News & Updates

Natural gas ratepayers should see cap-and-trade costs on bills, auditor says

Dec 7, 2016

TORONTO—A survey conducted at the behest of the auditor general suggests nearly all Ontarians who heat their home using natural gas want to see the costs of cap and trade clearly displayed on their bills — and so does the auditor herself.

The Liberal government’s plan to have companies buy and sell pollution credits to reduce Ontario’s greenhouse gas emissions is expected to add about $5 a month to home heating costs, but those increases will be buried in the “delivery” line on natural gas bills.

The Ontario Energy Board announced this summer that cost impacts of cap and trade, which comes into effect Jan. 1, will not appear as a separate line item on consumers’ bills for natural gas, which is used to heat most homes in the province.

Ontario’s auditor general commissioned a survey of natural gas ratepayers and it found that 89 per cent of respondents “thought it important to disclose the impact of cap and trade on natural gas bills,” according to the auditor’s recent annual report.

Deep within Bonnie Lysyk’s 800-page report on health services, highway contractors, climate change initiatives and more, is a reference to the survey and an urging from the auditor that the OEB change its mind.

“The Office of the Auditor General feels that more transparency is still required by disclosing the portion of charges in natural gas bills attributable to the cap-and-trade program,” she wrote in the report.

The OEB’s response to the auditor was that it will hold a hearing that will assess the “reasonableness of the cost consequences” of the natural gas distributors’ cap-and-trade compliance plans, and in the public notice for that hearing there will be a mention of the $5 monthly estimated impact on bills.

The OEB said in a statement that administering cap and trade will become a regular part of utility business.

“All of the natural gas utility business costs are within the delivery line so it just makes sense to include it there,” wrote spokesman Karen Evans. Utilities will be expected to provide consumers with ongoing information about the program, she added.

Ontario Energy Minister Glenn Thibeault said in an emailed statement that a decision on breaking out the costs of cap-and-trade for consumers is up to the Ontario Energy Board.

Energy Minister Glenn Thibeault was not available Thursday or Friday to answer questions, but he said in an emailed statement that the decision is up to the OEB and it is an independent regulator.

“As always, the OEB makes decisions to recover necessary system costs from ratepayers and includes these recovery fees in the line items they deem most appropriate,” he wrote. “The government respects the authority of the Ontario Energy Board in this regard.”

The OEB got feedback from 80 stakeholder groups on whether to include a separate line item, and 75 of them wanted to see costs broken out on consumers’ bills, the auditor noted, including the Independent Electricity System Operator, and Enbridge and Union Gas themselves.

Both the ratepayers and the gas companies want the costs clearly spelled out on bills, but the OEB is hiding them because the Liberal government wants them do, said Progressive Conservative energy critic John Yakabuski.

“It’s political,” he said. “There’s no question it’s political. They don’t want you to know what cap and trade is costing you.”

NDP energy critic Peter Tabuns said he doesn’t buy the government’s line that the OEB is independent and can’t be ordered to disclose the cap-and-trade costs.

“That’s not true, they tell them what to do all the time,” Tabuns said. “When you talk to people who work or have worked in the Ministry of Energy in the past, the OEB is not considered much bigger than a road bump when it comes to making things happen the way ministers want them to happen.”

Quebec and British Columbia include the cost of carbon pricing as a separate line item on bills.


Cap and trade is also expected to add about 4.3 cents a litre to the price of gasoline.


Jones, A. (2016, December 04). Natural gas ratepayers should see cap-and-trade costs on bills, auditor says | Toronto Star. Retrieved December 07, 2016, from


Is The Era Of Cheap Natural Gas Over?

Oct 11, 2016


Before there was a boom in oil production in the United States, the shale gas revolution led to massive flood of new supply, which sent prices careening downwards. Natural gas spot prices are always volatile, but have largely traded below $3 per MMBtu since 2014. With prices so low, companies pared back drilling plans and focused much more on liquids-rich and oil-heavy shale plays.

But a funny thing happened: instead of a subsequent crash in natural gas production as drillers pulled rigs from the field, output continued to rise, setting new records along the way. Part of that had to do with impressive advancements in drilling technologies and techniques, allowing companies to extract more gas for less money and with less effort. Another reason that gas output kept climbing was because a lot of gas is produced in conjunction with oil. The drilling frenzy for shale oil ensured that the gas kept flowing.

But the crash in oil prices put that to an end. Both oil and gas rig counts plunged, and natural gas production finally peaked in the U.S. and begun to decline. After hitting a high watermark in February 2016 at 92 billion cubic feet per day (Bcf/d), production has since shrunk by 5 percent. 

Meanwhile, on the demand side of the equation, the trajectory is only on the upswing. Years of low natural gas prices have led to a huge uptake in the electric power sector, hollowing out the coal industry, and leading to the construction of new gas-fired power plants at a frenzied pace. In years past, existing natural gas plants were simply used more, as low spot prices meant gas plants were cheaper to run than coal plants. But now an entirely new generation of power plants is coming online, which will ensure demand continues to rise into the future. The new plants are like a one-way ratchet, ensuring a structural increase in demand and not just a cyclical increase, as John Kemp of Reuters recently noted.

The U.S. has seen 25 gigawatts of new gas-fired electrical capacity added since 2012, bringing the gas fleet up to 448 GW. Another 11.5 GW will be commissioned by the end of next year as well. This is happening at the same time that utilities are rushing to shut down old coal-fired power plants, many of which have become unviable in a world with cheap gas and increasingly cheap renewable energy.

In short, the market for gas is seeing rising demand and falling supply, a recipe for a much tighter market. But that landscape is a 180-degree turnaround from what many analysts thought as recently as a few months ago. Last winter, mild temperatures led to lower-than-expected demand, and the record levels of production caused inventories to swell to levels not seen in years. On the heels of that incredibly bearish trend, prices dropped to their lowest point in nearly two decades in March. It was not hard to imagine several more years of rock-bottom prices.

But the most recent summer saw an unusual phenomenon play out, altering the expectations for natural gas prices. A time of year when inventories typically build, ahead of the annual spike in winter demand, the U.S. saw extraordinarily tepid increases in storage. That should not be surprising given that production began falling this year, but the weak summer storage build did catch the market off guard. Now natural gas prices have risen to $3/MMBtu for the first time in nearly two years. On Monday, during midday trading, Henry Hub was up another 2.6 percent to $3.28/MMBtu.

Things could grow tighter still as the same trends that led to the market to tighten are not going away: supply is falling, demand continues to rise (and will spike in the winter for heating needs), and storage levels are converging back towards average levels.

The era of sub-$3/MMBtu gas could be over for a while.



Cunningham, N. (2016, October 10). Is The Era Of Cheap Natural Gas Over? Retrieved October 11, 2016, from

Ontario Energy Board reviewing Enbridge-Spectra deal

Sep 23, 2016

The Ontario Energy Board is looking into Enbridge Inc.’s $37-billion deal to acquire Houston-based Spectra Energy Corp. to determine whether it must approve the resulting change in ownership of Spectra’s Union Gas subsidiary.

Enbridge says it intends to maintain separate operations for Toronto-based Enbridge Gas Distribution and Chatham, Ont.-based Union Gas, which together provide most of Ontario’s gas supply.


McCarthy, S. (2016, September 8). Ontario Energy Board reviewing Enbridge-Spectra deal. Retrieved September 23, 2016, from

Terence Corcoran: Ontario’s rude awakening from its California carbon dreams

Jun 3, 2016

In Ontario, the government of Kathleen Wynne has its green eyes set on $1.9 billion a year in new revenue after it joins the California cap-and-trade auction regime in 2017.

 The California dreamers within the Ontario Liberal government got a bit of a wake-up call last week when the Golden State’s cap-and-trade carbon-auction system crashed and nearly burned. At the quarterly auction of emissions permits offered by California and Quebec, only 11 per cent of the permits were bought, leaving giant holes in the revenue plans of both governments. The California government received only a fraction of an anticipated US$500 million while Quebec, anticipating $200 million, will be lucky to see $20 million.

In Ontario, the government of Kathleen Wynne has its green eyes set on $1.9 billion a year in new revenue after it joins the California cap-and-trade auction regime in 2017. Environment Minister Glen Murray, having skillfully leaked the provincial government’s big-spending green-energy plan, is preparing a final version based on the assumption that cap-and-trade will deliver a river of easy cash into which the government will dip. But what if the big California river is dry?

It’s way too early to declare the system a failure, but it is clear that Ontario is set to join an experimental carbon-trading regime that faces severe problems. A Wall Street Journal editorial this week referred to “The California Cap-and-Trade Bubble.” A market analysis circulating in California concludes that “Cap and trade is suffering from a confidence crisis amid significant uncertainty about the future of the program.” In Europe, where the traded price of carbon has collapsed to $9 a tonne, nations are battling over the shape of a new regime.

The uncertainties have a direct bearing on Ontario’s plans to join the California system in 2017 and 2018. In the short run, the California-Quebec market appears to have a massive surplus of previously issued emissions permits that trade on an open market at below the official floor price of US$12.73 a tonne set by the California Air Resources Board (CARB). Some say the surplus exceeds 100 million tonnes, which might explain why many of the usual buyers of emissions permits decided to stay away when the May auction offered up 77 million tonnes in new permits. As many as half the usual energy-consuming buying entities failed to bid.


Among the companies staying away from the May auction in California were Suncor’s Quebec-based operation and Valero Energy, which owns Canada’s second-largest refinery in Levis, Que. Calls to the companies to explain their absence were not returned, and one expert said they would be unlikely to explain their motives since doing so would amount to a breach of the auction rules. “This information is commercially sensitive and, as a rule, we don’t provide comment off the record,” a Suncor spokesperson said in an email.

The auction’s failure caught Pierre-Olivier Pineau, a professor of business management at HEC Montreal, by surprise. With strong growth in sales of SUVs and other gas-consuming vehicles, “there’s been no decrease in gasoline sales” in either Quebec or California, he said. So then why would two major Quebec-based companies stay away from the May auction?

Among the likely structural reasons for sitting out the auction is that the California regime faces longer-term legal and political challenges. First, a California appeals court is set to rule on a case challenging the constitutionality of the cap-and-trade system. The suit, filed by the California Chamber of Commerce and Morning Star Packing Co., hinges on whether cap-and-trade is a tax or a regulatory measure. Under the state constitution, the system would be deemed illegal if the court decides it effectively amounts to a tax.

Since the state of California, like Ontario, plans to use the billions collected from the sale of carbon emissions to build allegedly green projects, cap-and-trade looks like a wealth transfer and smells like a tax. Among the schemes to be funded from cap-and-trade in California is a bullet-train system up and down the state.

Beyond the court challenge, the California system is set to expire in 2020 unless the government renews it. Realistically, the contours of a new set of rules, targets and regulations need to be established within the next couple of years. Seeing uncertainty ahead, carbon-permit buyers may prefer to wait and see what’s coming next.

CARB officials dismiss the May auction failure, and a less-disastrous failure at an earlier auction in February, as nothing more than the usual “ups and downs, as there always are in markets.” Could be, although the European experience with cap-and-trade suggests otherwise.

At HEC Montreal, Pineau says Quebec appears to have no preparations in place to deal with dramatic changes in California’s system or its failure. In the event it fails, he says, Quebec companies would still have to meet emissions targets and would presumably have to do so by trading within Quebec. If Ontario were to join the Quebec system, minus California, the structure would have to be completely revamped, with new targets and new operating and pricing regimes.

Overall, the California-Quebec cap-and-trade connection is still in operation, but now under a cloud of uncertainty. As a result, the Ontario plan to join the California system and collect billions in easy revenues looks even more uncertain and undesirable than it does in Glen Murray’s $7 billion electric-car and natural-gas-reduction strategies.


Corcoran, T. (2016, June 3). Terence Corcoran: Ontario's rude awakening from its California carbon dreams. Retrieved June 03, 2016, from

A Confusing Plan for Climate Change

May 17, 2016


In light of Monday’s article published by the Globe and Mail we’d like to take a look at the position of our Ontario Government and their flip flopping relationship with Natural gas.

Globe Article published May 16, 2016:

There are many reasons for concern when reading this leak and many things that just don’t make any sense. For instance, removing natural gas a primary heat source for Ontario homes and business’? How can a Government drastically change their point of view when just two years ago they promised to “help Ontarians share in affordable supplies of natural gas”[i]? If we look at a mandate letter from our same Premier we see that this Government had envisioned Natural gas playing an integral role in powering our Province? They had even taken it a step further and proposed funding from the Government in the amount of $230 Million!![ii]

Read the mandate letter for yourself here:

September 25, 2014: Premier Wynne Energy Mandate Letter:

The biggest concern that our clients and our province should be worried about is the soaring electricity costs. The government has proposed geo-thermal based heat pump systems as the alternative to natural gas heating. The problem with a geo-thermal based heat pump system is that it is 100% electrical heat during the winter loading cycle. What that means for many consumers, and those highlighted in the Chatham-Kent area, would be an increase to a typical house hold utility bill of “$3,000 more per year”[iii].

The Government has severely lost sight of what was important to Ontarians just two years ago. Ontarians demanded a reduction in electricity pricing and part of the mandate letter was to “mitigate” those costs. Their current plan puts more onuses of electricity costs on the general populace and removes any chance of seeing our local business’ more competitive with even our neighboring provinces. [iv] The Government will also have to account for a huge supply of power generation in the province. Currently natural gas accounts for 6.6% of our electricity supply capabilities.[v] With so much electricity generated by natural gas it will be difficult to imagine the Government finding ways to build new power generation plants without incurring huge costs to our rate payers (population).


The good news is there is currently billions of dollars invested in bringing new sources of low cost natural gas resources to our business’ in Ontario. We are seeing projects by Union Gas, Enbridge and the TransCanada Pipeline (TCPL) to bring new pipelines to southern Ontario and we are expecting these projects to be completed this year. With so much invested in our infrastructure for natural gas it’s hard to imagine any Government completely removing Natural Gas as a heating source.



All content provided on this Canadian Energy Strategies inc., blog post is for informational purposes only. Canadian Energy Strategies inc., makes no representations as to the accuracy or completeness of any information on this site or found by following any link on this site.


Canada expects lower natural gas exports to U.S., higher LNG exports to other countries

Apr 27, 2016

graph of Canadian natural gas production, demand, and exports, as explained in the article text


In its recent publication, Canada's Energy Future (CEF), Canada's National Energy Board (NEB) projects that both Canada's natural gas production and its domestic natural gas consumption will increase through the next decade. Exports of natural gas by pipeline to the United States are expected to continue to decline. The planned construction of liquefied natural gas (LNG) export terminals on Canada's western coast, which would send LNG exports to Asian markets by 2019, plays a key role in maintaining Canada's overall natural gas exports.

Highlights from Canada's outlook include:

Net natural gas exports to the United States. The NEB expects that Canadian natural gas net exports to the United States will fall to 2.5 billion cubic feet per day (Bcf/d) by 2025, shrinking to a negligible volume by 2040. Net exports to the United States have already decreased from a high of 10.6 Bcf/d in 2007 to 7.4 Bcf/d in 2014. With the continued development of U.S. shale resources, such as the Marcellus, the United States now relies less on Canadian imports to meet demand. By 2040, CEF projects that U.S. natural gas exports to eastern Canada will largely offset Canadian natural gas exports to the United States.

Liquefied natural gas exports to other destinations. With the decline of natural gas exports to the United States, LNG exports are expected to be the primary driver of Canadian natural gas production growth, with production growing from 15 Bcf/d in 2015 to nearly 18 Bcf/d in 2025. The NEB analyzes two additional cases in CEF to explore the impact of LNG exports on production. In a low-LNG case, where no liquefaction facilities are constructed, production remains at the 2015 level of 15 Bcf/d through 2040. In a high-LNG case, where LNG exports reach 4.0 Bcf/d by 2023 and 6.0 Bcf/d by 2030, production increases to 22 Bcf/d by 2040. Based on these results, CEF anticipates that future Canadian natural gas production growth will rely on the construction of LNG export capacity.

Natural gas production. Recent technological advances in horizontal drilling and hydraulic fracturing have led to increased development of tight gas and shale gas resources in the Western Canadian Sedimentary Basin. CEF expects this development to continue as Canada's domestic natural gas production grows to nearly 18 Bcf/d by 2025. Tight natural gas accounts for 70% of projected production in 2025, and most of this natural gas is from the Montney formation in British Columbia and Alberta, where production is projected to triple from 3.0 Bcf/d to 9.6 Bcf/d between 2014 and 2040. Production growth also occurs in the Alberta Deep Basin (tight) and the Horn River Basin (shale). These increases offset the decline in production from other resources.


graph of Canadian marketed natural gas production, as explained in the article textSource: U.S. Energy Information Administration, based on Canada's National Energy Board, Canada's Energy Future 2016: Energy Supply and Demand Projections to 2040

Domestic natural gas consumption. Canadian natural gas consumption is also projected to rise, reaching 16.4 Bcf/d by 2025 and 18.6 Bcf/d by 2040. The industrial sector, which includes refining and oil exploration, is the primary driver of this growth, as well as the largest consumer of natural gas. Oil sands operations alone currently account for 20% of Canadian natural gas consumption. By 2040, CEF expects oil sands production to more than double to 4.8 million barrels per day, consuming 3.4 Bcf/d of natural gas. Another source of natural gas demand growth is electricity generation, whose consumption rises to more than 3.2 Bcf/d by the end of the projection period.


Dyl, K. (2016, April 26). Canada expects lower natural gas exports to U.S., higher LNG exports to other countries. Retrieved April 27, 2016, from

Why U.S. Natural Gas Prices Should Double

Apr 7, 2016

Natural gas prices should double over the next year.


Over-supply plus a warm 2015-2016 winter have resulted in low gas prices. That is about to change because supply is decreasing (Figure 1).

Total supply–dry gas production plus net imports–has been declining since October 2015* because gas production is flat, imports are decreasing and exports are increasing. Shale gas production has stopped growing and conventional gas production has been declining for the past 15 years. As a result, the supply surplus that has existed since December 2014 is disappearing and will move into deficit by November 2016 according to data in the EIA March STEO (Short Term Energy Outlook) .

During the last supply deficit from December 2012 to November 2014, Henry Hub spot prices averaged $4.05 per mmBtu. Prices averaged $1.99 per mmBtu in the first quarter of 2016, so it is reasonable to assume that prices may double during the next period of deficit.

EIA forecasts that gas prices will increase to $3.31 by the end of 2017 but that is overly conservative because it assumes an immediate and improbable return to production growth once the supply deficit and higher prices are established (Figure 1).

Production companies are in financial distress and are unlikely to return to gas drilling at the $2.75 price that EIA forecasts for November 2016. The oil-field service industry is in disarray and is probably unable to reassemble drilling and fracking crews and equipment in less than 6 to 12 months after demand resumes.

There are currently 92 rigs drilling for gas. That is 150 rigs less than the previous record-low set in 1992 (Figure 2). 

Production cannot be maintained at this level despite unrealistic faith in drilling efficiency and spare capacity from uncompleted wells. 

Figure 1. EIA U.S. natural gas supply balance and forecast. Production, consumption and supply balance values are 12-month moving averages. Source: EIA and Labyrinth Consulting Services, Inc.

 A Tale of Two Price Cycles


Storage and production patterns for 2015 – 2016 appear quite similar to patterns observed in 2011 – 2012. Both periods are characterized by exceptionally high storage and comparative inventory levels, and record-low spot gas prices.

The storage and comparative inventory surplus of October 2011 – March 2012 disappeared as gas supply fell in response to low prices (Figure 3). By April 2013, gas prices were near $4.20 because the surplus had become a deficit. A cold winter sent prices above $6.00 in February 2014.

A similar pattern may be occurring in 2016.

The monthly average Henry Hub price for gas in March 2016 was $1.71 per mmBtu. That is the lowest CPI-adjusted monthly price (February 2016 dollars) in 40 years (Figure 3 shows 1999-present).  The previous record low price was $2.01 in April 2012. The 2012 low coincided with a comparative inventory peak followed by an inventory deficit and gas prices that exceeded $4.00 by December 2013. The current 2016 price low must be near the latest comparative inventory peak.

Figure 2. U.S. gas-directed rig count, 1987-2016. Source: Baker Hughes and Labyrinth Consulting Services, Inc.


Comparative inventory is a measure of gas storage volume compared to a moving average of inventory values for the same time period over the 5 previous years. Comparative inventory (CI) provides an excellent negative correlation with natural gas spot prices.

Absolute storage levels were nearly the same for the last week of March 2016 (2,468 Bcf) and the last week of March 2012 (2,472 Bcf), and 2016 appears to be trending lower relative to 2012 (Figure 4).

Gas production was flat from February 2012 through December 2013 in response to the price collapse that culminated in April 2012 (Figure 5). The price minimum coincided with a supply surplus maximum that disappeared and became a supply deficit by February 2013.

Figure 3. U.S. natural gas storage and CPI-adjusted Henry Hub spot price in February 2016 dollars per mmBtu. Source: EIA, U.S. Bureau of Labor Statistics and Labyrinth Consulting Services, Inc.


Gas production has been flat since September 2015 (Figure 5).  Total dry gas production in March 2016 was 0.7 bcfd less than in September 2015 and the latest EIA data indicates that production for April is 1.2% (-0.83 bcfd) less than a year ago. EIA’s supply forecast (Figure 1) suggests that the present surplus will become a deficit later in 2016.

Why Natural Gas Prices Will Double

I used the EIA March 2016 STEO inventory forecast to calculate comparative inventory for the rest of 2016 and 2017.  This data indicates a fall in comparative inventory beginning in April or May 2016 (Figure 6).

Figure 4. Comparison of U.S. natural gas storage levels, 2012-2016. Source EIA and Labyrinth Consulting Services, Inc.


That should result in a return to higher gas prices. The price estimate based on comparative inventory (shown in red) is more bullish than EIA’s price forecast (shown in orange) but both indicate a substantial percentage increase in prices.

EIA forecasts $3.20 gas prices in January and February 2016, and $3.41 in December 2017.

My forecast based on comparative inventories is about 15% higher overall than EIA’s but peak prices are 20-30% higher.  

It calls for winter prices in the $4-range for 2016 and 2017.

Figure 5. Dry gas production, Henry Hub prices and total supply surplus or deficit. Supply surplus and deficit values represent 12-month moving averages as in Figure 1. Source: EIA and Labyrinth Consulting Services, Inc.

Figure 6. U.S. natural gas comparative inventory, Henry Hub price and forecast. Source: EIA and Labyrinth Consulting Services, Inc.


Putting Prices In Perspective

A doubling of gas prices to $4.00 per mmBtu may seem too optimistic based on current price levels that have averaged about $2.00 since the beginning of 2016.

Yet average prices since 1976 are $4.61 in 2016 dollars and the modal price for that period is $3.50 (Figure 7).

Moreover, the average price since January 2009 is $3.80 (2016 dollars) and the long-term trend-line since 1976 is more than $5.00 per mmBtu.

All the data presented in this analysis suggests that present gas prices represent the low point in a price cycle similar to October 2011-January 2015 in which $2 gas was the bottom in an overall cycle whose average price was $3.65. That price is consistent with average prices since 2009 and the long-term modal price. The average of 2011-2015 peak prices (November 2013-December 2014 period of negative comparative inventory–Figure 6) was $4.34 per mmBtu.

My forecast for gas prices to average $3.65 in 2017 (Figure 6) is in fact conservative.

It is based on the dubious EIA assumption that producers will immediately respond to an increase in gas prices to about $2.35 per mmBtu (their forecast price) with renewed drilling and that production will increase strongly throughout the rest of 2016 and 2017.

That is what happened in early 2014 (Figure 5) but then, gas prices were more than $6 and external capital was readily available before the oil-price collapse that began later that year. Although capital is still available, companies are more likely use it to pay down debt than to resume drilling especially for gas at least for the rest of 2016 and possibly longer.

 The days of pure gas players are pretty much over and liquids are a more attractive drilling target than natural gas at any price. 

Having said that, the best operators in the Marcellus Shale play need $3.50 to $4.00 gas prices to break even and most need $4.25 to $5.50. In the Utica and Woodford plays, most operators need at least $5.00 to $6.00 prices to break even.

February gas production has declined 0.7 bcfd from its peak in September 2015. EIA’s production forecast calls for a 1 bcfd increase by December 2016 and an almost 3 bcfd increase by December 2017. It is difficult to imagine that either price forecast shown in Figure 6 would result in the drilling resurgence necessary to realize those higher rates.

 That is why it is probably conservative to suggest that gas prices may double in the next year or so.



*Production, consumption and supply balance data in Figure 1 are 12-month moving average values.



 *Berman, A. (2016, April 7). Why U.S. Natural Gas Prices Should Double. Retrieved April 7, 2016, from





Quebec move to seek Energy East injunction provokes regional tensions

Mar 4, 2016


The Quebec government has raised the regional tensions ahead of Prime Minister Justin Trudeau’s climate summit set to begin Wednesday by requesting an injunction against the controversial Energy East pipeline.

Quebec is asking the court to force TransCanada Corp. to comply with provincial law and submit the Energy East project for a provincial environmental assessment. Provincial Environment Minister David Heurtel said the government is not signalling its intention to block the pipeline, but merely insisting that TransCanada follow provincial law.

But Saskatchewan Premier Brad Wall and conservative opposition leaders in Alberta slammed the move, saying it appears to be another Eastern Canadian attack on the western oil industry. Montreal Mayor Denis Coderre and his local counterparts recently stirred up a hornets’ nest of regional hostility when they announced their opposition to Energy East, which would carry 1.1 million barrels of crude to eastern refineries and an export terminal in Saint John, N.B.

However, Alberta Premier Rachel Notley said she received assurances from Quebec that the provincial government is not erecting new barriers to the pipeline project, and that it will respect National Energy Board jurisdiction.

“I was getting quite ready to come in here with guns blazing” on the Quebec action, Ms. Notley said during a news conference Tuesday in Edmonton. But, she said, she is ready to accept Quebec’s explanation that the provincial review is similar to one conducted by the Ontario Energy Board last year.

“We would be very concerned if this was about a new, competing, parallel process” that would require interprovincial pipelines to meet a series of provincial approvals across the country, she added. “If we ultimately determine that this is what this is intended to turn into, we will vigorously oppose it and you will hear a lot more from me on it.”

The flare-up in regional tensions comes at an inopportune time for the Prime Minister.

He meets his provincial and territorial counterparts on Wednesday and Thursday in Vancouver to discuss a national climate strategy. The Liberal government wants to see a national effort that would include a minimum carbon price across all provinces, as well as tougher energy efficiency standards, investments in green infrastructure and clean technology, and support to reduce greenhouse gas emissions in the country’s oil and gas industry.

At an event in Vancouver on Tuesday, Mr. Trudeau said some regional disagreements are to be expected and the country’s diversity is a source of strength rather than weakness. He added that it is “understandable” that provincial governments want to ensure resource projects garner social licence, and that his government is requiring companies and regulators to consult more with Canadians to win that support.

“One of the fundamental responsibilities of any prime minister of Canada … is to get our resources to market,” he said. “And in the 21st century, getting our resources to market means doing them in a responsible and environmentally sustainably way. In order to get projects built, we need a level of public confidence, of public trust that hasn’t been necessary in the past.”

Mr. Trudeau and Ms. Notley argue that one way to build support for resource projects is to have a credible pan-Canadian climate strategy that, in Alberta’s case, includes carbon pricing and an eventual cap on emissions from the oil sands.

“Canada must step up to a new and better role as one of the world’s most environmentally progressive economies, and one of the world’s most environmentally progressive energy producers,” the Alberta Premier said.

But Saskatchewan’s Mr. Wall said it appears Alberta’s approach is failing to win support for pipelines or the oil industry more broadly in other provinces. Quebec’s request for an injunction will create problems for national leaders, he said Tuesday.

“I’ve asked our trade minister and our trade officials to look at what options we have to say, you know, enough is enough,” Mr. Wall said. “Saskatchewan – and western Canada also – has to protect its own interest and send some strong messages if that’s what the province of Quebec is doing.”

Quebec’s Environment Minister David Heurtel insisted his province is merely requiring TransCanada is follow provincial law. Failure to do so could leave the company and the province subject to legal challenges down the road, he said, noting a court decision in British Columbia that will require that province to do its own environmental review of the Northern Gateway pipeline.

“This is not jurisdictional issue; it’s not east versus west; it’s not about Quebec trying to block Alberta or Saskatchewan,” Mr. Heurtel said in an interview. “We are neither for nor against the project.”




source: MCCARTHY, S., BAILEY, I., & PERREAUX, A. (216, March 01). Quebec move to seek Energy East injunction provokes regional tensions. Retrieved March 04, 2016, from