Providing coverage of Alaska and northern Canada's oil and gas industry
December 2007

Vol. 12, No. 51 Week of December 23, 2007

Alberta getting nudged off center-stage as tax hikes prompt big E&P companies to shift capital spending to United States

The verdicts are rolling in for Alberta’s proposed new royalty regime as the leading E&P companies take the wrapping off their 2008 capital budgets.

But, in the process, those companies are reinforcing a number of deeper, more troubling elements.

It’s well understood that conventional oil and natural gas reserves in Canada’s energy storehouse are depleting.

Similarly, the costs of labor, materials, oilfield services and municipal property taxes are becoming a deterrent.

The end result is bad news for a province that has relied heavily on the petroleum industry to compile 15 years of deficit-free budgets and wipe out its debt.

Without the oil sands and the prospect of some growth in unconventional gas prospects over the longer term, Alberta would be in a fix.

The message for the province is loud and clear: It can no longer take its future for granted and operate on cruise-control.

Companies decisively scaling back

Forget the earlier industry bluster and posturing. Companies are decisively scaling back their spending in Alberta, and, where they can, heading for Saskatchewan, British Columbia and the United States.

ARC Financial chief energy economist Peter Tertzakian said that “from a capital spending perspective, the current contraction (across Canada) … is the most severe in at least 20 years, especially in Alberta. In 2008, the resiliency of oil patch veterans will be tested.”

ARC estimates that Canadian conventional oil and gas spending (the bulk of which usually ends up in Alberta) will tumble to C$25 billion next year from about C$30 billion this year and the benchmark C$38 billion in 2006.

Richard Grafton, vice chairman of investment banker Canaccord Adams, said Alberta is “not really a place” where investors want to risk their exploration money because the upside is gone.

He said next year will be a difficult time for service companies, while mergers among trusts and juniors and North American credit issues will add to the woes.

The consensus among many industry observers is that failing a rebound in gas prices by early next year there will be a sweeping round of layoffs.

There is now little doubt that companies will punish Alberta for reworking its royalties by either staging a retreat in the province, or, where they can, heading to Saskatchewan, British Columbia and the United States.

EnCana to spend C$500 million less in Alberta

The clearest judgment on the state of the Alberta industry was delivered Dec. 12 by EnCana, which said its overall spending in Alberta in 2008 would be C$500 million less than it would have been under the existing royalty regime, dragging its Canadian drilling activity to a “very low level.”

The big independent had once threatened to withdraw C$1 billion from its Alberta budget next year, but scaled back because the government’s own framework was “less onerous” than the recommendations made by its royalty review panel, particularly scrapping a proposed oil sands severance tax.

Chief Executive Officer Randy Eresman said spending on Alberta gas projects and oil sands delineation drilling has been cut to “reflect the recent erosion of economic returns.”

He said that regardless of the 12-month wait until new royalties are implemented, EnCana’s 2008 budget has factored in those higher rates because of how they will affect future years’ cash flow from investments made next year.

Eresman said that in addition to royalty hikes, Alberta is being hurt by higher property tax, service, labor and energy costs, plus a sharp rise in the Canadian dollar against its U.S. counterpart that will boost operating costs by 10 percent.

Driving the point home, he said the industry, service sector, government and people of Alberta must “work together to reestablish the competitiveness of the development of Alberta’s resources.”

While EnCana’s budget will be unchanged in British Columbia at C$1 billion, the “significantly diminished returns” will take a bite out of Alberta drilling for shallow gas, deep gas, coalbed methane and oil sands delineation drilling.

Petro-Canada to slash Western Canadian gas activities

Ron Brenneman, chief executive officer at Petro-Canada, gave a similarly harsh assessment of the outlook in Western Canada (mostly Alberta) by announcing his company will increase its global spending in 2008 by 28 percent to C$5.3 billion, but slash its Western Canadian gas activities by 23 percent to C$415 million, while raising U.S. spending by C$60 million to C$190 million.

He said Petro-Canada’s gas business is “shifting away from Western Canada” to the U.S. Rockies, adding “it’s fair to say it’s been accelerated by factors such as changes to the Alberta royalty structure.”

Oil sands spending will rise to C$1.5 million from C$620 million, with C$1.17 billion earmarked to complete front-end engineering on its Fort Hills project, which is due for corporate sanctioning in the second half of 2008.

Although the planned royalty changes are “not enough to impact the overall viability” of integrated mining and upgrading operations, Brennan said the new regime might force Petro-Canada to re-examine its numbers and change the scope of Fort Hills.

But his overriding concern is the state of the Western Canada Sedimentary basin, where Petro-Canada’s shifting focus to the U.S., because of the basin’s maturity, was accelerated by Alberta’s royalty decisions.

“There are various estimates out there today that in order to justify full-cycle exploration and development of gas in Western Canada you need somewhere in the range of (gas prices at C$9 per thousand cubic feet). Gas is currently selling at C$7.”

He said finding costs have gone up exponentially in the past four years, with no corresponding increase in gas prices, while each successful well in the WCSB is yielding “less and less gas.”

“So the numbers don’t work. I’m talking about averages, of course, so there are some things that still work,” Brenneman said. “And that’s why we’re still spending C$415 million (in the WCSB). That’s not only Alberta … but a big chunk of that is in B.C.”

He said finding and development costs in the U.S. Rockies are “still pretty attractive (and the jurisdictions there) haven’t made any changes in their royalty rates.”

“If Alberta is sending a signal that it’s not interested in exploration, we’ll respond,” Brenneman said.

—Gary Park

Alaska well-placed in global survey

As reported in last week’s issue of Petroleum News, Alaska trails Wyoming and Colorado among U.S. states, but edges out all Canadian provinces except Saskatchewan in a study of investment “friendliness” among global oil and gas jurisdictions compiled by the Fraser Institute, an independent Canadian research organization.

An All-inclusive Composite Index placed Alaska 14th “best” among 54 jurisdictions in a field led by Colorado, followed by Thailand, Qatar, Romania and the United Kingdom (see story on Alaska’s placement in study in Dec. 16 issue of Petroleum News).

Saskatchewan was 13th, Texas 21st, Alberta 22nd, British Columbia 26th, the Northwest Territories 34th, Nova Scotia 35th, Newfoundland and Labrador 45th and Montana 47th.

Of the U.S. states, Wyoming was 10th, Texas 21st, Oklahoma 23rd, California 24th, Louisiana 27th and Montana 47th.

The “worst,” in descending order, were Bolivia, Venezuela, Ecuador, Iran, Russia, Argentina and Cuba.

The standings were compiled from a blending of responses from 375 worldwide companies, whose E&P budgets last year totaled US$85 billion, or 31 percent of global expenditures.

The respondents were given options to measure the various jurisdictions, such as “encourages investment,” is a “strong deterrent to investment” and “would not invest.”

The survey weighed a number of factors ranging from royalties, taxation and regulations, labor availability, political stability, environmental regulations and the business climate.

Of those deemed to have the most favorable regulatory climate, the Northwest Territories and Colorado shared top spot with Peru, Qatar, Romania and Thailand. Saskatchewan was 14th, Oklahoma 15th, Alaska 19th, Alberta 26th and British Columbia 32nd.

Of the E&P companies surveyed, their 2006 budgets were apportioned at 35.91 percent for conventional crude, 10.32 percent for unconventional sources (such as oil sands and oil shales), 33.93 percent for conventional natural gas, 11.31 percent for unconventional gas (such as coalbed methane) and 8.53 for “other.”

Survey before Alberta royalty review

The survey was conducted before the results of Alberta’s royalty review were known.

To that end Gerry Angevine, the Fraser Institute’s senior economist at its Center for Energy Policy, said he was surprised Alberta did not perform better than Saskatchewan.

“If Alberta didn’t do that well now, what will be the case next year?” he asked.

Saskatchewan’s newly appointed Energy Minister Bill Boyd said his province was encouraged by the results and would do its best to maintain the rating.

He said the province has no intention of raising royalties and undoing the “tremendous advantages” it now enjoys.

Currently Saskatchewan pumps 425,000 barrels per day of conventional crude, putting it second in Canada behind Alberta’s 540,000 bpd, although Alberta climbs to 1.9 million bpd after oil sands output is rolled in.

The study noted that even if Saskatchewan’s tax policies were less favorable than Alberta’s, it emerged on top in Canada once labor availability and the low cost of regulatory compliance were taken into account.

—Gary Park

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