2017: The Canadian Energy Year in Review

Each year when we write this Annual Review we marvel at how complex the industry has become only to find out that the following year makes the year before look tame. This year we had some assistance from south of the border when the new president turned many things on their head. That included energy policy but it turned out that the Americans have an amazing system of checks and balances. None of the threats have turned into reality but then the year is young.

As it turned out things at home are not that tame. Ontario took the bull by the horns and cut the price of electricity by 25 per cent loading the debt incurred on a regulated utility the Province owned to keep it off provincial books. That created some controversy which may not be over.

The first heading in last year’s Annual Review was “The Pipeline Delays Are Over.” It turns out we were wrong. Another heading was “Renewables Continue to Grow.” We were right about that.

In fact, the Province of Alberta this past year demonstrated how to buy renewables in an intelligent and cost-effective way. Those in Ontario shake their heads knowing that their cost of wind is likely four times the Alberta cost. So much for being a leader.

But as we said these are complex markets. This year’s Annual Review describes how three Provinces in this country can simultaneously rack up unbelievable debt building dams to deliver cheap hydroelectricity for their citizens.

“Storage and Embedded Generation” was another heading in last year’s Annual Review. That topic remains important. In fact integrating new technology into Canadian energy markets now represents the largest challenge for Canadian energy regulators. It is an important efficiency in a world with high prices and few tools left in the toolbox.

In this world it is not surprising that regulatory reform is being shouted from every corner by both energy regulators and the governments that appoint them. How that plays out in 2018 will be interesting to see. First to be reviewed was the National Energy Board. That led to two new agencies. One is a political agency, the other is an independent agency changed with conducting hearings. Next up to bat was the Ontario Energy Board. The Modernization Panel reviewing the OEB has yet to start work. It reports back at the end of 2018.

Before we turn to the Annual Review we should take a moment to reflect on the Energy Regulation Quarterly’s journey to its five year anniversary and thank some very important people.

The first five years have been interesting. This Journal was started by the Canadian Gas Association at no small cost. Some thought that it would simply become a form of lobbying for the gas industry. That turned out not to be the case. It proved to be remarkably independent.

Some thought that nobody would be interested in writing articles. That also turned out not to be the case. Over the five years, we have grown to depend on a very reliable group of contributors. Two of them are always featured in this annual year-end edition. They are David Mullan, an Emeritus Professor at Queen’s University, and Robert Fleishman, Senior Counsel at Morrison Foerster in Washington. Mullan’s annual article goes to the bread-and-butter of energy regulators – the new developments in administrative law. When that comes from the country’s leading administrative lawyer we should be particularly grateful. And we are.

Robert Fleishman’s annual Washington Report offers an important insight into energy law as it develops in the United States. Bob’s long service as the Editor of the Energy Law Journal in Washington led to many helpful tips for the Canadian startup.

We thank every one of our contributors and hope you keep up the good work. We also thank Tim Egan, the President of the Canadian Gas Association, and Mike Cleland, the former President of the Association that came up with this idea in the first place. We also thank the Canadian Electricity Association and their president, Anthony Haines, who later joined this effort and threw some money into the pot. We will report back when we hit 10 years.

Finally a special thank you to all of our interns from the Faculty of Law at the University of Ottawa. The ERQ is unique. This is the only energy journal that is published in both French and English. This means some heavy lifting for our interns. Thank you for all your help over the past five years. We learned a lot more from you than you learned from us.

Pipeline Delays are Back

Every year in this Annual Review, we start by reviewing the status of pipeline construction. There is no question that this is the dominant regulatory issue in Canadian energy markets. It is always useful to see where they all stand at year-end. Last year we reported that the pipeline delays were over. It turns out we were wrong.

The pipeline delays are back in full force. In fact, we could argue that the problem has never been greater. It now borders on a constitutional crisis.

The cost of these delays remains real. In 2014 we quoted the late Alberta Premier Jim Prentice who said that the lack of pipeline access cost the federal and Alberta governments $ 6 billion per year. This year the CD Howe Institute has weighed in and estimates that pipeline bottlenecks cut five dollars off the profits of every barrel of oil produced in Western Canada. Frank McKenna, the deputy chair of the Toronto Dominion Bank recently weighed in on the debate noting that the differential between benchmark U.S. prices and Western Canadian select heavy crude is now $11 a barrel. That is down from $40 a barrel in December 2013 but the cost remains significant. According to McKenna, this price differential cost Canada $117 billion in the past seven years.

In the end, it is all a very sad commentary on the Canadian regulatory process. And some would argue the lack of federal government initiative in establishing clear directions for national projects crossing provincial borders.

We can start with the saddest story of all -the TransCanada Energy East pipeline. If ever there was a case of regulatory mismanagement, this is it. TransCanada first announced the $15.7 billion project to build a 4500 km pipeline from Alberta to the East Coast in April 2013. The concept was based on the fact that Canada’s East Coast refineries rely on imports for 80 per cent of their requirements. Alberta crude could replace the foreign crude – an interesting idea.

The first major setback occurred in August 2016 when the NEB suspended hearings until the Board ruled on motions demanding that three panel members resign on the grounds they were biased because they had met with the ex-Premier of Québec. In September, the NEB replaced all three panel members with a new panel which threw out all of the decisions of the previous panel including all hearing steps and related deadlines.

Then in August 2017, the NEB released a decision indicating that it would allow a wider discussion of greenhouse gas emissions in the new hearings including a ruling that for the first time it would consider the public interest impact of upstream and downstream carbon emissions from the increased production and consumption of oil resulting from the project. That was enough for TransCanada. In October 2017, the company announced it was no longer going ahead.

Before moving ahead with more bad news we turn to one piece of good news for TransCanada. As reported last year President Trump had approved Keystone XL after President Obama had turned it down. That had led to all kinds of NAFTA claims and constitutional challenges. But those were dropped when President Trump arrived on the scene.

As the year 2017 came to a close, good news came from Calgary. TransCanada had secured a 500,000 barrels a day 20-year commitment after conducting an open season locking up about 60 per cent of the 830,000 barrel a day capacity. TransCanada Chief Executive, Russ Girling, thanked President Donald Trump for his continued support of project as well as the efforts of other U.S. backers and the Alberta government. The Alberta government had stepped in to commit 50,000 barrels a day for the project from some of the royalties it receives as barrels of oil. The premier’s spokeswoman noted: “it’s good for the project, it’s good for the industry and it’s good for our differential.”

Last year it looked like the Kinder Morgan Trans Mountain pipeline was moving forward. Kinder Morgan had filed the application for approval of the $5.4 billion project twinning the existing pipeline from Edmonton, Alberta to Burnaby, British Columbia on December 16, 2013. The project was designed to increase capacity from 300,000 barrels per day to 890,000 per day. The West Ridge Marine terminal would be expanded to allow Burrard Inlet tanker traffic to increase from 5 to 34 vessels per month not a small increase in capacity.

For some period of time Kinder Morgan had faced fierce opposition from the mayor of Burnaby and his allies but generally received support from both the NEB and the courts. However, the year 2017 produced a change in events. A new government was elected in B.C. and the new Minister of Environment announced that the Province was considering new regulations that would likely stop pipeline companies from shipping bitumen. The province said that the new regulations were necessary to give the province time to undertake studies and implement appropriate standards for spill response plans.

That has led to an al-out war between Alberta and British Columbia with Alberta stating it will no longer import B.C. wine or purchase electricity from B.C.’s Site C dam. B.C. responded by saying they will ship their wine to Asia which is where Alberta wants to send its crude.

The Prime Minister of Canada has weighed in saying that this pipeline is going to get built. The Prime Minister has attempted to assure the B.C. residents that the Kinder Morgan pipeline is not a danger to the B.C. coast given the billions of dollars the federal government has invested in its Oceans Protection Plan. The war of words will continue but this time the federal government does seem to be committed to its jurisdiction to regulate national projects. Stay tuned.

Shifting Markets

Last year we reported that Canada would soon lose its most important customer for natural gas and crude oil exports. That customer, the United States, is about to become energy self-sufficient given the substantial increase in production of gas and oil from shale formations. Between 2010 and 2015 crude oil production from U.S. shale regions increased 72 per cent while gas production increased 28 per cent.

This year a forecast by the International Energy Agency (IEA) predicts that the United States crude imports will fall to near negligible levels by 2040. The U.S. currently consumes 99 per cent of Canada’s crude exports amounting to about 3.76 million barrels per day according to the IEA. This is the reason Kinder Morgan is so important. Without access to Tidewater and Asian markets the Canadian petroleum production industry is finished.

There is another major shift that is affecting Canadian energy markets in a big way. That is the expectation that renewable production will significantly replace traditional crude oil and gas production. That is the reason that Royal Dutch Shell announced in March 2017 that it was selling most of its Canadian oil sands assets for about $7.25 billion. The company concluded that the energy industry is changing in a fundamental way that could turn oil sands operations into liability. Shell concluded that global oil demand could peak within a decade driven by increasingly competitive fossil fuel alternatives such as solar and wind and electric cars.

Lower prices for solar and wind power and batteries are one thing. But even more important, argues Shell, are tougher government restrictions on greenhouse gas emissions. As noted later in this Annual Review these renewable targets are increasing in virtually every jurisdiction in the world. The one exception is the United States. But even there it is really just at the federal level under agencies controlled by President Trump. Elsewhere, particularly in large states such as California, American jurisdictions are leading the worldwide charge.

The Drive to Renewables Continues

Renewables continue to grow across North America. For the first time, the United States got 10 per cent of its power from renewable energy. In Ontario, the IESO estimates that at the wholesale level wind and solar combined provide about 7 per cent of Ontario supply needs. Renewable resources now account for 35 per cent of systems energy capacity in Ontario with about 14,000 MW.

These trends will continue for two reasons. First all forecasts indicated that the prices will continue to decline between 2015 and 2025. According to the International Renewable Energy Agency generation cost for onshore wind will fall another 26 per cent but offshore wind generation cost will fall 35 per cent and utilities scale solar PV costs will drop 57 per cent.

At the same time it is expected that renewable energy targets will increase. Some are already very aggressive. In both California and New York, clean their energy standards mandate that 50 per cent of the state’s electricity must come from renewable energy by 2030. In Alberta, that percentage is 30 per cent by 2030. In Québec, it is 61 per cent by 2030.

At the end of 2017, Ontario quietly pulled the plug on its FIT program. That program began in 2006. More than 4200 MW of wind and solar was purchased under 20 year contracts during the first round of the program at what proved to be very high prices. Prices were subsequently reduced and in later versions of the FIT Program only 750 MW of contracts were awarded.

Contracted supply from the Ontario FIT program grew from 13 MW in March 2010 to 4661 MW by the end of 2017. Of the total 4661 MW just over 3000 MW was wind and 1659 MW was solar. The cost of the contracts is not available.

Today, there is relatively little need for additional generation. Ontario’s energy consumption has declined every year but one since 2008. Today, it stands at 1997 levels.

Just as Ontario was exiting the market Alberta came in with a big splash. As the year came to a close, the returns came in from Alberta’s first competitive bid. This bid is part of the Alberta New Democratic party’s initiative following their election in May 2015 under the Climate Leadership Plan. That plan included an economy wide carbon levy, a phase out of coal-fired generation, increased renewables, increased energy efficiency and increased use of distributed energy resources.

The results of the bid were a pleasant surprise for everyone involved. Four wind projects were selected totaling 596 MW with prices ranging from $30.90 to $43.30 MWh with the weighted average of $37.00 MWh. These record prices were so attractive that the AESO decided to purchase an additional 196 MW over and above its 400 MW target. The winning bidders included Capital Power for 201 MW, EDP Renewables Canada for 248 MW and Enel Green Power Canada for 146 MW.

The realized prices of $31 MWh were well below the last Ontario procurement in March 2016 which resulted in a realized price of $ 85 MWh for 300 MW of wind power. It turns out that competitive bidding works.

Construction Cost Overruns

It is no secret that building energy infrastructure in Canada can be difficult. Recently TransCanada threw in the towel in the Energy East project after years of delay and opposition. The final straw as mentioned above was the National Energy Board decision to consider the cost of carbon emissions in determining whether to allow the project to proceed. A new unexpected criteria was too much for TransCanada.

The TransCanada decision came only a few days after the decision of the Federal Court of Appeal ordering the federal government to renegotiate the terms under which the Trans Mountain pipeline crosses a First Nations reserve in British Columbia, raising new questions about the fate of Kinder Morgan Inc.’s federally approved plan to expand the pipeline. It turns out that regulatory challenges are not over once a construction permit is granted. Across the country major hydro-electric projects now face serious delays and cost overruns.

On the Atlantic, the Nova Scotia Utility and Review Board is dealing with the problems at the Muskrat Falls generating station and the implications for the Maritime Link transmission line. On the Pacific, the British Columbia Utilities Commission is grappling with the site C dam being built by BC Hydro. In the middle of the country, the Manitoba Public Utilities Commission is facing a similar problem authorizing billions of dollars necessary to complete the Keeyask generating station

We can start in the west and move east.

Site C is a multibillion-dollar project to construct a hydro dam and generating station on the Peace River, near Nelson, B.C. The project received provincial and federal environmental approvals in October 2014 and construction began in the summer of 2015. When completed the estimated $8.3 billion facility will provide peak capacity of about 1145 MW, enough power to a service 450,000 homes a year.

The Site C political fortunes changed during the provincial election campaign in May 2017 when the NDP promised, if elected, to have the Site C project reviewed by the B.C. Utilities Commission. After taking the reins of the provincial government in, the new Premier made good on the NDP promise and issued an Order in Council requesting the B.C. Utilities Commission to undertake an inquiry into certain aspects of the Site C project.

On November 1, 2017, the B.C. Utilities Commission issued its Final Report on the B.C. Hydro Site C project following a three month investigation. While the Final Report made no recommendation on whether the project should proceed it did warn that the cost of the project will be higher than expected. The Final Report also indicated the benefits of the Site C project could be obtained through other renewable generation projects at lower cost but noted that there would be substantial costs associated with terminating. The Final Report concluded that suspending the construction process would present substantial costs to rate payers along with additional uncertainty.

In the end, the British Columbia government decided to proceed with the construction of the Site C dam with full knowledge that completing the project would cost nearly $1.7 billion more than originally proposed. It was also highly unlikely that the project would meet its 2024 in-service date. The B.C. government is now anticipating a total cost of $10 billion and the setting aside of a further $700 million to address cost overruns. The Report concluded that cancelling the project would mean an unavoidable $4 million hit on the books of BC Hydro or the books of the Minister of Finance. That, the Report indicated, would lead to a 12 per cent rate increase immediately.

That takes us to Manitoba where the Manitoba Public Utilities Board is grappling with the Keeyask project, a 695 MW generating station 725 km north of Winnipeg on the Nelson River. The project was originally estimated to cost $6.5 billion and was to be in service by November 2019. It is now estimated to cost $8.7 billion. The project is a joint venture between Manitoba Hydro and four Manitoba First Nations.

The cost overruns were identified through an independent review by the Manitoba Board which followed a Manitoba Hydro application for a 7.9 per cent rate increase. At this point the project is continuing as planned.

That brings us to Newfoundland and Labrador and the Muskrat Falls 824 MW generating facility scheduled to begin operation in 2020. It is the first phase of the Lower Churchill project in Labrador which will ultimately have a capacity of 3000 MW capable of providing 16.7 TWh of electricity a year.

To date there is a projected cost overrun of 50 per cent. Costs have increased from $7.4 billion to $12.7 billion. There are also serious delays in the completion of the project. Construction of the Muskrat Falls generating facility began in 2013 and was expected to take 4 to 5 years. First power from the dam and Hydro station is now expected to be delayed until 2020.

The project, first announced in November 2010, is based on a $6.2 billion deal between Newfoundland and Labrador’s Nalcor Energy and Halifax based Emera. Under that agreement Nalcor will design and build the hydroelectric power station at Muskrat Falls and a transmission line called the Labrador Link running from Muskrat Falls to the Avalon Peninsula.

Emera will build an electrical interconnection called the Maritime Link between Newfoundland and Cape Breton and invest in the Labrador Island Link. Emera will construct and own a 500 MW $1.2 billion underwater power connection from Newfoundland to Nova Scotia known as Maritime Link which will permit future electricity exports to the Maritime provinces and the United States

As 2017 came to a close, Newfoundland’s Premier, Dwight Ball, established an inquiry into Muskrat Falls to be led by Supreme Court Justice Richard Leblanc. He will examine issues around the sanctioning of the project including whether Nalcor’s forecasts and assumptions were reasonable. He will also examine Nalcor’s execution of the project and why the Public Utilities Board was exempted from a full review. The Inquiry will begin its work in January 2018 with a final report due on December 31, 2019.

Muskrat Falls is scheduled to deliver full power in 2020. Currently various parties are criticizing the Commission’s terms of reference which they say are too narrow. Submissions on that issue are due on February 15.

There is little in common in these three hydroelectric projects with one exception – they are all too big to fail.

Regulating Carbon

Starting this year every Canadian province will be required to implement carbon pricing – either with the carbon tax or a cap and trade system. If they don’t they will face a federal government backstop carbon tax. With the exception of the province of Saskatchewan all Canadian jurisdictions have indicated they will bring in some form of carbon pricing. British Columbia and Alberta have instituted carbon taxes, while Ontario and Québec have opted for cap and trade systems linking them to California’s Western Climate Initiative.

As the year ended, the liberal government in Ottawa introduced a draft carbon tax legislation outlining the carbon price backstop that will apply to Provinces that do not have their own levy in place or have one that does not meet federal standards. Ottawa will set the levy at $10 a ton this year and increase it annually in $10 increments until it reaches $50 a ton in 2022. At that point, the tax will drive up the cost of gasoline prices by roughly 11 cents per liter.

The federal initiatives arrive at a time when the governments in power in both Ontario and Alberta will soon face elections. That is causing controversy in both provinces as the sitting governments face opponents that take a different view on carbon pricing.

Ontario’s first year of carbon pricing brought in nearly $2 billion from quarterly auctions. The Ontario system which was launched in 2017 is designed to lower greenhouse gas by putting caps on the amount of pollution companies in certain industries can emit. If they exceed those limits they must buy allowances at quarterly auctions or from other companies that have come in under their limits. The cap declines 4 per cent each year to 2020. As it decreases, the Government hopes companies will have more incentive to cut their emissions.

At the beginning of 2018, Ontario joined the Québec and California Carbon Market known as the WCI. That has raised another concern. It is argued that the proceeds from the auction will be lower because it will be cheaper for Ontario companies to buy allowances in those jurisdictions. This means that the greenhouse gas emissions will not be cut in Ontario according to Ontario’s Environment Commissioner and Auditor General.

One of the issues in this debate is what happens to the money the Program brings in. Currently the Ontario Government says it is directing that revenue towards green projects such as energy efficient improvements in hospitals, smart thermostats for homeowners, and bike lanes to further reduce greenhouse gas emissions. Both Opposition parties in Ontario question this, arguing that the money is not going to that purpose.

The price of carbon in Ontario 2017 auctions was roughly $18 per ton. By 2022, the Government expects that to rise to over $20 although some believe it may be higher. Under the Federal Government’s carbon tax, the price would be $50 a ton by 2022.

Alberta launched carbon regulation in 2007, setting limits on greenhouse gas for industrial facilities charging $15 per ton of carbon dioxide for emissions above that level. In November 2015, the new NDP government in Alberta introduced a more aggressive target tax at the level of $20 per ton in 2017 rising to $30 per ton in 2018.

British Columbia ushered in North America’s first broad-based carbon tax in 2008. That tax was initially set at $10 per ton and rose to $30 where it has remained since 2012. The money raised by the provincial government was used to reduce other taxes and as a result the taxes are said to be revenue neutral. British Columbia’s recently sworn in a New Democratic government presented its first provincial budget in September 2017 and announced new changes to the B.C. carbon tax. As of April 1, 2018, the carbon tax will increase by $5 per ton until it reaches the federal target carbon price of $50 on April 1, 2021, one year before the Ottawa 2022 deadline. B.C.’s carbon taxes are currently set at $30 per ton.

Québec launched a cap and trade program in 2013 and joined California in a carbon market that allows industry in either jurisdiction to buy and sell emission allowances that were issued by either the province or the state. The minimum price for those allowances in 2017 was $13.56 per ton and it rises each year. The Ontario government joined the Québec-California Carbon market at the beginning of 2018

Local Generation and Storage

This was a topic we reported on in last year’s Annual Review. An update may be helpful.

Setting the stage may also be helpful. Embedded generation can mean customer owned generation, utility owned generation, or third-party generation. The important criteria is that it is local generation. It is generation located near the customer. That means cost savings. Not only the customer but also for distributors and transmitters. That is why local generation is promoted in many jurisdictions.

Local generation can use different technologies. The ground was first broken by solar. Next came CHP. And now most of the attention is directed at storage. Many believe storage is the silver bullet. It has low carbon, increasingly attractive prices, amazing flexibility, and can be installed almost anywhere. And it has low off-peak energy costs.

One thing that all energy regulators understand is that the cost of electricity systems are driven by peaking costs. We build systems that are only used 10 per cent of the time or less. Storage is the solution to that. That is why the concern across North America is how to get more storage. What are the barriers to entry? Who should be supplying it and how should we set the price?

Local generation has been growing at a rapid clip. The Ontario IESO recently reported that at the end of 2017 there was more than 3800 MW of embedded generation in local distribution systems in Ontario. This was a 25 per cent increase over the previous year. That is a big number.

To some extent this rapid growth was driven by the IESO subsidies, particularly the Save on Energy and Industrial Accelerator programs which offered significant grants for those installing local generation. Often this was CHP. According to the IESO there are currently 69 CHP facilities installed in Ontario with a total capacity of 131 MW. The total incentive the IESO paid out was $121 million. There are an additional 36 systems contracted for with an estimated capacity of 46 MW. The incentive pay out will be approximately $42 million.

In Ontario, industrial customers have another incentive to install CHP facilities. It can reduce their exposure to global adjustment (GA) charges. That can reduce an industrial electricity bill by over 50 per cent. Ontario utilities also have an incentive to install CHP facilities. These CHP installations help Ontario utilities to meet their OEB CDM commitments, but CHP will no longer be eligible for incentives after July 1, 2018. Local generation can reduce a utility’s costs largely in terms of deferred capital investment. Energy regulators like local generation for the same reason. Deferred capital expenditure can reduce rates.

Last year, we reported that the FERC in Washington was taking the lead when it issued a Notice of Proposed Rulemaking to reduce barriers to energy storage and distributed energy resources. The FERC directed six U.S. Regional System Operators to draft reports on their progress with respect to storage development. Virtually all U.S. states now have program supporting the development of energy storage. Without a doubt the most aggressive is California.

In Canada, the Ontario IESO is taking the lead by supporting over 10 projects. The leading Ontario utility is Toronto Hydro with 7 projects in late construction or in-service. Toronto Hydro is currently building a 10MW battery storage to provide backup power for Metrolink’s Eglinton Light Rail Transit which enters service in 2021. Toronto Hydro is also working with Hydrostor to test the world’s first underwater compressed air energy storage project in Lake Ontario near Toronto Island.

Toronto Hydro is working with Ryerson University and the IESO to develop standardized pole mount energy storage systems for neighborhood applications. This energy storage system is unique because it doesn’t have a footprint. It is attached to existing power poles. If successful it could become a solution to address EV charger loads or power quality issues on over 175,000 poles across the city.

A much smaller utility, Festival Hydro in Stratford Ontario, has just installed Canada’s largest battery storage facility which will provide a storage capacity of 8.8 MW. This translates to 40.8 MWh energy capacity – enough to supply more than 10,000 homes for an hour. This project is also supported by the IESO. Festival Hydro hopes it will significantly reduce its infrastructure investment costs over the next few years.

We can expect regulators to challenge barriers to entry to storage. The U.S. energy storage market alone is expected to increase tenfold to U.S. $3.2 billion between 2016 and 2022. The cost of storage is also starting to fall. According to a recent McKinsey report the average battery pack costs are down from U.S. $1000 per kilowatt hour in 2010 to less than U.S. $230 per kilowatt hour in 2016.

As the year 2017 came to a close, Ontario‘s system operator, IESO and Ontario’s energy regulator, OEB were highlighting the importance of distributed energy resources, particularly energy storage. In December, the new President the Ontario IESO stated in one of his first speeches:

• DER’s need to be fully integrated into electricity system operations, planning, markets, regulations and policy driven incentives. This is something we’ve heard from LDCs in communities across the province desire to choose distributed resources as an alternative to traditional “wires” solutions.
• Another area of focus is creating a level playing field in which DER’s can efficiently, fairly and on a technology neutral basis compete with both transmission and distribution infrastructure and centralized power plants to provide electricity services.

Within a week this was echoed by the Ontario Energy Board when it issued its Strategic Blueprint 2017-2022. In identifying future regulatory challenges the Board stated:

• Does sector transformation create new utility services that need to be assessed and remunerated appropriately?
• What role should incumbent utilities play in the emerging market for distributed energy resources and related services?

Before the ink was dry on the OEB’s Strategic Blueprint, the Minister of Energy in Ontario appointed a Chair for a new Modernization Panel. The panel has a broad mandate including how the OEB can continue to protect consumers while supporting innovation and new technology, and how it should be structured and resourced. The panel will report back to the government by the end of 2018.

Local generation regardless of the technology will change the industry. It has great potential for cost saving in an industry that is politically challenged because of high prices.

One of the issues that will surface in Canada next year, as it has in the United States, is the role of net metering. Local generation means that there is a lot of generation capacity spread around the province. At any given point in time much of it may be idle. It is in everyone’s interest to make sure that excess capacity does not go to waste. Excess energy should be moved to somewhere where it has positive value. Net metering may be a step in that direction. In July 2017, the OEB made some revisions to its net metering regulations. More revisions are expected and draft rules are out for comment.

Natural Gas Developments

The year 2017 saw some important developments in the natural gas industry.

In November 2017, Enbridge Gas Distribution Inc. and Union Gas Limited, now under one owner with the acquisition of Spectra by Enbridge in late 2016, applied to the Ontario Energy Board to amalgamate and form a single natural gas distribution company effective January 1, 2019. The amalgamated utility would serve over 3.5 million natural gas customers in Ontario – and the combined revenue of the two utilities is approximately $31 billion. In the application, Enbridge and Union stated that their customers would not bear any of the costs related to the amalgamation. They also argued that if the Ontario Energy Board approves the amalgamation, customers will receive a total benefit of $410 million over a ten-year period.

The rates that Enbridge and Union currently charge customers are set using two separate frameworks that expire at the end of 2018. The Ontario Energy Board would normally review the costs of each of the gas utilities and set new rates starting in 2019. In a separate application, Enbridge and Union asked the Ontario Energy Board to defer its full review of their costs for 10 years and proposed a new methodology for setting rates between 2019 and 2028.

For a while it looked like Ontario might have one single monopoly providing natural gas service throughout the province. However, EPCOR, a public utility owned by the City of Edmonton entered the Ontario market in 2017 by buying all of the assets of Natural Resource Gas or NRG in Aylmer for $21 million.

NRG has 8000 customers. The OEB approved the acquisition in August 2017 applying the no harm test that the Board has used in the consolidations in the electricity industry. The Board also adopted the practice in the electricity industry of not allowing the applicant to recover any of the premium in the acquisition price from rate payers. EPCOR paid $21 million for assets which had a net book value of just over $14 million.

2017 also saw a continuation of the battle between EPCOR and Union regarding three natural gas franchises in South Bruce County. In March 2015 three municipalities had requested proposals from parties interested in providing gas in the municipalities. A number of companies applied and the municipalities chose EPCOR. EPCOR then applied to the Ontario Energy Board for approval of the franchise agreements granted by municipalities in November 2016.

Objections from Union regarding the nature of the bidding process resulted in the Board putting those applications on hold and holding a generic hearing to determine how competitive applications for natural gas franchises in Ontario should be best handled. The Board issued its Decision in the generic hearing in November 2016 and since that time has been reviewing various proposals from both EPCOR and Union. The first Procedural Order in that process was issued in January 2017 and what appears to be the last Procedural Order was issued in February 2018 with answers to be filed on March 2, 2018. A final decision is expected sometime in the spring.

Another important decision in the natural gas industry during 2017 occurred on the West Coast. That decision was one of the first regulatory decisions to deal with renewable natural gas which in a world of carbon costs is attracting a great deal of attention.

In August of 2015, FortisBC, which provides natural gas service in different areas of British Columbia, applied to the B.C. Utilities Commission for approval to modify the pricing regime for renewable natural gas (RNG) in the province. RNG is pipeline quality natural gas produced from decomposed organic waste from farms, sewage, landfill gas and municipal organic waste.

The regulatory proceeding began in September 2015 and continued until May 2017. In August 2017, the B.C. Utilities Commission approved a revised pricing structure whereby a portion of the incremental RNG cost is absorbed by the ratepayer and a portion is absorbed by the voluntary RNG market. The Commission agreed that the only way to sustain and develop renewable natural gas is to allocate the cost of the incremental RNG premium between the general rate base and the voluntary markets. The Commission noted that the RNG program fosters B.C. energy objectives including reducing GHG emissions, developing innovative technologies, encouraging switching to lower carbon energy, and reducing waste biomass.