Previous versions of the Canadian Energy Year in Review discussed major decisions that had impacts on the industry, but 2016 beats them all.

Alberta and Québec both announced major changes to their regulatory processes. Although not formally announced yet, big changes are in the wings in Ontario.

The real changes in the past year were at the federal level and involved pipelines. The driver was the new Prime Minister in Canada and the new President in the United States. Major decisions were made with respect to pipeline development after years of delay. Keystone XL was reactivated within days of the new President entering the White House.

During the past year the industry has undergone major consolidation at three levels: gas distribution, electricity distribution, and pipelines.  Those are detailed in the following report.

There is no question that the sector is undergoing rapid change. Some is driven by new technology giving customers greater options. In the search for lower cost electricity, many are moving to self-generation. The prospect of lower-cost renewable generation, backed up by gas-fired electricity and aided by lower-cost storage remains the hope of others, driven in part by the constant stream of higher renewable portfolio standards by States and Provinces.

More and more utilities are pursuing new market opportunities and new revenue streams in the face of customers leaving to self-generate.

At the close of the year Québec and Ontario signed an historic electricity trade agreement between the two provinces. Under the agreement Ontario will purchase a total of 14 TW hours of electricity from Hydro-Québec over a seven-year period between 2017 and 2023.

Ontario will reduce its electricity costs by $70 million by importing 2 TWh of power each year. The Ontario Minister of Energy noted that 2 TWh a year is enough to power the City of Kitchener and it would significantly reduce GHG emissions. The Quebec Minister of Energy noted that this is the largest agreement of its kind in Canadian history and Québec will continue to work with Ontario to explore opportunities to jointly promote clean renewable energy

The Pipeline Delays Are Over

After years of delay and setbacks, a number of major pipeline projects are moving forward.

The Enbridge Line 3 Replacement program was approved on November 29, 2016. The project will result in 370,000 barrels per day of additional capacity. The total project cost is estimated to be $ 7.5 billion with a target in-service date of 2019.

The $ 6.8 billion Trans Mountain Expansion project was also approved on November 29. This will yield 590,000 barrels per day as the project twins an existing pipeline carrying oil to a shipping terminal in Burnaby.

There was some negative news however. The Federal Government decided to drop Northern Gateway following NEB approval when the approval was suspended by a Federal Court decision on aboriginal claims.  And the Energy East project was forced to start over after the tribunal members decided to resign following claims of apprehension of bias.

A new panel assigned to Energy East has voided all of the decisions of the previous panel, with the result that the application is more or less being restarted, although the applicants do not need to reapply.  Energy East is a 4500 km pipeline designed to carry 1.1 million barrels a day from Alberta to Saskatchewan to refineries in Eastern Canada and a Marine terminal in New Brunswick. Eastern Mainline, which is part of the proposal, will build approximate 278 km of new gas pipeline beginning in Markham, Ontario finishing in Brouseville, Ontario.

The big news in some circles is TransCanada Keystone XL. The project was rejected by President Barack Obama in 2015 but restarted by President Donald J Trump within days of his moving into the White House.  The $ 5.3 billion project will transport 830,000 bd from Alberta and North Dakota to the US Gulf over a 1,179 mile line. President Trump signed the Executive Order on January 24. TransCanada filed the new application two days later.

Shifting Markets

In 2015 virtually all of Canada’s natural gas and crude oil exports were sold to one customer – the United States. That is changing. Technology to extract gas and oil from shale formulations continues to improve. Between 2010 and 2015 crude oil production from US shale regions increased 72%. Gas production increased by 28% in the same time frame.

As a result, Canadian exports of natural gas to the US fell by 23% between 2006 and 2015. To make matters worse on December 18, 2015 the United States lifted its 40 year ban on oil exports. The US is now exporting increased quantities of natural gas into central Canada. The bottom line is the Canada’s largest customer just became Canada’s largest competitor.

This highlights the importance of the recent approval of the Trans Mountain expansion. New markets like China and India have become critical. To serve those markets Western Canadian gas needs greater access to Tidewater and the Pacific Rim. Once the Trans Mountain expansion is complete the number of tankers leaving the Trans Mountain Burnaby terminal will increase by 300%.

A New Wave of Consolidation

In 2016 Canada saw a major consolidation in the energy sector.

On December 18 the OEB issued its decision approving the consolidation of the three largest electricity distribution companies in Ontario, Enersource Hydro Mississauga, Horizon Utilities Corporation and PowerStream. The three parties also agreed to purchase and amalgamate with Hydro One Brampton Networks owned by the Province of Ontario. The new company now called Alectra is the largest municipally owned LDC in Ontario and the second largest in North America second only to the Los Angeles Department of Water and Power in California. The new company will serve almost one million customers with a total rate base of $ 2.5 billion.

The purchase of Hydro One Brampton at a price of $607 million is the largest electricity distribution acquisition in Ontario to date. The Ontario government has long promoted consolidation and the number of electricity distributors in Ontario has gradually decreased from 300 two decades ago to just over 70 now.  This is all done in the name of efficiency. Only time will tell if that is the case but early indications are that the labor cost per Mw of distribution will be significantly less going forward.

The consolidations were not limited to the electricity segment. On September 6 Enbridge and Spectra Energy Corp., the parents of Enbridge Gas Distribution and Union respectively, announced a merger of the two companies.  The new Enbridge will have an enterprise value of $127 billion. The merger was not subject to OEB approval as the merging parent companies are not within the Board’s jurisdiction. The deal was presented as a merger of pipeline companies, each of whom happened to own a gas utility in Ontario.  So while the implications for gas customers remain uncertain, the assumption has to be that efficiencies in delivery will be sought under a single owner. Combined, the two gas utilities will have total revenues in excess of $31 billion.

It is reasonable to assume that pipeline mergers are driven by the same factors as electricity market – a search for greater economies.

And while the Enbridge – Spectra deal was the largest, it wasn’t the only big pipeline deal.  In July TransCanada completed its acquisition of the Columbia Pipeline Group for an aggregate purchase price of $13 billion including the assumption of approximately $ 2.8 billion in debt.

Both these deals had significant profile. But they weren’t the only ones. Increasingly Canadian utility players are actively acquiring assets south of the border. The Fortis Group, the AltaGas group, and EMERA have all been on the acquisition trail, growing into major continental players. These players are all Canadian based, integrated (gas and electric) enterprises – and it has happened quietly.

All of these may reflect the new maxim that it is cheaper to buy than to build, with more opportunity to buy clearly appearing south of the border.

Renewables Continue to Grow

Renewables continue to grow in both Canada and the United States. Renewable energy provided 17% of US electricity in the first half 2016 up from 14% for all 2015. The Canadian figures were slightly less (excluding hydropower).

More importantly the Renewable Portfolio’s Standards (RPS) continue to increase. In April the Québec government announced its Energy Policy 20301 which included a new RPS. The Québec government now wants renewable energy to meet 61% of Québec’s needs by 2030. Currently that number stands at approximately 47%.

In November Alberta followed by introducing its Renewable Electricity Act2 which set a goal of producing 30% of electricity in Alberta from renewable energy sources by 2030.

California has the most aggressive renewable portfolio standard. The state requires each firm that sells electricity to end users to obtain 33% of it from renewables by 2020 and 50% by 2030.

In August the New York Public Service Commission adopted a new Clean Energy Standard mandating that 50% of New York’s electricity must come from renewable sources by 2030. Oregon now has a RPS of 50% by 2040. Colorado is 30% by 2020, and Nevada is 25% by 2025. The New Mexico RPS is 20% by 2020.

While there remains strong enthusiasm on the part of decision makers in these and other jurisdictions for renewable programs, the public reaction to the costs these represent for energy services is showing signs of being less excited.

Capacity Markets

The most significant change in Canadian energy markets in 2016 was the decision of two provinces, Alberta and Ontario, to change the manner in which their energy markets function. Both provinces decided to move to what is termed a capacity market. There were however different reasons.

In Alberta’s case the province had decided to abandon coal and move to renewable energy. It was not clear that Alberta could attract the necessary investment under the current energy only arrangements.

Alberta will transition its electricity market into two separate markets – a market in which generators compete to sell electricity and a market in which generators compete for payments to keep capacity available. Generators will accordingly have two revenue streams, one from the sale of capacity and another from the sale of electricity.

In Ontario’s case the goal is market renewal and a new regime that relies more on competitive bidding than long-term power purchase agreements that the government have contracted for. Ontario believes the new regime will lead to greater cost control and innovation. Ontario will increasingly rely on competitive bidding as the contracts come to the end of their terms.

In November the Alberta government introduced the Renewable Electricity Act which established a goal of producing 30% of the total of electricity in Alberta from renewable energy resources by 2030. The Government intends to add 5000 MW of renewable electricity capacity by 2030 through the REP, a competitive process administered by the AESO, with the first 400 MW of renewable energy capacity procured through a competitive RFP in 2017 and subsequent tranches of capacity contracted to coincide with the retirement of coal power plants.

In November the Alberta government also announced that it had reached an agreement with Capital Power, TransAlta Corporation, and ATCO to compensate them for the early retirement of their plants. The total cost was $ 1.36 billion in annual payments of $ 97 million per year between 2017 and 2030. These payments represent the compensation for the early shutdown of 6 of the 18 coal-fired plants which were expected to operate past 2030. The other 12 coal-fired plants in Alberta are scheduled to close or convert to natural gas before 2030.

Capacity markets exist in the United States. These are not simple systems to administer. A great deal of effort will be required in both Alberta and Ontario to switch over to these new market designs. But there is general agreement among stakeholders that increased efficiencies will result.

Storage and Embedded Generation

The increased production of renewables has led to a rapid increase in cost-effective storage technology at both the customer and utility level. The largest utility storage facility in history is currently being installed in San Diego.

There are currently 2000 MW of solar embedded within LDCs in Ontario and that number grows every day. In 2016 Ontario utilities discovered how effective storage and local generation can be and more importantly how they can participate in this new market.

The leading example is PowerStream’s POWER.HOUSE project.  There PowerStream developed 20 residential solar and storage systems that PowerStream controls from its facilities with intelligent software creating a single facility that can meet system needs. That system has now been licensed to Thunder Bay Hydro. Not far from PowerStream, Veridian has deployed a residential grid in partnership with homebuilders.  That system will be managed and operated through Veridian system controls.

At the end the day a distributor of electricity does not really care if the customer is generating electricity. A distributor only passes through the generation costs in any event. It does not matter if the generation is from a distant monopoly generator or a local generator. What matters to the distributor is that they maintain some share of the distribution revenue stream. Ontario distributors are increasingly finding ways to do that.

In the United States distributors have for some time been selling and renting solar panels. It turns out that aggregating those solar panels and maintaining and connecting them is good business even where they are located on a customer premise. The term Community Solar is now very popular.

All of this will require further regulatory work in both Canada and the United States. The FERC in Washington took the lead when it issued a Notice of Proposed Rulemaking to reduce barriers to energy storage and distributed energy resources. The FERC has directed the six US regional system operators to draft reports on their progress with storage rules and DER aggregators in their respective marketplaces.  We may see Canadian regulators take similar steps.

A New Quebec Regulatory Regime

In April of 2016, the Quebec government issued its new Energy Policy 2030, Energy in Quebec – a source of growth (the Policy). With this Policy, the government seeks to favour a low emission economy, optimally develop energy resources, foster responsible consumption, capitalise on energy efficiency potential and promote the entire technical and social innovation chain. The Policy strives for a unifying vision to make Quebec, by the year 2030, a North American leader in the realms of renewable energy and energy efficiency and thus build a new, strong, low-carbon economy.

The Government sets ambitious and demanding targets: Enhance energy efficiency by 15%, reduce by 40 % the amount of petroleum products consumed, eliminate the use of thermal coal, increase by 25% the overall renewable energy output and increase by 50% bioenergy production.

To get there, the Policy provides four key strategic thrusts that will guide Québec’s energy transition over the next 15 years:

  • ensure integrated governance of the energy transition
  • promote the transition to a low-carbon economy
  • offer consumers a renewed, diversified energy supply
  • define a new approach to fossil energies

Alberta Reforms its Electricity Market

The Government of Alberta has announced ambitious, wide-ranging reforms to the electricity market.  While the government’s vision for the electricity market is not available in a coherent package, a number of policy approaches have been announced since the Alberta New Democratic Party was elected with a majority government in May of 2015.

Early in its mandate, and prior to the Paris Climate Change conference in late 2015, the government announced an aggressive Climate Leadership Plan3 based on recommendations from the government appointed Climate Change Advisory Panel chaired by Dr. Andrew Leach of the University of Alberta.

  • Alberta’s Climate Leadership Plan includes:
  • An economy wide carbon levy
  • Phasing out coal-fired electricity generation by 2030
  • Subsidies for renewable energy projects
  • Capping oil sands emissions by 100 mega tonnes per year
  • Reducing methane emissions by 45% by 2025

The government has also announced the introduction of a capacity market. The capacity market policy has been justified on the basis of resource adequacy.  That is, a policy intervention is required to ensure reliable capacity is available  to meet future demand given the changing nature of Alberta’s market.  The current energy only market was not viewed as capable of providing the necessary investment given the early retirement of coal fired generating plants and the introduction of significant renewable capacity to replace it. The intermittent nature of wind capacity will also require a significant investment in dispatchable resources when wind is low – likely gas-fired resources.

The Alberta ISO has stated Alberta’s security of supply outlook remains broadly healthy until 2020. However, uncertainty about the timing of coal unit retirements and other issues give rise to uncertainty about whether supply tightness may occur earlier.

The government has also announced its intention to cap the regulated rate option for Alberta consumers. The RRO is the administratively established default electricity rate for consumers who have not entered into a competitive contract with a retailer. The RRO rate will be capped at 6.8 cents/kWh for a four-year period effective June of 2017. The policy rationale to support the RRO cap is to address historic price volatility. The Government will backstop the cap by requiring taxpayers or revenues from the carbon levy to cover RRO supplier costs above 6.8 cents.

Additional policy announcements and actions include a yet to be determined plan to compensate communities impacted by the forced shut down of coal generating plants, the establishment of a standalone office to promote energy efficiency with an initial endowment of $700M, and establishing transition uplift arrangements for existing renewable investments to ensure fairness and stability in light of the subsidies being provided to new renewable investments in the clean power calls.

Lastly, the government launched a lawsuit to declare void a change in law clause in Power Purchase Arrangements.  As reported above, settlements were reached late in 2016 with three of the PPA buyers however Enmax remains as a respondent with a court decision expected in 2017.

A final note

It was a busy year. And it concluded on a note of dramatic change for the North American market, with the election of Donald Trump.  The continental climate alignment of the Obama-Trudeau governments is to be replaced by something new, at least on the America side. So too can we expect some dramatic tax and regulatory changes, if the Republican Congress and new administration are to be believed. All of this will affect Canada’s domestic energy scene, as the actions of our biggest trading partner always do.  The year ahead will not be a boring one for Canada’s regulated energy sector.


  1. Gouvernement du Québec, The 2030 Energy Policy- Energy in Québec: A Source of Growth, (Quebec:   Gouvernement du Québec, 2016).
  2. Renewable Electricity Act, SA 2016, c R-16.5.
  3. Government of Alberta, Climate Leadership Plan, (Edmonton: 22 November 2015), online: Government of Alberta <http://www.alberta.ca/climate-leadership-plan.cfm>.

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