2020: The Energy Regulation Year in Review

Few of us have experienced a year like 2020. For the energy sector it was a brutal combination of low oil prices, a national coronavirus lockdown, and a severe economic downturn. It was also a signature year in terms of the shift in rhetoric and investment dollars away from conventional fuels and technologies to emerging ones.

A National Climate Policy

In terms of energy law and policy, the year 2020 ended with a bang. On December 11, 2020 the Government of Canada enacted legislation to accelerate climate change initiatives throughout the country. What first caught people’s attention was the proposal to increase the Canadian carbon tax from $50 per ton in 2022 to $170 per ton in 2030. That would increase the price of gasoline by almost 40 cents a liter, and double the heating costs for many homes, although the government claimed consumers would get it back in the form of a tax rebate. The plan also included 64 different programs to cut pollution and build a clean economy at a cost of $15 billion.

The investments included $2.5 billion for clean power projects over three years, $1.5 billion to develop low carbon fuels, $287 million over two years to promote zero emission vehicles, $3billion over five years to decarbonize large-scale emitters, $2.6 billion over seven years to improve home energy efficiency, and $3 billion over 10 years to plant 2 billion trees.

The Electric Vehicle Revolution

At the provincial level, the focus was on electric vehicles. Québec announced it would abandon the sales of new gas-powered cars starting in 2035. BC said it would follow suit in 2040. This followed an earlier California law that would ban the sales of gas-powered cars and trucks by 2035 and the announcement by Britain in November 2020 that it would ban the sale of new gas and diesel cars starting in 2030.

Car manufacturers around the world watched these developments closely. They were also watching Tesla. In 2020, that company reached a market capitalization of $880 billion more than Toyota, Volkswagen, Daimler, General Motors, BMW, Honda, Hyundai, and Ford combined.

In Canada, Ford announced it would spend $1.8 billion to produce electric vehicles at its Oakville plant in Ontario. General Motors responded by saying it would phase out gas-powered vehicles entirely by 2035 and invest $1 billion to produce electric commercial vans in Ingersoll, Ontario. Chrysler said it would spend $1.5 billion to produce electric vehicles in Windsor, Ontario.

New Charging Networks

Electric vehicles require electric charging. During 2020 electric vehicle charging networks became a reality in Canada. Tesla led the pack with 584 locations and 1400 chargers across Canada. In January 2020, Canadian Tire announced a plan to construct a network of 240 fast chargers at 90 Canadian Tire retail locations across Canada.

The electric utilities were also active. By the end of 2020, BC Hydro had expanded its network to 85 locations across BC while the partnership of Ontario Power Generation and Hydro One agreed to install 160 fast chargers in Ontario by the end of 2021. The importance of this new network became apparent in September 2020 when the US electric vehicle charging network company, ChargePoint, went public at a valuation of $2.4 billion. The investors included Chevron, BMW, Siemens, and the Canada Pension Plan Investment Board.

Sustainable Investment

The year 2020 also saw a dramatic shift in financial markets. Renewable energy now dominates capital markets in both Canada and the United States. Next Era Energy, the world’s largest supplier of wind power, replaced Exxon Mobil and Chevron Corporation to become the world’s most valuable energy company. In August 2020, Exxon Mobil disappeared from the Dow Jones industrial average. It had been a member since the company was Standard Oil of New Jersey in 1928.

Increasingly companies are now required to disclose their climate impact now called their ESG (environmental social and governance) value. Carbon-based companies are also being blacklisted by pension funds. ESG investment has doubled over the past four years. Price Waterhouse now estimates that 60 per cent of mutual fund assets will be ESG by 2025. Reporting and transparency with respect to ESG values is driving both capital markets and climate change initiatives.

The tide has changed. Everyone saw this coming. The zero-carbon revolution has been creeping forward over the past decade. The year 2020, however, was the fork in the road. The energy sector will be very different going forward. Energy regulation will also be very different. The following review of the decisions by Canadian energy regulators over the past year highlights some of these changes.


In the last five years, four major Canadian pipeline projects, potentially representing a $50 billion investment, have either been cancelled or threatened by regulatory challenges.[1] The four projects are the TransCanada Energy East pipeline, the Enbridge Northern Gateway pipeline, the Kinder Morgan Trans Mountain Expansion and, last but not least, Keystone XL. Last year we examined the first three. Below we consider Keystone XL, which was terminated recently.

Keystone XL

The Keystone XL pipeline was a $20 billion project that TransCanada proposed in 2008 to transport 800,000 barrels of oil per day from Alberta to Nebraska and then into an existing pipeline that would carry the oil to the Gulf Coast. The border crossing between the US and Canada was completed last year, along with 90 miles of pipeline within Canada.

The U.S. Department of State reviewed the pipeline for nearly seven years. The Canadian portion of the line obtained NEB approval in 2010.[2] In May 2012, TransCanada filed an application for a Presidential Permit with the U.S. Department of State. This permit is required from the US President whenever a pipeline crosses an international boundary. That permit was held up by ongoing litigation in the Nebraska courts. In November 2014, the U.S. House of Representatives approved Keystone XL for the ninth time. However, President Obama then exercised his veto to defeat the project.[3]

TransCanada challenged the Obama veto with a constitutional claim[4] and a North American Free Trade Agreement (NAFTA) claim of $15 billon.[5] Before either case could be heard, President Trump was elected. One of President Trump’s first decisions in office was to approve Keystone XL.

TransCanada was not in the clear once President Trump issued the permit to allow the pipe to cross the Canada-US border in 2015. The November 2020 presidential election in the United States saw a new president elected. President Biden was sworn in on January 20, 2021. The next day he cancelled the presidential permit President Trump had granted.

Alberta had invested $1.5 billion in equity in Keystone and guaranteed a $6 billion project loan in 2020. The pipeline is backed by shippers as well as by TransCanada. Cenovus Energy is responsible for $100 million and Suncor Energy for $142 million. No doubt others are involved as well.

The decision by President Biden did not come as a great surprise. The Biden campaign was based on supporting climate change initiatives including the cancellation of Keystone XL.

To complicate matters, NAFTA came to an end on July 1, 2020. It was replaced by a new agreement, the United States- Mexico-Canada Agreement (USMCA). The USMCA does not contain the investor state arbitration remedy available under NAFTA. There are transition provisions for legacy claims and a three-year period to file those claims but the incident on which the claim is based would have to have taken place prior to July 1, 2020. There is also a state-to-state claim under Chapter 20 of the new USMCA but TransCanada and/or the Alberta government would have to convince the Canadian government to bring the claim. That may not be that easy.

That is not the end of the difficulties. Arguably TransCanada knew and understood the ground rules. The presidential permit contained an express condition that the permit could be terminated or revoked or amended at any time at the sole discretion of the President. This term is designed to limit NAFTA liability. A NAFTA claim could result in long and uncertain litigation.

Four projects are still moving forward. They are the Trans Mountain Expansion project (TMX), Coastal GasLink, Enbridge Line 3, and Enbridge Line 5. The status of those projects is set out below.

Trans Mountain Expansion

In 2018, the federal government purchased the Trans Mountain Expansion from Kinder Morgan for $4.5 billion. On February 22, 2019, the NEB released its reconsideration report on the project, recommending again that it proceed. The federal cabinet accepted that recommendation and approved the project. Construction of the project officially began on December 3, 2019. Shortly thereafter, on January 16, 2020, the Supreme Court of Canada unanimously dismissed the BC attempt to claim jurisdiction over this project[6] upholding an earlier decision by the B.C. Court of Appeal.[7]

On February 4, 2020, a unanimous Federal Court of Appeal dismissed the most recent legal challenge to the project.[8] The court made it clear that Indigenous groups have no veto and that courts should defer to the governments that make the initial decision on whether the duty to consult has been met.

In May 2020, the Province of British Columbia issued an amended environmental assessment certificate (EAC) in the response to the B.C. Court of Appeal’s decision in September 2019. In July 2020, the Supreme Court of Canada (SCC) denied leave to three First Nation groups seeking to appeal the Federal Court of Appeal’s February 2020 decision. The most recent decision by the SCC to deny leave to appeal to the three First Nation groups means there are no more outstanding legal challenges to the project.

Coastal GasLink

The Coastal GasLink pipeline project is owned and operated by TC Energy. The $6.6 billion project starts near Dawson Creek and, if completed, would run approximately 420 miles southwest to a liquefaction plant near Kitimat. The pipeline, as planned, would pass through the traditional territories of several First Nation groups. It has long been opposed by multiple hereditary chiefs, although a number of First Nations groups support the project and have an ownership interest. In December 2018, the Supreme Court of British Columbia granted an injunction preventing blockades of the pipeline.[9]

One element of good news came in July 2019, when the NEB released its decision ruling that the pipeline — including the export terminal in Kitimat — was under provincial not federal jurisdiction.[10] The NEB concluded that the pipeline would transport natural gas within BC, although it would also facilitate international exports, providing some clarity to the earlier Supreme Court of Canada decision in West Coast Energy on provinces’ right to control works and undertakings within their boundaries.[11]

In December 2019, the Alberta Investment Management Corp. — the Alberta public pension manager — teamed up with one of the largest American investment companies to acquire a majority stake in the Coastal GasLink.

Enbridge Line 3

The Enbridge Line 3 runs from Hardisty, Alberta to Superior, Wisconsin, and has been operating since 1968. Over the years, it became apparent that part of the pipeline had to be replaced if Enbridge wished to restore it to its historical capacity and move 800,000 barrels per day. The necessary authorization was obtained from regulatory bodies in Canada,[12] North Dakota, and Wisconsin. However, the $3 billion project ran into problems in Minnesota where environmentalists and First Nation groups opposed the project.

In June 2018, the Minnesota Public Utilities Commission approved the route and granted the necessary permits.[13] However, a year later that decision was overturned by the Minnesota Court of Appeal that found that the environmental impact statement placed before the Commission was inadequate.[14] On February 3, 2020, the Minnesota regulators approved a revised environmental review removing the last regulatory hurdle for the project.

The US portion of the Line 3 project involves replacing 364 miles of pipeline. Most of the work lies in Minnesota, with 27 miles located in North Dakota and Wisconsin. The replacement project is connected to an existing 1097-mile crude oil pipeline installed in the 1960s that runs from central Canada to Wisconsin. Enbridge now estimates that the capital cost of the Line 3 replacement project, including the Canadian segment already in service, will end up at $9.3 billion compared to the original estimate of $8.2 billion. Enbridge now estimates that Line 3 will be in service by the fourth quarter of 2021.

Enbridge Line 5

Enbridge is currently replacing Line 5 which runs from Superior, Wisconsin to Sarnia, Ontario. The state of Michigan is opposing the underwater segment which runs under the Straits of Mackinac in the Great Lakes. The concern relates to environmental damage that could result from a leak in the pipe that currently sits on the lake bed. The project was approved by the former governor of Michigan but his successor, Gov. Whitmer, challenged the constitutional validity of the project in 2018.

The Michigan District Court ruled the legislation constitutional in October 2019 and that decision was upheld by the Michigan Court of Appeal in January 2020. In January 2021, the Governor of Michigan ordered Enbridge to cease operating the segment the pipeline under the Straits of Mackinac by May 2021. Enbridge argues that the 645-mile pipeline has been operating safely for 65 years. However, to address the concerns, Enbridge is now proposing to place the pipe in a tunnel underneath the lake bed at a cost of $500 million.

Line 5 part is part of the Enbridge mainline system that transports crude from Alberta and Saskatchewan to refineries in the Michigan, Ohio, Pennsylvania, Ontario, and Québec. Enbridge has argued that those refineries will see their capacity drop by 45 per cent if Line 5 does not continue in service. On January 29, 2021, the Michigan Department of Environment Great Lakes and Energy (EGLE) approved the Enbridge application for the permits required to build the utility tunnel under the Straits of Mackinac. However, permits from the Michigan Public Service Commission and the US Army Corps of Engineers are still required.

NGTL 2021 System Expansion

Late in the year, the federal cabinet gave final approval to TC Energy’s $2.3 billion NGTL 2021 System Expansion Project, from near Grande Prairie to north of Calgary. The Commission of the Canada Energy Regulator (CER) had recommended approval of the Project to the Governor in Council in its report dated February 19, 2020.[15] Cabinet, however, considered a further report prepared after the CER Commission report had been submitted.[16] Cabinet concluded that several of the conditions recommended by the CER Commission should be “strengthened” and that a further condition, which had initially been proposed by a dissenting CER commissioner, should be added.[17] NGTL was apparently not provided an opportunity to comment on the amendments or the additional condition, in apparent breach of an admonition from the Federal Court of Appeal in Gitxaala Nation v Canada[18] that “[i]t goes without saying that as a matter of procedural fairness, all affected parties must have an opportunity to comment on any new recommendations that the coordinating Minister proposes to make to the Governor in Council.” The delays before cabinet have resulted in a delay of a year for the Project, which is now scheduled for completion in the second quarter of 2022.

Enbridge Contract Carriage Proceeding

The proceeding to consider Enbridge’s application to allow shippers to sign long-term contracts for priority access to 90 per cent of its Canadian Mainline capacity continued before the CER Commission throughout the year. Currently, and historically, the Mainline has operated as a common carrier, with capacity allocated on an uncommitted basis using a monthly nomination system. The current service and tolling settlement is due to expire on June 30, 2021. The CER Commission will hold oral cross-examination in May 2021.[19] The application is controversial and has pitted various producer, market and refiner interest against one another. The outcome will no doubt be a focus of our review of 2021 developments.


Net Metering

During 2020 regulators in both Canada and the United States looked at reforming net metering.

Essentially the goal was to determine if net metering could be expanded from a single customer to a group of customers. Net metering has been around for almost 10 years but in Canada it caught on in only Ontario and British Columbia. The political attraction was that net metering could promote renewable energy and potentially reduce the cost of electricity to the ratepayers. The opposition came from utilities that were not eager to lose demand or customers.

The most ambitious program took place in British Columbia. On April 20, 2019, BC Hydro submitted an application to the British Columbia Utilities Commission (BCUC) to amend its net metering program. This resulted in interventions by 14 parties, over 200 letters of comment, and a 52-page final decision a year later in June 2020.[20] The most contentious part from the preceding was BC Hydro’s request to limit the size of the generation facility to the customers’ annual load.

Utilities throughout North America have long argued that customers engaging in net metering should not be able to generate a profit. The basic concept was that customer should be able to offset the cost of electricity they bought from the utility with the revenue they received from selling electricity to the utility. The BC evidence was that some customers were making a significant profit, but it was a small percentage of the total. In the end, the BCUC rejected the BC Hydro proposal and refused to adopt a maximum generation volume.

The Ontario regulatory initiative was more aggressive. In October 2020, the Ontario Minister of Energy established a consultation to determine the viability of community net metering. Garden-variety net metering consisted of an individual customer exchanging electricity with the utility. Community net metering on the other hand involves groups of customers acting together as a community or organization. The government asked interested parties to make submissions by November 22, 2020, addressing such questions as: what constitutes a community, how should the credits be structured, and how should utilities recover any costs incurred? To date no report has been issued by the government or the Ontario Energy Board.

In the United States, many states have adopted some form of net metering. The most aggressive state is California which recently adopted changes to its net metering program. In California, net metering is driven by solar generation established by households. To dampen the impact, the total amount of net metering has been restricted so that it cannot exceed 5 per cent of total solar generation. More recent changes in California may have implications for future changes in both Ontario and British Columbia.

The first California change was a requirement that net metering customers switch to time of use (TOU) pricing. The highest rates are charged in times of peak demand which is late afternoon or early evening. The lowest rates are charged at off-peak times which is late at night and early in the morning when electricity usage is low. The implication for net metering is that the value of the credit for energy sold to the grid varies based on the TOU rate. This means that to get the highest net metering credits consumers need to sell the maximum energy to the grid during peak demand time.

The other change, which is relevant to Canada, is the implementation of a new component of electricity rates known as non-bypass charges or NBC. This is a small charge of $0.02–$0.03 per kilowatt hour which is added to energy charges. This amount is not credited to consumers which means that consumers earn a bit less then they pay for electricity. This has not limited the demand for net metering because the NBC makes up a small portion of the overall bill. In addition, customers with generation systems under 1 MWh have to pay a one-time interconnection fee to connect their systems to the grid. This cost is generally between $75 and $150.

It will be interesting to see where Ontario goes with community net metering. This has implications for customer owned generation throughout Canada. Increasingly, there is a demand by large industrial customers to be able to sell their excess electricity to other customers in what are essentially private power purchase agreements. This continues to be a major issue before the Alberta Energy Regulator which we discussed in last year’s issue. A detailed report on that issue is now before the Alberta government.

Pipeline Construction Reform

It is not often that we hear governments proposing some form of the deregulation in the energy sector particularly when it comes to pipelines. However, on January 20, 2021 the Ontario Minister of Energy proposed such a possibility. Section 90 of the Ontario Energy Board Act (OEBA) requires that anyone constructing a pipeline in Ontario requires a leave to construct (LTC) order from the Ontario Energy Board if the pipeline:

  • is more than 20 km in length
  • will cost more than $2 million
  •  has a pipe size of 12 inches or more
  • has an operating pressure of 2000 kilopascals or more

The Ontario government is proposing to change O.Reg 328/03 under the OEBA to increase the cost threshold from $2 million to $10 million. However, an OEB LTC will still be required for any pipeline that does not meet any of the other requirements outlined in section 90 of the OEBA. In addition, any party constructing a pipeline will still be required to obtain the existing authorizations from government Ministries or Municipalities. In addition, any reduction to the existing requirements would not apply to the construction of pipelines crossing an Ontario border which are regulated by the Canadian Energy Regulator or an addition to a pipeline that is part of an existing interprovincial pipeline.

The government estimates that the increase of the threshold from $2 million to $10 million would, based on the OEB LTC applications received between 2017 and 2020, reduce the number of projects requiring a LTC from the Board by 24 per cent. This could result in a significant reduction in regulatory costs which are ultimately borne by the ratepayers. Submissions regarding the government proposal are due by April 29, 2021.

Small Utility Regulation

Ontario is different than most Canadian jurisdictions when it comes electricity regulation. Canada is dominated by large government owned utilities that provide generation, transmission, and distribution. In Ontario, most of the distribution has traditionally been done by municipally owned distributors. Recently there has been a high degree of consolidation but there are still 31 small distributors each with less than 20,000 customers. In 2020, the OEB announced the new Ontario initiative to streamline the regulatory process for these small distributors. It started with the with a stakeholder meeting on January 28, 2021 and will conclude with a report in time to set the 2023 rates.

Green Industrial Rates

As 2020 came to an end, the British Columbia government announced new Green Energy Incentive Rates for industrial customers in the province. There are two new rate plans. The first was the Clean Industry and Innovation Rate. The second was the Fuel Switching Rate. Both rates are available until March 31, 2030 and customers can enjoy these discounted rates for seven years. The discount is 20 per cent for the first five years, 13 per cent in the sixth year and 7 per cent in the seventh year.

Under the Clean Industry and Innovation Rate, power costs are lowered for eligible industrial customers involved in carbon sequestration, hydrogen production, synthetic fuel production and carbon capture and storage. In addition, industrial customers setting up data centers with over 70 GWh a year of electricity demand are eligible to benefit from these lower rates.

The Fuel Switching Rate is available to existing and new industrial customer switching from fossil fuels to electricity to power their operations. To qualify, a customer must demonstrate that the electrification will reduce greenhouse gas emissions. The discounted rate applies only to the fuel switching portion of the electric load. The Fuel Switching Rate is not available to oil pipelines, oil refineries, methanol production or natural gas liquefaction facilities. There is also minimum energy demand requirement. The increase in electricity demand from fuel switching must be at least 20 GWh a year.

In addition to the new BC Hydro rates, the province of British Columbia has allocated $84 million to federal green infrastructure funding to establish an electrification fund for qualifying industrial customers including those in the oil and gas sector. BC Hydro will provide funding up to 50 per cent of the eligible costs to maximum of $15 million per project with the customer responsible for the balance of the cost.

To qualify, projects must satisfy the following conditions. They must switch from carbon-based fuel to use electricity, support public infrastructure and the interconnection. The work must also be completed by spring 2027.

The mild little switch from philosophy of electricity must meet certain minimum thresholds based on customer type. For industrial customers, 5 MW with a minimum interconnection cost of $5 million. For transportation of bulk environmental customers 2 MW with the minimal interconnects cost of $2 million. The applications will be reviewed on a first-come first-served basis.

New Capacity Auctions

Ontario was slow to recognize the benefits of competitive bidding. That concept was ignored in the years of FIT contracts which were based on the concept of first come first serve. That was met with all kinds of complaints about illegal preferences leading to a number of lawsuits and international arbitrations — some of which are still proceeding.

Good news arrived on December 10, 2020, when the Independent Electricity System Operator (IESO) announced the results of a new capacity auction under which 1000 MW of capacity was secured at a price which was 26 per cent below the price in the 2019 demand response auction.

The total number of bidders was not announced but over 1700 MW of resources enrolled in the auction. The auction also included storage assets which was particularly welcome given the regulatory struggles to determine where storage fits into the Ontario marketplace. That issue still before the Ontario Energy Board.

Participants have committed to provide capacity for summer 2021 to help manage peak seasonal loads. The next capacity auction is scheduled for December 2021. The IESO states it intends to explore additional enhancements to enable additional resources to compete.


Energy Storage

The development of energy storage in terms of regulation has been moving slowly in Canada compared to the United States. In January 2020, the OEB issued the Toronto Hydro rate case decision[21] rejecting an application to include storage in the utilities rate base stating that the applicant should pursue a policy change in the Board’s ongoing consultation on distributed energy resources. However, in August 2020, a Board Staff report suggested that Ontario local distribution companies may operate behind the meter energy storage and treat it as part of regulated operations if the purpose is to remediate poor service reliability. There is still some confusion regarding the status of what appears to be a new policy instrument.

In the United States, the storage market is moving more quickly. Readers will recall that in 2018 FERC issued a final rule, Order No. 841[22] which was designed to incorporate storage more fully into the market-place. There were a number of appeals and challenges to this Order but in the end the situation moved forward with FERC in August 2020 accepting a proposal from MISO to allow cost recovery for energy storage projects that address transmission system needs.[23] Interestingly, the OEB Staff Report was released at the same time. Other US RTO/ISO agencies are now developing proposals to promote the integration of energy storage solution to address different transmission issues.

The August 10 FERC approval in MISO allowed, for the first time under certain circumstances, electric storage facilities to qualify as transmission only assets eligible for full cost of service rates. At the same time merchant energy storage is developing in both Canada and the United States using battery energy storage systems. Broad Reach Power has begun construction of two separate 100 MW facilities in Texas while WCSB Power is developing a 20 MW facility in Alberta.

Innovation Funding

In the past Canadian energy regulators have been reluctant to fund through rates projects that were considered to be experimental or research in nature. For example, applications to both the Ontario and Nova Scotia regulators to fund EV charging were declined.[24] Things have changed. The year 2020 saw energy regulators in British Columbia, Ontario, and Nova Scotia take dramatic steps in funding new technology through ratepayer dollars. We turn first to British Columbia.

In June 2020, the BCUC issued a decision in response to an application by FortisBC to establish a Clean Growth Innovation Fund.[25] The utility actually proposed two funds, one for a gas utility and one for an electricity utility. The application by the electricity utility failed but the one by the gas utility succeeded.

The utility proposed a charge of $0.30 per customer per month for the electric utility and $0.40 per customer per month for the gas utility. The anticipated annual funding based on the number of forecasted customers was $4.9 million for the gas utility and $0.5 million for the electric utility.

The BCUC approved the innovation fund for the gas utility because there was a “demonstrated need to accelerate natural gas innovation activity to meet the climate change targets set by the Province of British Columbia which had legislated a 40% reduction GHG emissions over the next decade.”

The decision represents a key milestone for innovation funding. Previous applications were directed at specific projects. This application however, created a fund for projects that would be considered from time to time. The application also proposed a governance model to ensure that the funds were applied to innovations that would benefit customers. The decision also addressed accountability and annual reporting by the utility.

The starting point in the Board’s analysis was a determination of the demand for funding. The Commission relied on the evidence from the utility that pointed to Canada’s commitment to reduce GHG emissions by 30 per cent between 2005 and 2030 and BC’s commitment to reduce emissions by 40 per cent by 2030 and 80 per cent by 2050. To this were added commitments by the City of Vancouver. The panel concluded that the utility had demonstrated the need to accelerate its innovation activities in light of governmental climate policies with respect to decarbonization and electrification.

The Commission faced a major hurdle when one of the interveners argued that the Commission did not have jurisdiction to set the rate increases proposed by the utility. This is not a unique argument. In the past Canadian energy regulators have faced continual objections regarding rates for special classes including most recently indigenous customers[26] and previously rates for low-income consumers[27].

In this case, the BCUC found that the innovation fund did not offend cost of service principles relying on section 59 of the Utilities Commission Act that gave the BCUC broad discretion to use any mechanism or method for setting a rate that it considered advisable. The Commission concluded that a fixed rate adder to support the innovation fund was one such mechanism. This decision will be closely watched by regulators throughout Canada.

Smart Grid Pilots

The British Columbia regulator was not alone in financing new technology in 2020. In December 2019, Nova Scotia Power submitted an application to the Nova Scotia Utility and Review Board to approve a $7 million capital expenditures on a smart grid pilot. The purpose of the pilot was to determine if new software developed by Siemens could monitor and manage distributed energy resources (DERs) in a fashion that would increase grid reliability and reduce costs.

The project was driven by the growing importance of distributed energy resources in the operations of Canadian electricity utilities. The DERs used in this project were solar generation, battery storage, and electric vehicle charging.

The overall cost of the pilot project was $19 million but of that amount nearly $12 million was external funding leaving one third to be funded by Nova Scotia Power customers. The criteria the Board applied in determining whether this capital investment was justified was called the Innovation Justification Criteria (ITC). The ITC test was: can the project be reasonably expected to produce valuable data and learning to develop a business case prior to full-scale development?

One of the issues the Board had to contend with was a concern by interveners about the lack of competitive bidding in putting the project together. In particular, there was a significant reliance on Siemens with respect to software. This was discounted when it was explained that Siemens was largely responsible for obtaining the federal funding which was supporting the project. There was also some concern about potential cost overruns. The Board made it clear that its decision approving the pilot project was limited to the expenditure of $7 million and recovery of any cost overruns would require Board approval.

This decision by the Nova Scotia Board[28] is a rare but important example of ratepayer funding of new technology. The Board’s decision was clearly influenced by the significant funding from outside sources such that only one third of the total capital cost was being borne by ratepayer as was the condition that the utility was at risk for any cost over runs. The Board also established a meaningful compliance and reporting structure that will be instructive to other regulators examining similar ventures. The extensive evidence from independent outside experts also provides some useful lessons for future applicants.

Hydrogen Blending Pilots

On October 30, 2020, the Ontario Energy Board issued a decision[29]approving an application from Enbridge Gas to construct a pilot project which blends hydrogen into conventional natural gas to be distributed in an area north of Toronto. The Board approved the application and allowed Enbridge to construct the necessary facilities and set rates related to the project. The rates were designed to ensure that the ratepayers that receive blended gas did not pay more than other Enbridge Gas customers.

The objective of the pilot is to reduce the GHG emissions relating to the sale of natural gas. Hydrogen has no carbon emissions when it is burned. As a result, combining hydrogen with natural gas reduces the overall carbon footprint.

In this pilot, 2 per cent of the total product will be hydrogen. Because hydrogen has a lower heating value than conventional natural gas it takes a greater volume of hydrogen to provide the same energy content. The result is that customers receiving blended gas must consume a higher volume than customers receiving conventional natural gas. This requires a price adjustment which the Board approved to compensate customers in the blended gas district for the cost of the extra gas.

The pilot project will deliver blended gas to approximately 3600 customers in the blended gas area over five years. At the end of that period Enbridge is required to file a detailed report to the regulator that will assess the costs and benefits of the project. Enbridge has indicated that it plans to apply for similar projects in other gas markets it is currently serving in Canada.

Demand Control Tariffs

In March 2020, the Nova Scotia Utility and Review Board released its decision[30] with respect to a unique demand control tariff for the Nova Scotia Power’s largest customer, Port Hawkesbury Paper. The main feature of this new tariff is that the customer gives control of its load to the utility. That means that Nova Scotia Power can increase or decrease the load depending on system conditions. The ability to make those changes can lead to significant savings to the Nova Scotia Power system and ultimately to ratepayers.

Under the tariff, the cost savings are divided between the utility and the customer with 25 per cent of the savings going to the customer in the form of a load shifting credit. The remaining 75 per cent is credited to Nova Scotia Power customers. The new tariff however must provide a minimum of four dollars per megawatt hour towards the fixed costs of Nova Scotia Power.

It is estimated that the total benefit to Nova Scotia Power customers will range between $6 million and $13 million annually over the three-year tariff period for an average of $10 million. Detailed reporting by Nova Scotia Power to the regulator is required on both a quarterly and monthly basis.


Constitutional Issues

The year 2020 started out with two constitutional decision. The first took place on January 16, 2020, when the Supreme Court of Canada dismissed British Columbia’s attempt to regulate the transportation of heavy oil through the province.[31] The nine-member panel delivered a rare decision from the bench stating that it agreed with the British Columbia Court of Appeal’s decision.

The BC government was attempting to block the Trans Mountain Expansion pipeline that it believed would significantly increase the flow of heavy oil from Alberta to the British Columbia coast. To do this, BC proposed to change its Environmental Management Act in April 2018. Those changes would prohibit the possession and transportation of heavy oil without a provincial permit. In response to political controversy the British Columbia Premier referred the matter to the B.C. Court of Appeal. That court unanimously held that the amendments were outside the scope of provincial jurisdiction given that they primarily focused on a federal interprovincial undertaking.

The next decision occurred in February 2020 when the Alberta Court of Appeal held that the federal carbon tax was unconstitutional.[32] A few months earlier the Saskatchewan and Ontario Courts of Appeal held that this legislation was within federal jurisdiction.[33]

The Alberta Court of Appeal claimed the carbon tax was an unconstitutional “Trojan Horse” that would forever alter the constitutional balance between the provinces and territories. In considering the proposed regulation of GHG emissions the Alberta court interpreted the peace order and good government provision more narrowly than Saskatchewan and Ontario courts although both of those decisions also had a dissent. The Alberta court held that this arm of federal jurisdiction was not the grand entrance hall into every head of provincial power. In the end, the Alberta court clearly stated that the new legislation would allow the federal government to limit the provinces exclusive jurisdiction over property and civil rights.

The three decisions have been appealed to the Supreme Court of Canada where they were heard in September 2020.

Intervenor Standing

There was a time when many Canadian energy regulators interpreted standing on a relatively narrow basis. Over time, most energy regulators clarified their standing rules. Standing was generally allowed if the potential intervenor could show that it was “directly affected” by the application.

In December 2020, the Alberta Court of Appeal issued its decision in Normtek Radiation[34] which broadens the standing rule beyond the narrow directly affected concept.

Normtek Radiation was in the business of transporting radioactive material. It opposed an approval to amend a landfill contact opposed in a decision of the Alberta Environmental Appeals Board. The Board had approved the disposal of concentrated radioactive material in a manner Normtek believed was contrary to industry and government standards. Normtek was not directly affected by this ruling but was concerned that failure to follow industry standards would damage the entire industry including Normtek.

Normtek’s request for standing was rejected. Because Normtek operated outside the area of environmental impact, the Board ruled that Normtek was not directly affected. Normtek then appealed the Board decision to the Alberta Court of Appeal. The court reversed stating that it was not necessary that there be an adverse impact in order for the appellant to be directly affected. The Alberta Court of Appeal held that the general economic impact of the approval was sufficient. In short, the court held that Board’s interpretation of “directly affected” was too narrow. This decision may open the door to a broader interpretation of standing.

The Importance of Reasons

The court in Vavilov[35] emphasized the necessity of providing reasons Not only were reasons important, the court stated they required justification, transparency, and intelligibility. Decisions must be justified, not just justifiable.

The court went on to identify two fundamental flaws that were to be avoided. First, a decision must have internally coherent reasons and will not be considered reasonable where the decision reached does not follow from the analysis undertaken. The second fundamental flaw relates to the requirement that the decision must be justified in light of the legal and factual constraints that bear on it. Finally, decisions must avoid persistently discordant or contradictory legal interpretations and departures from long-standing practices or established internal authority without satisfactory explanations for the departure. Without a credible explanation of its failure to follow precedence, a decision will be considered unreasonable.

In October 2020, the Ontario Divisional Court in Halton Hills Hydro[36] had an opportunity to decide the first case under Vavilov. The applicant utility claimed that the Board had erred in its decision on three grounds. First, the Board had failed to set rates that were just and reasonable. Second, the Board had arbitrarily not followed past practices. And third, the reasons for the decision were not sufficient.

The Court rejected all three arguments. The decision, with respect to reasons, was particularly interesting. In rejecting this ground, the Court stated as follows:

[33] The reasons on this issue are brief but sufficient. The Board did not need to state the history of this issue in the Board’s jurisprudence in the way that I have done in these reasons. A specialized tribunal providing reasons to experienced participants in the Board’s processes need not explain things that are well known to the parties. Reasons are instrumental, and these reasons conveyed to the parties the basis of the Board’s decision.

[35] This is not a case where the court has “no idea what prompted the decision”. To paraphrase from the Court of Appeal: “[t]he… reasons … need not be lengthy. They need not be complex. But, as the Divisional Court observed, they must at least answer the question “Why?”. The OEB’s decision answers the question “why”. The reasons are sufficient.

In May 2020, the Ontario Divisional court struck down a decision of the Ontario Ministry of the Environment in Nation Rise Wind Farm.[37] The Ministry had issued a permit for the windfarm that was reversed by the Minister on the basis that the project was not in the public interest. The wind farm operator appealed the decision to the Divisional court. The court found that the Minister’s decision was unreasonable because the process by which the Minister made the decision was procedurally unfair. Relying on the Supreme Court of Canada decision in Vavilov the court found that there was a denial of procedural fairness when the Minister failed to grant the operator with an opportunity to address a remedy after the decision was made. The court also found that the failure to advise the operator that a new issue relating to bat colonies was being considered in the appeal and was instrumental in determining that the project was not in the public interest.

A different result was reached by the Yukon Court of Appeal in Yukon Energy Corporation.[38] There, the utility appealed the decision of the Yukon Utilities Board on the basis that the Board failed to consider certain aspects of Yukon Energy evidence and had considered irrelevant evidence in concluding that certain costs incurred were not prudent. The court rejected the application stating that the hearing panel was entitled to exercise its discretion when it declined to approve the cost submitted by Yukon Energy, that the hearing panel did not take into account irrelevant factors in exercising its discretion and accordingly did not commit any error of law.

Cross Border Disputes

Earlier in this editorial we outlined in some detail disputes underway with respect to pipeline construction. Similar disputes are taking place in electricity transmission. These disputes usually involve Hydro Québec (HQ), Canada’s largest public utility. Two projects are currently facing difficulty.

The first is a $2 billion transmission line that will be laid under Lake Champlain and the Hudson River to supply New York City with renewable energy. HQ is facing difficulty in Québec over the refusal to bury the line underground although its US partner has agreed to do that on the American side.

The second project is known as New England Clean Energy Connect or NECEC. It is a 1200 MW transmission line from Québec to Massachusetts. This is an agreement to sell 9.5 TW hours of power for 20 years. Most of it will be consumed in Massachusetts but Maine has been guaranteed 500,000 MWh per year as an incentive to allow NECEC to pass through the state. This project has been underway for three years and most state and federal permits have been obtained.

In November 2020, United States Army Corps of Engineers issued a federal environmental permit for the project which paves the way for Central Main Power to begin construction. On January 15, 2021, the project received presidential approval from the U.S. Department of Energy. The project is still awaiting approvals in the US from the ISO New England. In Canada, the project has received the necessary approvals from the Régie in Montreal. However, on January 15, 2021 the U.S. Court of Appeals for the First Circuit, which sits in Boston, issued an injunction suspending work on the route.

Environmental groups have successfully challenged the project on the ground one of the federal permits was improperly issued. To complicate matters, a coalition of groups has filed a petition with the Maine Secretary of State asking the Secretary of State to hold a referendum that would retroactively require state legislature approval for any transmission lines over 50 miles. It would also prohibit any construction in the upper Kennebec region effectively closing down the NECEC project.

This is not the first time that Hydro Québec has faced this situation. In 2019, a New Hampshire Court blocked the project known as Northern Pass that would have delivered 1100 MW of power to New Hampshire.

Jurisdiction Decisions

In Planet Energy,[39] the Ontario Energy Board had ordered Planet Energy to pay an administrative penalty of $155,000. Planet Energy objected and appealed to the Ontario divisional court on the basis that the Board had no jurisdiction to impose an administrative penalty because the Board had exceeded the time limitation in section 112 of the Ontario Energy Board Act.

The court rejected the appeal on the basis that Planet Energy had not raised the issue with the Board, relying on the principle that the court had the discretion to ignore arguments that were not made before the Board in the first instance as set out in the Supreme Court of Canada decision in Alberta Teachers.[40] The court noted that while our viewing court has the discretion to address a new issue raised on judicial review, that discretion will generally not be exercised if the issue could have been raised before the tribunal and was not.

Planet Energy was followed by a decision of the Alberta Court of Appeal in April 2020 in Fort McKay First Nations v Prosper Petroleum Ltd.[41] The Alberta Energy Regulator (ARE) had approved Prosper Petroleum’s application to build a 10,000 barrel per day bitumen recovery project within 5 km of the Fort McKay First Nation reserve. The question before the regulator was whether or not the project was in the public interest. The panel found that the project was in the public interest but declined to consider the adequacy of consultation and the honour of the Crown. The AER stated that this was the responsibility of the Alberta government.

Fort McKay First Nations appealed to the Court of Appeal which set aside the AER decision. The court found that while AER may have been statute barred from assessing the adequacy of crown aboriginal consultation the AER was not relieved of its duty to assess the adequacy of the consultation. The Court of Appeal held that where a tribunal had the power to consider questions of law without clear indication that the Legislature intended to exclude such jurisdiction, tribunals have implied jurisdiction to consider issues of constitutional law. The court noted this is especially the case where the tribunal is assessing the public interest.

The Fort McKay case was followed by the Ontario Divisional court decision in May 2020 in Nation Rise Wind Farm.[42] There, a Director of the Ministry of the Environment had issued an authorization to Nation Rise Wind Farm permitting construction of a 100 MW windfarm near Ottawa. A group of citizens filed a notice of appeal to the Minister who was required to determine if the decision was in the public interest. The Minister found the decision was not in the public interest and revoked the permit. In so doing the Minister relied on evidence that had not been before the Director in the first instance. In addition, the Minister failed to advise Nation Rise Wind Farm that new evidence and a new issue was being considered.

The Divisional court agreed with Nation Rise Wind Farm that the Minister’s decision was unreasonable and that the process by which he reached the decision was procedurally unfair. The court rules that the Minister did not have the authority under section 145 of the EPA to confirm, offer, or revoke the decision of the tribunal. The court found that section 145 requires the Minister to deal only with the matters in the appeal that were raised by the party bringing the appeal. The court found that the Minister unreasonably concluded that he had authority to add new issues on the appeal.

The next decision was the decision of the Manitoba Court of Appeal in June 2020.[43] There, the Public Utilities Board of Manitoba had ordered Manitoba Hydro to create a new customer class for aboriginals living on First Nations reserves. Manitoba Hydro appealed the Commission’s directive creating a special class. The Court of Appeal held that establishing customer classes is an inherent part of setting utility rates. However, while the Board had the authority to create such classification it had to do so within the statutory limits provided by legislation.

The court held that the Board had exceeded its scope of authority in directing the creation of the class stating that the ability to consider factors such as social policy and bill affordability in approving and fixing rates it is not authority to direct the creation of customer classifications implementing broader social policy payments and poverty reduction which have the effect of redirecting Manitoba Hydro’s funds and revenues to alleviate such conditions.

The next decision was the decision of the Ontario Divisional Court in Rogers Communication[44] in November 2020. There the Ontario Divisional court issued a decision dismissing an appeal with respect to a charge approved by the Ontario Energy Board for wireline attachments to electricity distribution poles. To arrive at a provincewide rate for pole attachment the OEB had conducted review of charges for wireline attachments and issued a final report in March 2018 setting a provincewide rate of $43.63 with annual adjustments based on a OEB inflation factor.

A group of carriers appealed to the Divisional court and asked the court to set aside the report arguing that the OEB had failed to follow the provisions of the Ontario Energy Board Act requiring the OEB to hold the hearing. Their position was that the Board’s attachment charges were a rate for transmitting electricity or retailing electricity which required the OEB to hold a hearing.

The divisional court responded that the use of rental space on a pole by a telecommunication company had nothing to do with retailing or distribute electricity. The court further noted that previously these rates had been adjusted by amending the license of electricity distributors which contained a requirement that distributors must allow access to the poles at a specified rate which was approved by the OEB and included in the distribution license. The court concluded that the change to the attachment charge was a lawful exercise of the OEB’s jurisdiction and did not require OEB hearing. The court also concluded that the process followed by the OEB was procedurally fair.

The next decision with respect to Board jurisdiction was the decision of the Ontario Energy Board in Waterfront Toronto in January 2021. There, Enbridge asked the Board to order Waterfront Toronto to pay $70 million to cover the cost of a new pipeline.[45] Waterfront Toronto, a consortium of three governments: the City of Toronto, the Province of Ontario, and the government of Canada. Waterfront Toronto argued that it was not requesting the pipeline and in any event the Board has no authority to order Waterfront Toronto to pay any or all of the cost of a pipeline because Waterfront Toronto was not a consumer of gas.

Waterfront Toronto relied on earlier decisions that found that the Board’s authority to allocate costs for pipeline construction was within the Board’s jurisdiction because it formed part of the Board’s ratemaking authority. However, in this case because Waterfront Toronto was not a gas customer, no ratemaking authority was involved and accordingly the Board had no jurisdiction to order Waterfront Toronto to pay the cost. The decision has not been appealed.

The last decision on jurisdiction is the February 2021 ruling in Yukon Energy Corporation.[46] The Yukon Utilities Board had disallowed certain costs claimed by the utility in a rate case. Yukon Energy argued that the Board had made three errors of law. First, it failed to determined Yukon Energy rate base in accordance with requirements of the Act. Second, it considered the irrelevant evidence in determining that the costs were not properly incurred. Finally, the Board failed to consider Yukon’s evidence in relation to the cost claim.

The Board decision was reviewed by a Review Panel of the Board which dismissed the Application on the basis that there had been no error of law.

The Yukon Court confirmed that the Board had properly exercised its discretion. The Board had made a determination that the costs incurred were not necessary to provide service to the public. The Board had concluded that Yukon Energy had not acted prudently by incurring these costs. In addition, the court found that the Hearing Panel did not take into account irrelevant factors in exercising its discretion and accordingly did not commit any error of law.


In the introduction to this Annual Review we indicated that the Canadian energy sector was facing a dramatic shift in rhetoric and investment away from conventional energy driven by climate change concerns. We also indicated that this shift would have a significant impact on Canadian energy regulators. Decisions by both the regulators and the courts in the last year point to two important developments.

The first was the unusual number of challenges to the jurisdiction of Canadian energy regulators. In total there were ten challenges in 2020. Half of them succeeded. The final results will depend on some outstanding appeals. The increase in the number jurisdiction decisions is no doubt a by-product the Vavilov decision by the Supreme Court of Canada in December 2018. It will take a while for the impact of Vavilov to be fully understood.

The other trend which is equally important is the increased role of energy regulators in promoting the introduction of new technology. This new technology invariably relates directly or indirectly to climate change and carbon reduction.

The first decision took place on the Pacific coast where the BCUC allowed a gas utility to establish an innovation fund to be paid for by ratepayers at a cost of $ 24.5M over a five-year period. Next was the decision of the Ontario Energy Board on an Enbridge application to undertake a pilot project that would examine the costs and benefits of blending hydrogen into natural gas. Finally, on the Atlantic coast we saw the Nova Scotia Board approve a pilot project by Nova Scotia Power to obtain partial funding of pilot project that would evaluate new software to allow more efficient operation and management of distributed energy resources.

These three cases represent a dramatic change by Canadian energy regulators. Traditionally energy regulators have been reluctant to use ratepayer dollars to fund new and unproven technology. This caution may come from the long-standing regulatory principle that before assets can become part of the rate base they must be “used in useful.” But as we said in the Introduction the times of changed.

No doubt regulators and governments will closely watch these three important decisions. They all have monitoring programs and it will be interesting to see how detailed and public the review will be. These three decisions represent a useful change in direction by Canadian energy regulators. It is interesting that the three decisions took place at the same time in three different provinces before three different regulators. That they took place in both electricity and gas is also interesting.

We will see more of these decisions going forward. Regulators can bring a unique set of skills to the problem. The problem is that new technology often requires a very significant capital investment. Regulators are in a unique position to direct and evaluate pilot projects and determine the utility of the new technology before major financial commitments are made.

The other interesting difference between these three cases is the form of financing. In the British Columbia case the ratepayers cover all of the costs. In the Nova Scotia case the ratepayers cover one third of the cost, and in the Ontario case the utility covers all of the cost. It will be important to evaluate these different funding approaches. It can be argued that in a world where there is substantial capital to fund green energy investments there should not be a need for the ratepayer to fund all of the cost. Having private capital involved, particularly if it is non-utility capital as in the Nova Scotia case, offers additional surveillance, review, and verification.

  1. $15.7 billion for Energy East, $7.9 billion for Enbridge Northern Gateway, $7.4 billion for Trans Mountain expansion, and $20.6 billion for Keystone XL.
  2. Re TransCanada Keystone XL Pipeline (March 2010), OH-1-2009, online: National Energy Board <docs2.cer-rec.gc.ca/ll-eng/llisapi.dll/fetch/2000/90464/90552/418396/550305/604643/604441/A24669-1_NEB_-_Reasons_for_Decision_-_TransCanada_Keystone_XL_Pipeline_-_OH-1-2009.pdf?nodeid=604637&vernum=-2>.
  3. US, The White House, Message from the President of the United States returning without my approval S. 1, The Keystone XL Pipeline Approval Act (S Doc no 114-2) (Washington, DC: US Government Publishing Office).
  4. TransCanada Keystone Pipeline LP v Kerry, 4:16-cv-00036 (SD Tex 2016).
  5. TransCanada Corp. & TransCanada Pipelines Ltd. v United States of America (Canada v United States) (2016), online: State Department <www.state.gov/transcanada-corp-transcanada-pipelines-ltd-v-united-states-of-america/>.
  6. Reference re Environmental Management Act, 2020 SCC 1 [Reference EMA].
  7. Reference re Environmental Management Act (British Columbia), 2019 BCCA 181.
  8. Coldwater First Nation v Canada (Attorney General), 2020 FCA 34.
  9. Coastal GasLink Pipeline Ltd. v Huson, 2018 BCSC 2343.
  10. Re Jurisdiction over the Coastal GasLink Pipeline Project (26 July 2019), MH-053-2018, online: National Energy Board <docs2.cer-rec.gc.ca/ll-eng/llisapi.dll/fetch/2000/90464/90550/90715/3615343/3715570/3809973/C00715-1_%20NEB_%E2%80%93_Letter_Decision_%E2%80%93_Coastal_GasLink_%E2%80%93_MH-053-2018_-_A6W4A5.%20pdf?nodeid=3809655&vernum=-2>.
  11. Ibid (citing Westcoast Energy Inc. v Canada (National Energy Board), [1998] 1 SCR 322, 156 DLR (4th) 456).
  12. Re Enbridge Pipelines Inc., Application dated 5 November 2014 for the Line 3 Replacement Project (April 2016), OH-002-2015, online: National Energy Board <docs2.cer-rec.gc.ca/ll-eng/llisapi.dll/fetch/2000/90464/90552/92263/2404881/2545522/2955931/2949686/A76575-1_NEB_-_Report_-_Enbridge_-_Line_3_ Replacement_decisions_and_recommendations_-_OH-002-2015.pdf?nodeid=2949922&vernum=-2>.
  13. Minnesota Public Utilities Commission, “Line 3 Review Process”, online: <mn.gov/puc/line3/process/>.
  14. In re Applications of Enbridge Energy, LP, 930 NW 2d 12 (Ct App Minn 2019).
  15. Re NOVA Gas Transmission Ltd., Application dated 20 June 2018 for the 2021 NGTL System Expansion Project (February 2020), GH-003-2018, online: Canada Energy Regulator <docs2.cer-rec.gc.ca/ll-eng/llisapi.dll/fetch/2000/90464/90550/554112/3422050/3575553/3575989/3905746/C04761-1_Canada_Energy_Regulator_%20Report_-_NOVA_Gas_Transmission_Ltd._GH-003-2018_-_A7D5G0.pdf?nodeid=3905626&vernum=-2>.
  16. Natural Resources Canada, “Crown Consultation and Accommodation Report for the NOVA Gas Transmission Ltd. 2021 System Expansion Project (GH-003-2018)” (October 2020), online: <mpmo.gc.ca/measures/nova-gas-transmission-ltd-2021-ngtl-2021/nova-gas-transmission-ltd-2021-report/321>.
  17. Natural Resources Canada, News release, “Government of Canada Approves the NOVA Gas Transmission Ltd. 2021 System Expansion Project” (20 October 2020), online: <www.canada.ca/en/natural-resources-canada/news/2020/10/government-of-canada-approves-the-nova-gas-transmission-ltd-2021-system-expansion-project.html>.
  18. 2016 FCA 187 at para 337 (Emphasis added).
  19. Canada Energy Regulator, “Enbridge Pipelines Inc. (Enbridge), Canadian Mainline Contracting Application, Hearing Order RH-001-2020, Procedural Update No. 1 – Oral Hearing Preliminary Information” (23 February 2021), online: <docs2.cer-rec.gc.ca/ll-eng/llisapi.dll/fetch/2000/90465/92835/155829/3773831/3890507/4038614/4049665/C11628-1_Commission_%E2%80%93_PU_No._1_-_Enbridge_%E2%80%93_Canadian_Mainline_%20Contracting_%E2%80%93_Hearing_Timetable_and_Preliminary_Cross_Estimates_-_A7R4K7.%20pdf?nodeid=4049666&vernum=-2>.
  20. Re British Columbia Hydro and Power Authority Application to Amend Net Metering Service under Rate Schedule 1289 (23 June 2020), online: British Columbia Utilities Commission <www.bcuc.com/Documents/Decisions/2020/DOC_58477_Decision-with-Order-G-168-20-BCH-Net-Metering-RS1289.pdf>.
  21. Re Toronto Hydro-Electric System Limited (19 December 2019), EB-2018-0165, online: Ontario Energy Board <https://www.rds.oeb.ca/CMWebDrawer/Record/663131/File/document>.
  22. Electric Storage Participation in Markets Operated by Regional Transmission Organizations and Independent System Operators, 162 FREC ¶ 61,127 (2018), online: FERC <www.ferc.gov/sites/default/files/2020-12/Order-No-841.pdf>.
  23. Midcontinent Independent System Operator, Inc., 170 FERC ¶ 61,186 (2020), online: FERC <cms.ferc.gov/sites/default/files/2020-05/20200310135710-ER20-588-000.pdf>.
  24. Re Toronto Hydro-Electric System Limited (22 February 2012), EB-2010-0142, online: Ontario Energy Board <https://www.rds.oeb.ca/CMWebDrawer/Record/329716/File/document>; Re Nova Scotia Power Incorporated (4 January 2018), 2018 NSUARB 1, online: Nova Scotia Utility and Review Board <https://www.canlii.org/en/ns/nsuarb/doc/2018/2018nsuarb1/2018nsuarb1.html>.
  25. Re FortisBC Energy Inc. and FortisBC Inc. (22 June 2020), G-165-20, G-166-20, online: British Columbia Utilities Commission <www.bcuc.com/Documents/Decisions/2020/DOC_58466_2020-06-22-FortisBC-MRP-2020-2024-Decision.pdf>.
  26. Manitoba Hydro Electric Board v Manitoba Public Utilities Board, 2020 MBCA 60 [Manitoba Hydro].
  27. Dalhousie Legal Aid Service v Nova Scotia Power, 2006 NSCA 74.
  28. Re Nova Scotia Power Incorporated (7 May 2020), 2020 NSUARB 63, online: Nova Scotia Utility and Review Board <www.canlii.org/en/ns/nsuarb/doc/2020/2020nsuarb63/2020nsuarb63.html>.
  29. Re Enbridge Gas Inc. (29 October 2020), EB-2019-0294, online: Ontario Energy Board <https://www.rds.oeb.ca/CMWebDrawer/Record/691859/File/document>.
  30. Re Nova Scotia Power Incorporated (26 March 2020), 2020 NSUARB 44, online: Nova Scotia Utility and Review Board <www.canlii.org/en/ns/nsuarb/doc/2020/2020nsuarb44/2020nsuarb44.html >.
  31. Reference EMA, supra note 6.
  32. Reference re Greenhouse Gas Pollution Price Act, 2020 ABCA 74.
  33. 2019 SKCA 40, 2019 ONCA 544.
  34. Normtek Radiation Services v Alberta Environmental Appeal Board, 2020 ABCA 456.
  35. Canada (Minister of Citizenship and Immigration) v Vavilov, 2019 SCC 65
  36. Halton Hills Hydro Inc. v Ontario Energy Board, 2020 ONSC 6085.
  37. Nation Rise Wind Farm Limited Partnership v Minister of the Environment, Conservation and Parks, 2020 ONSC 2984 [Nation Rise].
  38. Yukon Energy Corporation v Yukon (Utilities Board), 2021 YKCA 1 [Yukon Energy].
  39. Planet Energy (Ontario) Corp. v Ontario Energy Board, 2020 ONSC 598.
  40. Alberta (Information and Privacy Commissioner) v Alberta Teachers’ Association, 2011 SCC 61.
  41. 2020 ABCA 163.
  42. Nation Rise Wind Farm Limited Partnership v Minister of the Environment, Conservation and Parks, 2020 ONSC 2984.
  43. Manitoba Hydro, supra note 26.
  44. Rogers Communication Canada Inc v Ontario Energy Board, 2020 ONSC 6549.
  45. Re Enbridge Gas Inc. (22 January 2021), EB-2020-0198, online: Ontario Energy Board <https://www.rds.oeb.ca/CMWebDrawer/Record/700885/File/document>.
  46. Yukon Energy, supra note 38.

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