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Eastern Canadian utilities have started to resort to U.S. shale gas. (Jean Becq/Encana Corp.)
Eastern Canadian utilities have started to resort to U.S. shale gas. (Jean Becq/Encana Corp.)

Alberta’s new energy problem: Natural gas is on the discount rack Add to ...

Alberta’s energy industry has gone from battling a bitumen bubble to grappling with a gas-price gap – a deep discount on the province’s natural gas that threatens new cuts in drilling activity and production levels.

The discount on natural gas prices in Alberta compared with Henry Hub, La., the pricing point for U.S. gas futures, has widened by 86 per cent in the last two months.

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Alberta gas for August delivery is selling for about $2.48 per gigajoule, down 25 per cent from the beginning of June. At Henry Hub, the equivalent amount of gas sells for about $3.50.

One cause of the gap: the cost of moving the fuel to Ontario and Quebec via TransCanada Corp. has surged for shippers without long-term contracts. That is making Alberta producers reluctant to send gas east.

With other export pipelines running full, or close to full, supplies are building up within Alberta, pushing up storage levels and pressuring already-weak prices.

Alberta’s gas is now selling at a discount of $1.60 (U.S.) per British thermal units discount to the price at Union Gas’s Dawn hub southeast of Sarnia, Ont. The discount has nearly doubled in the past two months.

If the situation persists, it has the potential to cause an even more severe drop in industry output. Production rates in Alberta have already been chopped by 25 per cent since 2005, due in part to a huge increase in competing U.S. shale gas production.

“That’s the risk. It’s scaring the hell out of me, to be honest,” said Samir Kayande, analyst and vice-president, energy, at ITG Investment Research. Companies with little or no gas-price hedging positions are most exposed to the price plunge, he said, pointing to Birchcliff Energy Ltd., Paramount Resources Ltd. and Tourmaline Oil Corp. as examples.

The big question is whether the wide gap, or “basis differential” between the Alberta gas, priced at the AECO-C hub in the province’s southeast, and Henry Hub is a short-term irritant or the beginning of a long-term problem, Mr. Kayande said.

Early this year, Alberta’s oil sands-derived crude sold at deep discounts to the price of U.S. benchmark light oil due partly to fears about insufficient capacity to move a growing supply to export markets. That prompted the Alberta government to warn of a $6-billion shortfall in resource revenue.

Prices for Alberta heavy oil have since roared back as more transport options, such as rail, have become available.

But gas markets are providing new headaches.

Normally, gas-price differentials reflect the transport cost between Alberta and Eastern markets. Changes in regulated tolling on TransCanada’s mainline pipeline system that took effect on July 1 have contributed to lower flow rates, analysts said.

Volumes on the system between the Alberta-Saskatchewan border and Southern Ontario had already declined as Eastern Canadian utilities have started to tap into cheaper supplies from the Marcellus shale gas fields of the U.S. Northeast. Prospects for more have raised questions about the viability of the Canadian mainline.

Gas flows have fallen to the point where TransCanada has proposed switching one of its adjacent lines to oil service for its Energy East pipeline.

The toll changes, imposed by the National Energy Board, were designed to increase the competitiveness of the 14,101-kilometre system, which has been the backbone of Canadian gas transportation since the 1950s, TD Securities analyst Aaron Bilkoski said in a recent report.

The NEB set a fixed toll of $1.42 per gigajoule through 2017 for “firm,” or guaranteed, capacity, down from $2.56 per GJ, and gave TransCanada the power to set tolls for “interruptible” and “short-term firm” service, which offer less protection against being halted for operational or other reasons.

Those tolls have been set at premiums of 220 per cent above firm for interruptible and as much as 1,200 per cent for winter short-term service, according to Mr. Bilkoski.

“Given the extremely high tolls on non-firm transportation, less (Western Canadian) natural gas is being sent out of the province,” Mr. Bilkoski wrote. It is likely that Alberta inventory increases will exceed last year and the five-year average as a result, he said.

For its part, TransCanada said it has seen a big increase in new firm contracts since the NEB first announced the new toll structure in March. Executives said on a conference call last week that the company has signed deals for capacity of more than one billion cubic feet a day, nearly doubling that service.

FirstEnergy Capital Corp. analyst Martin King said he believes the market will level out over time. “Maybe on average we’ll have a bit of a wider basis than we did before, but it’s not the end of the world, either,” he said.

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