The New Industry Dynamics

Six factors currently drive the energy sector in Canada at the national level: the drop in the price of oil; pipeline delays; the increase in shale gas; the increase in the delivery of crude oil by rail; increased carbon regulation; and the drive to renewable energy.

There have been other changes at the local level, particularly in Ontario and Alberta. The year started off when Ontario legislation came into force on January 1 completing the merger of the Independent Electricity System Operator (IESO) and the Ontario Power Authority (OPA).

In April, Ontario announced its intent to develop a cap and trade system linking with Québec in California through the Western Climate Initiative (WCI). Alberta followed a few months later announcing an economy wide carbon price of $30 per ton beginning at $20 per ton in January 2017 and moving to $30 per ton in January 2018. The carbon price would be applied to end-user emissions similar to the system now in place in Québec and California. Distributors of transportation and heating fuels would be required to acquire emission permits reflecting the emissions their products create when used. Permits could be acquired either through the purchase of credits from other emitters, through the purchase of Alberta-based offsets or through the payment of the carbon levy to the Alberta government.

On November 12, 2015 Ontario announced the completion of the first phase of Hydro One’s initial public offering that generated $1.8 billion in gross proceeds dedicated to critical infrastructure and transportation investment. The divestiture was based on recommendations from the Premier’s Advisory Council on Government Assets led by Ed Clark formerly Chair of the TD bank. The Hydro One divestiture was quickly followed by the November 19th vote of the Markham Council on the proposed merger of PowerStream, Enersource and Horizon Utilities and the joint acquisition of Hydro One Brampton. This was the final shareholder approval required to complete the megamerger long promoted by the Ontario government. A merger application will be placed before the Ontario Energy Board next month.

On December 13, 2015 the Ontario Minister of Energy announced an updated contract with Bruce Power for the refurbishment of six nuclear units at a cost of $13 billion. In December the government also announced a $234 million commitment to fund natural gas expansion in the province. At the same time the Ontario Energy Board established a generic hearing to determine whether existing ratepayers should subsidize the expansion and who would be eligible for the subsidy.

The year ended with the Auditor General claiming that Ontario customers had paid $37 billion above market price for electricity over the past eight years. At year-end Alberta also made an important announcement- it would phase out its coal-fired power plants by 2030 and replace two thirds of the existing coal-fired capacity with renewable energy.

The Oil and Gas Market Collapse

From an industry perspective, no economic variable is more important than the price of oil. In 2014, we saw the price drop by over 50 per cent.   The price decline continued in 2015. The price is now below US$30 per barrel, the lowest level since 2003. It is a long time since we experienced this turn of events. Thirty years ago, the price of crude dropped 67 per cent between November 1985 and March 1986. Between June 2014 and December 2015, crude prices have also fallen by 70 per cent.

It is clear why this happened. American production is skyrocketing from the shale deposits. This led to an oversupply and so the world market prices dropped. Over the past five years, American shale gas production has tripled from about 10 billion cubic feet per day to more than 30 billion cubic feet per day. Tight oil has registered similar gains and now stands at over 3 million barrels per day. This new gas production comes from the Marcellus shale in Pennsylvania, the Utica shale in New York, and the Barnett shale, as well as shale deposits in British Columbia.

In 2013, the total US recoverable gas resource was estimated to be 2,689 trillion cubic feet. In the same year, US demand was 26 trillion cubic feet. That means there is enough natural gas to meet demand for more than 100 years. Cheap gas has changed the industry. It has led to a massive investment in new LNG facilities that have been permitted in the past few years. Cheap gas also means it is cheaper to produce electricity from gas-fired generation, a major factor behind distributed generation, another disruptive technology.

The Saudi share of the world oil market declined, but rather than drop production, the Saudis dropped price. That action was based on their view that the Saudi cost of production is below the shale cost. Shale production costs however continued to drop based on new technology. To add insult to injury, crude is now flowing from Iran with the recent lift of sanctions.

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 US$15 billion between 2015 and 2017, cancelling or delaying some 40 projects. Conoco Phillips, the largest US exploration and production company, is cutting its capital spending 33 per cent this year. Suncor Energy, the largest Canadian energy company, is cutting its 2015 budget by $1 billion as it delays major oil sands production and the expansion of the White Rose project off Newfoundland and Labrador.

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. This is where the regulatory challenge comes in. Later in this editorial we described the regulatory challenge associated with customer owned generation. Customers move to local generation to reduce their energy costs. A significant part of the economy comes from cheap natural gas combined with advanced CHP technology. Hence the move by gas utilities in California to offer both gas and electricity service under a new DERS tariff – not good news for the electric LDC, or the regulator.

Pipeline Delays

The dominant regulatory issue in Canadian energy markets involves pipelines. It is useful to review where these pipeline projects stand at year end. 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.

All of these pipeline projects were reviewed extensively in last year’s annual review. There is little that can be added. There is one exception. The controversy regarding TransCanada Keystone XL line has now ended. It has been declared dead by President Obama.

The President’s decision has resulted in a claim for damages of $15 billion under Chapter 11 of the North American Free Trade Agreement (NAFTA) on the ground that the denial of a Presidential Permit for the Keystone XL Pipeline was arbitrary and unjustified, and breached the US administration’s NAFTA obligations. TransCanada also filed a lawsuit in the US Federal Court in Houston claiming that the President’s decision to deny construction of Keystone XL exceeded his power under the US constitution. This will no doubt keep many high-priced lawyers and arbitrators busy for years.

There are lessons to be drawn from Keystone – lessons which the company is learning again in connection with its Energy East pipeline. That lesson is that pipeline construction is all about dealing with environmental and aboriginal groups. To this we can now add mayors looking for economic benefits. A group of 12 mayors in the Montreal area have now banded together to oppose Energy East and the mayor of Burnaby has become famous in connection with his opposition to the Kinder Morgan Transmountain expansion.

The Energy East debate has the unfortunate potential to drive a wedge between East and West-a controversy not seen since the current Prime Minister’s father was in office. Readers that visit the Glenbow museum in Calgary should watch the 15-minute video detailing Alberta’s objection to the National Energy Program. This is required viewing for those who forget how divisive national energy policy can be.

Fortunately Energy East has some allies, particularly in New Brunswick. That may make a difference. And the decision of Canadians on October 19, 2015 to grant Justin Trudeau’s Liberals a majority government representing 184 of 338 seats in the House of Commons may signal a greater commitment to a national energy policy.

Crude-by-rail Takes Off

The inability to build 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, Northern Alberta, or the shale deposits in the Bakken formation, North Dakota.

The Canadian dependence on oil trains results from the fact that the US$6 billion Keystone XL pipeline has been blocked since 2008, and the more recent Enbridge Northern Gateway, an US$8 billion dollar investment to move oil sands crude to Kitimat, British Columbia, and then to Asia, is nowhere after six years. The result is a massive growth in crude-by-rail traffic. 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 per cent increase in two years.

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 so 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 Mégantic, 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-Mégantic on 5 July 2013. On that day, 72 cars carrying North Dakota crude were handed off by the Canadian Pacific Railway in Montréal to a short-line railway called the Montréal, Maine and Atlantic Railway to take the crude to the Irving refinery at Saint John, New Brunswick. Sixty-three of the 72 cars derailed in Lac-Mégantic, 30 miles north of the US border, killing 47 people and causing hundreds of millions of dollars in damage.

The Lac-Mégantic accident also led to class actions in Québec and Illinois. The defendants include: the two companies that produced the oil; the two railroads (the Canadian Pacific Railroad and the Montréal, Maine and Atlantic Railroad); the four companies that manufactured and leased the tank cars; the Irving refinery in Saint John, New Brunswick; and the three companies that owned the crude.

The litigation also involves the Canadian regulator, Transport Canada, and the Government of Canada. Both the regulator and the Government of Canada were accused of negligence. The regulator was accused on the ground that 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 rail- road 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.

The year 2015 finally saw the end of this saga. Both the American and Canadian governments approved new safety standards on railcars and increased insurance requirements for carriers. Courts in Canada and the United States also approved a class action settlement that saw some $446 million in compensation paid. The settling parties included Irving Oil in New Brunswick, World Fuel Services which sold the crude to Irving, Conoco Phillips, and the makers of the tank cars.

Of the $ 446 million settlement some $ 111 million went to the families of those killed, and $200 million to the Québec government and the town of Lac Mégantic. The rest went to other claims and legal fees. The only party that has not settled is the Canadian Pacific Railroad that now faces additional litigation from the province of Québec on the basis that the company was negligent in handing over the tank cars to Montréal, Main, and Atlantic Railroad which is now bankrupt. Litigation by the CPR still continues in the Federal Court of Appeal.

The Drive to Renewables

The past five years have seen a dramatic increase in the amount of electricity generated from renewable resources, principally wind and solar. Figures just released by the Federal Energy Regulatory Commission indicate that renewables now account 17 per cent of operating generating capacity in the United States but over 65 per cent of new capacity. Goals and mandates for renewable energy continue to grow. The goal is 100 per cent in Hawaii by 2045, 75 per cent in Vermont by 2032, 50 per cent in California by 2030, and 80 per cent in Germany by 2050.

In November the Ontario IESO selected nine new energy storage projects through a RFP for 16.75 MW of capacity. This marked the completion of a procurement of 50 MW of energy story called for in the 2013 LTEP.

Production from both wind and solar is unpredictable and that has placed a reliance on investment in new storage facilities. Historically storage has provided backup for commercial and industrial operations. Today it is crucial to the integration of renewables. In a world of increased renewables, storage is a key reliability asset. Many government agencies are now establishing programs to encourage procurement by both utilities and non-utilities.

The wind and solar investment has been driven by government incentive programmes. In Canada, that was largely the province of Ontario, which established a widespread feed in tariff (FIT) programme under the Green Energy and Green Economy Act, 2009.1 Under the FIT contracts, the government offered a 20-year supply contract at prices substantially above market. To further complicate matters, the Ontario programme had a substantial minimum domestic content requirement. That requirement was successfully challenged by Japan and Europe in WTO cases requiring amendments to the programme.2

Another challenge was the action taken by the Government of Ontario to cancel some of these programmes. The province discovered there was excess capacity on the network at night when there was less demand for the energy and wind blows the hardest. As a result, the province ended up paying American customers to take energy off the grid. The 2011 cancellation of all offshore wind projects and the 2009 decision to drop the rates for ground mounted solar from 80 cents to 59 cents per kilowatt hour led to further disputes.3 At year end there were two NAFTA tribunals hearing claims involving cancelled Ontario renewable projects and one action in the Ontario courts concerning another cancellation.

The biggest renewable story of the year may be the Alberta government announcement on November 22, 2015 to phase out its coal-fired power plants by 2030 and replace two thirds of the coal fired electricity capacity with renewable energy.

The province’s Advisory Panel recommended that this be done while retaining Alberta’s competitive electricity market structure. The Panel proposed a clean energy call with the Alberta government providing long-term revenue certainty for new renewable power. This would be an open competitive request for proposals with the government committing to a schedule of annual financing to achieve 350 MW of new capacity by 2018. The government plans to purchase renewable energy credits or REC’s from the projects under long-term contracts.

The other challenge in this new policy is how to determine the compensation for the coal-fired plants that will be removed from service prior to their planed end-of-life. The Alberta IESO-plans to establish a Panel of facilitators to determine the amount of stranded assets and the relevant compensation.

The New Regulatory Challenges

As energy regulators look forward to 2016 they can expect four major challenges: the allocation of stranded asset costs between customer and utilities, an increase in market manipulation hearings, and the challenge of regulating customer-owned generation and carbon.

The Allocation of Stranded Asset Costs

The last two years have seen a number of decisions by both regulators and courts that have dramatically changed the regulatory landscape in Canada. They all deal with a very simple question. Who bears the cost of stranded assets? Is it the ratepayer or the shareholder? At the end of the day they all came to the same conclusion: stranded asset costs are for the account the shareholder.

The controversy really began with the Supreme Court of Canada Stores Block decision in 2006.4 That case established two important principles. First, the customer has no ownership interest in the assets of the utility. Second, the regulator has no authority or jurisdiction to grant the ratepayer any part of the proceeds from the sale of an asset.

It follows by extension that the regulator has no authority to penalize the ratepayer if the asset declines in value. Put differently, the costs of stranded assets are for the account of the shareholder not the ratepayer. It took nine years of litigation following Stores Block to confirm that point.

Stores Block may be the beginning of the end. The end came between 2013 and 2015. In 2013 the NEB delivered its TransCanada Pipelines decision5 followed by the Alberta Utility Commission’s UAD decision6 and the confirmation of that decision in 2015 by the Alberta Court of Appeal decision in Fortis Alberta.7

The prudence doctrine which was challenged in both Alberta and Ontario8 came before the Supreme Court of Canada in 2015. Both cases concerned the long accepted prudence doctrine which held that an examination of prudence could not be based on hindsight and furthermore, there is a presumption of prudence.

The Supreme Court rejected that notion concluding that the prudence principles could not be found in the statute.9 In short utilities could not rely on those principles to support their argument that they were entitled to be compensated for the cost of stranded assets. Utilities had argued that past investments were prudent decisions and accordingly they were entitled to recover the cost of them throughout their life. The fact that the assets turned out not to be useful could only be determined with hindsight.

That principle the Supreme Court said was simply an urban myth and not binding law. It was simply a convention that regulators had adopted over the years; a convention that regulators could change any time they wished. Which is exactly what regulators did in both Ontario and Alberta.

The Supreme Court’s decision in Ontario Power Generation10 involved three important issues. The first was the discretion energy regulators have in setting just and reasonable rates. The second was the right of tribunals to participate in appeals of their own decisions. The third issue which is often overlooked was what is the scope and binding nature (if any) of public utility law.

The majority in Ontario Power Generation reaffirmed the broad discretion of energy regulators to set rates using the tools and methodologies that they consider appropriate the circumstances. In reality this was no great surprise. That movement began with the three decisions of the Supreme Court of Canada in 2011 involving Labrador Nurses Union,11 Alberta Teachers12 and Nor Man Regional Health.13

The second issue may however have far-reaching and practical implications. The Court rejected the argument of OPG and its unions that the input of tribunals in appeals from their decision should be largely restricted to addressing jurisdictional issues and providing clarifications. The Majority adopted a more flexible approach in determining the scope of tribunals appeals including such factors as whether the appeal would be otherwise unopposed and whether the tribunal’s original ruling was adjudicative or regulatory in nature. The Majority concluded that the OEB was not acting improperly defending its own decision given that the decision was regulatory in nature and practically speaking no one else was likely to defend it.

The third issue is equally interesting. The prudence principle is a time-honored concept of public utility law first established by the US Supreme Court in 1923 by Justice Brandeis in Southwestern Bell.14 Canadian courts and regulators have adopted the principle over the years including most recently the 2006 decision of the Ontario Court of Appeal in Enbridge,15 the 2004 decision of the Alberta Court of Appeal in Atco Electric16 and the decision the Federal Court of Appeal in the same year in TransCanada.17

Some practitioners have come to believe that the principles of public utility law such as the prudence doctrine, the obligation not to discriminate unjustly between customers,18 not to set rates retroactively,19 not to refuse to serve a customer20 or refuse access to essential facilities21 and not to contract for rates different than the tariff rate22 are a form of common law. But we forgot, as Justice Rothstein reminded us, that regulators are not courts and common law is a court concept. Regulators live in a different world, period. They are administrative tribunals and any principles binding on them must be found in the statute. There was nothing in the statutes governing the OEB that stated that the regulator cannot use hindsight in determining prudence or that there was a presumption of prudence. As a result, this so-called concept of public utility law was not binding.

Of course that doesn’t mean that there are not some binding principles. Stores Block23 is a good example. The issue there was property law. It is also a principle of public utility law that ratepayers have no property interest in the assets of utility. However, the Supreme Court of Canada there held that that principle was binding on regulators because it was a fundamental property law concept.

Justice Rothstein may have left town but the Supreme Court still sits in Ottawa. And an application for leave to appeal is currently before that court in connection with the Alberta Court of Appeal decision in Fortis Alberta. The court’s decisions in OPG and Atco Pensions were released one week after Fortis Alberta. So the prudence doctrine and the scope of the principles binding on regulators may come back to that court shortly. The decision on the application for leave is expected by the end of June, 2016.

Regulating Market Manipulation

On July 27, 2015 the Alberta Utilities Commission released a major Canadian decision involving market manipulation.24 The 217 page decision followed a three year investigation and a three-week hearing. The Alberta decision is a major step forward in this branch of energy regulation.

The Commission used a two phase proceeding. Phase One dealt with the substantive allegations. Phase Two dealt with the appropriate administrative penalties.

The Commission found that TransAlta intentionally took certain coal-fired generating units off-line for repairs during periods of high demand. The Alberta Market Surveillance Administrator (MSA ) argued that TransAlta could have made those repairs during periods of lower demand but instead the company elected to drive up electricity prices by reducing supply during peak hours. The Commission accepted that position.

The MSA also claimed that two TransAlta traders used non public information to trade in the Alberta electricity market. The Commission found however that that the first trader took all reasonable steps to avoid breaches by obtaining direction from senior TransAlta management and concluded that the trader had established a defense of due diligence. In the case of the second trader the Commission concluded the MSA had failed to demonstrate that the trader had used non public records during the relevant period.

Under the Consent Order25 TransAlta agreed to pay in excess of $56 million consisting of an administrative penalty of $51.9 million and, $4.3 million in MSA costs. The administrative penalty of $51.9 million consisted of two components. The first was disgorgement of $26.9. The second was an administrative monetary penalty of $25 million.

The decision is a textbook on the principles involved in regulating market manipulation. Like the decision on liability, the decision on the Consent Order explains in detail the jurisdiction of the Commission to accept the Consent Order.

This is a growing part of energy regulation. In recent years Ontario has also moved aggressively to enforce breaches of the Market Rules. A number of settlements have been reached although few are public. As energy markets trend toward more competitive solutions we will see more of these cases. The Alberta decision is a welcome example of timely and first class legal decision-making to be appreciated regardless of which side is viewing it.

Customer-owned Generation: Is Gas the New Electric?

Electricity sales peaked nearly six years ago throughout Canada. 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 grid cost.

Electricity distributors are particularly vulnerable. Distributors exist to distribute electricity from a central generator to the customer’s premise. If a customer can generate their own electricity, they do not need a distributor. Or at least not a full time distributor.

A new wave of technology is unfolding that will soon allow many electricity customers to generate their own electricity. The new technology threat is Micro CHP. This technology produces both heat and power. In fact the electricity is a free by product. A 1 kW CHP unit can provide heat and power for the average residential home. Of course the residential household will be the last market segment to convert. Before then will come micro grids for office buildings, universities and hospitals. This will be a competitive market with service supplied by both regulated and unregulated companies. The technology runs on gas, and gas is cheap. Gas may be the new electric. The California Commission recently granted San Diego Gas and Electric (SOCAL) the right to provide CHP service to hospitals, universities, and prisons as a regulated service.26 While the service involves the supply of both heat and power, the Commission ruled that SOCAL was not distributing electricity because the CHP facility was located on or near the customer premise and the electricity was not being resold.

The reason the customers want to leave the utility is at that there are lower cost alternatives. The most expensive part of electricity service in major markets is not the distribution services that distributors provide. It is the cost of the commodity – the cost of generation. Customers engaged in self-generation are simply trying to buy down the commodity cost.

There are four interesting questions:

  • Will customer generation become community generation?
  • Who will be the providers of private power systems?
  • Will local generators get access to LDC local lines?
  • What is the role of the regulator?

Earlier in this editorial we suggested that the major regulatory challenge in 2016 will involve the determination of who bears stranded asset costs, the customer or the utility.   Customer-owned generation may present an even greater regulatory challenge. By the end of 2016 most experts would agree that:

  • The distinction between gas and electricity will start to disappear as will the distinction between generation and distribution.
  • 20 per cent of the electricity in major markets will be generated locally.
  • Customers will move to new lower cost local generation with or without the assistance of the local electricity distributor. If they have to string their own wires, they will.
  • Local generation will become a highly competitive market. Competitors will include both electricity and gas distributors.
  • Co-Gen systems will migrate from customer premise to communities of interest or micro grids. Hospitals and universities will lead the movement.
  • Regulators will be forced to recognise the cost savings offered by the new technology and allow both regulated and unregulated companies to participate in the new competitive market.

Regulating Carbon

Canadian energy regulators will, as suggested above, face a serious challenges as they navigate through new rules from the courts on the allocation of stranded asset costs, new market manipulation prosecutions, and the regulatory challenges raised by customer-owned generation. There is one further challenge that energy regulators will face in 2016 – the new carbon tax regime that is developing across Canada.

To date Québec and British Columbia have been the leaders but 2015 saw important initiatives in both Ontario and Alberta.

Alberta will be facing an economy wide carbon price of $30 per ton of carbon beginning at $20 per ton in January 2017 and moving to $30 per ton January 2018. The price will be adjusted to keep pace with price increases in other jurisdictions. The carbon price (the word tax is not popular in Alberta) will be revenue neutral with funds generated to be reinvested into clean research and technology.

There will be a special 100 Mt of carbon limit on oil sands emissions compared to the current level of 70 Mt.

The Advisory Panel in Alberta described the Alberta proposal as being similar to programs in Québec and California and indicated that distributors of transportation and heating fuels would be required to acquire emission permits to reflect the emissions their products create when consumed. That will likely create some significant work for the Alberta Energy Regulator.

In Alberta the Advisory Panel recommends separate rules for large industrial facilities which produce over a hundred thousand tons a year. All emissions from those facilities will be priced but the facilities will be allocated credits in proportion to their output.

In Ontario the Minister of Climate Change announced in April 2015 that his government will develop a cap and trade system linking with Québec and California through the WCI. Ontario intends to finalize the regulations for implementation in 2017 and is expected to issue draft regulations in the first quarter of 2016. The Ontario Energy Board is expected to hold a consultation process which will specify in greater detail on the role of Ontario gas companies in this initiative.

As this Year in Review went to press the federal government announced that it hopes to set a minimum carbon price of at least $15 per ton for all provinces. The theory is that this floor price would encourage provinces that don’t have any tax to establish their own carbon price in order to collect the revenue.

The national minimum price being proposed is based on the price recently established by the WCI which now includes California and Québec. The minimum price auctioned off last year by the WCI was just above $15 per ton. That price is scheduled to increase to $20 per ton by 2020. The $15 per ton price contributes about 3.5 cents a liter to the price of gasoline.

Ontario is expected to join Québec and California in the WCI next year. British Columbia currently leads Canada with a carbon tax of $30 per ton. Alberta will introduce a $20 per ton carbon price next year. That is expected to increase to $30 a ton by 2018.

Most economists believe the $15 per ton price is not high enough to reduce greenhouse gases by the stated goal-a 30 per cent reduction from 2005 levels by 2030. Some economists claim that the price necessary to achieve the 2030 targets is closer to $280 per ton. The battle continues to unfold but one thing is clear- the direction of the Canadian federal government has changed significantly.

In the end, carbon policy will be about exceptions. There will be no bright lines but Ontario will lead the way.

Under the Province’s new plan, 102 large industrial firms will get free permits until 2017. This, as you might guess, is to allow them to “remain competitive.”

Fuel wholesalers, however, must purchase allowances for every litre of gasoline and cubic meter of natural gas they sell. The electricity sector, however, will get free allowances. The reason is- Ontario consumers are already paying for high cost wind and solar generation in an effort to reduce carbon.

  1. Green Energy and Green Economy Act, 2009, SO 2009, c 12, Sched A.
  2. Canada— Measures Relating to the Feed In Tariff Program (Complaint by European Union) (2014), WTO Doc WT/DS 426 (Appellate Body Report).
  3. Trilluim Wind Power Corp v Ontario, 2013 ONCA 6083; Capital Solar Power Corp v Ontario Power Generation, 2015 ONSC 2116; Carhoun and Sons v Canada, 2015 BCCA 163.
  4. ATCO Gas and Pipelines Ltd v Alberta (Energy and Utilities Board), 2006 SCC 4, [2006] 1 SCR 140 [Stores Block].
  5. Re TransCanada Pipelines Limited (Reasons for Decision) (March 2013), RH-003-2011 (National Energy Board).
  6. Re Alberta Utilities Commission Utility Asset Disposition (Decision) (November 2013), 2013 -417 (Alberta Utilities Commission).
  7. FortisAlberta Inc v Alberta Utilities Commission, 2015 ABCA 295.
  8. Power Workers Union (Canadian Union of Public Employees, Local 1000) v Ontario (Energy Board), 2013 ONCA 359, 116 OR (3d) 793); ATCO Gas and Pipeline Ltd v Alberta (Utilities Commission), 2013 ABCA 310, 556 AR 376.
  9. ATCO Gas and Pipelines Ltd v Alberta (Utilities Commission), 2015 SCC 45;Ontario Energy Board v Ontario Power Generation Inc, 2015 SCC 44.
  10. Ontario (Energy Board) v Ontario Power Generation Inc, 2015 SCC 44.
  11. Newfoundland and Labrador Nurses Union v Newfoundland and Labrador Treasury Board, 2011 SCC 62, [2011] 3 SCR 708.
  12. Alberta v Alberta Teachers Association, 2011 SCC 61, [2011] 3 SCR 654.
  13. Nor-Man Regional Health Authority Inc v Manitoba Association of Health Care Professionals, 2011 SCC 59, [2011] 3 SCR 616.
  14. Southwestern Bell Telephone Company v Public Service Commission,262 US 276 (1923).
  15. Enbridge Gas Distribution Inc v Ontario Energy Board,  [2006] OJ No 1355 (QL), 210 OAC 4 (Ont CA) [Enbridge].
  16. ATCO Electric Limited v Alberta Energy and Utilities Board, 2004 ABCA 215 [ATCO Electric].
  17. TransCanada Pipelines Limited v National Energy Board, 2004 FCA 149 [TransCanada].
  18. Red Deer v Western General Electric, (1910) 3 Alta LR 145; Bell Telephone v Harding Communications [1979]
  19. 1 SCR 395; St. Lawrence Redering v Cornwell, [1951] OR 669; Epcor Generation Inc v Alberta (Utilities Board), 2003 ABCA 374; Energy Commission, (1978) 87 DRL (3d) 727; Brant County Power v Ontario (Energy Board), EB-2009-0065 (10 August 2010) [Brant County Power]; Apotex Inc v Canada (Attorney General), [1994] 3 SCR 1100 [Apotex]; Portland General Exchange Inc, 51 FERC ¶61,108 (1990); United States v. Illinois Central Railroad,, 263 US 515,524 (1924).
  20. Northwestern Utilities Ltd v Edmonton (City), [1979] 1 SCR 684; Bell Canada v Canada Radio Television and Telecommunications Commission, [1989] SCJ No 68 at 708; Brosseau v Alberta (Securities Commission), [1989] 1 SCR 301; EuroCan Pulp and Paper v British Columbia Energy Commission, (1978) 87 DLR (3d) 727; Brant County Power, supra note 18; Apotex, supra note 18; Chastain v British Columbia Hydro, (1972) 32 DRL (3d) 443 [Chastain]; Challenge Communications Ltd v Bell Canada, [1979] 1 FC 857 [Challenge Communications]; Associated Gas Distribs v FERC, 898 F2d 809 (DC Cir 1990); San Diego Gas & Elect Co v Sellers of Energy, 127 FERC ¶ 61,037 (2009).
  21. Chastain, supra note 19; Challenge Communications, supra note 19; New York ex rel NY& Queens Gas Co v McCall, 245 US 345 (1917) 35 n62; Pennsylvania Water & Power Co v Consolidated Gas, Elec.Light & Power Co of Balt, 184 F2d 552 (4th Cir 1950).
  22. CNCP Telecommunications, Interconnection with Bell Canada, Telecom Decision, CRTC 79-11, 5 CRT 177 at 274 (17 May 1979); Otter Tail Power Co v US, 410 US 366 (1973); RE Canada Cable Television Assoc (Decision) (7 March 2005), RP 2003-0249 (Ontario Energy Board).
  23. Keogh v Chicago & Northwestern Ry Co, 260 US 156 (1922); Square D Co v Niagara Frontier Tariff Bureau, 446 US 409 (1986).
  24. Supra, note 4.
  25. Market Surveillance Administrator v TransAlta Corporation (Decision) (July 2015), 3110-D0I-2015 (Alberta Utilities Commission).
  26. Market Surveillance Administrator v Transalta Corporation (Request for Consent Order) (October 2015), 3110-D03-2015 (Alberta Utilities Commission).
  27. Re Application of Southern California Gas Company to Establish a Distributed Energy Reserve Tariff (Decision) (October 2015), A 14-08-007 (California Public Utilities Commission).

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