to meet their emissions thresholds. Besides the federal OBPS, there are a number of provincial and territorial (P/T) carbon pricing systems that the federal government has concluded meet the minimum national standards for carbon pricing and can therefore replace the federal OBPS. The result is that we have a hodge podge of carbon pricing systems: 1. some P/Ts with their own OBPS like the federal system, 2. Québec with a unique cap-and-trade system like California, and 3. other P/Ts which use the federal OBPS because those P/Ts do not have one of their own.¹ So, piecing these systems together, we have a price on carbon emissions everywhere in Canada that all businesses need to consider when making production decisions.

This includes a large emitter, like a cement or steel plant or an oil sands facility, which is considering whether to proceed with a decarbonization project that would reduce its carbon emissions. A key factor in that decision is the carbon price savings (operating cost reductions) that would come over time from the resulting reduced emissions from the facility, plus, if the proposed decarbonization project is expected to reduce emissions below the applicable emissions threshold, the value of the carbon credits that would be generated and sold in the market over time generating additional revenue.

Carbon pricing is also on the mind of a proponent of a new clean energy project that is looking to build a low-carbon-emitting facility and displace competitor products being produced at existing high-carbon-emitting facilities. The new facility, which will be costly to build and operate, will only be profitable if its products can be priced competitively versus those from the existing facility. This will often only happen if the higher emitting competitor continues to pay a price on carbon and recover it through higher prices. In this regard, think of a new renewable (low-emitting) electricity project that is looking to displace the electricity from an existing gas-fired power plant in the market. Similar reasoning would apply where producers of new clean energy sources are proposing to displace higher carbon energy sources that currently bear a carbon price. In this regard, think of a new project to produce and sell hydrogen that is intended to displace natural gas and other hydrocarbons used in industrial processes in the market.

The net result is that many of these energy transition projects can only be justified if carbon pricing – or some other “stick” – exists to incent the investment. However, broad support does not exist in Canada for carbon pricing, as evidenced by the opposition that has been expressed by several P/Ts. More importantly, the federal Conservative Party of Canada, who are leading today, in many polls, have made “Axe the Tax” a key component of the platform upon which they will campaign in the next election. An election that must be held before Oct. 20, 2025. This all culminates in political/policy uncertainty when it comes to carbon pricing that is preventing proponents from making positive final investment decisions on their energy transition projects as 2023 comes to a close.

If we are going to unlock these projects in time for them to help Canada meet its climate targets, including our 2030 Paris commitments, and for the country to grow and prosper in tomorrow’s low-carbon world, the federal government and P/Ts need to jointly tackle the carbon price uncertainty issue early in 2024. There are some alternatives, including financial mechanisms like the use of carbon contracts for difference and legislative options, but ultimately this is going to take the federal government and P/Ts working together and jointly providing assurance that carbon pricing in some form or, alternatively, that carbon-emission limits or costs will be imposed at a national or provincial level for some time, that justify positive final investment decisions being made now. This will help Canada get on with its clean energy transition in 2024 at the pace and scale that we need to be successful.

¹ Though the focus here is on the carbon pricing system that applies to large emitters, the same political/policy uncertainty applies to other federal carbon reduction pricing and regulatory ”sticks”, like the Clean Fuel Regulations, the proposed Clean Electricity Regulations, and the proposed federal Oil and Gas Sector Greenhouse Gas Emissions Cap announced by the federal government on Dec. 7, 2023 that will work in tandem with carbon pricing on large emitters to incent emission reductions in most parts of the oil and gas sector.  

The Court found that the IAA consisted of “two distinct” regulatory schemes: (1) a Designated Projects Regime that subjects certain projects that would otherwise fall outside federal jurisdiction to federal oversight and regulation; and (2) a Federal Projects Regime that applies to federal projects, including projects on federal lands or outside of Canada.

The Majority found that Parliament “plainly overstepped its constitutional competence” in enacting the Designated Projects Regime, which purported to grant the federal government the power to regulate projects based on the mere possibility that they would have “effects within federal jurisdiction”. Likewise, the Majority found that the Designated Projects Regime, which directed the federal agency to consider matters beyond those of federal jurisdiction and regulate the project, was ultra vires. Conversely, the Majority found that the Federal Projects Regime, which it described as “secondary” to the Designated Projects Regime, could be severed from the unconstitutional portions of the IAA and remain in force and effect.  In dissent, Justices Karakatsanis and Jamal would have found the IAA constitutional in its entirety.

The IAA Reference is a significant division of powers case and marks an important development in the ongoing saga of constitutional litigation with respect to jurisdiction over environmental matters. Shortly after the SCC released its opinion, the Federal government announced that it intends to amend the IAA as soon as possible, including the scope of its discretionary designation and decision-making provisions. However, the Federal government has yet to introduce such amendments, and it remains to be seen whether same will cure the constitutional defects and regulatory uncertainty present in the original IAA.

Shell Canada Limited v Alberta (Energy)

In Shell Canada Limited v Alberta (Energy), 2023 ABCA 230 (CanLII), the Court of Appeal of Alberta upheld a decision of the Court of King’s Bench related to Alberta’s oil sands royalty regime. The Court of Appeal quashed a decision of the Alberta Minister of Energy which disallowed certain costs claimed by Shell. This case is one of a number of recent decisions which have held administrative decision makers accountable for unreasonable or procedurally unfair decisions.

Background

Alberta’s oils sands royalty regime provides the mechanism for the Crown to receive a share of the economic revenue, or royalty, generated from the development of the oil sands.  The Oil Sands Allowed Costs (Ministerial) Regulation, Alta Reg 231/2008 (the Allowed Costs Regulation) sets out the framework for determining if a particular claimed cost is an “allowed cost”. As part of the royalty regime, oil sands project operators are required to submit end of period statements that include information regarding the allowed costs claimed by the operator. The statements are subject to audit by the Alberta Department of Energy (the Department).

In this case, Shell claimed costs which included integrated costs for shared resources used to run operations on Shell’s integrated Jackpine and Muskeg River Mines, which are on adjoining lands. The Department determined these costs were not “solely dedicated” to project operations within the meaning of the Allowed Costs Regulation, and they were therefore disallowed.

Despite the request by Shell, the Minister of Energy refused to convene a Dispute Review Committee (Review Committee or DRC) to review the dispute related to the costs claimed by Shell. The Minister of Energy concluded that Shell’s position was “without merit”. Shell subsequently applied for judicial review of the Minister’s decision. The judicial review judge found that the Minister’s decision was unreasonable and quashed the decision. The judicial review judge also declared that the Minister was required to convene a Review Committee.

Decision

On appeal, the Court held that the Minister’s decisions did not explain the analysis undertaken or test applied to determine that Shell’s position was “without merit”. The reasons simply repeated the Department’s position that Shell’s interpretation was “inconsistent with the regulations as written”. The reasons did not disclose the reasoning process that led to that conclusion, fail to address the context and purpose of the regulations and, in the result, do not bear the “the hallmarks of reasonableness — justification, transparency and intelligibility”.

The Court of Appeal concluded that the Minister’s decision was unreasonable. The Court of Appeal also  held that it was appropriate for the issue to be referred to a Dispute Review Committee rather than remitting that issue back to the Minister. While it is often appropriate to remit a matter back to an administrative decision maker (in this case the Minister), the Court found that it was appropriate to declare a Review Committee be established.

Takeaways

The decision by the Court of Appeal confirms that the courts will intervene if a decision by an administrative decision maker, such as the Minister of Energy, is unreasonable. A decision by an administrative decision maker must be justified and transparent and disclose the reasoning behind the decision.

The court’s decision is important to the energy industry in Alberta. This decision is a number of decisions by the courts in Alberta which have challenged the decisions made by the Minister of Energy. This decision confirms that the judicial review process can be used to challenge decisions by the Minister of Energy related to the oil sands royalty regime.

Taylor Process v Alberta

In Taylor Processing Inc v Alberta (Minister of Energy), 2023 ABKB 64, the Court of King’s Bench of Alberta quashed three decisions made by the Alberta Minister of Energy (Alberta Energy) related to the payment of Crown royalties pursuant to the Mines and Minerals Act and its regulations, including the Natural Gas Royalty Regulation, 2009. The Court acknowledged that the threshold for quashing an administrative decision is high, but determined that remitting the issue back to Alberta Energy would be “pointless” given that Alberta Energy had failed to establish any evidentiary basis for its decision in the first instance. As a result of the Court’s decision, Alberta Energy was ordered to return over $20 million in royalties to Nova, with interest. Read the full case summary here.

These new ITCs are expressed as a percentage of eligible expenditures on qualifying property to be used in Canada in eligible activities. They are refundable, meaning that the government will pay them to qualifying taxpayers even if they do not have Canadian income tax owing. Each of these new ITCs is directed at specific clean economy segments:

Clean Technology: the Clean Technology ITC is available for various forms of clean energy generation, including from wind, solar, water and geothermal sources, as well as small modular nuclear reactors and stationary electricity storage equipment.

Carbon Capture, Utilization & Storage (CCUS): The CCUS ITC is directed at equipment used exclusively to capture, transport or store carbon dioxide in an eligible project (dual-use heat and/or power equipment may also qualify). Unlike most of the other ITCs that are limited to new property, refurbishment costs may also be eligible for the CCUS ITC.

Clean Hydrogen: the Clean Hydrogen ITC is applicable to equipment that produces hydrogen from either electrolysis or natural gas and has been extended to support equipment converting hydrogen into ammonia in some cases. There are three levels of ITC offered, depending on how clean (i.e., carbon-intensive) the hydrogen being produced is (no ITC applies if 4 kg or more of CO2/H kg is produced).

Clean Technology Manufacturing: The Clean Technology Manufacturing ITC is directed further up the supply chain, at Canadian companies that are manufacturing or processing clean technologies and their precursors. It applies to machinery and equipment used to manufacture or process key clean technologies, and extract, process, or recycle key critical minerals, including machinery and equipment used in manufacturing (and related activities) of: 

• grid-scale electrical energy storage equipment;
• renewable or nuclear) energy equipment;
• zero-emission vehicles, and
• various upstream components and materials for such above-noted activities.

Machinery and equipment used in the extraction, processing, or recycling of lithium, cobalt, nickel, graphite, copper, and rare earth elements also qualifies.

Clean Electricity: The Clean Electricity ITC will apply to eligible investments (including refurbishments) in the following types of property:

• non-emitting electricity generation systems, i.e., wind, solar, hydro, wave, tidal, and both large and small-scale nuclear;
• abated natural gas fired electricity generation meeting an emissions threshold;
• stationary electricity storage systems; and
• inter-provincial electricity transmission equipment.

Various technical details apply to these Clean Economy ITCs, including the way they are computed, how they apply when claimed through a partnership rather than a directly by an eligible taxpayer, and additional requirements applicable to some or all of them. A number of these are summarized in the table below. Particular care must be exercised regarding the impact of any government assistance received or expected to be received as part of the project (late in 2023 the government announced that low/no-interest loans with reasonable repayment terms would not be considered as “government assistance” for this purpose).

*  Labour requirements must be met to attain highest ITC %

**  Directly or through as a member of a partnership

***  Period during which certain actions can cause ITCs claimed to be reversed

Paris Agreement and COP26

On Dec. 12, 2015, Canada and 194 other countries reached the Paris Agreement. Under the Paris Agreement, countries committed to developing national plans to reduce their emissions, known as Nationally Determined Contributions, or ‘NDCs’. As part of the Paris Agreement, countries are required to update their NDC target and each NDC target must be more ambitious than the one before.

In 2021, COP26 was held in Glasgow, Scotland, which marked the first 5-year period since the Paris Agreement was signed. The signatories to the Paris Agreement gathered to increase climate action, including through more ambitious emissions reduction targets and plans to accelerate the global shift to clean energy, clean technology, and clean growth.

Canada’s path to net-zero

Prior to COP26, Canada announced a new target of reducing emissions to 40-45 per cent below 2005 levels by 2030.  The Government of Canada also created legislation that formalized Canada’s commitment to achieve net-zero emissions by 2050 and will legally bind the Government to a process toward that objective, which is called the Canadian Net-Zero Emissions Accountability Act.

The Canadian Net-Zero Emissions Accountability Act, which came into force on June 29, 2021, legislates the Government of Canada’s commitment to achieve net-zero greenhouse gas emissions by 2050. The Canadian Net-Zero Emissions Accountability Act establishes a legally binding process to set five-year national emissions-reduction targets as well as develop credible, science-based emissions-reduction plans to achieve each target. It also establishes the 2030 emissions target as well as a requirement to set national emissions reduction targets for 2035, 2040 and 2045.

As part of the Canadian Net-Zero Emissions Accountability Act, in March 2022, the Government of Canada published the 2030 Emissions Reduction Plan. The 2030 Emissions Reduction Plan describes how Canada expects to meet its obligations under the Paris Agreement and COP26 to reduce emissions to 40-45 per cent below 2005 levels by 2030. Part of the 2030 Emissions Reduction Plan is to reduce oil and gas sector emissions and transitioning to net-zero.

Energy sector regulations and programs

The path to net-zero and the 2030 Emissions Reduction Plan has resulted in various regulations and programs that impact the oil and gas / energy sector, including the following:

• Methane regulations: Federal regulations require the oil and gas sector to reduce methane emissions by 40-45 per cent below 2012 levels by 2025. This includes stringent regulations related to reducing and leaking non-emergency flaring of methane from upstream oil and gas production.
• Clean Fuel Regulations: The Clean Fuel Regulations increase incentives for the development and adoption of clean fuels, technologies, and processes. The Clean Fuel Regulations also require liquid fossil fuel (gasoline and diesel) suppliers to gradually reduce the carbon intensity – or the amount of pollution – from the fuels they produce and sell for use in Canada over time, leading to a decrease of approximately 15 per cent (below 2016 levels) in the carbon intensity of gasoline and diesel used in Canada by 2030.
• Emissions Reduction Fund: The Emissions Reduction Fund (ERF) – Onshore Program assists companies invest in green solutions and infrastructure to continue progress towards reducing methane emissions in the context of the COVID-19 pandemic.
• Clean Growth Program: The Clean Growth Program (CGP) was an investment in clean technology research, development, and demonstration projects in three Canadian sectors: energy (including oil and gas), mining, and forestry.
• Energy Innovation Program: The Energy Innovation Program (EIP) advances clean energy technologies that will help Canada meet its climate change targets, while supporting the transition to a low-carbon economy. It funds research, development and demonstration projects, and other related scientific activities.
• CCUS Investment Tax Credit: The Government is developing an investment tax credit for capital invested in CCUS projects to encourage the development and deployment of CCUS technologies.

Impact on energy companies

Canada’s path to net-zero will have a significant impact on the energy industry going forward, in Alberta.

Alberta has traditionally relied on coal-fired electricity generation, which is on track to be eliminated as a fuel source for electricity by the end of 2023. Emissions from Alberta’s power sector has declined more than 40 per cent since 2005, in part, as a result of the shift away from coal.

In addition, Alberta has been a leader in energy projects in Canada. Alberta’s experience in the energy industry has allowed corporations to capitalize on the push towards renewable energy projects. Further, Alberta’s ‘open market’ electricity sector (at least until recently) provided the most opportunity for renewable energy projects and energy storage.

Similarly, Alberta’s experience in the energy industry has led to growing interest in carbon capture. The Oil Sands Pathways to Net Zero Coalition is such an example of leadership commitments from energy corporations to achieve net zero targets using carbon capture.

While the Alberta energy industry has made significant investments in renewables and carbon capture, further steps are required in order to meet net-zero and the targets in the 2030 Emissions Reduction Plan.

Canada’s electrical distribution system was largely designed around centralized, carbon-emitting energy sources. In most cases, it’s not possible to merely change the source of power. Switching to renewable sources will require upgrading or replacing legacy systems to include distributed resources and a two-way flow of power. This process may compromise reliability over the short term and impact Canadians’ ability to access electricity when they need it.