It’s a high-stakes gamble.
Oilsands developers are betting that Ottawa keeps its promise to limit the costs of Kyoto, that oil prices stay high and that the price of skilled labour comes down.
If they’re wrong, the billions of dollars companies are lining up to build new oilsands plants could disappear into the tar pits like so many dinosaurs.
Houston-based ConocoPhillips announced last week it plans to start construction next year on the $1.4-billion Surmont facility southeast of Fort McMurray. The steam-assisted gravity drainage (SAGD) project, which got regulatory approval in May, is slated to produce a peak of 100,000 barrels of oil a day (b/d).
Earlier this month, Canadian Natural Resources Limited signalled it was nearing a “Go” on its proposed $8.5-billion Horizon oilsands mining operation north of Fort McMurray. CNRL boosted spending on the 232,000-b/d project by $600 million in 2004.
And in September, Devon Energy Corp. of Oklahoma City said it’s full steam ahead for its $500-million Jackfish project, also a SAGD operation that’s expected to pump out 35,000 b/d.
The oilpatch is fond of playing follow the leader.
Look for Nexen Inc. to give the green light to its already approved $3-billion Long Lake oilsands facility by the end of December.
Even Petro-Canada, despite chief executive Ron Brenneman fretting about spiralling construction costs, will take the chocks off its $5.8-billion oilsands expansion.
They’re all counting on assurances, provided by “au revoir” Prime Minister Jean Chretien, that implementing the Kyoto accord to cut greenhouse gases won’t harm the sector. It would be wise to get the same guarantees in writing from Paul Martin – just to hedge their bets.
THE OL' ONE-TWO
Here’s a combination punch that the conventional oil and gas sector has to brace itself for – falling oil prices and rising operating costs.
The conventional side right now is ducking one-half of the combo – the escalating costs – only because the other half of the punch – the declining oil prices – has yet to be delivered.
Operating costs in Western Canada’s oil and natural gas fields are continuing to rise, according to Ziff Energy Group in Calgary.
In its 2003 study of 176 oil and gas fields in the region, Ziff reports that average oil operating costs increased six per cent to $6.85 barrel of oil equivalent in 2002, up from $6.50 in 2001.
The average operating cost for gas increased three per cent over 2001, to 70 cents per thousand cubic feet in 2002.
Increased drilling activity also led to rising costs for related services, such as well servicing. The cost of repairs and maintenance also climbed.
Companies that are depending on volatile world oil prices and North American gas prices to achieve their production targets and offset their rising operating costs are playing with fire. With no control over cyclical commodity prices, they’ll get burned when – not if – those prices fall.
The smarter strategy, as Ziff Energy CEO Paul Ziff and other analysts recommend, is for producers to be more energy efficient and do everything possible to reduce operating costs.
ROBUST RESERVES
The amount of oilsands recoverable with current technologies continues to increase, while conventional oil and gas reserves keep declining.
Oilsands companies replaced 162 per cent of their production in 2002, pushing remaining oilsands reserves to 6.9 billion barrels, the Canadian Association of Petroleum Producers said last week.
Annual oilsands production reached 268 million barrels in 2002, compared with reserve additions of 434 million barrels at year-end.
In contrast, additions to crude oil reserves amounted to 370 million barrels in 2002, replacing just 69 per cent of the 535 million barrels produced.
For natural gas, new reserve additions of 5.3 trillion cubic feet (tcf) weren’t enough, despite record-high drilling activity, to offset the 6.4 million tcf produced – for a replacement rate of 84 per cent.
What does it all mean? As EnCana Corp. CEO Gwyn Morgan noted last week, North American natural gas markets face a supply crunch that can be met in the near term only by increasing production from unconventional sources, such as coalbed methane (CBM) and tight-sand deposits. They are more difficult and costly to extract and, in the case of CBM gas, present largely unknown environmental challenges.
REEL PROSPECTS
The cod are gone but Alberta firms are still fishing for natural gas in the Atlantic.
Canadian Superior Energy Inc. has just shelled out more than $14 million to acquire, through its wholly owned subsidiary Canadian Frontier Energy Corp., two exploration properties offshore Nova Scotia.
The purchase makes Canadian Superior one of the largest acreage holders in the area, with interests in six exploration licences totalling nearly 1.3 million acres, says company president Greg Noval.
Acquiring offshore licences, however, is like setting a trawl line in the sea. Actually catching the fish depends on a lot of skill – and a little luck.
EnCana Corp. appears to have a nibble, though. Duke Energy, whose pipeline would carry gas from EnCana’s Deep Panuke project near Sable Island, 300 kilometres southeast of Halifax, said positive results at two wells near the project could revitalize the on-hold $1.3-billion offshore gas development.
EnCana is also teaming up with Shell Canada Ltd. to drill a deep-water exploration well on the Weymouth licence, a block of ocean floor about 250 km southeast of Halifax.
For EnCana, which put its Deep Panuke project in the deep freeze in February, it looks like the fish are biting again.
EMISSIONS DECLINE
Alberta’s aging sour gas processing plants are getting the polluting sulphur out – of the air, that is. Overall sulphur emissions from the so-called grandfathered plants declined from more than 200 tonnes a day to about 150 tonnes a day, or about 20 per cent, from 2000 to 2002, the Alberta Energy and Utilities Board (EUB) says in a new report. Most of the decrease was due to the plants processing less sour gas.
Sixty of the old plants had been grandfathered, or exempted, from meeting the same stringent sulphur-recovery or reduction requirements as new gas plants. But in 2001, the EUB established new guidelines and a schedule for the aging plants to meet the same standards as new facilities.
During the last three years, seven plants were upgraded or had sulphur-recovery equipment installed to meet the standards; three plants were re-licensed to meet the requirements (through consolidating operations or reducing the amount of gas processed); and three plants were shut down.
There are still 47 grandfathered sour gas plants that must either meet the sulphur-recovery standards for new plants or be phased out by the end of 2016.
