Oilfield geologists don’t have all the answers.

That’s the firmest conclusion that can be drawn from an Alberta Energy and Utilities Board (EUB) geological study that’s supposed to be crucial in settling a nasty dispute between oilsands developers and natural gas producers.

The EUB study, of the Wabiskaw-McMurray geological formations in the Athabasca oilsands area, found that about 60 per cent or 464 out of 777 gas pools in the underground formations are in contact with bitumen deposits.

That’s bad news for nearly 30 gas producers operating in the region, including Paramount Energy Trust, BP Canada Energy Co. and Canadian Natural Resources Ltd. But it’s making oilsands developers like Petro-Canada smile. The most affected producer is Paramount, which produces more than half its gas – more than 44 million cubic feet daily – from the area.

The EUB says production of Wabiskaw-McMurray gas is depleting the reservoir pressure needed to extract the tar-like bitumen using steam-injection technology. And the bitumen, the EUB notes, has 600 times the energy value of the gas. But Susan Riddell Rose, Paramount’s chief operating officer, has a point in arguing that the EUB’s geological study raises as many questions as it answers.

For instance, if only 60 per cent of 777 gas wells are in contact with the bitumen and threaten oilsands extraction, why did the EUB last summer order 938 gas wells in the area to be shut in?

What geological or other evidence did the regulator have for ordering this shutdown of two per cent of Alberta’s gas production?

After producers protested, the EUB agreed to allow 608 of the original 938 gas wells to continue operating. But 330 wells – representing more than 40 per cent of the area’s gas production – remain shut in on an interim basis.

One can sympathize with Paramount, whose trust unit price tumbled more than 10 per cent last week in the wake of the EUB’s geological study.

Still, this “gas-over-bitumen” battle has dragged on for more than six years of consultations and public hearings, causing uncertainty for oilsands developers, gas producers and investors. The sooner the issue is settled, the better.

EUB staff is to recommend January 26 which individual gas wells in the Athabasca oilsands region either will be permanently shut down or allowed to continue operating.

In the economic interest of all Albertans, those staff should rely on more information than just this one geological study in making their recommendations.

JUNIORS JUMPIN' IN BASIN

Some major firms are deserting Alberta’s Western Canadian Sedimentary Basin faster than pop tart Britney Spears got her marriage annulled.

Over the last few months, Murphy Oil Corp., ChevronTexaco Corp., El Paso Corp., Marathon Oil and ConocoPhillips have all put their Western Canadian assets on the block.

But that’s just dandy for many junior players that are finding the basin still yields plenty of oil and gas.

Many junior firms showed strong share gains in the two months following the third quarter. They included Diaz Resources (up 68 per cent), Canadian Superior (48 per cent) and Connacher Oil and Gas (47 per cent).

Third-quarter profit in 2003 for 68 Canadian juniors totalled $86.5 million, while cash flow amounted to about $300 million, says a report by Iradesso Communications Corp., a Calgary-based investor relations firm.

More than 61 per cent of the junior players’ production consisted of natural gas – a reflection of record-high average gas prices last year.

Maybe the stellar performance will be enough to make the majors say “Oops!” – as a certain ex-married pop singer might say.

RECORDS BUSTED

There’s still plenty of oil and gas in Western Canada, judging by the latest well-drilling estimates from the Canadian Association of Oilwell Drilling Contractors (CAODC).

Canadian companies drilled 19,851 wells in 2003 – 37 per cent more than in 2002, says Saj Shapiro, the CAODC’s manager of economic analysis.

The total for 2003 included 13,944 gas wells – much of it for shallow gas – along with 4,473 oil wells and 1,233 dry holes.

More than 580 rigs, or 86 per cent of the Canadian drilling fleet, are expected to be active throughout the first quarter of 2004. “Every rig that’s out there is employing about 45 direct employees,” plus service contractors, Shapiro says.

Chalk the record-setting year up to high commodity prices for oil and gas.

Shapiro says that with companies planning capital expenditures of $24 billion in 2004 (including the oilsands), the CAODC expects at least 18,000 wells will be finished.

HIGH COST, HIGH RISK

Seismic surveys showing that the Orphan Basin off Newfoundland may hold three times as much oil as the separate Jean d’Arc Basin feeding production from the Hibernia and Terra Nova oilfields are encouraging.

But the survey results should also be treated with caution.

As EnCana Corp. has discovered at its Deep Panuke gas project offshore Nova Scotia, it’s incredibly difficult and expensive to develop oil and gas in the North Atlantic’s harsh environment.

Geophysical Service Inc., with offices in Calgary, Houston and Milan, Italy, says it expects Newfoundland’s Orphan Basin to produce six to eight billion barrels of oil, based on three summer seasons of seismic surveys.

Last month, a joint-venture partnership of Chevron Canada Resources, Imperial Oil Resources and ExxonMobil Canada acquired eight deepwater parcels in the Orphan Basin, in exchange for a plan to spend $673 million over five years exploring the basin, about 370 kilometres northeast of St. John's.

As K.C. Williams, Imperial’s president and CEO, says: “This frontier basin is a high-risk and high-cost area.”

Those costs including drilling in a basin where depths range between 2,000 and 2,500 metres, and grappling with a regulatory maze where it takes more than 600 days to get a project approved.

This is a place where one exploratory well can cost up to $100 million.

It doesn’t take long to fill a hole that deep with a huge pile of money.

RALPH COUGHS UP GAS RELIEF

It’s enough to give you a warm glow all over.

Albertans can expect to receive about $62.50 off their next natural gas bill that for most homeowners will be about $225 to $250.

The Energy and Utilities Board approved higher January gas rates – from $7.32 per gigajoule in southern Alberta to $7.80 per gigajoule in the North. Those rates will trigger a provincial government rebate.

But forget about having some extra cash to help pay off Christmas credit-card bills or buy some clean wind-generated energy. The rebates will be in the form of credits, deducted from the balance of your gas bill.

The Alberta government expects to take in $6.7 billion in non-renewable resource revenue for the current fiscal year – nearly $2 billion more than estimated in the spring budget.

So when your $250 gas bill arrives this month, don’t forget to thank Ralph Klein for chipping in 60 bucks.