2013: A Challenging Year for Canadian Energy Regulators

Managing Editors

It is always useful to look back at the end of each year and analyse the main developments in energy regulation and identify the challenges going forward. That, after all, is one of the purposes of the Energy Regulation Quarterly.

Most would agree that 2013 was anything but business as usual. Energy regulators saw substantial price increases, driven by high cost renewables. Huge quantities of new shale gas appeared on the market along with massive pipeline construction. And most important, the demand for energy by most customers declined.

The Shale Revolution

Five years ago there were plans to build a terminal outside Quebec City to receive liquefied natural gas (LNG) from large gas exporters like Russia. Today we are trying to build a pipeline to move natural gas from British Columbia’s shale deposits in the northern part of province to the coast at Kitimat where it will be converted to LNG and shipped to Asia.

Five years ago the price of gas was close to $14 per GJ. The shale gas revolution changed all that – prices at the end of 2013 at both Dawn and Henry Hub were close to $3 per GJ, driven by natural gas production from Bakken, Eagle Ford, Marcellus and Barnett in the U.S. and Horn River in B.C. The volume of shale gas five years ago was 2 trillion cubic feet per year. By the end of 2013 it was over 8 trillion cubic feet.

This massive shift in production and its implications is set out in some detail in the article in this issue by Gordon Pickering, one of the world’s leading experts on gas markets.

Shale gas is creating important new opportunities, but it is also creating challenges.  In Canada, the ability to move this resource to Asian markets is important because the Asian price is as much as three times higher than the North American price, and it helps reduce Canada’s dependence on U.S. markets. But building new pipelines is not an easy exercise. There are serious aboriginal and environmental challenges.

Furthermore, the location of significant deposits of shale gas close to markets in the northeastern U.S. has led to one of the most important and difficult regulatory decisions Canada has seen in a long time. The TransCanada mainline was designed to transport 7 billion cubic feet (bcf) of gas per day. By 2013, the volume was down to 1.5 bcf a day due in large part to the increase in U.S. shale gas supply 3 bcf a day in 2006 to 29 bcf per day.

The declining volumes led TransCanada  to increase the tolls on the remaining customers to cover their fixed costs. That was not a happy prospect and the National Energy Board (NEB) struggled with the facts. One of the problems was that TransCanada’s customers started using lower-cost interruptible service because they knew it wouldn’t be interrupted. The NEB’s response in the end was to deregulate that aspect of the service and of course prices went up. But that deregulation had unintended consequences and the matter is far from resolved as we go to press. It is entirely possible that the case will have to be reheard on new evidence but that remains to be seen.

The Great Pipeline Debate

In Canada 2013 was the year of the pipeline. At least five projects were in play.

The most controversial case is the TransCanada Keystone XL line. This project does not directly involve Canadian regulators and approval is currently in the hands of the U.S. president. It has however set the stage for the conflict between pipeline companies and environmental groups. And that issue has become very important to Canadian regulators. One of the stronger cards TransCanada initially had in its hand  – energy security for Americans – has diminished because of the aformationed huge surge in shale gas which promises American energy self-sufficiency by 2035.

Keystone is a big investment for TransCanada. The company has spent $2.3 billion on the southern portion and estimates additional costs of $5.4 billion on the northern portion. The U.S. state department’s Final Supplemental Environmental Impact Statement offers both good news and bad news. This report, released at the end of January 2014, states that a barrel of Alberta oil results in 17 per cent more greenhouse gas emissions than the average barrel refined in the U.S. But it also notes that building the pipeline will not have much impact on climate change because without it Alberta crude will likely be shipped to markets  anyways, either by other pipelines or by rail.

There is some truth to that. Major projects are underway to move crude from the Alberta oil sands to the B.C. coast for shipping to Asia. And oil trains are now a regular feature on the landscape. Rail transport accounted for 80,000 barrels a day (b/day) in Canada at the end of 2013 compared to almost nothing two years earlier. And given the disasters in Lac Megantic and elsewhere we are beginning to discover that oil trains are not a better alternative in terms of safety or pollution.

The second major Canadian project under review in 2013 was Enbridge’s proposed $5.5 billion Northern Gateway Pipeline designed to connect oil sands crude to the West Coast where it would be shipped to higher priced international markets in the Pacific rim. This project also ran into heavy environmental criticism and equally important coastal First Nations opposition. The Joint Review Panel Report recommending approval of the project is reviewed in this issue by Rowland Harrison.

The duty to accommodate First Nations concerns has become a growing responsibility of Canadian energy regulators. Over the last several years both regulators and courts have struggled with this issue. This is an important constitutional issue and Keith Bergner’s excellent lead article sets out these developments in a very comprehensive fashion.

The third project of note in 2013 was Kinder Morgan’s application to twin its existing oil pipeline from Edmonton to Burnaby, B.C. at a cost of $5.4 billion. This project would increase the capacity of the pipeline from 300,000 to 900,000 barrels per day. Given that this is an existing line the opposition is not as great as in the Keystone XL or Northern Gateway project. But environmental groups and First Nations are engaged and nothing in the world of pipeline construction is guaranteed.

This concern is borne out in Enbridge’s Alberta Clipper project a 1,600 km crude oil line running from Hardisty, Alberta to Superior, Wisconsin. The company had originally understood that a presidential permit to increase the capacity on the line to 800,000 b/day from the current 450,000 b/day would be issued by mid year. But it has been delayed by a request from environmental groups that the state department conduct an inquiry and issue a Supplemental Environmental Impact Statement that considers the cumulative impact of Alberta Clipper and Keystone XL.

The final and, in some ways, most interesting project is TransCanada’s most recent initiative – the Energy East pipeline. This is a $12 billion investment by TransCanada to convert its existing gas pipeline to an oil pipeline running from Alberta to the Quebec border and then build a new pipeline through Quebec and New Brunswick to the Irving refineries on the coast.

In some respects this line is a reaction to the declining demand for natural gas transportation on the TransCanada Mainline and the recent decision of the NEB on TransCanada’s application to revise its tolls on that line.

The Energy East project has an interesting twist. While the federal government and the NEB have exclusive jurisdiction over interprovincial pipelines, the Ontario Minister of Energy has asked the Ontario Energy Board (OEB) to conduct a province wide consultation on the impact of the Energy East proposal. The Minister has asked the Board to consider the impact of the line on Ontario natural gas consumers in terms of rates, reliability and access to supply. The Minister also asked the OEB to consider the impact of the pipeline on safety and environmental issues, the impact on local communities, the impact on First Nations communities and the short and long-term impact on the economy of the province. At the end of this process, which will involve consultations accross the province in coming months, the OEB will submit a report to the Minister which will inform an intervention planned by the province in the federal hearing.

The No Growth World

The problems raised by declining demand seen in the TransCanada MainLine case will soon face Canadian local distribution companies particularly in Ontario. Ontario appears to lead the country in the three factors that are causing the drop in energy demand – increased prices, increased energy efficiency and a move to electricity distributed generation.

The recent long-term energy plan (LTEP) issued by the Ontario government  offers some interesting insights. In 2005 electricity demand in Ontario was 155 TWh. That dropped to 141 TWh in 2013 – a 9 per cent reduction. In 2011, the average household consumption of electricity was 10 MWh. In 2031 it is predicted to be 7.5 MWh. The Energy Information Agency (EIA) forecasts that lighting per household in 2035 will be 827 kWh per year or 47 per cent below the 2011 level. The average consumption for commercial customers in 2011 was 18 kWh per square of floor space. In 2031 it is forecasted to be 15 kWh per square foot.

Much of these demand reductions are driven by customer reaction to higher prices. In Ontario the Regulated Price Plan (RPP) supply cost for electricity has gone from 5.5 cents in May 2008 to 8.9 cents by the fall of 2013 – an increase of 63 per cent. The LTEP forecasts that a typical residential bill in Ontario will go from $125 a month in 2013 to $178 per month in 2018 a increase of 42 per cent.

One factor contributing to these price increases is the high cost of renewable electricity  now entering the system. This new generation is expensive compared to traditional generation. The last Ontario RPP report indicated that the cost of electricity generated from hydro was 4.8 cents per kWh, and nuclear was 6 cents per kWh.  Wind however is 12 cents per kWh while solar is 49 cents per kWh.

Ontario has also been a leader in conservation. Almost five million customers across Ontario were mandated by the province to adopt smart meters with access to time of use pricing at a cost of $1 billion. As a result peak demand has dropped by about three per cent or 1,000 MW. In the past, conservation was led by the utilities and in most cases driven by the government.

The role of conservation and its impact on demand will only escalate. The Ontario LTEP states that Ontario will invest in conservation first before new generation. Since 2005, 1,900 MW of electricity demand has been eliminated through conservation. The LTEP report estimates peak reductions from conservation at 1,500 MW in 2015 and almost 3,000 MW by 2030.

Future conservation initiatives however will be different. More will happen on the customer side of the meter, not be driven by the utilities or the government. Customers faced with rising costs will take their own initiatives using up-to-date technology.

Google recently paid $3 billion to purchase a company called Nest, a supplier of smart thermostats. Smart thermostats may become more important than smart meters. Smart thermosats have the advantage that they connect through the Internet. They can be installed in minutes not months. The transmission costs are zero. And the devices that communicate with them are already in the customer’s hands. They are known as smart phones. In this new world everything is smart: smart meters, smart grid, smart phones and now, smart thermostats.

There are other technologies that will influence behavior on the customer side of the meter.  Advanced batteries will lead to cheaper energy storage for electric vehicles, homes and businesses. Electricity storage, which was targeted by the minister in Ontario’s LTEP,  may become the next disruptive technology. This will create some interesting challenges for Canadian energy regulations.

The third factor behind declining demand may be the real game changer. Customers, particularly electricity customers, are moving off the grid, again enabled by technology. In this case it’s solar. The solar industry struggled initially. But now prices are dropping rapidly. The average cost of a solar PV panel in 1977 was $77 per watt. Today these panels can be bought for under a $1 per watt. Worldwide, new solar generation capacity will soon out strip wind capacity. In 2013 over $100 billion of solar systems will be installed accounting for over 100 GW. Today companies are financing residential roof top solar in exchange for the excess power. Moving solar into the commercial market is the next step. Walmart installed over 65 MW of solar in 2013, Costco 39 MW and IKEA 21.5 MW.

Local generation is not restricted to solar. California manufacturers are resorting to self generation and micro turbines causing the share of electricity sold to manufacturing to drop from 33 per cent to 10 per cent. These trends present real problems for utilities. And for regulators.

Energy generation and distribution are industries with high fixed costs. As long as demand grows a substantial amount of incremental revenue drops to the bottom line. But when the opposite occurs and demand declines, profit drops. As customers go off the grid, the remaining customers are forced to pay more and more of the cost of the fixed assets through higher rates. As rates continue to increase, more customers will find alternatives. This is now known as a utility death spiral.

The New Regulatory Challenge

In some respects last year’s TransCanada MainLine case was a wake-up call for those regulating local distribution companies, and indeed those regulators saw troubles coming. The OEB for example will release a study this spring addressing the declining volume issue squarely.

Their recommendations will likely involve a new demand charge because in a world of declining demand, rates can no longer be based solely on volume. But a rate totally dependent on a demand charge can undo all the gains from extensive energy efficiency programs throughout the country. The Ontario demand charge however will be unique in that the amount will depend on the peak usage of the customer. Those with higher peaks will have a higher demand charge than those with a lower peak. Other jurisdictions engaged in this type of analysis include the California Energy Commission which has recently been mandated to undertake a rate review by the State legislature.

The no growth world also poses real problems for incentive ratemaking, which has become the standard bearer in many jurisdictions. The concept is simple enough – the rate increase is limited to an industry price index increase minus a productivity factor. But in a no growth world, there is no productivity increase. When demand falls in an industry with high fixed costs, productivity drops. And not because of inefficiency. The demand decline which drives the drop in productivity is in large part driven by factors that the utility cannot control.

Both gas and electric utilities will face this issue, although the gas utilities are isolated to a degree. Their cost of energy, the natural gas they purchase, has also dropped dramatically in North America because of shale gas. Electric utilities are on the other end of the spectrum – their cost of energy is being driven up by high-cost renewables and  high-cost new construction in traditional generation.

The long-term solution to the utility death spiral may require more than new pricing. It may be that if electric utilities are to survive they will have to become integrated energy service companies. For that to happen, regulators and legislators will have to rewrite the rules of the game.The argument is that to survive utilities must be able to participate in the new markets. Policy makers and regulators will have to remove the artificial boundaries that over the years have been created in both product and geographical markets.

Should a local distribution company be prohibited from engaging in generation? It is not just generation. There are a host of other “new” services such as energy storage, energy efficiency and electric vehicle charging that regulators will have to face in the near future. And utilities will argue that they should be able to seek unique new partnerships. At the end of the day, utilities will argue for a level playing field where they can compete with new entrants that are and in turn entering their market.

There may be important advantages. First, it may save the utility. And that everyone would concede, is a good thing.  It may also stimulate the development of new technology. These companies have access to capital and knowledge. And they can leverage the core relationship they have with their customers. There will always be a concern that utilities will use revenues from monopoly markets to subsidise activities in competitive markets. But the distinction between these market may be blurring.

The time may have passed for blackline rules that establish a boundary between service activities that in the world of modern technology make less sense.

This is not a simple exercise. Regulators and legislators will struggle. It is a delicate balance. But we only have to look at the TransCanada Mainline decision and other articles in this issue of ERQ to know that the next regulatory challenge is on the horizon.

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