Two-month blip an illusion

Canadian well completions edge ahead of 2006 numbers in October, November, but oil and gas discoveries lag, pointing to grim 2008

Gary Park

For Petroleum News

Even the shreds of hope are worth clinging to in Canada these days despite what is widely expected to be the choppiest year in recent memory for the Alberta industry in 2008.

Given that, there was the faintest hint of encouragement towards the end of 2007 as Canadian operators exceeded 2006 well completions in October and November (the December numbers won’t be available until late January).

They drilled 1,797 wells in November (39 better than a year earlier) after tallying 1,956 in October (up 38). Even Alberta and British Columbia edged ahead of the November 2006 count.

To the end of November, 17,038 wells were drilled, off 20.4 percent from the 11-month count in 2006 of 21,417 and the record year of 2005 when rigs were released on 22,455 wells.

Wells started in November also climbed marginally to 1,834 from 1,792 in November 2006, but the 11-month total was 17,032, off 20 percent.

Final count will fall short

For the January-November period, Alberta dropped 20 percent to 12,746 wells and British Columbia was off 37 percent at 798 wells, while Saskatchewan declined 11 percent to 3,143 wells.

Exploratory wells tallied 3,218, down 41 percent and plunging towards the most recent low point of 2,985 wells in 1999.

Oil development completions were 4,212, the most in seven years, but the 9,546 gas development completions hit their lowest ebb since 2003.

Oil discoveries were 718, 94 behind the 11-month count in 2006, but the second highest in nine years, largely driven by the high price of oil and activity in Saskatchewan’s Bakken play.

Gas well discoveries were reported at 2,376, a precipitous decline of 1,237 from the previous year.

Gas production down

And FirstEnergy warns the outlook is even worse, with gas supply reductions increasing to 2 bcf per day over the next two years as gas supplies head for the “proverbial cliff” unless prices rebound before late 2008.

The grimmest statistics of all these days cover rig utilization, which fell to 40-45 percent from mid-October to November 2007, from 54-58 percent in the same period of 2006 and a staggering 84-90 percent in 2005.

Alan Laws, an oilfield services analyst with Merrill Lynch, told the Financial Post there is not the demand to “create the normal post-Christmas snap back of activity. It’s going to be a pretty harsh winter (the peak drilling season in Canada).”

Regardless of an 18-month slump in gas prices, persistently high drilling and service costs and industry unhappiness over Alberta’s planned royalty hikes, it’s not as if the leading E&P companies are short of the financial means to revive their capital programs at short notice.

Cash flows high

Even capital spending at C$17.2 billion beat the comparable quarter in 2006 of C16.23 billion.

And, despite the collective industry spurning of Alberta, land sales racked up the third highest total on record.

But the dip in rig utilization in the fourth quarter to 34 percent — the worst since the prolonged industry swoon from 1986 to 1992 — is seen as setting the stage for a drive to 14,500 wells or less in 2008, about 10,000 wells short of the 2005 benchmark year.

Roger Soucy, president of the Petroleum Services Association of Canada, said that although some rigs are destined for the United States or overseas, many will simply be decommissioned or sit idle.

For some, consolidation may be the only means of survival as they follow the pre-Christmas merger of Peak Energy Services Trust and Wellco Energy Services Trust.

Peak Chairman and Chief Executive Officer Chris Haslam said “we’re now in the 18th month of this current down-cycle” and because of royalty changes and cap-ex cutbacks “there will be a significant reduction of drilling in Alberta.

“Opportunities do present themselves in down markets and we want to be very nimble in terms of being able to react to that,” he said.

Haslam estimates the merger can generate combined initial savings of C$5.5 million a year through reduced administrative and operating costs and even more once integration begins.

For the first nine months of 2007 Peak reported a net loss of C$8.72 million, compared with a C$19.13 million profit in the same period of 2006, and Wellco tumbled from a comparable profit of C$13.48 million to a net loss of C$1.58 million.

M&As could grow

Some analysts say there is little future for companies producing less than 10,000 barrels of oil equivalent per day, which means tough times for the host of small gas-weighted companies who are being shut out of the equity markets and are reportedly on the prowl for buyers or merger partners.

Tambosso is counting on more corporate rather than asset deals, especially by juniors who feel they are getting a raw deal from the marketplace.

That wave could easily turn into a tsunami for the bigger players, unless they can successfully shift their powerbases from Alberta to Saskatchewan, British Columbia, the United States or overseas.

There are estimates that the market value of companies with 95 percent of their production in Alberta — mostly juniors, which rely on dwindling light oil and shallow gas plays — has been slashed by 25 percent.

Alberta face-to-face with royalty deadline

It set a nominal Jan. 22 deadline to reach an agreement with the two producers, or resort to “other means.”

The 90-day negotiating period has proceeded without any party walking away from the table, although there have been hints of more progress towards a resolution with Suncor, partly because Syncrude is a consortium of seven companies, four of whom are also operators of their own projects.

At stake is the government’s determination to “level the playing field for all industry stakeholders” by rewriting royalty contracts with the two companies that were not due to expire until 2016.

Investment banker Tristone Capital has accused the government of “tossing these contracts out the window,” further eroding “confidence in the security of the business environment in Alberta.”

Industry concerned

He said that giving only 14 months’ notice of its intention to impose new royalties — 1 percent to 9 percent during pre-payout on projects and 40 percent once capital costs are recovered — is a “very dramatic and negative step.”

For the government, the test is two-pronged: First, whether it can win over Suncor and Syncrude, and, secondly, what impact that will have on investment prospects in the single most important long-term element of Alberta’s oil and gas revenues.

Marcel Coutu, chief executive officer of the Canadian Oil Sands Trust, the largest stakeholder in Syncrude at 36.74 percent, has opted for the high road, saying the trust is open to discussing a “fair and equitable” renegotiation of its contract, so long as its “legal rights” were preserved.

The outcome has added significance for four other Syncrude partners — Imperial Oil 25 percent, Petro-Canada 12 percent, ConocoPhillips 9.03 percent and Nexen 7.23 percent — who are heading up their own oil sands operations.

Suncor Chief Executive Officer Rick George, who initially said the changes could have a “significant impact on industry economics,” indicated before Christmas that there is “no reason why a reasonable solution cannot be found.”

He said Suncor, in acknowledging that the oil sands resources belong to Alberta, is “very supportive” of reaching a deal.

George said his is “very optimistic” about the outcome of on-going discussions.

Beyond reiterating that any shift to a new royalty framework must “recognize and preserve our legal rights to the embedded value of our contracts,” Coutu would not comment on the status of the negotiations.

Spokesmen for the government told the Calgary Herald there is “marginally” more progress with Suncor than Syncrude, but Premier Ed Stelmach is confident agreements will be reached with both.

Accidental release of documents

In a 2006 report to the government, Alberta Energy estimated that since royalties were capped at certain commodity price levels in the mid-1990s, Alberta has lost as much as C$2.8 billion in “uncaptured economic rent” for just natural gas in 2003 and 2004.

At that time, a division within the department urged the government to hike conventional oil and gas royalties to “restore Alberta’s fair share at high prices” — a case that has since been reinforced with both oil and natural gas soaring to all-time highs.

Hugh MacDonald, energy spokesman for the opposition Alberta Liberal party, argued that if Albertans had been given access to the information during last year’s royalty debate they would have viewed the Stelmach government’s softening of royalty changes as “unacceptable.”

He said the disclosure provides 100 percent support for the stands taken by the government-appointed royalty review panel and the provincial auditor-general, both of whom were adamant that Alberta has denied itself a proper share of royalties.

—Gary Park