2019: The Energy Regulation Year in Review


Canada may soon receive the worldwide prize for being the most difficult jurisdiction to build energy projects in. This is particularly the case with pipelines. In the last five years, investors have walked from four major projects. In total they accounted for over $50 billion1 in investment. Those four projects were the TransCanada Energy East pipeline, the Enbridge Northern Gateway pipeline, Trans Mountain expansion and the Teck Frontier oilsands mine located between Fort McMurray and Fort Chipewyan.

Trans Mountain was saved at the last minute when the Government of Canada made the decision to buy the pipeline for $4.5 billion. Teck Resources has regulatory approval for its proposed Frontier oil sands project and a federal cabinet decision on the project was expected at the end of February. However, just a week before the expected cabinet decision, the company withdrew the application, no doubt influenced by the blockade that was ongoing at the time on the Canadian National Railway across the country by aboriginal groups opposed to the Coastal GasLink project.

The four projects still inching forward are the Trans Mountain Expansion project (TMX), Keystone XL, Coastal GasLink and Enbridge Line 3. Before we look at the current status of those four, it is useful to examine what happened in the two failed projects, Energy East and Northern Gateway.


In April 2013, TransCanada filed an application to build the Energy East pipeline, a 4,500 km pipeline from Alberta to the east coast of Canada at a cost of $15.7 billion. The rationale was sound enough. Canada’s east coast refiners relied on imported crude for 80 per cent of their requirements. Alberta crude could replace that foreign crude.

However, things went off the rails when the National Energy Board (NEB) suspended hearings in order to rule on a motion that two panel members hearing the case were biased. Eventually the NEB agreed and replaced the two panel members. The case started over with new panel members who threw out all the decisions the previous panel had made. The real nail in the coffin was a change in government policy. The new panel issued a decision indicating that for the first time, the panel would consider in its evaluation of the project, the cost of greenhouse gas emissions resulting from the increased production and consumption of oil caused by the project. That was enough for TransCanada. In October 2017 the company canceled the project.

The Enbridge Northern Gateway pipeline also ran into unexpected and unprecedented developments. That pipeline was to run 1,178 kilometers from Bruderheim, Alberta to a marine terminal in Kitimat, B.C. and cost $7.9 billion. There were two lines at issue. One would transport 525,000 barrels per day of Alberta oil west to tidewater. The other would bring 93,000 barrels of condensate to Alberta used in processing Alberta bitumen.

The NEB joint review panel issued its report to the federal cabinet on December 19, 2013 and recommended approval subject to over 200 conditions. The federal cabinet accepted the panels’ recommendations in June 2014 and ordered the NEB to issue the necessary Certificate of Public Convenience and Necessity to start construction.

One of the conditions of the joint review panel was that Enbridge engage in consultations with the First Nations. Those consultations inched along until the Federal Court of Appeal in June 2016,2 in a 2-1 split decision, ruled that the consultations were inadequate. The Court’s decision overturned the federal cabinet’s June 14, 2013 approval of the Northern Gateway pipeline.

A second and even bigger problem resulted when the federal government decided in late 2015 to issue a moratorium on crude oil traffic off the B.C. north coast. The view by many was that the moratorium served only one purpose, namely to cancel the Northern Gateway project. It turned out they were right. Late in 2016, the federal government announced it would not approve Northern Gateway.


Four projects remain under various states of regulatory approval, Trans Mountain, Keystone XL, Coastal GasLink and Enbridge Line 3.

Trans Mountain Expansion

As indicated 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 after that on January 16, 2020, the Supreme Court of Canada unanimously dismissed the B.C. attempt to claim jurisdiction on this project3 upholding an earlier decision on B.C. Court of Appeal Decision.4

On February 4, a unanimous Federal Court of Appeal dismissed the most recent legal challenges to the project,5 which is proceeding. The Court was clear, first, that Indigenous groups have no veto and, second, that courts should defer to the government that make the initial decision on whether the duty to consult has been met.

Keystone XL

The Keystone XL pipeline, a $5 billion project, was first proposed by TransCanada in 2008 to transport oil from Canada through the Midwest and Texas to the Gulf of Mexico. The U.S. Department of State reviewed the pipeline for nearly 7 years. The Canadian portion of the line obtained NEB approval in 2010. The U.S. approval was finally obtained in late 2019.

American approval was held up by a huge environmental lobby notwithstanding the U.S. State Department January 2014 Financial Environmental Assessment that concluded that the pipeline is unlikely to significantly increase the rate of oil sands drilling or heavy crude demand. The report also found that the pipeline is only one part of the larger global greenhouse gas emissions picture and that tar sands oil will likely be extracted whether or not the pipeline is built.

In May 2012, TransCanada filed a new application for a Presidential Permit with the U.S. Department of State. That review has been held up by ongoing litigation in the Nebraska courts. In 2012, Nebraska’s governor signed into law a statute that enabled major oil pipeline carriers to obtain approval from the state’s governor for pipeline route across the state rather than from state Public Service Commission. The governor then approved the route proposed by TransCanada allowing TransCanada to exercise eminent domain to acquire the necessary land. Nebraska landowners then challenged the decision before the Commission.

In November 2014, the House of Representatives passed legislation and approved Keystone XL for the ninth time. That bill was subsequently defeated in the Senate by one vote. Midterm elections in November saw the Republicans regain a majority in both the House and Senate for the first time in 8 years. A January vote passed both the House and Senate but failed to get the 66-vote majority required to prevent a presidential veto. President Obama then exercised his veto to defeat the legislation.

TransCanada opposed the Obama veto with a constitutional challenge and a NAFTA claim. Before those could be heard, President Trump was elected. One of President Trump’s first decisions in office was to approve Keystone XL. Further regulatory challenges along the pipeline route at the state level were largely resolved in 2019. It is now expected that the pipeline will be completed.6

Coastal GasLink

The Coastal GasLink pipeline is owned and operated by TC Energy. The $6.6 billion project starts near Dawson Creek and runs approximately 420 miles southwest to a liquefaction plant near Kitimat, B.C. The pipeline passed through the traditional territories of several First Nations. It has long been opposed by several Wet’suwet’en hereditary chiefs although a number of First Nations groups support the project. In fact, twenty elected bands along the pipeline route have endorsed the project and have an ownership interest in the project.

In December 2018, the Supreme Court of B.C. granted an injunction preventing blockades of the pipeline.7 More recently, blockades have occurred across Canada led in part by Mohawks of the Bay of Quinte of Belleville in Ontario. The blockades across Canada have resulted in a nationwide stoppage of rail traffic. As a result, the pipeline has halted all construction and the Canadian National Railway has laid off 450 workers in eastern Canada and cancelled over 400 trains.

There has been one element of good news for the Coastal GasLink pipeline. In July 2019, the NEB released its decision ruling that the pipeline, including the export terminal in Kitimat, was under provincial not federal jurisdiction.8 The NEB concluded that the pipeline would transport natural gas within B.C. although it would facilitate international exports providing some clarity to the earlier Supreme Court of Canada decision in West Coast Energy.9

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 majority stake in the Coastal GasLink. The blockade was finally removed and work on the line continues.

Enbridge Line 3

The Enbridge line 3 runs from Hardisty, Alberta to Superior, Wisconsin. It 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, North Dakota and Wisconsin. However, the project ran into problems in Minnesota where environmentalists and native groups opposed the project. Nevertheless, in June 2018, the Commission approved the route and granted the necessary permits. However, that decision was overturned a year later by the Minnesota Court of Appeal that found that the environmental impact statement placed before the Commission was inadequate.10 On February 3, 2020, the Minnesota regulators approved a revised environmental review resolving the last regulatory hurdle for the project.11


Amidst the challenging outlook for energy development projects, a significant decision allowing a proposed deep-water drilling project offshore from Newfoundland and Labrador to proceed came as welcome news late in the year. On December 17, 2019, the Minister of Environment issued his decision, subject to more than 100 conditions, that the project is not likely to cause significant adverse environmental effects. The CNOOC International Flemish Pass Exploration Drilling Project proposes drilling on two exploration licences. The proponent could drill up to 10 offshore wells between 2020 and 2028. Further approvals are required from the Canada-Newfoundland and Labrador Offshore Petroleum Board. The licences are located more than 200 nautical miles offshore and, therefore, any commercial production would trigger Canada’s obligation under the United Nations Convention on the Law of the Sea (UNCLOS III) to make payments to the international community, commencing in the sixth year of production and rising annually to 7 per cent in the 12th year.12

Earlier in the year, however, the future of Canada’s northern offshore oil and gas industry was cast in doubt by the passage of Bill C-88, which, inter alia, amended the Canada Petroleum Resources Act13 to authorize the Governor in Council to prohibit certain works or activities on federal Crown lands in the North and in the Arctic offshore when in the national interest. The amendment followed from the joint U.S.-Canada announcement in December 2016 that offshore oil and gas activity in Canadian Arctic waters would not be authorized indefinitely, to be reviewed every five years with a science-based assessment. Holders of existing licences were not permitted to undertake activities and the government returned $430 million in security deposits. Although activities cannot be undertaken, the licences remain in place. The Mayor of Tuktoyaktuk described these developments as “put[ting] the nail in the coffin” of any further exploration in the Beaufort Sea.14 Meanwhile, Russia is pushing ahead with an ambitious plan to develop Arctic oil worth more than $300 billion.15


The Alberta Capacity Market

On November 23, 2016,16 the Government of Alberta announced that Alberta would implement a capacity market. The Alberta Electric System Operator (AESO) filed an application for the approval of rules to implement the capacity market on January 31, 2019. An oral hearing was held by the Alberta Utilities Commission (AUC) from April 22, 2019 to June 11, 2019.

The opponents argued that the capacity market and the rules the AESO proposed to operate that market were not in the public interest and that the application should be rejected in its entirety. There were three main grounds to the arguments:

  • The proposal was based on provisional rules, which do not create the certainty necessary to encourage investment.
  • There is no need for a capacity market and the uncertainty of a new and complicated regulatory process would have been sure to bring. The analysis that the AESO presented in support of the initial capacity market recommendation was flawed.
  • Improvements to the energy market, in particular the implementation of shortage pricing that was recommended by three experts in the AUC’s proceeding, should be implemented instead.

On July 24, 2019, the Government of Alberta announced that Alberta would not be proceeding with a capacity market, and that the industry would remain with an energy-only design before the AUC could reach a decision. On the government’s instructions, the AESO withdrew the application before the AUC.

In late July 2019, the AESO received direction from the Alberta Ministry of Energy:

…to provide advice regarding market power and market power mitigation by November 29, 2019. Additionally the AESO was directed to provide any analysis and recommendations on whether any changes to the energy only market are needed, including changes to the price floor/ceiling and shortage pricing, by July 31, 2020. The AESO recognizes that there is a strong linkage between market power mitigation, the price floor/ceiling and shortage pricing, and will consider this connection as it undertakes its work.17

On October 8, 2019, the AESO issued a request for input from the Market Surveillance Administrator, market participants, and other interested parties on market power mitigation due by October 29, 2019. The AESO provided a report to the Minister by November 29, 2019, which has not been made public.

On February 12, 2020, the AESO held a stakeholder consultation. Comments are due by February 26, 2020 on the 10 questions listed in Appendix A. The AESO’s objectives18 are to:

evaluate the ability of the current pricing framework in the energy market to maintain resource adequacy and economic efficiency in both the short and long term, and explore options to address deficiencies or increase efficiency in the current energy-only market pricing framework. Administrative price mechanisms, such as the current price cap, offer cap and price floor, must be set at levels to allow for efficient market outcomes while also protecting consumers from cost risk.19

A New Federal Regulator

Early in 2018, the federal government introduced Bill C-69,20 new legislation that would replace the National Energy Board with the Canadian Energy Regulator (“CER”). The CER is much more complex than the NEB because its scope is much greater and its jurisdiction goes beyond federally regulated pipelines and includes potential offshore renewable energy projects.

There are now four institutional components to the regulatory framework. First is the Board of Directors of the CER that is responsible for providing strategic direction and advice. Second, is the Commission of the CER, the members of which will conduct hearings. Third, and most critically, is the Chief Executive Officer who is responsible for the management of the CER’s day-to-day business and affairs. The CEO reports to the Minister, not the Board of Directors. Fourth, is the federal cabinet, which will make decisions based on the recommendations of the Commission of the CER.

To complicate matters, the factors that this new institution must consider are much wider than the NEB ever faced, or for that matter, any Canadian energy regulator currently faces. The new legislation requires that the review process must consider environmental, gender, and Indigenous considerations or what is described as the intersection of sex and gender with other identity factors including Canada’s ability to meet its environmental obligations and its commitments with respect to climate change. All that will keep the industry guessing for years.

Two articles in the Energy Regulation Quarterly have been very critical of the governance structure created by Bill C-69. The first article is by the current chief executive officer of the AUC.21 The second article, in this issue of ERQ, is by the former chair of the Alberta Energy Resources and Conservation Board and two former members of the NEB.22

The first decision by the Canadian Energy Regulator was handed down on September 7, 2019. The decision concerns the Enbridge mainline system, the largest crude oil pipeline in Canada with the capacity of almost 3 million barrels per day. It connects Edmonton, Alberta with major markets in eastern Canada and US Midwest. This line is currently operated as a common carrier rather than on a contract carriage basis. Under the common carrier model, capacity is allocated on the basis of monthly nominations rather than long term contracts. Common carriage has, in effect, been required on federal oil pipelines since the NEB was established in 1959, subject to the ability of the NEB, and now the Commission, to grant exceptions.

At issue is the decision by Enbridge to change its operations from a common carrier model to a contract carriage model whereby 90 per cent of the capacity will be under long term contracts with the remaining 10 per cent allocated on the traditional basis. The Alberta shippers are split in their affiliation with some supporting the new regime and others opposed.

The main concern argued by opponents of the changes proposed by Enbridge is that Enbridge will be abusing its market power. The allegation is that there will be under the new regime a lack of transportation options for many shippers. The CER observed in its initial decision that the Enbridge system controlled 70 per cent of capacity out of Alberta and that it was concerned about the perception of abuse of Enbridge’s market power.

On December 19, 2019, Enbridge filed a comprehensive “Canadian Mainline Contracting Application” with the CER for approval of a new service and tolling framework, to take effect on the expiration of the current service and tolling framework on June 30, 2021. The proposed new framework would convert 90 per cent of capacity to contract carriage, with 10 per cent reserved for uncommitted volumes. The Commission of the CER has announced that it will conduct an oral hearing on the application commencing on a date to be announced.23

The Ontario Energy Board

The province of Ontario elected a Conservative government on June 2018 replacing the Liberal government that had governed the province for 15 years. One of the major election issues was the Conservative Party’s criticism of the Liberal government with respect to managing energy policy in the province largely based on the claim that Ontario’s electricity prices had increased by 71 per cent between 2008 and 2016 while, during this period, the average increase across Canada was less than half of that amount, or 34 per cent. The new government concentrated on abolishing the green energy projects developed by the liberals including a number of renewable energy projects. In March of 2019, the new government turned its attention to reforming energy regulation in general and the Ontario Energy Board (OEB) in particular.

On March 21, 2019, the Ontario government introduced the Ontario Energy Board Act.24 Some of the changes were to be implemented through proposed legislative amendments set out in Bill 87.25 Other changes were implemented through regulatory and policy updates. Bill 87 was passed by the Ontario government on May 9.26 Among other things, it amended the OEB’s governance structure and operations. These changes were based on the Ontario Energy Board Modernization Report.27

Like the federal reforms, the OEB will now be governed by a Board of Directors with a chief commissioner reporting directly to the chair of the Board. The report recommends necessary changes to ensure that the Board operates more effectively, in particular that it prioritizes its regulatory agenda and be evaluated against key performance indicators that relate to matters such as decision time cycle, stakeholder satisfaction and organizational excellence.

The concern is that the Board of Directors will be charged with “ensuring the independence…of the adjudication process.” However, the President and the Board of Directors can be expected to have a close relationship with the government, and it is the government that is the source of challenges to independence.

The report does not address perhaps the largest problem in the sector, which is the lack of regulatory oversight of procurement of capacity. This problem and its financial consequences have been noted by the Auditor General. The Report does not address how the OEB’s mandate should be changed to provide oversight. Ontario is one of the very few jurisdictions without oversight over procurement and the cost consequences have been devastating.

To date, the new government has appointed a board chair but is still searching for a chief commissioner. As in the case of the CER, there has been considerable criticism of the new structure, but only time will tell if it works. The main criticism of course is that the energy regulator is no longer independent of the government. Of course, others will argue it never was independent in any event.


In 2019, regulatory commissions across Canada were struggling to define the regulatory treatment for Distributed Energy Resources or DERS. In Alberta, the subject is being reviewed by both the AUC and the AESO in parallel.28

Virtually all studies focus on at least three major issues: customer owned generation, energy storage and Electric Vehicle (EV) charging. Each are considered below.

On March 29, 2019, the AUC established a Distribution System Inquiry asking market participants to make submissions relating to:

emerging trends in technology and innovation potentially affecting distribution systems, including distribution system design, operation, capital requirements and the cost of providing service. This module will also consider how innovation and technological change create the opportunity for new market entry within a monopoly franchise, including self-supply.29

This proceeding is ongoing. Future phases will consider the following questions:

  • Is there under-investment in certain key technologies in the Alberta electricity distribution sector?
  • Would additional investment make the Alberta electricity distribution sector more cost effective?
  • Is the electricity local distribution company an important instrument of change?
  • Are there regulatory barriers to innovation and new technologies? and
  • How should the regulatory framework be transformed in order to increase investment and efficiency in the Alberta electricity distribution sector?

DERs are also under consideration by the OEB: 30

  • On March 15, 2019, the OEB announced that it was starting a consultation process to look at how the electricity sector in Ontario should respond to DERs and encourage utilities and regulated service providers to “embrace innovation” in their operations and customer service. The stated aims of the consultation were to drive lower costs, improve service and offer more consumer choice “by encouraging utilities and other service providers to embrace innovation,” and to “secure the benefits of sector transformation and mitigate any adverse consequences.”31
  • On July 17, the OEB issued a letter explaining its “refreshed” approach to stakeholder engagement for its previously-announced consultation processes on Utility Remuneration and Responding to DERs. Among other things, the OEB’s updated approach was intended to “enhance the opportunity for stakeholder perspectives to inform subsequent steps in relation to these initiatives following the OEB’s transition to its new structure.”32
  • On August 13, the OEB issued a letter launching a review of the requirements for licensed electricity distributors to connect distributed energy resources (DER Connections Review). The DER Connections Review is a companion initiative to the OEB’s ongoing Responding to DERS consultation.33

The OEB has heard from stakeholders about what should be addressed in the Responding to DERs consultation. OEB staff will provide a report describing stakeholder perspectives and setting out a proposal outlining objectives, issues and guiding principles for the Responding to DERs consultation to proceed. However, before that report is issued, OEB staff has convened an additional session (in February 2020) where they will outline and seek input on OEB staff’s current thinking of the scope of the consultation.

Customer-Owned Generation

The last 10 years have seen a dramatic increase in local generation compared to central generation. New technology is made it possible to locate generation closer to the customers it serves reducing transmission costs including line losses. The technology at issue is mostly gas generation, known as CHP and solar generation. The attraction of both technologies is driven by a rapid reduction in cost over this timeframe. For example in 2019, the AUC grated approval for a 500 MW solar project, the largest of its kind in Canada. That facility once completed in 2021 will generate 400 MW, enough to supply power to over 100,000 homes.

The important regulatory issues faced in customer-owned generation are:

  • Should community generation be limited to behind-the-fence operations?
  • Should community generators have access to regulated electric Local Distribution Company (LDC) lines to distribute electricity within the LDC service area?
  • Should regulated electric LDCs be allowed to offer local generation as a rate-based service? If so, what measures are necessary to protect competing suppliers?
  • Should community generators be allowed to sell excess power to the grid? If so, on what terms?

Under Alberta’s Micro-generation Regulation, eligible alternative and renewable generators are allowed to receive credit for any power they send to the grid. In Alberta, micro-generation facilities are defined to be less than 5 MW in size.

The latest data from the AESO (May 2019) show that there is approximately 48.7 MW of micro-generation capacity installed in Alberta, about 89 per cent of which is solar. This is up from less than 6 MW five years earlier, an increase of approximately 8 times.

In Ontario, there has been substantial investment in distributed energy resources over the past 15 years. Much of this investment has been made by investors under contracts with a government entity, first the Ontario Power Authority and now the Independent Electricity System Operator. There are 33,671 contracts that have a total capacity of 3,588.8 MW that accounts for 13.4 per cent of total capacity as of March 31, 2019.34 The prices in these contracts were set in a variety of ways, including competitive bidding, standard offers (for example, under Feed-in-Tariff programs), and negotiations. These data do not include more than 30,000 “microFIT” contracts (maximum of 10 kW capacity) that have a total capacity of about 260 MW, virtually all of which is solar.

In both Alberta and Ontario, the generic proceedings have to some degree been overtaken by more specific proceedings arising in rate cases and related matters. The leading example is Alberta where In September 2019, the AUC launched a consultation on generation self-supply and power export.35 The consultation was prompted by three recent decisions36 in which the AUC for the first time restricted the circumstances in which the owner of a generating unit is allowed to both consume electricity produced by that unit on its own property and export that electricity to the power pool. The existing exemptions that permit the self-supply and export of electricity to the power pool are related to (i) owners of industrial systems and (ii) micro-generators.37 Currently, these type of generators account for approximately 5,000 MW38 of generation capacity out of 15,570 MW of capacity in Alberta.39 This is a significantly greater proportion than exists elsewhere in Canada.40

The Bulletin asked respondents to address three options:

  • Option 1: Status Quo;
  • Option 2: Limited self-supply and export; and
  • Option 3: Unlimited self-supply and export.

The consultation attracted considerable interest; 33 stakeholders submitted comments in response. Most of them favoured Option 3. In January 2020, the AUC issued a second Bulletin41 that requested parties to comment on submissions provided by two of the respondents, Capital Power and AltaLink.

The parties were asked in the Commission’s January 9, 2020 Bulletin to respond to the concerns raised by Capital Power as follows:42

Allowing an exemption for some energy reduces the amount of supply competing to be dispatched. Further, an expanded amount of self-supply and export reduces market visibility of both available supply and load to be served inhibiting price discovery. Exempting supply or some energy from pool participation reduces the effectiveness of and benefits from having a competitive market.

The MSA, one of the interveners, argued that in effect, there are two related markets: the self-supply market and the non-self-supply market. The latter is the Power Pool. Both have existed for some time.

If the Commission adopts option 3, “unlimited self-supply and export,” it is likely that the self-supply market will expand. That will not necessarily reduce the size of the non-self-supply market or the degree of competition between those suppliers. It will, however, expand the options available to consumers in Alberta and that will increase competition in that segment of the market. Further, customer-owned generation that does not have a legislated exemption from participating in the power pool (e.g., industrial systems and micro-generation)43 could easily be required to explicitly participate in the power pool by making offers and receiving dispatch. The MSA remains of the view that option 3 will increase competition not decrease it.

The MSA does not believe it is necessary that the generator be behind-the-fence. Nor should community generation be disadvantaged. The fact that the generator is owned by several customers as opposed to one customer should not matter if the cost allocation for rates is done correctly. There are cost allocation issues with respect to a single customer behind-the-fence generator. Those same issues exist where a community generator serves a number of customers.

Another question that should be addressed is whether the local generation facility must be owned by a consumer or whether it can be owned by a third-party. The MSA believes that the local generation market should be open to third parties. This will increase competition, which will support fair, efficient, and open competition.44

Local generation can bring a number of economies and benefits to the Alberta electricity system. They are, by definition, closer to the customer and transmission, and distribution costs are reduced.

Local generation is the product of new, more efficient technology that did not exist when much of the current regulatory framework was put in place. This new technology offers significant cost reductions. The Commission should remove, not create, artificial barriers to entry.

Local generation, including community generation, constitutes a form of market entry. New market entry has been central to the competitiveness of Alberta’s electricity market. Entry not only constrains the exercise of market power in generation, but can also promote productivity improvements in the distribution industry.

New entry is particularly important in Alberta at the present time. The Power Purchase Arrangements will come to an end in one year, and it is generally agreed that their expiration will lead to increased concentration and market power in Alberta. New entry through customer-owned generation will reduce market concentration.

The discussions concerning customer-owned generation can also lead to a similar analysis on customer-owned storage. In part, this is driven by the FERC decision in 2018 in Order 841, which ruled that storage is a generation asset. In the end, the real issue with respect to customer-owned generation is not whether it should be allowed but whether it should be restricted to behind-the-meter applications, generation owned by customers as opposed to third parties and what rates these generators should pay to transmitters and distributors who provide grid access when they wish to sell excess power to the grid.

All of those issues are currently in front of the Alberta Utilities Commission, which will provide a recommendation to the government by the end of March 2020.

Energy Storage

Regulatory agencies across Canada have all been trying to promote storage over the last few years. There is good reason for this: first energy infrastructure is built to handle peak loads. If the peaks can be reduced the related capital investments can be reduced with cost savings.

Secondly, the generation of electricity worldwide is moving from carbon based energy to green energy. One significant different between the two is green energy like wind and solar is highly variable. Not surprisingly, planners have discovered the advantage of marrying solar plus storage in particular as outlined in a recent Brattle study in December 2019.45

The other rationale that is stimulating demand is the growth of Behind-the-Meter (BTM) storage as customers attempt to curtail their costs. BTM energy storage today represents only 70 MW or 15 per cent of the U.S. energy storage market. By 2022, it will represent 1300 MW or 30 per cent of the market.46 There are significant similarities between local generation and local storage. Both may be customer owned and can offer excess capacity to other customers. This service will increase efficiency in the Alberta energy sector and bring significant cost savings.

The next important factor driving this demand is recognition by utilities that storage can be an important grid asset to reduce costs. This was fueled at least in the US by the FERC order 841, which was confirmed in 2019 after it was appealed. The FERC in the U.S. in Order 84147 confirmed in Order 841-A48 ruled that storage is a generation asset.

BTM storage is an issue in the recent consultation initiated by the AUC.49 It was also addressed in the recent Toronto hydro rate case,50 where Toronto Hydro attempted to include storage in its rate base. That request was turned down by the Ontario Energy Board which concluded that the matter be deferred to the boards DERS consultation underway.51

Finally, it is important to recognize the significant decreased in cost that has taken place in the storage markets over the last few years. Between 2010 and 2018, the average price of a lithium ion battery pack dropped from $1,160 per kilowatt-hour to $176 per kilowatt-hour — an 85 per cent reduction in just eight years. Within the next few years, Bloomberg New Energy Finance predicts a further drop to $94 per kilowatt-hour in 2024 and $62 per kilowatt-hour in 2030.

It has been suggested by Bloomberg New Energy Finance that the global energy storage market will grow to 2,857 GWh by 2040 and attract over $620 billion in investment over the next 20 years. In Ontario, the IESO has used a number of competitive processes to develop over 25 storage projects resulting in over 50 MW of capacity. In December 2018, the IESO published a report titled Removing Obstacles for Storage Resources in Ontario.52 This was followed by an OEB initiative in March 2019 to similar effect and a study by Energy Storage Canada in May 2019 entitled Maximizing Value and Efficiency through Energy Storage.53 This was in some respects similar to the Alberta Electric System Operator (AESO) study a year earlier called Dispatchable Renewables and Energy storage.54

Electric Vehicle Charging

The total number of Electric Vehicles (EVs) on the road globally reached 3.1 million in 2017, up 50 per cent from the previous year. China and the US had the highest sales volume in 2017. Norway is the world leader in terms of sales share with EVs accounting for more than 39 per cent of new sales in 2017. Nine countries, including France, the U.K., and Norway, have plans to phase out all gasoline-powered vehicles between 2025 and 2050.

Although just 2.2 per cent of the world’s vehicles are electric, a record 2.2 million EV were sold last year. Bloomberg New Energy Finance (BNEF) predicts that EVs will reach 19 per cent of light vehicle sales in China by 2025 compared to 14 per cent in Europe and 11 per cent in the U.S. Currently, those numbers are 4 per cent in China, 2 per cent in Europe, and 2 per cent in the U.S. BNEF predicts that EVs will reach 55 per cent of global vehicle sales by 2040. It is estimated that by 2020, the price of EVs in Europe will be less than the price of internal combustion engine vehicles. That goal will be reached in China by 2023 and in the U.S. by 2025.

In United States, Edison Electric Institute (EEI) estimates that by 2030 the number of EVs in the U.S. will reach 18.7 million compared to 1 million at the end of 2018. It took 8 years to sell 1 million EVs in the U.S. and EEI predicts that the next 1 million will be sold in 3 years. It is predicted that the annual sales of EVs in the U.S. will exceed 3.5 million in 2030, accounting for more than 20 per cent of annual vehicle sales. It should also be noted that it is estimated that 9.6 million charging ports will be required to support the 18.7 million EVs in the U.S. in 2030.

Canada has experienced significant expansion in EVs with Ontario, Quebec, and British Columbia accounting for 97 per cent of all plug-in vehicles sold in Canada between 2013 and 2018. Between 2017 and 2018 sales increased by 80 per cent with the result that the national EV market share is now 2.5 per cent compared to less than 1 per cent in 2017. Sales in Ontario by the end of 2018 were more than 6,000, a 209 per cent increase over the same period in 2017. Ontario accounts for 44 per cent of all new EV sales in Canada.

The recent phase 2 report by the British Columbia Utilities Commission in its Electric Vehicle Service Inquiry (June 2019) sets out an excellent review of the current Canadian situation, stating:55

Due to initiatives by the federal, provincial, and municipal governments, as well as utilities and private firms, public charging infrastructure is continuing to grow in Canada. By the end of December 2017, there were approximately 5,843 EV charging stations in Canada, of which 5,168 were Level 2, 483 DCFC, and 190 Tesla Superchargers. This represented a 38 per cent increase in public charging infrastructure installations across Canada in 2017 compared to 2016.56

Recent private sector developments include the formation of Electrify Canada, a partnership formed by Electrify America in cooperation with Volkswagen Group Canada to build DCFC infrastructure, in July 2018. It plans to build 32 fast charging stations in southern B.C., Ontario, and Quebec, with operations expected to start mid-2019.57 In February 2019, PetroCanada announced it is building a network of 50 DC fast chargers across Canada from Halifax, Nova Scotia, to Vancouver, with the first station opened in Ontario.58

Federal initiatives have been led by Natural Resources Canada (NRCan), in collaboration with a variety of other partners, which has supported the construction of more than 500 EV fast chargers to date.59 In 2017, NRCan collaborated with three private companies in 2017 to install 34 fast-charging stations along the Trans-Canada Highway in Ontario and Manitoba.60 NRCan’s ongoing Electric Vehicle and Alternative Fuel Infrastructure Deployment Initiative (NRCan EV Initiative) offers repayable contributions to support the construction of a coast to coast EV fast charging network. The NRCan EV Initiative will pay up to 50 per cent of the total project costs to a maximum of fifty thousand dollars ($50,000) per charging unit.61 BC Hydro received funding for 21 stations under its Phase 1 implementation, out of a national total of 102.

At the provincial level, the Governments of Ontario, Quebec and B.C. have actively supported the development of EV charging infrastructure.62 Hydro-Quebec’s Electric Circuit, launched in 2012, was Canada’s first public charging network for EVs, offering both 240-volt and 400-volt charging stations. By early 2019, the Circuit included 1,700 stations, including 176 fast charging stations.63 The stations are installed in the parking lots of the Circuit’s numerous partners across Québec and in the North-East of Ontario, and operated by Hydro-Quebec. In 2019, Hydro Quebec announced it had received funding for 100 new stations from the Federal government to be installed before the end of 2019 and have long-term plans to build 1600 fast charging stations over the next 10 years.64

In Alberta, the NRCan EV Initiative supported an initial three EV fast charging stations at Canadian Tire locations in 2017,65 while in February 2019 the Alberta Government announced plans to provide $1.2 million to co-fund the Peak to Prairies EV network, in collaboration with local partners, and the Federation of Canadian Municipalities. The network will consist of 20 fast charging stations that will be installed across southern Alberta by the end of 2019. Long-term ownership and operation of the charging infrastructure will be carried out by ATCO.66

A variety of regulatory models are used in other jurisdictions. Ontario, California, Washington, Oregon, New York, and a number of other U.S. states exempt EV charging from energy regulation. Re-sale of electricity is permitted without prior approval, and prices are set by the market. British Columbia and some other U.S. states require EV charging service providers to become public utilities, subject to all other aspects of energy regulation, including pricing.

Some jurisdictions allow public utilities to provide EV charging services and recover costs through rates. Other jurisdictions do not allow public utilities to deliver EV charging services or only allow them to deliver EV charging services as a non-rate-based venture.

The status of EV charging in a variety of North American jurisdictions is surveyed below.

British Columbia

On November 26, 2018, the British Columbia Utilities Commission (BCUC) issued its Phase I Report from its Inquiry into the Regulation of Electric Vehicle Charging Service.67 In this Report, the BCUC found that the public EV charging market does not exhibit monopoly characteristics and economic regulation is not required to protect consumers. The BCUC recommends that the B.C. Government issue an exemption with respect to the BCUC’s regulation of EV charging services, but retain oversight of safety.

The BCUC’s Inquiry evolved out of an application by FortisBC Inc. for approval of an EV charging rate for service at FortisBC-owned charging stations. The BCUC approved the requested rate on an interim basis in January 2018, but also adjourned the FortisBC application in favour of conducting the general inquiry into whether and how EV charging in British Columbia should be regulated.

The Phase 2 inquiry focused on non-exempt public utilities (BC Hydro and FortisBC) and found that there is no obligation on non-exempt utilities to build charging stations.


In 2018, California authorized the state’s three investor-owned utilities to recover $738 million for EV charging infrastructure. San Diego Gas & Electric adopted a $137 million rebate program for 60,000 Level 2 home-based charging stations (240V chargers similar to an electric dryer or oven) and an EV-only variable hourly energy rate. Pacific Gas and Electric adopted a $22 million program supporting 234 fast-charging stations at 52 sites and make-ready infrastructure at a minimum of 700 sites to support the electrification of at least 6,500 medium- or heavy-duty vehicles. Southern California Edison adopted a $343 million program to install the make-ready infrastructure at a minimum of 870 sites to support the electrification of at least 8,490 medium- or heavy-duty vehicles and three new time-of-use rates for commercial customers with EVs.

Nova Scotia

In Nova Scotia, the Utility and Review Board denied a request from Nova Scotia Power Incorporated to recover from ratepayers the cost of purchasing and installing 12 EV fast charging stations at locations across Nova Scotia, as the board found that EV charging stations are similar to other equipment on customers’ premises and need not be ratepayer assets.68


Ontario regulators have not been kind to EV charging. In 2012, the Ontario Energy Board denied a request for $600,000 to fund an electric vehicle pilot project.69 The impetus for the application was the Ontario Government’s 2009 pronouncement that 1 in 20 vehicles would be electric by 2020.70 Toronto Hydro proposed that it would use the money to install and monitor between 30 and 40 EV charging stations in the city. The OEB allowed $200,000 in cost associated with this activity provided the money was not used to fund a provision of the service to the public. The Ontario Energy Board cautioned that policy development regarding ownership and operation of EV charging had yet to take place and it was premature to conclude the charging infrastructure should be included in Toronto Hydro’s rate base.

That argument was repeated in 2019 in the Toronto Hydro application for 2020-2024 electric distribution rates and charges. Again, the OEB concluded that the decision71 was premature and the matter should be deferred to the ongoing inquiry by the board with respect to distribution energy resources. It should be added that one of the things the new conservative government did when they came to power was to cancel electric vehicle incentive program and the rebates for EV purchases that the previous liberal government had implemented.


Most Canadian energy regulators have some responsibility to monitor and penalize breaches of reliability standards. In Ontario, by way of example, those responsibilities fall to the Independent Electricity System Operator72 although the Ontario Energy Board has some oversight.73 In Alberta, it is the AESO’s responsibility to propose the reliability standards for approval by the Alberta Utilities Commission based on standards set by the North American Electric Reliability Corporation (NERC). The AESO conducts audits on the market participants and refers suspected contraventions to the MSA, which can issue specified penalties defined by the AUC. The complexity of this regulatory regime increased more recently with the introduction of the Critical Infrastructure Protection standards or CIP74 introduced by the NERC in 2010. They were adopted in Ontario in 2016 and in Alberta in 2017.

The CIP standards have introduced a new complexity and for the most part concern cyber security risks. The most recent example is a closing of an unnamed American pipeline based on a cyber-attack.75

In 2017, for the first time, Canadian regulator established a regulatory hearing to deal with certain issues relating to these new cyber security standards. The proceeding was prompted by a submission by the MSA to the Commission in October 29, 2019 in connection to the Commission’s 2019-2022 Strategic Plan. The particular issues raised concern with the use of guidelines that have been established by NERC but are not in use in Alberta, and the degree of publicity that should be attached to the penalties or fines awarded by the MSA with respect to breaches of the cyber security standards by market participants and the AESO. In Alberta, the MSA has the unique responsibility for auditing the AESO. The AUC Rules relating to these standards require the MSA to publicly post the specified penalties it issues. The MSA has refrained from doing so because of security risks. This same issue concerns American regulatory authorities. A joint staff white paper regarding penalty disclosures was released in 2019 by FERC and NERC.76

Critical Infrastructure Protection (CIP)

The Critical Infrastructure Protection (CIP) Standards were first introduced by the North American Electric Reliability Corporation (NERC) in 2010 and became effective in Alberta in 2017. Today, there are 11 CIP standards, which set out cyber security requirements to protect the bulk power system.

Canadian regulators have faced regulatory challenges under these new CIP standards. Compared to the traditional reliability standards that the market participants have been dealing with since 2010, the CIP standards are much more complicated and the security risks they address are more significant. As a result, there is a significant backlog in Alberta and other Canadian jurisdictions.

Cyber security is a rapidly evolving field in any industry, not just electricity. As a result, the NERC CIP standards are evolving at a pace that far exceeds the development pace of the other NERC Standards. Since 2010, NERC has moved from version 0 to version 6 which is currently in effect. Version 7 and 8 of some of the CIP standards will be effective in 2020.

Alberta adopted version 5 as its first version of the CIP Standards with an effective date of 2017. The AESO has chosen to adopt the CIP standards as close to “as is” as possible. However, there are certain elements that have been removed from the NERC CIP Standards in Alberta, for example the Table of Compliance Elements and the Guidelines and Technical Basis.

Across North America, the adoption of the first version of the CIP standards or significant changes to the content with new versions of the CIP standards has typically resulted in a significant increase in reported potential violations, either self-reported or determined through monitoring. This is generally attributed to the relatively new concepts that are being introduced to the electric industry through the standards and the complexity of the CIP standards.

The Alberta Consultation

In Alberta, the MSA proposed significant rule changes involving Sanction Guidelines developed by NERC that can reduce the cost and delays related to CIP standards being incurred by both the MSA and market participants. On October 29, 2019, the MSA asked the AUC to hold a consultation to resolve a number of outstanding issues. That submission was made in a proceeding the AUC established to review its 2019-2022 Strategic Plan.

The consultation asked market participants to respond to the following questions:77

  • Should AUC Rule 027 be amended to allow the MSA to rely on NERC Sanction Guidelines in determining specified penalties for breaches of the CIP reliability standards?
  • Should AUC Rule 027 be amended to allow the MSA to rely on NERC’s Table of Compliance Elements to determine the severity of breaches of CIP reliability standards?
  • Should the MSA be authorized to make preliminary determinations of breaches of CIP reliability standards to be followed by a review procedure conducted by the MSA before making a final determination?

This consultation was announced on January 31 and interested parties are expected to file their submissions by February 29.

The Disclosure Problem

AUC Rule 027 requires the MSA to publish any specified penalty issued for a contravention of a reliability standard no later than 45 days after the penalty has been issued and post the penalty to the MSA’s website.

There is, however, a wide-ranging controversy in Canada and the United States about whether this provision is appropriate in the case of CIP penalties. The CIP penalties relate mainly to cyber security breaches, which can result from deliberate attempts by third parties to damage critical infrastructure. The question is whether the publication contemplated would assist those third parties in targeting certain facilities that have been found to have inadequate protection. The MSA has on previous occasions advised the AUC of its concerns in this regard. To date, the MSA has not published any CIP breaches on its website awaiting further clarification from the Commission.

More recently, a Joint Staff White Paper has been published by FERC and NERC.78 Those agencies are currently carrying out a consultation on this matter. There may be merit in the Alberta approach on publication of CIP breaches complying with the U.S. approach that is ultimately determined.

The MSA has proposed that a consultation be held to address the following question:

  • Should AUC Rule 027 be amendehe argument that assets purchased are red to limit the publication of breaches of CIP reliability standards to the publication standard proposed by the Joint FERC-NERC Staff White Paper?

The Commission has indicated that a process outlining a consultation to deal with this issue will be developed shortly.


The B.C. Alberta Blockade

Earlier in this report, we discussed the opposition to the Trans Mountain expansion project to expand capacity by twinning the existing pipeline system with 987 kilometers of new pipe to transport oil sands production from Edmonton, Alberta to Burnaby, B.C. The project includes an expanded marine terminal in Burnaby with a significant increase in tanker traffic under the Lions Gate Bridge.

That led to fierce opposition from the Mayor of Burnaby and Premier of B.C. The province in an attempt to stop the project, proposed an amendment to the Environmental Management Act.79 Alberta objected on the basis that the act was unconstitutional because it interfered with the federal government’s exclusive jurisdiction over interprovincial pipelines. The British Columbia Court of Appeal agreed.80 B.C. then appealed to the Supreme Court of Canada, which upheld the British Columbia Court of Appeal decision.81 The Chief Justice read a unanimous decision from the bench dismissing the case on the same basis as the British Columbia Court of Appeal. It took the Court 10 minutes to reach this decision.

Before the court decisions, Alberta had struck back indicating that it was not going to buy B.C. wine or electricity from the new B.C. Site C hydro facility. Alberta was also going to stop supplying gas to heat B.C. homes. A temporary injunction was obtained. This blockage has also ceased with the recent Supreme Court of Canada decision on January 16, 2020.

The Carbon War

While the B.C. and Alberta governments were fighting with each other, the provinces of Alberta, Ontario, New Brunswick and Saskatchewan were fighting with the federal government regarding the federal government’s proposed carbon tax. The federal government had enacted legislation requiring each province to legislate a carbon tax meeting certain standards. For those provinces that refused, the federal government would impose its own mandatory pricing carbon scheme on that province.

The opposition of the provinces was threefold; first, they did not believe the carbon tax would be effective. Second, they felt it imposed significant cost on commuters that drive to work every day. Third, they believed it was unconstitutional.

During 2019, the cases wound their ways through the courts. In May 2019, the Saskatchewan Court of Appeal issued a 3-2 majority decision82 that found that the federal government did have the constitutional authority to implement a carbon tax. A month later, in June, the Ontario Court of Appeal, in a 4-1 majority decision, came to the same result. Both decisions found that the federal carbon tax legislation was a valid exercise of the federal governments’ authority under the federal governments’ peace, order and good government authority indicating constitution.

Ontario and Saskatchewan have both appealed those decisions to the Supreme Court of Canada, which will be likely heard in April 2020. To confuse matters, the Alberta Court of Appeal ruled on February 24, 2020 that the Carbon Tax was unconstitutional.83

This was a 4-1 decision led by the Chief Justice of the province. The Alberta decision does a good job of explaining the differences between the Alberta court and the courts in Ontario and Saskatchewan that found the legislation to be within federal jurisdiction. It turns out that it depends on how you define or characterize the carbon tax. The Alberta Court of Appeal understandably said the carbon tax was a policy instrument that regulated natural resources in the province. The Alberta Court of Appeal understandably relied on Section 92A, which provides that natural resources are exclusive provincial jurisdiction. The logic was straightforward; Alberta is a one-industry province. That industry relates to the exploration and development of the generation and transportation of oil and gas. The proposed federal tax was aimed only at that industry. The Ontario and Saskatchewan decisions have relied on the broad national concern doctrine under the federal parliament’s peace, order and good government power. The Chief Justice found that the regulation of greenhouse gas emission does not fall within this doctrine and noted that the application of interjurisdictional immunity was rarely relied upon by the courts and had been used in only three cases in the entire history of constitutional litigation. Other justices argue that this legislation was a Trojan horse, which would allow the federal government to exercise control over virtually anything that traditionally fell within provincial jurisdiction. This matter will now go to the Supreme Court of Canada, which will hear all three cases together on March 24, 2020.

In the meantime, the provinces of New Brunswick and Prince Edward Island have struck a strange deal with the Federal government. They proposed that they would enact the federal government carbon tax but eliminate a tax in the same amount that each province currently had in place to pay for highways in the province.

It turns out that the federal government was going to give the provinces the money it received from the carbon tax, so the provinces were revenue neutral under this initiative. What this new scheme did to reduce carbon in these provinces may be a mystery to some.

Stranded Assets Revisited

In 2016, a wild fire destroyed most of Fort McMurray Alberta. In 2019, three companies, ATCO Gas, ATCO Electric Transmission and ATCO Electric Distribution, brought applications to the AUC to recover approximately $5 million for assets destroyed in the fire. In the three decisions,84 the Commission approved or disallowed recovery based upon the Commission’s Utility Asset Disposition (UAD) principles related to stranded assets as set out in the Stores Block decision.85 There were important descents and warnings about “the possible deleterious effects” of this principle with the commission calling for a “debate on the evolution of public utility regulation in Alberta”.

This regulatory uncertainty has a long and interesting history. In 2013, the AUC issued what is known as Utility Asset Disposition decision.86 It was one of several decisions building on and interpreting the Supreme Court of Canada’s Stores Block decision.

The Stores Block case itself started in Alberta when TransAlta, a major Alberta Utility, sold an office building in downtown Calgary for significant profit. The utility wanted to keep all the profits. The Commission said the profits should be shared between the utility and the ratepayers. The Supreme Court of Canada disagreed that ratepayers had no property interest; they were simply entitled to service. However, as the Fort McMurray fires demonstrate, the flipside of this can create real problems for utilities. Put simply if the utility gets to keep all the profits from selling an asset, then presumably it gets to bear all the cost when an asset is destroyed.

This is not the first time Alberta has struggled with this issue. The problem appeared in 2013 when Southern Alberta faced unusual floods from the Bow and Elbow River. At that time, the Government proposed new legislation, which amended the impact of Stores Block in Alberta.

The principle at issue in this case affects all Canadian utilities and all Canadian regulators. It is worth repeating the findings of the Alberta Utilities Commission at paragraphs 129-132 of decision 21609 involving ATCO Electric:87 Future considerations

129. In the previous section of this decision, the Commission determined that in the circumstances of this proceeding the retirements resulting from the RMWB wildfire were extraordinary. Accordingly, the unrecovered capital investment in the retired assets is for the account of the shareholder of ATCO Electric.

130. The Commission’s finding that costs of the retirement event should be allocated to shareholders results in just and reasonable rates. This finding is consistent with the governing legislation, the fundamental property and corporate law principles established by the courts and the guidance of the courts on the allocation of risk and benefits associated with property ownership. This guidance was reviewed by the Commission in the UAD decision and subsequently upheld on appeal. The guidance limits the Commission’s flexibility in dealing with cost allocation upon the retirement of utility assets, both those reasonably anticipated and those that are unanticipated. The regulatory framework resulting from this guidance is bounded in part by the following findings by the courts:

The argument that assets purchased are reflected in the rate base should not cloud the issue of determining who is the appropriate owner and risk bearer…the utility absorbs losses and gains, increases and decreases in the value of assets, based on economic conditions and occasional unexpected technical difficulties…

The concept of assets becoming “dedicated to service” and so remaining in the rate base forever is inconsistent with the decision in Stores Block (at para 69). Such an approach would fetter the discretion of the Board in dealing with changing circumstances. Previous inclusion in the rate base is not determinative or necessarily important; as the Court observed in Alberta Power Ltd. v. Alberta (Public Utilities Board) (1990), 72 Alta. L.R. (2d) 129, 102 A.R. 353 (C.A.) at p 151: “That was then, this is now.”

Past or historical use of assets does not permit their inclusion in rate base unless they continue to be used in the system.

Since the authorities have established that ratepayers cannot share in any of the sales of assets, it follows that holding property within the rate base, once its use has expired, works to the detriment of the ratepayer…since ratepayers cannot share in sale proceeds of utility assets, their protection for fair treatment lies in excluding assets not required for utility operations from the rate base.

… the terms of the regulatory compact have always been subject to evolution and the re-balancing of competing interests of consumers and utility companies when times and circumstances change…There is no industry today that is immune to change. Or that enjoys a right to be protected from the consequences of change, whether those arise from legislative choices, deregulation or court decisions.

The Commission provided a reasonable rationale for its conclusion that there is and should be a distinction between ordinary depreciation and unforeseen loss or obsolescence of capital, which was characterized as a form of extraordinary depreciation. I am persuaded that it was reasonable for the Commission to conclude that the extraordinary depreciation situations were outside the definition of what would be a reasonable opportunity of return for utility investors. The Commission, in its expert and policy role, could reasonably conclude that the legislation indicated that whereas ordinary depreciation is a legitimate matter for a form of shared risk between utilities and ratepayers, these forms of extraordinary depreciation of prudently acquired capital are not risks to be shared with ratepayers.

…In the absence of Stores Block and the subsequent jurisprudence from this Court, other policy choices would have been open to the regulator. Although it would be tempting to confine the application of these decisions only to gas utilities, (to minimize what I consider to be deleterious effects on the regulation of utilities in Alberta), the legal principles in Stores Block remain good law.

131. Although the Court of Appeal emphasized that the Stores Block line of cases remains good law, it also noted that more than a decade of incremental litigation on individual, fact-specific Commission decisions, has arguably resulted in some “deleterious effects on regulation of utilities in Alberta.” In making this observation, the Court indicated that the Commission would have greater flexibility to deal with UAD matters in the absence of this line of court decisions and reminded lawmakers that they have the ability to consider these issues from a broader public policy perspective should they wish to alter the status quo and provide the Commission with greater discretion in addressing UAD fact-specific issues as noted below:

Absent the pronouncements in Stores Block, the Commission would likely have greater flexibility on the issue of who bears the undepreciated cost of assets rendered useless as the result of extraordinary events.

The Commission, and this Court, are bound by Stores Block and the subsequent decisions from this Court. Only legislative amendment, reconsideration, or a reversal of Stores Block by the Supreme Court of Canada can change that.

132. The Commission appreciates the difficulty utilities face operating in an environment where they must anticipate reasonably foreseeable future events, not just to properly align depreciation parameters but also to reduce the risk of shareholder losses due to an extraordinary retirement. Notwithstanding these efforts, utilities recognize that shareholder losses are likely to occur despite having acted prudently in conducting their operations. Similarly, it is not in the interest of customers that they pay higher rates that reflect risk-adjusted returns or depreciation parameters and investment decisions which factor in every possible retirement contingency. It is also not in the interest of customers that utilities incur higher borrowing costs or that the delivery of safe and reliable service be compromised due to financial hardship resulting from an extraordinary retirement. Further, it is in the interest of neither utilities nor customers to engage in continual fractious debate in characterizing retirements. Again, no party benefits if utilities are compelled to respond to negative economic incentives by adopting risk-averse policies that impede regulatory efficiencies or improvements in service or reliability where prudent investment would otherwise occur. These are perhaps some of the possible deleterious effects on the regulation of utilities in Alberta noted by the courts.

Less Deference

Courts have often extended deference to energy regulators, particularly when they are interpreting their home statute. The high-water mark in Canada was the decision of Justice Brian O’Ferrall in Capital Power v Alberta Utilities Commission88 that was the subject of an article in the Energy Regulation Quarterly.89 Similar principles have been developed in the United States where it is called the Chevron doctrine,90 which has been applied in U.S. cases91 although that has been reduced in recent decisions.92

A decision of the Supreme Court of Canada, in December 2019, in Vavilov93 appears to reduce the degree of deference in Canadian law as well. There are many Canadian energy regulators whose decisions are subject to review by the courts pursuant to express statutory rights of appeal. Other cases where there is no statutory right of appeal are nonetheless subject to judicial appeal by the courts. In either case, the regulatory decisions are reviewed by the courts with respect to the merits of the decision, as well as for breaches of procedural fairness or natural justice. In either case, the review on the merits turns on the application of the standard of review to be applied. It is either a non-deferential “correctness” standard or alternatively a deferential “reasonableness” standard. Tribunals, such as energy regulators, are usually granted the latter treatment.

Prior to Vavilov, the distinction between statutory appeals and judiciary reviews was blurred and often the review in courts would apply the same deferential approach to both. The Supreme Court’s decision in Vavilov changes the law first developed in Dunsmuir in 200894 with respect to statutory appeals. Now there is a presumption that the standard of review will be reasonableness, unless there is a clear legislated direction that a different standard was intended. The court has indicated that there are five specific categories where derogation from the presumption of reasonableness is warranted. These are:

  • A specific standard of review has been set out in the statute;
  • A statutory right of appeal has been set out in the statute;
  • Constitutional questions;
  • General questions; and
  • Questions regarding the jurisdictional boundaries between administrative bodies.

The Supreme Court Decision in Vavilov is an important one. A detailed analysis is contained in David Mullan’s Annual Review of Developments in Administrative Law relevant to Energy Law and Regulation in this issue of Energy Regulation Quarterly.


AESO’s request for feedback on pricing framework review, session 1 material asked the following questions:

  1. At the session, the AESO outlined the objectives of the pricing framework, which includes ensuring both long term adequacy and ensuring efficient short-term market response. Do you have any comments on the objectives of the pricing framework?
  2. Please provide your comments on the AESO’s description of Alberta’s Energy-Only Market Pricing Framework, and the administrative price levels, in particular the purpose of the offer cap. Is there anything you would change or add to this description?
  3. Please provide your comments on the AESO’s description of Alberta’s Energy-Only Market Pricing Framework, and the administrative price levels, in particular the purpose of the price cap. Is there anything you would change or add to this description?
  4. Please provide your comments on the AESO’s description of Alberta’s Energy-Only Market Pricing Framework, and the administrative price levels, in particular the purpose of the price floor. Is there anything you would change or add to this description?
  5. The AESO’s forward looking resource adequacy assessment indicates that the energy only market with the existing offer cap will provide reasonable financial returns while meeting the supply adequacy requirements. Do you agree with the AESO’s conclusions? If no, please describe your concerns.
  6. The AESO’s historical revenue sufficiency assessment indicates that the energy only market with the existing offer cap has historically sent efficient and timely price signals to the market. Historically assets have been added when pricing signals indicated that profitable entry could occur. Do you agree with the AESO’s conclusions? If no, please describe your concerns.
  7. Are there foreseeable situations where asset variable costs would be greater than $999.99/MWh? If yes, please describe the situation.
  8. The AESO has described the scope for this process, general agenda items and timing for upcoming stakeholder engagements, with the timing of the sessions aligned with the AESO’s deliverable to the Government of Alberta Energy Minister. Please describe if you believe the scope is appropriate. If not, please describe/provide your rationale.
  9. Is the approach used for this engagement effective? If no, please provide specific feedback on how the AESO can make these sessions more constructive.
  10. Please provide any other comments you have related to the pricing framework engagement.


  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 Teck Frontier oil sands project.
  2. Gitxaala Nation v Canada, 2016 FCA 187.
  3. Reference re Environmental Management Act, 2020 SCC 1.
  4. Reference re Environmental Management Act (British Columbia), 2019 BCCA 181.
  5. Coldwater Indian Band v Canada (Attorney General), 2020 FCA 34.
  6. US, In re Application No OP-0003 – (TransCanada), 303 Neb 872 (Neb Sup Ct 2019), online: <https://www.nebraska.gov/apps-courts-epub/public/supreme>.
  7. Coastal GasLink Pipeline Ltd v Huson, 2018 BCSC 2343.
  8. Jurisdiction over the Coastal GasLink Pipeline Project, MH-053-2018 (2019) (National Energy Board).
  9. Westcoast Energy Inc v Canada (National Energy Board), [1998] 1 SCR 322.
  10. US, In re Application of Enbridge Energy, Limited Partnership, for a Certificate of Need and a Routing Permit for the Proposed Line 3 Replacement Project in Minnesota from the North Dakota Border to the Wisconsin Border, (Minn App Ct 2019), online: <https://mn.gov/law-library-stat/archive/ctappub/2019/OPa181283-060319.pdf>.
  11. US, In the Matter of the Application of Enbridge Energy, Limited Partnership for a Certificate of Need for the Proposed Line 3 Replacement Project in Minnesota from the North Dakota Border to the Wisconsin Border, PL9/CN-14-916, PL9/ PPL-15-137, February 3, 2020.
  12. See Rowland J Harrison, “Offshore Oil Development in Uncharted Legal Waters: Will the Proposed Bay du Nord Project Precipitate Another Federal-Provincial Conflict?” (2018) 6:4 Energy Regulation Quarterly.
  13. Canada Petroleum Resources Act, RSC 1985, c 36 (2nd Supp).
  14. Kate Kyle, “Feds return $430M to oil and gas companies ahead of Arctic offshore exploration ban” CBC News (18 December 2019), online: <https://www.cbc.ca/news/canada/north/beaufort-sea-moratorium-deposits-nwt-1.5399157>.
  15.  Atle Staalesen, “Moscow outlines a €210 billion incentive plan for Arctic Oil” ArcticToday (5 February 2020), online: <https://www.arctictoday.com/moscow-outlines-a-e210-billion-incentive-plan-for-arctic-oil/>.
  16. Government of Alberta, News Release, “Consumers to benefit from stable, reliable electricity market” (23 November 2016), online: <https://www.alberta.ca/release.cfm?xID=44880BD97DCDC-D465-4922-25225F9F43B302C9>.
  17.  AESO, “Request for Information regarding Market Power Mitigation” (8 October 2019), online: <https://www. aeso.ca/assets/Uploads/Mitigation-Stakeholder-Letter-v6.pdf>.
  18.  AESO, “Market Efficiency – Pricing Framework”, online: <https://www.aeso.ca/stakeholder-engagement/ aeso-initiatives/market-related-initiatives/market-efficiency-pricing-framework/>.
  19. AESO, “AESO Initiatives Engagement” (2020), online: <https://www.aeso.ca/event/2020-02-12-review-of-price-cap-price-floor-and-shortage-pricing>.
  20. Bill C-69, An Act to enact the Impact Assessment Act and the Canadian Energy Regulator Act, to amend the Navigation Protection Act and to make consequential amendments to other Acts, 1st Sess, 42nd Parl, 2019.
  21. Bob Heggie, “Governance of Administrative Agencies” (2019) 7:3 Energy Regulation Quarterly.
  22. Rowland J Harrison QC, Neil McCrank QC, Dr Ron Wallace, “The structure of the Canadian energy regulator: A questionable new model for governance of energy regulation tribunals?” (2020) 8:1 Energy Regulation Quarterly.
  23. Canada Energy Regulator, “Enbridge Pipelines Inc. (Enbridge) Canadian Mainline Contracting Application (Application) Notice of Public Hearing and Registration to Participate Instructions” (24 February 2020), online: <https://docs2.cer-rec.gc.ca/ll-eng/llisapi.dll/fetch/2000/90465/92835/155829/3773831/3890507/3908468/3910006/C04811-1_CER_-_Notice_of_Public_Hearing_and_Registration_to_Participate_Instructions_%E2%80%93_Enbridge_Canadian_Mainline_Contracting_Application_-_A7D5Y6.pdf?nodeid=3910007&vernum=-2>.
  24. Ontario Energy Board Act, SO 1998, c 15, Schedule B.
  25.  Bill 87, Fixing the Hydro Mess Act, 1st Sess, 42nd Leg, Ontario, 2019.
  26. Ibid.
  27. Ontario Energy Board modernization Review Panel final report, (October 2018), online: <https://files.ontario.ca/endm-oeb-report-en-2018-10-31.pdf>.
  28.  In Alberta, see details on AESO’s website including roadmap, online: <https://www.aeso.ca/market/current-market-initiatives/energy-storage>; Alberta Utilities Commission Distribution System Inquiry, online: <http://www.auc.ab.ca/Pages/distribution-system-inquiry.aspx>.
  29. Alberta Utilities Commission, “Distribution System Inquiry”, Proceeding 24116, Exhibit 24116-X0106, para 12.
  30. Ontario Energy Board, “Re: Utility Remuneration and Responding to Distributed Energy Resources Consultation Initiation and Notice of Cost Awards Process Board File Numbers: EB-2018-0287 and EB-2018-0288” (15 March 2019).
  31. Ibid.
  32. Ontario Energy Board, “Utility Remuneration and Responding to Distributed Energy Resources Board File Numbers: EB-2018-0287 and EB-2018-0288” (17 July 2019).
  33. Ontario Energy Board, “Re: Board File Number: EB-2019-0207 Distributed Energy Resources Connections Review Initiative” (13 August 2019).
  34. Independent Electricity System Operator,”A Progress Report on Contracted Electricity Supply: First Quarter 2019” (2019) at 18.
  35. Alberta Utilities Commission, “AUC Bulletin 2019-16”, online: <http://www.auc.ab.ca/News/2019/Bulletin%202019-16.pdf>.
  36. EPCOR Water Services Inc re EL Smith Solar Power Plant, Decision 23418-D01-2019 (20 February 2019); Advantage Oil and Gas Ltd re Glacier Power Plant Alteration, Decision 23756-D01-2019 (26 April 2019); International Paper Canada Pulp Holdings ULC re Request for Permanent Connection for 48-Megawatt Plant, Decision 24393-D01-2019 (6 June 2019).
  37. EPCOR Water Services Inc re EL Smith Solar Power Plant, Supra note 36 at para 101.
  38.  AltaLink Management Ltd, “Re: Bulletin 2019-16 Consultation on the Issue of Power Plant Self-Supply and Export” (11 October 2019), at para 13, online: <http://www.auc.ab.ca/regulatory_documents/Consultations/2019-10-11-SelfSupplyandExport-AltaLinkManagementLtd.pdf>.
  39.  Market Surveillance Administrator, “2019 Market Share Offer Control” (24 September 2019), online: <https://static1.squarespace.com/static/5d88e3016c6a183b1bcc861f/t/5d8cf795c3fa58146f1f13ad/1569519510719/2019+Market+Share+Offer+Control+Report.pdf>.
  40. In Ontario, by way of example, this generation accounts for 10 per cent of total supply compared to 30 per cent in Alberta. Specifically, in Ontario at the end of 2019 there was approximately 3,400 MW of local, distribution-connected generation capacity and another 37,500 MW of transmission-connected generation capacity. See IESO, “Ontario’s Supply Mix”, online: <http://www.ieso.ca/en/Learn/Ontario-Supply-Mix/Ontario-Energy-Capacity>.
  41. Alberta Utilities Commission, “Bulletin 2020-01” (9 January 2020), online: <http://www.auc.ab.ca/News/2020/Bulletin%202020-01.pdf>.
  42. Capital Power, “Re: Alberta Utilities Commission Consultation on the issue of power plant self-supply and export: Comments of Capital Power Corporation” (11 October 2019), online: <http://www.auc.ab.ca/regulatory_documents/Consultations/2019-10-11-SelfSupplyandExport-CapitalPower.pdf>.
  43. The Commission’s Decision in EPCOR Water Services Inc re EL Smith Solar Power Plant, supra note 34 discusses all generator exemptions from power pool participation in extensive detail.
  44. Electric Utilities Act, SA 2003, c E-5.1, s 6(1); also see the Fair, Efficient and Open Competition Regulation, AR 159/2009.
  45. The  Brattle  Group,  “Solar-Plus-Storage:  The  Future  Market  for  Hybrid  Resources”  (December  2019), online: <https://brattlefiles.blob.core.windows.net/files/17741_solar_plus_storage_economics_-_final.pdf>.
  46. GTM Research and Energy Storage Association, “U.S. Energy Storage Monitor: Q4 2017 Full Report” (December 2017).
  47. Electric Storage Participation in Markets Operated by Regional Transmission Organizations and Independent System Operators, 162 FERC ¶ 61,127.
  48. Electric Storage Participation in Markets Operated by Regional Transmission Organizations and Independent System Operators, 18 CFR § 35.
  49. Supra note 41.
  50. Toronto Hydro-Electric System Limited Application for Electricity Distribution Rates beginning January 1, 2020 until December 31, 2024, EB-2018-0165, Decision and Order (19 December 2019).
  51. Ibid.
  52. IESO,  “Removing  Obstacles  for  Storage  Resources  in  Ontario”  (19  December  2019),  online:  <http://www.ieso.ca/en/Sector-Participants/IESO-News/2018/12/IESO-report-outlines-next-steps-to-leveling-playing-fiel d-for-energy-storage>.
  53. Energy Storage Canada, “Maximizing Value and Efficiency for Ratepayers through Energy Storage: A Roadmap for Ontario” (May 2019), online: <https://energystoragecanada.org/highlights/2019/5/29/maximizing-value-and-efficiency-for-ratepayers-through-energy-storage-a-roadmap-for-ontario>.
  54. AESO, “Dispatchable Renewables and Energy Storage” (31 May 2018), online: <https://www.aeso.ca/assets/Uploads/AESO-Dispatchable-Renewables-Storage-Report-May2018.pdf>.
  55. See  British  Columbia  Utilities  Commission,  “An  Inquiry  into  the  Regulation  of  Electric  Vehicle  Charging Station:  Phase  Two  Report”  (24  June  2019),  online:  <https://www.bcuc.com/Documents/Proceedings/2019/DOC_54345_BCUC%20EV%20Inquiry%20Phase%20Two%20Report-web.pdf>.
  56. See  International  Energy  Agency  Hybrid  &  Electric  Vehicle,  “2018  HEV  TCP  Annual  Report”  (2018), online: <http://www.ieahev.org/assets/1/7/Report2018_Canada.pdf>.
  57. See Electrify Canada, “About Electrify Canada”, online:<https://www.electrify-canada.ca/about-us>; Electrify Canada, News Release, “Volkswagen Group Canada Forms Electrify Canada to Install Ultra-Fast Electric Vehicle Chargers”  (19  July  2018),  online:  <https://elam-cms-assets.s3.amazonaws.com/inline-files/Volkswagen%20Group%20Canada%20Forms%20Electrify%20Canada%20to%20Install%20Ultra-Fast%20Electric%20Vehicle%20Chargers.pdf>.
  58. See Petro-Canada, “Introducing our EV fast charge”, online: <https://www.petro-canada.ca/en/personal/fuel/alternative-fuels/ev-fast-charge-network>.
  59. See Transport Canada, “Zero-emission vehicles”, online: <http://www.tc.gc.ca/en/services/road/innovative-technologies/zero-emission-vehicles.html>.
  60. See Natural Resources Canada, “EV Charging Stations across Trans-Canada Highway (TCH) – Ontario and Manitoba”, online: <https://www.nrcan.gc.ca/energy/funding/icg/19851>; The project was funded by an $8-million “repayable contribution” from NRCan under the Canadian Energy Innovation Program, as well as private investment from eCAMION, a Toronto-based energy storage system developer, Leclanché, an energy storage provider, and Geneva-based power producer SGEM. “Fast-charging stations for electric vehicles coming to Trans-Canada Highway”, (24 July 2017), online: <http://www.ecamion.com/fast-charging-stations-for-electric-vehicles-coming-to-trans-canada-highway/>.
  61. Natural Resources Canada, “Electric Vehicle and Alternative Fuel Infrastructure deployment Initiative” (2019), online: < https://www.nrcan.gc.ca/energy/alternative-fuels/fuel-facts/ecoenergy/18352>.
  62. While Ontario had pledged to take provide ZEV incentives and support infrastructure rollout by ensuring recharging capacity was integrated into designated parking facilities owned by the Ontario government and GO  Transit parking facilities, they have since ended their vehicle and charging incentive programs; Government of Ontario, “About Low Carbon Vehicles”, online: <http://www.mto.gov.on.ca/english/vehicles/electric/electric-vehicle-incentive-program.shtml>.
  63. Hydro-Quebec, Press Release, “Electric Circuit and Groupe Filgo-Sonic Inaugurate EV Charging Superstation in Saint-Apollinaire” (11 March 2019), online: <https://news.hydroquebec.com/en/press-releases/hq/1469/electric-circuit-and-groupe-filgo-sonic-inaugurate-ev-charging-superstation-in-saint-apollinaire/>.
  64. Jacob Serebrin, “Federal government to fund 100 new electric car charging stations in Quebec” Montreal Gazette (23 January 2019), online: <https://montrealgazette.com/business/local-business/federal-government-to-fund-100-new-electric-car-charging-stations-in-quebec>.
  65. JWN, “Alberta is getting its first electric vehicle charging corridor” JWN (28 November 2017), online: <https://www.jwnenergy.com/article/2017/11/alberta-getting-its-first-electric-vehicle-charging-corridor/>.
  66. ATCO, “Peaks to Praises Electric Vehicle Charging Station” (1 February 2019), online: <https://www.atco.com/en-ca/projects/peaks-to-prairies-electric-vehicle-charging-station.html>.
  67. British Columbia Utilities Commission, “An Inquiry into the Regulation of Electric Vehicle Charging Service: Report Phase 1” (26 November 2018), online: < https://www.bcuc.com/Documents/Proceedings/2018/DOC_52916_2018-11-26-PhaseOne-Report.pdf>.
  68. In the Matter of an Application by Nova Scotia Power Incorporated for approval of its capital work order Cl# 50295, Electric Vehicle Charging Station Network Pilot Project, in the amount of $419,908, 2018 NSUARB 1, at 13.
  69. Decision and Order on Suite Metering Issues, EB-2010-0142.
  70. Ontario, Ministry of Transportation, “A Plan for Ontario: 1 in 20 by 2020: The next steps towards greener vehicles in Ontario” (July 2009).
  71. Supra note 48.
  72.  IESO,  “Ontario  Reliability  Compliance  Program”,  online:  <http://www.ieso.ca/en/Sector-Participants/System-Reliability/Ontario-Reliability-Compliance-Program>.
  73. Ontario Energy Board Act, 1998, SO 1998, c 15, Sched B, s 59.
  74. North American Electric Reliability Corporation, “Critical Infrastructure Protection Standards”, online: <https://www.nerc.com/pa/Stand/Pages/CIPStandards.aspx>.
  75. US Department of Homeland Security, CISA, “Ransomware Impacting Pipeline Operations” (18 February 2020), online: <https://www.us-cert.gov/ncas/alerts/aa20-049a>.
  76.  Federal Energy Regulatory Commission, “Joint Staff White Paper on Notices of Penalty Pertaining to Violations of Critical Infrastructure Protection Reliability Standards” (27 August 2019), online: <https://www.ferc.gov/media/news-releases/2019/2019-3/AD19-18-000-Joint-White-Paper-NoFR.pdf>.
  77. Alberta Utilities Commission, “Rule 027: Specified Penalties for Contravention of Reliability Standards”, online: <https://engage.auc.ab.ca/AUC_Rule_27>.
  78. Supra note 74.
  79. Environmental Management Act, SBC 2003, c 53.
  80. Supra note 4.
  81. Supra note 3.
  82. Reference re Greenhouse Gas Pollution Pricing Act, 2019 SKCA 40.
  83. Reference re Greenhouse Gas Pollution Pricing Act, 2020 ABCA 74, at 6.
  84. Z Factor Application for Recovery of 2016 Regional Municipality of Wood Buffalo Wildfire Costs, 21608-D01-2018; 2018-2019 Transmission General Tariff Application, 22742-D02-2019; Z Factor Adjustment for the 2016 Regional Municipality of Wood Buffalo Wildfire, 21609-D01-2019.
  85. ATCO Gas and Pipelines Ltd v Alberta (Energy and Utilities Board), [2006] 1 SCR 140.
  86. Utility Asset Disposition, Decision 2013-417, online: <http://www.auc.ab.ca/regulatory_documents/ProceedingDocuments/2013/2013-417.pdf>.
  87. Supra note 82 at 30-32.
  88. Capital Power Corporation v Alberta Utilities Commission, 2018 ABCA 437; McLean v British Columbia Securities Commission, 2013 SCC 67 at paras 40-41; Walton v Alberta Securities Commission, 2014 ABCA 273 at para 17
  89. Gordon E Kaiser, “Capital Power Corporation: The Alberta Line Loss Debate” (2019) 7:1 Energy Regulation Quarterly, online: <https://www.energyregulationquarterly.ca/case-comments/capital-power-corporation-the-alberta-line-loss-debate#sthash.9cQcSMWB.dpbs>.
  90. Chevron v Natural Resources Def Council, 467 US 837.
  91. Cajun Electric Power Coop v FERC, 1924 F (2d) 1132 (DC Cir 1991); Koch Gateway Pipeline v FERC, 135 F (2d) 810 (DC Cir 1998); California Independent System Operator Inc v FERC, 372 F (3d) 395 (DC Cir 2004); Massachusetts v Environmental Protection Agency, 549 US 497 (2007); Assn. of Public Agency Customers v Bonnebille Power Admin, 126 F (3d) 1158 (2009); Michigan v Environmental Protection Agency, 576 US 1 (2015); FERC v Electric Power Supply Association, 577 US 1 (2016); Next Era Desert Centre Blythe v FERC, 852 F (3d) 1118 (DC Cir 2017).
  92. Epic Systems Corp v Lewis, 584 US 1 (2018).
  93. Canada (Minister of Citizenship and Immigration) v Vavilov, 2019 SCC 65.
  94. Dunsmuir v New Brunswick, 2008 SCC 9.

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