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It’s all about liquids in Western Canada With main commodity in doldrums, region’s natural gas producers find refuge in gas liquids, which generate about half their netbacks Gary Park For Petroleum News
The swing from price-crippled natural gas to oil and natural gas liquids, NGLs, could add 1 million barrels per day to Western Canada’s output over the next five years, analysts and investors were told at Calgary conferences.
Powered by high returns for NGLs, the shift accounted for 295 conventional oil rigs and 117 bitumen rigs in the first week of September, with 263 rigs drilling horizontal wells.
And the signs point in only one direction: The long gas-targeted domination of the region seems destined for a drawn-out slump.
Michael Zenker, head of North American gas and power research for Barclay’s Capital, reinforced that bleak outlook when he forecast that although gas prices are unlikely to fall below current levels of US$4 per million British thermal units, there is little hope of them rising over the next couple of years.
He said that even longer-term price forecasts of US$5.50 do not improve the economics of many plays.
In a website forecast, AJM Deloitte expects prices will average US$4.50 per thousand cubic feet this year, rising to US$5 in 2012 and US$7 by 2020.
Well permits up For the first eight months of 2011, energy regulators across Canada issued 12,068 new well permits — 21 percent more than the same period last year — with horizontal holes claiming 6,095.
Oil and bitumen approvals totaled 7,721, compared with 5,668 in the January-August period of 2010, with Alberta claiming 4,138 (up 1,364 from a year earlier) and Saskatchewan tallying 3,155 (up 1,050).
Gas and coalbed methane permitting continued its downward spiral in Western Canada at 2,208 wells from 3,225 in the first eight months of 2010.
Based on that trend, Jay Williams, a Bentek Energy analyst, told one of the conferences that “there’s a lot of (oil and liquids) growth on the way,” powered by the use of horizontal technology to probe deeper into reservoirs.
“The best place to find oil is where you last found it,” he observed.
Williams estimated the price disparity between gas liquids and dry gas has widened to more than 20 from 11 in 2008, forcing more companies to transfer to liquids-rich plays to improve their drilling economics.
Land sales lift revenues On top of the drilling statistics, government land sales have lifted revenues in Alberta to C$2.76 billion so far this year at an average C$850 per hectare from C$1.71 billion at an average C$713 last year, while gas-dominated British Columbia sales have slumped.
“Companies are buying up Alberta lands to go after oil,” Williams said. “They did it in 2010 and now they’re starting to deploy a lot more rigs to start drilling those areas.”
“For gas producers, the returns from NGLs are allowing companies to develop gas plays that would otherwise be uneconomic,” said Jim Bertram, chief executive officer of Keyera, an Alberta-based midstream company. He estimated liquids currently make up more than half a producer’s netback and are the only source of economic returns with gas prices stuck around $4 per thousand cubic feet.
Jason Skehar, president of Bonavista Energy, told a Peters & Co. conference that the widening over the last four years of the gap between NGLs and natural gas means that virtually all of his company’s gas opportunities in Western Canada are concentrated on liquids-rich plays.
And he believes there is ample reason to believe the liquids demand will continue, partly to provide feedstock to a recovering North American petrochemical sector.
Alberta is estimated to consume about 125,000 bpd of condensate, almost 100,000 bpd short of its consumption, with a large portion of those volumes used as diluents to move heavy oil or bitumen through pipelines.
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