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Royalty dread spreads Natural gas, which adds more to Alberta coffers than conventional crude, under attack
By Gary Park For Petroleum News
For the past year it has all been about the oil sands. Now it’s starting to be all about natural gas.
As the Alberta government closes in on the bewitching decision-making hour, which could determine whether it is turned into rags or riches, the spotlight in the Royalty Ruckus is shifting to the province’s most valuable, yet most fragile resource.
No aspect of Alberta’s natural resource industry has experienced a more sickening ride in the last two years than conventional gas, which had a fleeting taste of an unparalleled windfall two winters ago and is now close to a tipping point.
In fiscal 2005-06, the government enjoyed a windfall from its gas royalties of C$8.388 billion before tumbling by more than C$2 billion in 2006-07 and facing a projected fall to C$4.6 billion in 2009-10.
Just how sour things have turned is reflected in an Oct. 15 short-term Canadian gas deliverability report by the National Energy Board — a forecast that should cause some anxiety in the United States, which depends on Canada for about 15 percent of its gas supplies.
If the Alberta government adopts the recommendations of its royalty review panel and raises its take from gas to 63 percent from 58 percent, the message from the industry is that the gas will effectively return to its dismal past, when it was largely an unwanted byproduct of oil production.
Drillers: increase would make gas drilling too expensive Don Herring, president of the Canadian Association of Oilwell Drilling Contractors, said implementing the royalty increase will make gas drilling in Alberta too expensive and will result in fewer wells and more jobs being lost.
He said the wheels are already starting to fall off the gas industry cart, with disastrous results for his member companies, which derive 70 percent of their work from gas drilling.
Paul Ziff, chief executive officer of the consulting firm Ziff Energy Group, has questioned whether the government has been provided with enough accurate information from an Energy Department technical report to make a correct decision on conventional gas royalties.
That report said that “despite the increase in costs in recent years, there is evidence that (gas) costs are still competitive,” contending that Alberta still ranks “below average in terms of profitability in North America.”
Citing a case study by IHS/CERA, the Energy Department contends that the average total cost including capital, operating, return on capital, severance tax and royalties for new wells in the United States and Canada is US$6.83 per thousand cubic feet, a figure that is “substantially” higher than the average cost in Alberta.
The study rates three conventional and three unconventional areas in Alberta among the lowest of 76 areas in the US and Canada.
Ziff challenges gas costs But a news release by the Ziff Energy Group said the conclusion that the Alberta Foothills gas play is the “lowest cost and most economically attractive gas play” in the province “flies in the face of both empirical knowledge and Canadian E&P industry experience.”
Ziff said that rather than being the lowest-cost gas play the Foothills region, based on its own F&D costs since the mid-1990s, has had the highest F&D costs of any play.
The firm also suggested the government data “may be somewhat dated (using 2005 numbers) and the foreign exchange is not current … a major issue when comparing the economics of U.S. and Canadian plays.”
Paul Ziff has been unable to find any company in Canada ready to confirm that Canada offers the best netbacks in North America or that the Foothills is the best place to be.
If that were the case, he said Alberta would be outperforming U.S. gas operations, instead of being barely above average levels of the last six years, while the U.S. is 50 percent higher.
Buckee: data suspect Such technical analysis aside, leaders among Alberta’s gas producers have flat out told the government it could ruin the gas sector by hiking royalties.
Although retired as chief executive officer at Talisman Energy, Jim Buckee is not about to ride quietly into the sunset.
With typical forthrightness, he sent a letter to Premier Ed Stelmach saying the royalty panel’s findings were based on suspect data, especially relating to gas.
“The decisions being made now affect the investment required to make future natural gas discoveries,” he said. “You can’t get royalties from wells that are not drilled.”
Buckee predicted Talisman, rather than pay higher royalties, would cut C$500 million from its Alberta gas spending in 2008 and move the money to the U.S. and overseas.
Noting that gas accounted for 60 percent of the 2006-07 royalties, he said Alberta would be foolish to harm a sector already reeling from low commodity prices.
“It’s the dominant product,” Buckee said. “There’s the potential for huge blunders here.”
Companies say higher royalties will hurt investment in gas Petro-Canada Chief Executive Officer Ron Brenneman, while conceding there is room for increasing gas royalties, said “the reality is that in the (Western Canada Sedimentary basin) the industry is pretty much tapped out in terms of investment economics. Right now, at current prices, investment can’t tolerate much higher royalties.”
EnCana, Canadian Natural Resources and ConocoPhillips have all joined that chorus, while the junior sector has warned it faces virtual extinction, compounded by the fact that it faces an added 40 percent increase in 2008 in the base fee for a government-approved levy on oil and gas wells collected by rural municipalities.
Martin King, an analyst with FirstEnergy Capital, said any royalty adjustments will only intensify the cost-driven slump in gas drilling and production in the Western Canada Sedimentary basin and could prevent the sector from taking advantage of a decline in domestic production and slowing liquefied natural gas imports in the U.S., which FirstEnergy believes could cause prices to improve in the first half of 2008 from the predicted 2007 average of US$7.08 per million British thermal units.
King said that price will be the ultimate decider for companies to readjust their drilling programs, but “it will take six to 12 months to feel the positive impact of stronger prices on production.”
NEB: deliverability dropping Without being able to factor in higher royalties, the National Energy Board forecast for the 2007-09 period said Canadian gas deliverability (the total amount of gas that could be supplied at any given time) could shrink by 7 percent to 15 percent over the period from 17.1 billion cubic feet per day at the end of 2006 to 14.5 bcf-15.8 bcf per day in 2009, sharply below its earlier predictions of 17 bcf per day.
Daily output from the WCSB over the forecast period is expected to drop to 13.7 bcf from, 16.2 bcf.
Currently about 60 percent of all Canadian gas is shipped to U.S. markets.
The NEB said deliverability has been fairly stable at about 17 bcf per day since 2000, with 98 percent originating from the WCSB and the rest from Atlantic Canada, which is expected to average about 440 million cubic feet per day in the short term.
Deliverability from the WCSB hangs primarily on the price of gas in North America, which is volatile because of weather-driven market demand, the availability of imported LNG and possible supply disruptions in the Gulf of Mexico.
“There is a pervasive drilling downturn that’s impacting most resources in the Western Canada basin,” said NEB gas supply analyst Ken Martin, echoing NEB chairman Gaetan Caron who said “the drilling that has sustained Canadian gas deliverability is gone, for the moment.”
The federal regulator said factors contributing to the projected downturn are maturing fields in the WCSB and the combination of high costs, low commodity prices and a strong Canadian dollar which is eating into profit margins from exports to the U.S.
Production from the WCSB is already down 800 million cubic feet per day as companies have slashed their budgets by 25-30 percent, deferring an estimated C$6 billion in drilling programs.
Chris Theal, an analyst with Tristone Capital, said any decision to implement punitive royalty measures will make the production outlook “worse than what the NEB is suggesting.”
He said the recommendation to hike gas royalties to 65 percent from 36 percent for wells producing more than 600,000 cubic feet per day would remove the incentive to chase bigger gas targets, given that 5 percent of the higher-deliverability wells represent 47 percent of Alberta’s volumes and 63 percent of the royalties.
Based on current trends, Ziff analyst Bill Gwozd said the current ratio, which sees 10 bcf per day of Canada’s 17 bcf of output shipped into the U.S., will be reversed by 2010 and by 2015 the volume available for export will be down to 5 bcf per day.
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