2014 was a tumultuous year for the energy industry in Canada. The year saw the continued growth of high cost renewables, the collapse of oil prices, and a sudden increase in the number of crude by rail shipments.

It was also a busy year for many energy regulators. We saw what amounted to a reversal of the National Energy Board’s Mainline decision, a continuation of the battle to build pipelines across Canada, and a new Ontario-Quebec energy alliance.

We will examine these developments in this Editorial, as is our practice at the end of every year. We will also try to forecast the important regulatory developments coming in 2015.

The big issue that will challenge Canadian regulators in 2015 is the regulation of electricity rates in a world where utilities are facing declining volumes. We also look forward to the decision of the Supreme Court of Canada in April when it decides two appeals, one from Alberta and one from Ontario, dealing with one of most fundamental regulatory principles, the prudence of utility decision making.

Pipeline Construction Stalls

There is no question that the dominant regulatory issue in Canadian energy markets relates to pipelines. The ERQ has reviewed many of these projects at various stages in past issues. It is useful to see where they all stand year end. The product that is trying to find its way to market originates in the Alberta oil sands near Fort McMurray and the Bakken shale oil in North Dakota.

The cost of landlocked crude is real. Alberta Premier Jim Prentice has estimated that the lack of pipelines costs the federal and Alberta governments $6 billion per year. Western Canadian crude trades at a substantial discount to the international oil price because Canadian crude lacks easy access to world markets.

There are four projects that continue to dominate the discussion, TransCanada’s Keystone XL pipeline, the Enbridge Northern Gateway line, the Kinder Morgan Trans Mountain expansion and more recently the TransCanada Energy East project. All four projects have faced serious opposition from First Nations, environmental groups and local communities.

The TransCanada Keystone XL Pipeline

The Keystone XL pipeline, a $5 billion project, was first proposed by TransCanada in 2008 to transport crude from Canada through the Midwest and Texas to the Gulf of Mexico. The US Department of State has been reviewing the pipeline for nearly 7 years. The Canadian portion of the line obtained National Energy Board approval in 2010.

American approval has been held up by environmental opposition nationally, and local opposition in Nebraska. The latter led to court decisions and ultimately gubernatorial action to support the line, shifting the focus back to the national debate and the U.S. Congress.   In November 2014 the House of Representatives passed legislation that 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 67 vote majority required to override a presidential veto. On February 24, President Obama exercised his veto. That is where things stand as we go to print.

The Enbridge Northern Gateway Pipeline

The Enbridge Northern Gateway pipeline would run 1178 km from Bruderheim, Alberta to a marine terminal in Kitimat, British Columbia. One line would transport 525,000 barrels per day of Alberta oil west to tidewater. The other would bring 93,000 barrels per day of condensate back to Alberta to be used in the processing of Alberta’s bitumen.

The National Energy Board Joint Review panel issued its Report to the Federal Cabinet on December 19, 2013, and recommended approval of the project subject to 209 conditions. The Federal Cabinet accepted the panel’s recommendation in June 2014 and ordered the National Energy Board to issue Certificates of Public Convenience and Necessity subject to the conditions.

One of the conditions that the Joint Review panel established was a requirement that Enbridge reengage its consultation with First Nations. Enbridge restarted those consultations and they remain ongoing.

There are currently 18 appeals and review applications before the Federal Court of Appeal. There are five judicial review applications regarding the Joint Review Panel’s Report and nine judicial review applications relating to the Cabinet’s Order in Council directing the National Energy Board to issue Certificates of Public Convenience. To top things off, there are four appeals relating to the Certificates issued by the National Energy Board.

Most of these appeals have been commenced by First Nations groups challenging the adequacy of consultation. The others were brought by environmental groups challenging the adequacy of the environmental assessment. One of the larger issues is the Joint Review Panel’s refusal to take into account upstream environmental effects of oil sands production, an issue the Province of Quebec has taken up in the Energy East proceeding.

The Kinder Morgan Transmountain Expansion

On December 16, 2013, Kinder Morgan filed an application for approval of the $5.4 billion Trans Mountain Expansion project. Twinning the 1150 km existing pipeline from Edmonton, Alberta to Burnaby, British Columbia, the project would increase the capacity from 300,000 barrels per day to 890,000 barrels per day. The Westridge Marine terminal in Burnaby would also be expanded to allowBurrard Inlet tanker traffic to increase from 5 to 34 vessels per month.

The initial public hearing was the largest in the country – 1650 registered participants of whom 400 were granted full intervener status. Initially the line was to go through the

streets in Burnaby. Faced with widespread public opposition, Trans Mountain changed the route to tunnel through the Burnaby Mountain Conservation area. That met with even greater opposition. The City of Burnaby began issuing various bylaw infractions including an Order to cease and desist. Trans Mountain in response filed a motion with the National Energy Board seeking an order directing Burnaby to permit access to allow Kinder Morgan to do the necessary engineering studies.

In October 2014, the National Energy Board granted Trans Mountain permission to access the Burnaby Mountain facility to conduct the necessary studies. This was met with more protesters.

In September 2014, Trans Mountain filed a Notice of Constitutional Question with the National Energy Board. The Board agreed with Trans Mountain that the Board had the authority to determine that specific Burnaby bylaws were inoperative if they conflicted with the National Energy Board rulings under section 73 of the National Energy Board Act.

The Board also accepted Trans Mountain’s submissions that the doctrine of federal paramountcy or alternatively inter jurisdictional immunity made Burnaby bylaws inapplicable. This was the first time that the National Energy Board had issued an order against a municipality in connection with a dispute regarding a pipeline company’s access to the lands. The Federal Court of Appeal denied the City’s motion for leave to appeal from the Board’s decision, finding that federally regulated pipelines have the power to access public and private lands for the purpose of performing surveys and investigations under the National Energy Board Act. Richard King has provided an excellent summary of this constitutional battle in this issue.

The TransCanada Energy East Project

On October 30, 2014, TransCanada filed an application with the National Energy Board for approval of the Energy East project. This is a $12 billion project consisting of a 4,600 km pipeline to carry 1.1 million barrels of crude oil per day from Alberta and Saskatchewan to refineries in Montreal and Saint John, New Brunswick. To do this, TransCanada proposes to convert 3000 km of existing natural gas pipe to oil service between Saskatchewan and Ontario and to build 1600 km of new pipe in various provinces to connect with the converted pipe.

Shortly after filing the application, TransCanada revised its plan for a marine terminal in Cacouna, Quebec when the federal government concluded that beluga whales in the area would be in danger. At the same time, it was clear that Energy East was running into opposition in Ontario and Quebec, driven in part by local gas distributors (Enbridge and Union in Ontario and Gas Métro in Quebec) who were concerned they would lose gas transmission capacity.

The Provinces of Ontario and Quebec subsequently joined forces and insisted that seven conditions must be met if TransCanada wanted to obtain their approval of the pipeline. One of those is that natural gas capacity be sufficient to meet the needs of each province. Another and perhaps more important condition is that certain environmental assessments be taken into account concerning greenhouse gases.

Quebec appears to be seeking an environmental assessment that includes consideration of upstream greenhouse gas emissions from production outside the province. That is something the National Energy Board has consistently refused to consider and is the subject of one of the Federal Court appeals in connection with Northern Gateway.

Energy East is an interesting regulatory process. Few would doubt that the Federal government and the National Energy Board have exclusive jurisdiction over interprovincial pipelines. But pipelines also require environmental approvals, many of which are under Provincial jurisdiction.

Ontario and Quebec have initiated hearings before their own energy regulators to deal with their concerns regarding Energy East. Both regulators have been instructed to file Reports with the Provincial Minister of Energy. The Régie filed its report on December

18, 2014 and the Ontario Energy Board is expected to file its report in the spring. The plan is that these reports will serve as the basis for the interventions by both provinces in the National Energy Board hearing.

In the meantime many remain hopeful that Ontario, Quebec, and Alberta reach a settlement and put that settlement before the National Energy Board.

One argument that will be front and center is the very clear desire of the federal government and the Alberta government to get Alberta crude to tidewater. Northern Gateway is mired in aboriginal environmental opposition and the Trans Mountain expansion is not faring much better. In some respects Energy East is more promising, particularly if a deal can be brokered with Ontario and Quebec on environmental issues.

It may seem like a strange outcome but Energy East may result in the first carbon pricing plan adopted by a number of Canadian provinces

The Mainline Settlement

The most important regulatory decision in 2013 was the National Energy Board’s decision on March 27 to restructure TransCanada’s rates. That decision introduced some new and important legal concepts. The most important decision of 2014 was the reversal of that decision.

The 2013 Board decision, discussed in an earlier issue of ERQ, was that the cost of stranded assets should not be borne by the customer but by the utility. The rationale was that the utility had in the past been allowed a premium in its rate of return. That premium, paid by ratepayers, was designed to cover this risk. Now that the risk had arrived, it was TransCanada’s responsibility to manage it.

At the time, this finding sent shockwaves around the regulatory world, particularly the utility world. Utilities, citing well established legal principles, believed that if they made prudent investments they were entitled as of right to recover the cost of that investment. The Board did offer compensation of some measure – it increased the companies ROE from 8.07 per cent to 11.5 per cent, suggesting that perhaps the future looked a little riskier than the past.

The Board then gave TransCanada what it believed was the necessary tool to work its way out of the situation. Essentially the Board deregulated rates for discretionary services. The Board allowed TransCanada complete pricing discretion on short-term and interruptible services. There was some logic to this move. Interruptible services are always cheaper than fixed long-term services. Because every customer knew that the Mainline had excess capacity, they contracted for cheaper short-term service knowing they would never be interrupted. The reduced revenue did not help the TransCanada bottom line.

There was one other important finding in the initial decision that factored into subsequent events. The Board had found that TransCanada had no duty to serve because it had no exclusive franchise territory.

TransCanada applied to the Board for a review and variance. The essential component of that application was to increase the price from $1.42/gj in the decision to $1.52/gj. The Board rejected that application in its entirety.

TransCanada then turned to the marketplace. Because the Board had found that the utility had no duty to serve, TransCanada withdrew from earlier commitments to build new capacity. This led Union Gas and Gas Métro to apply to the NEB for an order requiring TransCanada to connect a new Union, Gas Métro pipe from Maple to Vaughn.

In another interesting turn of events, TransCanada and Enbridge entered into a Memorandum of Understanding which allowed joint use of parts of a new Enbridge facility from Parkway to Albion giving exclusivity to TransCanada. That exclusive arrangement was challenged by Union Gas and Gas Métro in a motion before the Ontario Energy Board. Enbridge then terminated the MOU with TransCanada. TransCanada responded by suing Enbridge in the Ontario Superior Court for
$ 4.5 billion.

All of this led to a settlement agreement between the three gas distributors and TransCanada crafted during the OEB fight. The settlement agreement includes capacity builds by each of Union, Enbridge, and TransCanada in the east, with a resultant decline in long-haul revenues being picked up by short-haul shippers including primarily Union, Enbridge, and Gas Métro. The settlement was then filed with the OEB in support of the Union and Enbridge projects and subsequently brought to the National Energy Board for approval of the resulting new tolls.

Under the settlement agreement, the tolls were even higher than TransCanada had proposed in the Review and Variance Application that the NEB had rejected. In addition, TransCanada received additional revenue recovery protection from a “bridging contribution” by shippers for revenue shortfall.

Finally the settlement agreements established a new rate of return on equity at 10.1 per cent. The March 27, 2013 decision had set the ROE at 11.5 per cent to recognize the increased risk that TransCanada faced. Previously that ROE had been 8.07 per cent.

On November 20, 2014 the NEB approved the Mainline settlement. Rates for 2015 to 2020 were increased substantially. Long-haul tolls increased from those approved in the original decision by 18 per cent. Short haul rates increased by 52 per cent.

The original National Energy Board decision on the Mainline restructuring in March 2013 had set the rate between Empress to Dawn at $1.42. Under the terms of settlement, that rate became $1.68. In effect the litigation between the parties before the National Energy Board, the Ontario Energy Board and the Ontario Superior Court had essentially reversed the original Mainline decision.

The Settlement Decision certainly casts some doubt on the principle advanced by the Board in the original decision that the risk of stranded asset costs was to be borne by the utility, not the customer. In the end it was the customers that bore the risk. The customers had no choice. TransCanada used the hammer that the Board had given it when the Board declared that TransCanada had no duty to serve. Relying on that principle, TransCanada withdrew planned facility expansions. For a short time the customers considered building the capacity themselves. But it became clear that was going to involve long and expensive litigation. Union, Enbridge, and Gas Métro decided to settle.

The New Ontario Quebec Alliance

Quebec and Ontario are in the process of developing important agreements regarding electricity trading and energy policy. Currently both governments and their energy regulators are involved in finalizing an electricity trade. The basic understanding is that Ontario will be allowed to borrow 500 MW of electricity from Quebec in the winter. In return Quebec can borrow 500 MW from Ontario during the summer. The Ontario amount cannot exceed the amount that Quebec borrows from Ontario. No money changes hands.

For a long time the Crown corporations that control much of the electricity production in Canada have concentrated on dealing with American parties south of the border. This changed in a major way on July 22, 2013 when the Nova Scotia Utility And Review Board approved the Maritime Link project that will deliver of power from the Muskrat Falls hydroelectric project in Labrador to Nova Scotia and through New Brunswick to the northeast Eastern US markets. The Quebec-Ontario energy trade is another important step in the development of East-West cooperation between Canadian provinces.

The other aspect of the growing Quebec-Ontario energy alliance is the cooperation between the two provinces in the Energy East negotiations, noted above.

It is evident that one of the conditions the two provinces are likely to demand is some commitment from the federal government on carbon pricing. Some media reports suggest that the Alberta government will join the Ontario-Quebec conversation in some capacity.

As in the Mainline settlement, the three gas distributors – Union, Enbridge, and Gas Métro – are key players behind the scene on Energy East. However a reading of the Quebec report suggests that those interests can be accommodated. The Ontario Report will no doubt address that issue as well.

Looking Ahead

The Supreme Court of Canada and the Prudence Test

As noted above, The National Energy Board did not accept the prudence test argued by TransCanada in the mainline case, despite previous confirmations of the test at the Supreme Courts of both Canada and the United States. TransCanada did not appeal the decision. However two cases, the Power Workers case in Ontario and the Atco Gas case in Alberta raised this same prudence principle. Both of those cases have been appealed to the Supreme Court of Canada. The cases were heard together on December 3. A decision is expected in April.

These are important decisions which could easily change the regulatory landscape in Canada. There is nothing more important to a utility than the ability to recover major capital or operation expenditures in rates.

In Power Workers, the Ontario Energy Board denied Ontario Power Corporation recovery of $145 million of labor costs. Those costs were driven by a collective agreement the utility had entered into with the union two years earlier. In reaching that agreement, the parties had involved an independent arbitrator.

Both the union and the utility argued that the Board was required to presume the compensation costs were prudent. The Board disagreed and found it could rely on benchmarking studies comparing the OPG labor costs with the costs at other utilities. The benchmarking studies had been ordered by the Board in an earlier rate case. As a result of this analysis, the Board disallowed $145 million in labor costs.

The Board recognized the constraints on OPG but held nonetheless that ratepayers were only required to bear reasonable costs. An appeal to the Ontario Divisional Court upheld the $145 million reduction, stating that the Board must have the freedom to reconsider current compensation arrangements in order to protect the public interest. That decision was overturned by the Ontario Court of Appeal, which held that the costs were committed costs fixed by collective agreements and the Board had violated a fundamental principle of the prudence test – namely whether an investment or expenditure decision is prudent must be based on the facts available at the time. The Board cannot use hindsight.

The ATCO case in Alberta is similar to the Power Workers case. In the Alberta case, the utility had asked the Utilities Commission to approve a special charge to the ratepayers which would cover a unfunded pension liability of $157 million. Those costs included a cost-of-living allowance that was set in advance each year by an independent administrator. The allowance was set at 100 per cent of the consumer price index.

As in Power Workers, the Alberta utility argued that this was a committed cost set by an independent authority and was therefore a prudent expenditure by the utility. The Alberta Commission disagreed and reduced the cost-of-living allowance to 50 per cent of the consumer price index.

In disallowing part of the expense, the Commission relied on evidence that an escalator equal to 100 per cent of CPI was high by industry standards. The utility appealed to the Alberta Court of Appeal which upheld the Commission decision.

There are only a few fundamental principles of public utility law. The prudence doctrine is one of them. Disallowing capital or operations expenditures years after the decision has been made concerns utilities. But the regulators from both provinces were united in another principle – utilities cannot rely blindly on a third party, whether a labor arbitrator or a pension administrator. The regulator has a responsibility (as does the utility) to make a determination whether the costs are reasonable for ratemaking purposes. Utilities may have a greater due diligence burden going forward. The Supreme Court of Canada decision will have major implications for Canadian ratemaking.

Customer Owned Generation

At the beginning of this editorial, we mentioned that the producing sector is facing a dramatic change in circumstances brought about by the sudden 50 per cent drop in the price of crude. There is another industry participant that is also facing dramatic change- the electricity distributor.

The agent of change here is not crude, it is customer-owned generation. There is a wave of technology unfolding that will soon allow many electricity customers to generate their own electricity.

Across North America electricity sales peaked nearly 6 years ago. Per capita consumption has been stagnant for over a decade. In part this is a reaction to higher prices. It is also a reaction to widespread conservation and energy efficiency programs. But more recently it is a function of new options customers have to generate their own electricity at prices less than the grid cost.

As new self-generation technologies enter the market at increasingly lower cost points, it is the electric distributors which are particularly vulnerable. Distributors exist to distribute electricity from central sources of generation (e.g., large natural gas power plants, wind farms, hydro facilities, etc) to the customer’s premises. If a customer can generate a portion of their own electricity, they can rely less on electricity from their distributor.

Customer generation first gained prominence with solar power, which has witnessed a dramatic decline in solar panel price – falling 20 per cent per year between 2009 and 2013. In the same timeframe the output has risen from over 1000 MW to 12,000 MW in the United States. In this period, solar as a percent of newly constructed US power plant capacity has risen from 6 per cent to 31 per cent.

Solar is a bigger problem for utilities in the southern United States. In 2014, San Diego Gas and Electric had 39,000 rooftop solar installations representing 270 MW of capacity equivalent to 6 per cent of the companies peak load. But the utility estimates that by 2015 rooftop solar will equal 540 MW or 12 per cent of peak load.

The real customer-owned generation threat for the Canadian electricity distributor and the Canadian energy regulator is not solar. It will have an impact but not nearly as substantial as in the southern United States.

In Canada, the emerging technology innovation is micro combined heat and power (CHP). As the name suggests, the technology is a single unit producing both heat and electricity. It is not new technology – CHP has been used in industrial applications for decades and a number of Canadian natural gas utilities have experimented with residential-CHP units over the years1. The issue at the time was cost, with installed costs in the order of $20,000. What is new to the North American market is consideration of an application small enough to be considered at the household level. The Japanese are global leaders in technology development here and they have the cost of a residential unit down to the $$7,000-10,000 range. Efforts are under way to bring this down to below $5,000 by 2017.

This will be an aggressive competitive market with equipment and services supplied by well-known multinationals, and opens the door to a discussion about the opportunity to integrate electric and natural gas delivery systems (CHP at the residential level is natural gas fuelled) in a way that has never occurred before.

Nor will this market be limited to CHP. Panasonic, Toshiba, and Tokyo Gas are currently developing hydrogen fuel cell units for the same purpose.

The first regulatory issue concerns a change to rate structures. Across North America, electricity regulators are implementing fixed charges to protect their utilities. Fixed charges are controversial and would have a significant impact on the economics of micro-CHP – in the event the fixed charge was proportional to the decline in electricity use of a home through self-generation.

Some argue fixed charges shift costs from heavier and wealthier users to poorer and less frequent users. Conservationists say that fixed charges will remove the incentive for conservation. Economists say they will simply drive-up prices by charging consumers for electricity they do not use. To the extent prices go up, customers will abandon the grid even more quickly. Some will argue that fixed charges are simply a stranded asset charge. They will argue, as the NEB found in Mainline, that stranded asset costs should be borne by the utility, not the consumer. Finally, some argue that fixed charges run counter to the principles of incentive rate making.

Where fixed charges will end up is hard to say. The Ontario Energy Board is taking the lead in Canada. In April 2013 the OEB established a consultation and has received over 30 submissions. The Board will issue a report in March (2015).

Many argue that fixed charges are not a long-term solution in any event. What is the long-term solution?

This technology will arrive whether the regulators or the utilities like it or not. Customers will move to lower cost generation. Politicians will not block them.

The Canadian electricity distributor may have been shielded from solar by the weather. But CHP and hydrogen fuel cells are a different matter. They are not dependent on the sun. We should remember that only 11 per cent of wind and solar is customer owned. In the case of CHP and hydrogen cells that figure may end up being much much higher.

The only real long term solution may be to allow utilities to take a direct role in supplying distributed generation to their customers. Distribution utilities, after all, have the key assets: capital, brand recognition, and strong customer relationships. Distribution utilities can easily compete with the strongest multinationals. It is unlikely that customers will insist on owning and maintaining these systems. But customers will want the lower electricity costs customer owned generation offers.

The Ontario Energy Board has taken a leadership step in this direction. Under the direction of the Minister of Energy, the Board has reduced the traditional barriers that prevented electric utilities from operating and owning CHP generation and other energy efficiency technology. These facilities can now be owned and financed within the utility. These are however not rate based assets and accounting standards must be followed to ensure that there is no cross subsidization.

Five years from now the only successful electricity distributors may be hybrid organizations offering both monopoly and competitive services. No doubt the transition will have its challenges. It may prove to be even more challenging for the regulators as they look to balance the needs of the utility and the changing consumer demands and preferences related to electricity self-generation.

  1. For further information on studies in Canadian residential CHP, visit Canadian Center for Housing technology, Stirling Engine, online: Government of Canada <http://www.ccht-cctr.gc.ca/eng/projects/chp_striling.html>.

Leave a Reply