By Gordon Kaiser, Kaiser Arbitration
Noted regulatory expert Gordon Kaiser reviews the 2014 year and identifies underlying trends for the energy sector. Significant precedents were set, long-established core principles were reconsidered, and a major previous decision was effectively reversed. The industry has undergone structural change. New responsibilities have been placed on the shoulders of utilities and others. Provocative, insightful and challenging, Mr. Kaiser’s observations trace how the energy sector and the regulatory system are changing each other and suggest crucial implications for consumers and market participants to consider. An earlier version of this review appeared in the Energy Regulation Quarterly and it also draws on a lecture delivered at the Osgoode Hall Law School. – Editor.
2014 was a tumultuous year for the energy industry in Canada. The year saw the continued growth of high cost renewables, the collapse of the oil and gas markets, and a sudden increase in the number of crude by rail shipments.
It was also a busy year for any 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, and try to forecast the important regulatory developments coming in the year ahead.
The big issue that will challenge Canadian regulators in 2015 is the regulation of electricity rates in a world where those 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.
We will also look at path-breaking plans for energy cooperation between Ontario and Québec. Finally we will examine the possible settlement of the Energy East pipeline dispute as the Federal and Alberta Governments attempt to complete the drive to bring Alberta crude to tidewater.
The changing industry dynamics
The oil market collapse
From an industry perspective there is no economic variable more important than the price of oil. In 2014 we saw the price drop by over 50%. It is now below $50 a barrel, which many commentators believe is the cost of production in North America.
It is a long time since we experienced this turn of events. Thirty years ago the price of crude dropped 67% between November 1985 and March 1986. Between June 2014 and February 2015 crude prices have fallen by 57%. They could head lower.
It is clear why this happened. American production is skyrocketing from the shale deposits particularly in North Dakota. This led to an oversupply and the world market prices dropped. The Saudi share of the world market declined and rather than drop production the Saudis dropped price. That action was based on their view that the Saudi cost of production is below the Bakken shale cost.
The price of oil has an immediate impact on other products. Natural gas prices are now at a two-year low. Gasoline prices have dropped for 88 straight days, the longest streak of falling prices on record.
The impact on producers, whether in North America or the rest of the world, is real. Royal Dutch Shell, the largest European group, is cutting its capital spending by over $15 billion between 2015 and 2017, canceling or delaying some 40 projects. Conoco Phillips, the largest US exploration and production company, is cutting its capital spending 33% this year. Suncor Energy, the largest Canadian energy company, is cutting its 2015 budget by $1 billion as it delays major oil sands production as well as expansion of the White Rose project off Newfoundland and Labrador.
The impact on the regulated energy sector is less clear. For the most part public utilities have guaranteed rates of return. Lower gas costs could well reduce the cost of producing electricity from gas-fired generation. Some of that saving may flow through to consumers. Certainly the regulated gas distributors will find the commodity portion of their price is reduced and that will flow through to customers.
But the real impacts will be on the production side. There may, however, be some impact on the billions of dollars riding on the five major pipeline projects in Canada. The cuts to date have been largely confined to production expansion. This is an industry with huge fixed costs. As long as the revenues cover variable costs the producers will keep existing operations running.
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 shale gas in Pennsylvania and New York and the Bakken shale oil in North Dakota.
The cost of landlocked crude is real. Alberta’s Premier has estimated that the lack of pipelines costs the Federal and Alberta governments $6 billion per year. That is because Western Canadian crude trades at a substantial discount to the international oil price because Canadian crude lacks easy access to world markets.
There are five projects that continue to dominate the discussion, TransCanada’s Keystone XL pipeline, the Enbridge Northern Gateway line, the Enbridge line 9 Reversal, the Kinder Morgan Transmountain expansion, and more recently the TransCanada Energy East project. All five projects have faced serious opposition from First Nations and environmental groups.
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 a huge environmental lobby notwithstanding the State Department’s January 2014 Final 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 US 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 for a pipeline route across the state from the state’s governor rather than from the 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 challenged the decision in the Nebraska courts arguing that divesting the Commission of its regulatory authority was unconstitutional. The lower court agreed and on appeal the Nebraska Supreme Court affirmed the decision. However, the Nebraska Constitution requires a super majority of at least five votes to strike down laws as unconstitutional. The decision was only 4 to 3 and the legislation therefore stands.
After that development the focus shifted to 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 66 vote majority required prevent a presidential veto. President Obama has continually stated that he will exercise his veto to defeat the legislation. That is where things stand now.
The Enbridge Northern Gateway Pipeline
The Enbridge Northern Gateway pipeline will run 1178 km from Bruderheim, Alberta to a marine terminal in Kitimat, British Columbia. One line will transport 525,000 barrels per day of Alberta oil west to tidewater. The other will 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 a Certificate 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.
Northern Gateway, like many of these pipelines projects, faces many appeals. There are currently 18 appeals before the Federal Court of Appeal filed by nine different applicants. There are five judicial reviews regarding the Joint Review Panel’s Report and nine judicial reviews 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 other appeals 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. This has turned out to be a lively issue in subsequent proceedings. This is an issue the Province of Québec is taken up in the Energy East proceeding.
The Enbridge Line 9 reversal
In March 2014 the National Energy Board approved the Enbridge application to reverse the segment of its existing pipeline between Westover, Ontario and Montréal, Québec. The Board also allowed the company to expand the entire capacity from Sarnia, Ontario to Montréal from 240,000 barrels a day to 300,000 barrels a day. Enbridge had previously obtained Board approval to reverse the pipeline flow for the section running between Sarnia in southwestern Ontario.
At first this appeared to be an uncontroversial project. The pipeline was built in 1976 and operated without major incident for 35 years. However the Board’s approval was subject to a number of conditions and in October 2014 the National Energy Board decided that the company had failed to meet one of those conditions. Enbridge had not installed shutoff valves around some major waterways. Enbridge is the process of addressing those concerns and the lines is expected to go into service in 2015.
The Kinder Morgan Transmountain Expansion
On December 16, 2013, Kinder Morgan filed an application for approval of $5.4 billion Transmountain Expansion project. The project involved twinning the 1150 km existing pipeline from Edmonton, Alberta to Burnaby, British Columbia. This would increase the capacity from 300,000 barrels per day to 890,000 barrels per day. The project also included the expansion of the Westridge Marine terminal in Burnaby, which would allow the number of tankers traveling down the Bernard Inlet to increase from 5 to 34 per month.
The initial public hearing was the largest in the country – 1650 registered participants, 400 of which were granted full intervener status. Initially the line was to go through the streets in Burnaby. When they faced public opposition, Transmountain change 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. Kinder Morgan 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 the Kinder Board permission to access the Burnaby Mountain facility to conduct the necessary studies. This was met with more protesters.
In September 2014, Transmountain filed a Notice of Constitutional Question with the National Energy Board. The Board agreed with Transmountain that the Board had the authority to determine the specific Burnaby bylaws inoperative if they conflicted with the National Energy Board rulings under section 73 in the Act.
The Board also accepted Transmountain’s submissions that the doctrine of federal paramountcy or alternatively interjurisdictional 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 National Energy 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 Montréal and St. 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, Québec 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 Québec, driven in part by local gas distributors (Enbridge and Union in Ontario and Gas Metro in Quebec) who were concerned they would lose gas transmission capacity.
The Provinces of Ontario and Québec 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.
Québec 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 has exclusive jurisdiction over interprovincial pipelines. But it turns out that pipelines also require environmental approvals, many of which are under Provincial jurisdiction.
Ontario and Québec 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 Regie 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 it will surprise few if Ontario, Québec, 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 and environmental opposition and the Transmountain expansion is not faring much better. In some respects Energy East is more promising, particularly if a deal can be brokered with Ontario and Québec 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 Canadian provinces.
Crude by rail takes off
The inability to build new pipelines in Canada and the United States has led to a rapid increase in moving crude by rail. The oil starts in one of two sources – the oil sands in Fort McMurray in Northern Alberta or the shale deposits in the Bakken in the North Dakota.
The Canadian dependence on oil trains results from the fact that the $6 billion Keystone XL pipeline has been blocked since 2008 and the more recent Enbridge Northern Gateway, an $8 billion dollar investment to move oil sands crude to Kitimat BC and then to Asia, is nowhere after five years.
The result is a massive growth of traffic in crude by rail. In Canada crude by rail exports have grown from 20,000 barrels a day in 2012 to 170,000 at the end of 2014 – an 800% increase in two years. In the US, the growth was 400% between 2011 and 2012 – a one year period.
In the process, producers discovered some important features about crude by rail economics. Rail transport costs more than pipeline but rail offers a larger network. There are 57,000 miles of pipeline in North America but there are 140,000 miles of rail. And virtually every refinery in North America has a rail line coming to it. That is not the case with pipelines. And pipelines like long term commitments. Not crude by rail. The greater flexibility by rail allows refiners to take advantage of spot market pricing.
But there is a real downside to crude by rail. In 2013 and 2014 there were six crude train accidents. In 2013 there was Lac Megantic, Quebec in July, Aliceville Alabama in November, and Casselton, North Dakota in December. In 2014 there was Plaster Rock, New Brunswick in January; Lynchburg, Virginia in April; and Wadena Saskatchewan in October.
By far the greatest wake-up call came from Lac Megantic on July 5, 2013. On that day 72 cars with North Dakota crude were handed off by the Canadian Pacific Railway in Montréal to a short line railway called the Montréal Maine and Atlantic to take the crude to the Irving refinery at St. John, New Brunswick. Some 63 of the 72 cars derailed in Lac Megantic, 30 miles north of the US border, killing 47 people and causing billions of dollars in damage.
There has been a huge legal fallout as Federal regulators in both Canada and the US issued new regulations. These involved stricter tank car standards, more accurate testing and description of crude, better community notification, and greater insurance coverage.
The Lac Megantic accident also led to class actions in both Québec and Illinois. The defendants include the two companies that produced the oil, the two railroads (the Canadian Pacific Railroad and the Montréal Main and Atlantic Railroad), the four companies that manufactured and leased the tank cars, the Irving refinery in St. John, New Brunswick, the three companies that owned the crude, Transport Canada, and the Government of Canada.
Of interest to energy regulators may be the fact that both the regulator and the Government of Canada were accused of negligence – the regulator on the ground they were aware of the dubious history of the MMA, including its poor safety record, which included multiple violations. The company apparently had 129 accidents going back to 2003 and the poorest safety record of any railroad in North America. The Government of Canada’s liability was based on the ground that it had delegated its responsibility to a regulator that was negligent in the performance of its duties and statutory mandate.
Another interesting development from these accidents is the increased level of interest in major cities in both Canada and the United States in prohibiting crude by rail traffic within their boundaries. Both Toronto and Mississauga have taken that position as have a number of cities in California. This has led to constitutional battles in both countries. It reminds us of the City of Burnaby in British Columbia and its opposition to Trans Mountain.
The move in both Canada and the US to force railroads to upgrade tank cars is significant. And it will happen quickly. The liability for the railroads is too great and the traffic is too valuable. There is no doubt that oil trains will continue to be a fixture across North America given the slow development of pipeline construction. It may seem strange to some that that stopping pipelines on environmental grounds has led to a new form of transport that arguably causes even greater risks to the environment.
Crude by rail will continue even if pipelines get built because it offers shippers greater flexibility to get to refineries. The new safety regulations will be met ahead of schedule by the railroads. Crude is the largest source of new traffic they have seen in 50 years.
The new regulatory landscape
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 problem TransCanada faced was declining volumes over a number of years. When the pipeline was built it was designed to transport 7 bcf/d of gas. By the time of the National Energy Board hearing, the volume had declined to 1.5 bcf/d. Because most of the costs were fixed, the line was running at a huge loss. As a result, tolls increased. By 2013 it looked like a rate of 2.74/gj would be necessary to cover the cost of transportation from Empress to Dawn. In 2006 that rate was $.80/gj
The problem was caused by two factors. First, the expansion of shale production in the US had accelerated dramatically starting in 2008. That product was much closer to important Eastern customers than Western gas. Second, the production in Alberta had dropped significantly. This led to a 50% reduction in mainline flows over the six years from 2006 to 2012. The utilization of factor fell from 80% to 40%.
TransCanada responded by filing a path-breaking application to restructure tolls. The company proposed to shift $400 million in costs to users of the Alberta system as well as to reallocate $1.2 billion of accumulated depreciation from the prairie and Eastern triangle segments to northern Ontario segment.
The result was a 72 day hearing with 60 lawyers and 80 witnesses. Many interveners advocated a write-down of the Mainline rate base by removing approximately $3 billion from the requested $5.8 billion rate base. The Board rejected this proposal on the grounds that it did not have the jurisdiction to do it. Instead the Board concluded that the cost of stranded assets should not be borne by the customer but by the utility. (See IPPSO FACTO June 2013, cover story.) The rationale was that the utility had in the past been allowed a premium in its rate of return. That premium, paid by ratepayer, was designed to cover this risk. Now that the risk had arrived it was TransCanada’s responsibility to manage the risk.
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 – they increased the companies ROE from 8.07% to 11.5 %, 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 also 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 142/gj in the decision to 1.52/gj. The Board rejected that application 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 Metro to apply to the NEB for an order requiring TransCanada to connect a new Union, Gaz Metro pipe from Maple to Vaughan.
In another interesting turn of events, TransCanada and Enbridge entered into a Memorandum of Understanding that 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 Gaz Metro 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 resulting decline in long-haul revenues being picked up by short-haul shippers including primarily Union, Enbridge, and Gaz Metro. 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, the 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%. The March 27, 2013 decision had set the ROE at 11.5% to recognize the increased risk that TransCanada faced. Previously that ROE had been 8.07%.
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%. Short haul rates increased by 52%.
The original National Energy Board’s 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 were 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 Gaz Metro decided to settle.
The New Ontario-Quebec Alliance
Québec and Ontario are in the process of developing important agreements regarding energy trading and energy policy. Currently both governments and their energy regulators are involved in finalizing an energy trade. The basic understanding is that Ontario will be allowed to borrow 500 MW of electricity from Québec in the winter. In return, Quebec can borrow 500 MW from Ontario during the summer. The Ontario amount cannot exceed the amount that Québec borrows from Ontario. No money changes hands.
For a long time the crown corporations that control much of the energy 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 power from the Muskrat Falls hydroelectric project in Labrador to Nova Scotia and through New Brunswick to the northeast Eastern US markets. The Québec Ontario energy trade is another important step in the development of East-West cooperation between Canadian provinces.
The other aspect of the growing Québec-Ontario energy alliance is the cooperation between the two provinces in the Energy East negotiations. Both provinces have instructed their energy regulators to hold their own hearings on the subject matter and issue a report. The Québec report was released in December. The Ontario report is expected in the spring.
Even as those hearings move forward, the two Premiers are negotiating through their Energy Ministers. 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. It is generally expected that the Alberta government will join in the Ontario Québec in the negotiations before long.
The National Energy Board hearings on Energy East have yet to start. It may be a while before they begin, given the growing controversy of who will be entitled to appear in the NEB hearings. In any event, it is possible that like Mainline, the Energy East proceeding may involve the three provinces presenting a settlement agreement that has been hammered out with TransCanada before the hearing.
As in the Mainline settlement, the three gas distributors – Union, Enbridge, and Gaz Metro – are key players behind the scene. However, a reading of Québec 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
In the Mainline case before the National Energy Board, TransCanada relied on the prudence test that had been confirmed by both the Supreme Court of the United States and the Supreme Court of Canada over the years. TransCanada argued that the decision the company made years ago to build the mainline was a prudent decision based on the facts at the time, and the company was entitled to recover the capital costs in rates. Now that over half of the pipeline was underutilized and not generating revenue the company should be entitled to write off those assets and recover the costs in rates.
The National Energy Board did not accept that argument, but for a variety of reasons. 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 that 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 the Power Workers case, the Ontario Energy Board denied Ontario Power Generation 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 used 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 that would cover an unfunded pension liability of $157 million. Those costs included a cost-of-living allowance that was set in advance each year by independent administrator. The allowance was set at 100% of the consumer price index.
As in the Power Workers case, 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% of the consumer price index.
In disallowing part of the expense, the Commission relied on evidence that an escalator equal 100% 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 production sector is facing a crisis it has not seen in 30 years – the 50% drop in the price of crude. There is another industry participant that is about to face a crisis – 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 increasingly it is a function of new options customers have to generate their own electricity at prices less than the grid cost.
Distributors are particularly vulnerable. Distributors exist to distribute electricity from a central source to the customer’s premise. If a customer can generate their own electricity they do not need a distributor, or at least they do not need a full time distributor.
Customer generation first arrived on the scene in the form of solar. The price of solar fell 20% 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 new US power plant capacity has risen from 6% to 31%.
Solar, of course, 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% of the company’s peak load. But the utility estimates that by 2015 rooftop solar will equal 540 MW or 12% of peak load.
The real 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.
The real technology threat in Canada is micro-CHP. These units will produce both heat and light. In fact the electricity is a free by-product. A 1 kW unit can provide heat and light for the average residential home. There are six suppliers worldwide led by Toyota and Honda. These companies were recruited by the Japanese government after Fukushima to develop this technology. The cost of a residential unit today is around $10,000. By 2020 it will be less than $3000.
Of course the individual residential household will be the last market segment to convert. Before then will come microgrids for office buildings and condominiums. This will be an aggressive competitive market with equipment and services supplied by well-known multinationals. CHP has the added advantage that it is usually fuelled by natural gas, which is expected to be low cost for years to come. 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.
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 quicker. 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 was expected to issue a report in March.
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 cells are a different matter. They are not dependent on the sun. We should remember that only 11% of wind and solar is customer owned. In the case of CHP and hydrogen cells, that figure may be closer to 50%.
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 are 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 that 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.
The New IRM Calculation
There is an additional complication arising from declining utility volumes. If volumes are declining the productivity factor becomes negative. Virtually all regulators use a form of incentive rate regulation (IRM) or performance based rates (PBR). The concept is identical. PBR is a price cap formula where the price can be no greater than an inflation index, such as the consumer price index minus a productivity factor, usually referred to as X. With volume declining, the X factor becomes negative. And it has nothing to do with the utility’s performance.
Ontario has been involved in various forms of IRM for years. First-generation IRM came into force in 2000, second-generation IRM in 2006, third-generation IRM in 2008, and fourth-generation IRM in 2013. The process remained the same throughout except that the inflation indexes were modified and the calculation of the productivity factor varied.
The term of the IRM plans has eased over the years. It started as two years and is now 5 years. Most have included an earnings sharing mechanism (ESM) where at the conclusion of the plan the customers and the utility share the surplus or deficit in earnings relative to the allowed return on equity. That split and the extent of the dead-band has varied, but the concept has been constant.
The implications of declining volume for IRM first became evident in Union Gas case (EB-2013-0202) in 2013. This was a custom IRM application for rates in 2014- 2018. The case started April 29, 2013. The result was reached by settlement through negotiations between the utility and the interveners. The settlement was approved by the Board on October 7, 2013.
The Union application consisted of a traditional IRM but Union argued that the X factor or productivity factor was negative or at least zero. The interveners rejected that. Ultimately Union agreed that the price cap would be 40% of the inflation factor. No evidence was called with respect to productivity – it was strictly a matter of negotiation.
This concept was taken by the interveners into the Enbridge case shortly after (EB-2012-0459). This was not a settlement but a board decision after a hearing. This was a proposed a five-year custom IRM plan to begin January 1, 2014. The Board rejected the argument that the price cap should be inflation factor minus 60%. Instead they held that the increase in O&M should be limited to 1% per year over the five year term.
This trend continued in the Hydro One Transmission case (EB-2014-0140). This was a negotiated settlement in a two year Custom IRM application. In order to make the deal Hydro One agreed to reduce O&M by $20 million in each year. That reduced the amount from $452 m to $432m in 2014 and to $437m in 2016. O&M in the 2013 base year was $ 431m. As a result, O&M over the period was almost flat.
Finally we saw the Horizon Utilities case (EB-2014-0002), an application for a 5 year Custom IRM for 2015-2019. This was also a settlement. The parties agreed to limit the increase in O&M by 1.4% a year over the five year period.
What these four cases show is that the IRM mechanism has moved from the use of a productivity discount to limiting O&M expenses to something below inflation. The concept is the same. The Ontario Energy Board has essentially said to utilities: If you want to set rates for five years, O&M costs must stay below the rate of inflation.
Mr. Kaiser practiced law as a partner in a national law firm for over 25 years specializing in energy, telecommunications, competition law and intellectual property, and served as Vice Chairman of the Ontario Energy Board for six years. He has appeared in the courts in ten provinces as well as the Federal Court of Canada and the Supreme Court of Canada. Currently Mr. Kaiser acts as an arbitrator and mediator in complex commercial contracts with particular reference to energy, telecommunications, construction, project finance and intellectual property. More of his analysis and commentary may be found online at http://www.energyregulationquarterly.ca