Each year when we write this Annual Review we face the same issues. The first issue on the list is always pipelines. In the 2016 Annual Review the first heading was “The Pipeline Delays are Over”. Last year, the first heading of the review was “Pipeline Delays are Back”. This year, the first heading is “Pipeline Delays Continue”.


The events of 2018 regarding pipeline development in Canada are identical to 2017 except that there were new players. There were new players in the sense that there were different pipelines. But the regulator was the same – the National Energy Board (NEB).

In 2017, the pipeline at issue was the TransCanada Energy East pipeline. That was a $15.7 billion project to build a 4500 km pipeline from Alberta to the East Coast. The application was filed in April 2013. The argument was that Canada’s East Coast refiners rely on imports for 80 per cent of the requirements and Alberta crude could replace that foreign crude. That argument seemed to have some merit.

Things went off the rails when the NEB suspended hearings until the Board could rule on a motion to remove two panel members on the grounds of an apprehension of bias. In the end, the NEB started over with three panel members and threw out all of the decisions the previous panel had made. To add insult to injury, following a change in government policy, the NEB panel issued a new decision allowing a consideration of greenhouse gas emissions including a ruling that, for the first time, the Board would consider the impact of upstream and downstream carbon emissions from the increased production and consumption oil resulting from the project. That was enough for TransCanada. In October 2017, the company threw in the towel and cancelled the project.

The events of 2018 were not much different, except the pipeline was different. In this case, it was the Kinder Morgan Trans Mountain pipeline. This was an application for approval of a $5.4 billion project to twin an existing pipeline from Edmonton Alberta to Burnaby, British Columbia. That application had also been first filed in 2013. The project was designed to increase capacity from 300,000 barrels per day to 890,000 per day and expand the tanker traffic in the Burrard Inlet from five tankers to 34 tankers per month.

That came to an end when the Federal Court of Appeal ruled there had been a failure to adequately consider the increased marine traffic (under the Canadian Environmental Assessment Act)1 and a failure by the Crown in the constitutional requirement to adequately consult with the aboriginal bands affected.

Like TransCanada the year before, Kinder Morgan threw in the towel. But Kinder Morgan did it slightly different than TransCanada. The company gave the federal government a deadline to solve the problem.

The government’s solution to the problem was to buy the pipeline for $5.4 billion. Whether that will solve the problem remains to be seen. There has been some good news however. On February 21 the NEB, on a re-hearing, approved the Trans Mountain project concluding that there were real environmental and aboriginal issues, but they were trumped by national concerns.

Just as important as the Federal Court’s decision in Trans Mountain was the opposition from the Province of British Columbia. The new government in BC announced that it was considering regulations to stop pipeline companies from shipping bitumen through the province. Alberta responded by saying it would no longer import BC wine or purchase electricity from BC’s site C dam. In addition to the provincial government, Kinder Morgan had to contend with the Mayor of Burnaby just as TransCanada had to deal with the Mayor of Montréal. It turns out that big city mayors do not like pipelines either.

As this year’s Annual Review goes to press, TransCanada announced it will remove the word “Canada” from the corporate name. Imagine that. This is the company that built Canada’s first East-West pipeline more than 50 years ago. Now it will focus on the United States and Mexico where it can build facilities.

Alberta, the province whose population has paid significant income taxes to the federal government, now faces serious economic troubles with the decline in their energy industry. At 7a.m., it’s still dark in Calgary during the winter. If you walk up from the hotel on the Bow River towards the city you face a line of gleaming buildings. The top half of most have no lights on. They are empty. It is called ghost space. The space is not even on the market. Their owners know that, in the current circumstance, the buildings are not rentable.


Early in 2018 the federal government introduced Bill C-692, new legislation that would replace the NEB with the Canadian Energy Regulator or CER as it is now referred to. The CER is much more complex than the NEB. First, its scope is much greater. Its jurisdiction goes beyond federally regulated pipelines. The new regulatory reach includes offshore oil and gas exploration, production projects and potentially offshore renewable energy project.

Second, there are now three decision-makers. First is the Board of Directors that controls the CER. Then there are the members of the CER itself – the Commission members who will conduct hearings. Last, but not least, is the federal cabinet which has a veto on any decision 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.

Some argue that the new legislation creates investor uncertainty. But we cannot fault the government for trying. The NEB pipeline approval process had been under siege from all sides in recent times. In the new world, the fate of pipeline projects will no longer be decided by expert tribunals, instead the federal Cabinet will run the show.


The year 2018 saw the entire energy industry in Canada focus on technology and innovation. Every trade organization produced a conference or a study on the subject. The regulators also entered the game.

In Ontario, for example, the IESO established the Energy Storage Advisor Group. The goal of that organization is to identify the technology and other barriers to entry facing storage assets. The ability of storage to significantly lower electricity costs has long been recognized. Energy grids are necessarily built to handle the peak demand which is often reached less than ten per cent of the time.

In many respects the IESO initiative followed the Notice of Proposed Rulemaking the FERC in Washington issued a year earlier. The goal of that proceeding was to reduce barriers to energy storage and distributed energy resources. Ultimately the FERC directed the six regional system operators or RTO’s to prepare plans dealing with the introduction of storage and DER resources in their respective marketplaces.

The IESO Energy Storage Advisor Group issued its report at the close of the year. It made a number of recommendations including a request that regulators create a clear plan for the introduction of storage in the rate base of LDCs in the province. The Ontario initiative was followed up by a much broader inquiry by the Alberta Utilities Commission (AUC) into technology impacts on the electricity distribution system in Alberta.

The traditional scope of electric LDC’s activities is also being questioned/pressured by new technology. Central generation is being replaced by local generation. Local Generation (and storage) can offer significant cost savings to consumers. If local distributors do not respond to these new market demands they could lose significant load. Customer owned generation is growing. Customers directly connected to generation do not need a distributor.

A generic inquiry into the role of the electric LDCs in deploying new technology is long overdue. The industry has long been concerned about the role of embedded generation and storage including the development of micro-grids. The question of where regulation starts and where it ends is on everyone’s mind. The larger question is whether local distributors should become local generators and be in a position to take advantage of micro energy technology.


It is not just the provinces that were fighting each other in 2018. The provinces are also fighting the federal government when it comes to carbon taxes.

On October 31, 2018 the new Ontario government introduced the Cap and Trade Cancellation Act3 which repealed the Ontario cap and trade regime brought in by the previous Liberal government. That legislation retired or cancelled emission allowances and offset credits held by Ontario participants under the regime.

The Canadian federal government then passed legislation indicating the provinces must enact a carbon regime acceptable to the federal government or the government would impose a tax. The proceeds from carbon pollution pricing would be returned to the federal government or the province the money came from.

Under the federal program, any provincial carbon pricing system to be determined compliant by the federal government must at a minimum establish a carbon price of $20 per ton of carbon dioxide equivalent by January 1, 2019. There must also be incremental increases in each year to reach $50 per ton by 2022. As indicated federal carbon pricing will apply to the provinces that have not implemented provincial carbon pricing system which meets the federal carbon pricing standard by January 1, 2019.

Currently Ontario, New Brunswick, and Saskatchewan are off side. In April 2018, the government of Saskatchewan commenced a reference case to Saskatchewan Court of Appeal to challenge the constitutionality of the federal carbon pricing regime. On October 14, 2018 the government Ontario followed suit in the Ontario Court of Appeal. The general wisdom from constitutional experts is that the federal government has jurisdiction.

It is worth noting that in November 2018 a class action suit was filed in Quebec seeking relief against the government of Quebec on the basis of its alleged inaction on climate change. The action was commenced by an environmental group that represents all Quebec citizens age 35 and under. This matter follows a number of class-action lawsuits in the United States in recent years.

The Quebec claim seeks a declaration that the government’s behaviour contravenes the Canadian Charter of Rights and Freedoms (Canadian Charter)4 and the Quebec Charter of Human Rights and Freedoms (Quebec Charter)5. In particular, the claim alleges that governments breach the section 7 right to life integrity and security the person and the section 15, right to equality, of the Canadian Charter and similar sections of the Quebec Charter.

The claim is in the procedural stage. In order to proceed it must be certified by the Quebec Superior Court. It is unclear at this point of the claim will be successful.


In July 2018, the new Conservative government in Ontario enacted legislation that cancelled 559 wind and solar contracts. The government claimed this would save the Ontario taxpayers $790 million. Two of those contracts were wind contracts. The first was Otter Creek, a 15 MW wind project near Wallaceberg. The second was the Strong Breeze project, a 57 MW project near Belleville. The rest of the contracts were smaller solar contracts with the result that wind accounts for about 25 per cent of the cancellation capacity.

However, there was a third wind contract, the 18.5 MW White Plains project, in Prince Edward County that was singled out for special consideration and was subject to special legislation. That was because the project had received its notice to proceed (NTP). The only way this contract could be cancelled was to enact special legislation to design to do that. That is exactly what the new government did.

The cancelled wind projects had one thing in common. They were strongly opposed by the community which they were located. White Plains had an additional special feature in that its NTP had been granted by the previous government during the writ period. The new government argued that this was exceptional and unauthorized. The standard practice was that during the writ, the existing government should not enter into new contracts or make significant regulatory decisions which could bind the conduct of the future government.

While there was a great deal of publicity regarding these cancellations, they represent a small part of the capacity under FIT contracts in Ontario. At the end of 2017 the total wind capacity in Ontario was 2833 MW. The cancelled wind only amounted to 29 MW or 1 per cent of the total. In the case of solar, the total megawatts contracted for the IESO by the end of 2017 was 1659 MW. The cancelled solar was only 333 MW or 20 per cent. In short, the number contracts were large but the volume was small.

Of interest to many readers, in particular the developers, was the terms of compensation. These were established in the regulations and essentially provided for binding arbitration in the event dispute. It was noteworthy that most of these cancelled contracts had not reached the NTP and therefore the claimants were not entitled to lost profits. Compensation was largely limited to expenses incurred.

This was however, a major reversal in the trend across North America towards investment in renewable energy. The rational however was fairly simple. First, the new energy was expensive. Second, the province did not need the energy given that Ontario consumption has been declining for a number of years.


Alberta is the second jurisdiction in Canada to abolish coal generation. This is not an exercise for the faint of heart. In Ontario, it led to an endorsement of FIT contracts based not on competitive bidding but on who arrived first at the doorstep of the IESO or the Minister.

In Alberta, the ISO recommended to the new government elected in 2015 that, given the proposed ban of coal-fired electricity generation, they should move to a capacity market to ensure that the lights would stay on. The government accepted this recommendation and charged the AESO with drafting the necessary rules. The AUC is charged with approving those rules and has 6 months from the date the application is filed to render its decision.

The application was filed January 31. The race is on. Intervenor evidence is due February 28. The hearing starts April 22 and finishes May 31. Final arguments are filed June 21.This is fast track regulation.

Capacity markets are not new. They are used in 25 U.S. states serving 150 million people. They are based on regular auctions for capacity by the RTO’s with regulatory oversight of both independent market monitors and the national energy regulator, FERC.

There will be important lessons here for other Canadian jurisdictions. The Ontario IESO is said to be considering capacity market procurement for an incremental portion of its requirements. In Alberta however, the province is betting the farm and is moving to shift virtually all of its energy market to a capacity market. It will have some challenges but the Alberta Commission seems to be on top of it.


2018 saw lots of utility mergers and acquisitions. Most were in Ontario. For the first time in history, the acquisitions took place in both gas and electricity markets.

On March 18, 2018, the Ontario Energy Board (OEB) granted approval of the merger between Entegrus and St. Thomas, the acquisition of Midland by Newmarket on August 23, the acquisition of Collingwood by Epcor on October 1, the merger of Guelph and Alectra on October 18, the merger of Thunder Bay and Kenora on November 15 and the merger of Whitby and Veridian on December 20. It was a busy year.

One transaction was denied however. On April 12, the $41.3 million acquisition of Orillia by Hydro One was turned down. The OEB ruled that Hydro One had failed to provide sufficient evidence that the transaction would meet the no harm test. In coming to that conclusion the Board considered the rate increases Hydro was seeking in connection with three previously acquired utilities, Norfolk Power, Haldiman County Hydro and Woodstock Hydro. The intervenors argued that these rate increases were evidence that there were no cost savings for distributors previously acquired by Hydro one. Hydro One filed a motion for review but that was not successful. Hydro One subsequently filed a new application with additional evidence intended to meet the no harm test. The Board has yet to rule on that application.

For the first time in many years there has also been some activity in the gas sector. The big news was the amalgamation of Enbridge Gas Distribution and Union Gas, approved on October 30, creating a massive province wide monopoly in gas distribution. However, at the same time, there was a new entrant. That was Epcor, an Alberta company owned by the city of Edmonton, was successful in obtaining three natural gas franchises in Kincardine Ontario, in competition with Union Gas. Epcor also purchased a small gas utility in Aylmer, Ontario called Natural Gas Resources (NRG).

Hydro One faced other difficulties with respect to acquisitions. After a year of trying it failed in its attempt to purchase, at the cost of $4.4 billion, Avista, a large American utility in the Pacific Northwest. Hydro One ended up paying a $103 million termination fee when that deal for fell through. The two companies together would have had over 2 million customers and ranked among the 20th largest North American utilities.

The parties agreed to call off the merger based on opposition from U.S. regulators in the state of Washington. The state regulators were concerned about the undue influence by the Ontario government in the Hydro One operations. The Ontario government owns 47 per cent of Hydro One and the new Ontario Premier had just fired the chief executive officer of Hydro One on the grounds that his $6 million in annual compensation was too high. An excellent article in this issue by Scott Hempling outlines the colorful story.


In the energy regulatory world, the courts have the last say. That was as true in 2018 as in any other year. It is also true of this Editorial.

No review of recent developments in the courts would be complete without a reference to the first article in this issue of the ERQ. That is the article on “2018 developments in administrative law relevant to energy Law and regulation”. Regular readers will know that this article appears every year in the year-end edition. It is a classic. Carefully crafted by Canada’s leading administrative lawyer David Mullan. It is required reading by all regulators and the counsel that appear before them.

This Annual Review will not repeat any of the David’s work but there are few cases outside of the administrative law world that are noteworthy. Of course the biggest case of the year was the Federal Court of Appeal decision setting aside the Trans Mountain pipeline approval. That was dealt with above. No further discussion of that is required.

An interesting little case was that the decision of the Ontario Divisional Court on December 31, 2018, in a class action against Hydro One. It seems that Hydro One made some massive billing errors and overcharged some of its 1.3 million customers. Those customers brought class action claim of $100 million in damages relating to the overcharges. However, the motions judge in 2017 refused to certify the class citing two reasons. First, he said there were insufficient common issues noting that a number of individual trials would be required because each customer incurred different amounts of damages. The most important reason however was the second one. The motion judge ruled that there were administrative remedies and procedures that would be more efficient than a class action.

In particular, he noted that the OEB had a complaint process and one of its objectives was to protect the interests of customers with respect to prices. As a result, the justice found that the OEB could be expected to respond to the appropriate cases and provide the appropriate remedies. The Ontario Divisional Court agreed with motion judge’s findings and dismissed the case. This may become an important principle in future cases.

The next decision of note was the Capital Power6 decision by Mr. Justice O’Farrell of the Alberta Court of Appeal. That was a long-running battle on how to allocate the cost of line losses. In the end, the interesting thing was the degree of deference that the court granted the regulator. In finding the proper remedy, the AUC had in some sense engaged in retroactive ratemaking by making retroactive adjustments – something that is generally forbidden in utility cases.

Justice O’Farrell emphatically supported the principle that court should defer to expert tribunals making legal decisions within the special expertise including jurisdictional determination, such as the retroactive adjustment of rates saying that a deferential standard must be applied even true jurisdictional issues. Justice O’Farrell gave deference to the Commission’s decision on its jurisdiction to adjust the line loss allocations retroactively because the Commission’s essential function and expertise was ratemaking, stating:

Where do the applicants think the common law prohibition against retroactive ratemaking came from? It came from roughly 100 years of public utility regulation and public utility board jurisprudence in this province and elsewhere in North America. Admittedly, the courts have contributed to the development of the prohibition, invoking concepts such as the presumption against retroactive application of legislation. But it is important to understand that the underlying rationales for the prohibition were not derived solely from the common law, or statute law for that matter. The prohibition against retroactive ratemaking was derived from general principles of fairness, reliance, certainty and finality, which the common law recognized, but which existed independent of the common law. These are values which gained currency, not because of the law, but because they made sense in a fair and orderly society. Courts have no monopoly or special expertise when it comes to the application of principles of fairness. And that is what the Commission did in this case: it applied principles of fairness to a function (i.e., ratemaking) in respect of which is has a special expertise.7

The decision in Capital Power is particularly interesting given recent developments in the United States. There concept of deference to administrative tribunals and regulators began with the 1984 decision of the United States Supreme Court in Chevron.8 For over 30 years, Chevron has been applied in a number of cases by granting deference to the statutory interpretations of energy regulators. This lasted until May 2018 when the Supreme Court issued is decision in Epic Systems.9 That decision essentially restricted the deference that courts grant regulators by limiting it to the interpretation of the home statute – a much narrower restriction than had applied before.


2019 will be a year of major changes. Two major elections are on the horizon. Leaving those aside, we know this. We will likely have a new Federal Energy Regulator in Canada, a new Alberta capacity market, and a new OEB.

The wild card is what happens to the electricity LDC sector across Canada. The Alberta Inquiry may be instrumental. LDC’s from outside the province have intervened and we understand have been welcomed. Imagine that. The first national inquiry into technology and regulatory change. The new AUC Chair has certainly picked up the mantle from Willie Grieve. Which is where we should end this year-end review. The first article in this edition of the ERQ is a Memorial to Willie. The words are well said.


  1. Canadian Environmental Assessment Act, SC 2012, c 19, s 52.
  2.  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, 2018.
  3.  Bill 4, Cap and Trade Cancellation Act (CTCA), 1st Sess, 42nd Leg, Ontario, 2018.
  4.  Canadian Charter of Rights and Freedoms, Part I of the Constitution Act, 1982, being Schedule B to the Canada Act 1982 (UK), 1982, c 11.
  5.  Charter of Human Rights and Freedoms, CQLR c C-12.
  6.  Capital Power v Alberta (Utilities Commission), 2018 ABCA 437.
  7.  Ibid at para 45.
  8.  Chevron USA Inc v Natural Resources Defense Council, 467 US 837 (1984).
  9.  Epic Systems Corp v Lewis, 584 US _ (2018).


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