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U.S. companies take measured steps in Western Canada Maturing basin, currency shifts influence spending plans; EOG breaks step with U.S. peers, counting on Canada to deliver most of gas-production growth Gary Park Petroleum News Calgary Correspondent
Fading prospects, rising costs in the Western Canada sedimentary basin and a faltering U.S. dollar have dominated recent decision-making by the Canadian units of U.S.-based companies, as they either divest assets or scale back capital spending.
In the latest round of quarterly reports, Anadarko Petroleum joined the swelling ranks of those who see Canada pricing itself out of the market.
James Hackett, chief executive officer of the Houston-based company, said spending in Canada will be lower than last year’s US$450 million, but by how much will have to wait until budgets are finalized.
“It’s a challenge in Canada,” he declared, noting that the 22 percent rise in the value of the Canadian dollar against its U.S. counterpart over the past couple of years has raised operating and capital costs, while undermining the returns from production.
The indications are that spending north of the 49th parallel will be US$375 million to US$425 million, which, after factoring in a 20 percent hike in the Canadian dollar during 2003, would mean a budget roughly the same as last year’s C$540 million.
That echoed earlier concerns expressed by Burlington Resources, which chopped its Canadian budget by as much as C$100 million to C$953 million, moving more capital to the United States.
Hackett said he has confidence Anadarko’s Canadian staff, whose jobs are not threatened, will “figure out creative ways to do things more efficiently.”
If oil and natural gas prices remain high and Anadarko finds itself with excess cash, a late-year boost to spending is also possible, he said.
Regardless, Anadarko is counting on a 3 percent to 5 percent rise in Canadian production this year, expecting to operate 10 rigs and drill 175 development wells and 40 exploration wells during 2004.
Output for 2003 averaged 383 million cubic feet of gas per day, compared with 370 million in 2002, while crude oil and condensate volumes slumped to 17,000 barrels per day from 33,000 the previous year. Daily numbers for the final quarter averaged 397 million cubic feet of gas and 19,000 barrels of oil and condensates.
One of the company’s hot spots was the Wild River area of Alberta, which has seen steady production growth from the 26 wells completed in 2003 that posted a 100 percent success rate.
Anadarko said the deep basin-centered gas play may have opened up a 1 trillion cubic foot opportunity on the company’s current land position.
Employing its own techniques, Anadarko has “significantly” dropped costs and raised well productivity from the tight formations.
Expansion of the Wild River gas plant in the fourth quarter boosted processing capacity and throughout to 79 million cubic feet per day from 30 million. More expansions could follow any future development success. EOG Resources: Leading all U.S. independents in Canada last year and trailing only EnCana and Husky, EOG completed 1,041 wells and is aiming at 1,300 in 2004.
The upshot, the company told a fourth-quarter conference call, is that EOG will buck the trend among its U.S.-based peers as it counts on Canada to deliver most of its forecast 6.5 percent rise in North American gas production.
Canadian capital spending will exceed US$560 million as “production growth is skewed this year ... more heavily in Canada than in the U.S.,” said Mark Pap, EOG chairman and chief executive officer.
The company added 118.3 billion cubic feet of new gas reserves in Canada last year from extension and discoveries and lifted full-year gas production to 165 million cubic feet per day from 154 million in 2002 and closed out the year with fourth-quarter output of 195 million.
EOG’s Canadian oil volumes increased to 2,300 barrels per day from 2,100 bpd, while natural gas liquids dropped to 600 bpd from 800 bpd.
A major focus of this year’s drilling will be 100 coalbed methane wells to exploit the Horseshoe Canyon formations in southeastern Alberta.
The company has so far drilled or completed 10 coalbed methane wells on 110,000 net acres and sees the potential for up to 200 billion cubic feet in that area. ConocoPhillips: Like a growing number of its peers, ConocoPhillips sees the Alberta oil sands as its best hope for both upstream and downstream health.
Canadian crude oil and condensate output slumped to 28,000 bpd in the final quarter from 37,000 bpd a year earlier, although 12 month volumes climbed to 30,000 bpd from 13,000 bpd in 2002.
Gas production nosed down in the final quarter to 431 million cubic feet per day from 442 million in the same period of 2002, but surged to 435 million for the year from 165 million for all of 2002.
Gas liquids averaged 10,000 bpd in 2002 vs. 4,000 bpd the previous year.
President and Chief Executive Officer Jim Mulva told a conference call that his company has scheduled a construction start this quarter on its long-awaited C$1.4 billion Surmont oil sands project. Both ConocoPhillips and Total hold 43.5 percent and Devon Canada holds the remaining 13 percent.
He said ConocoPhillips is on the look-out for further opportunities like Surmount, although the near-term emphasis for the entire company will be on “organic growth.”
Surmount, which became the battleground in the feuding between bitumen and natural gas producers, occupies a lease of about 14.2 square miles and has about 15 billion barrels of bitumen in place, of which about one-third is thought to be recoverable using steam-assisted gravity drainage technology.
The regulatory approval is for a four-stage development, starting at 25,000 bpd in 2006 and growing to 100,000 bpd in 2014, with an operating life of 40 years. A pilot project is already producing 600 bpd. Devon Energy: Another emerging oil sands player, Devon found some bottom-line joy in Canada from lower tax rates that contributed a gain of US$218 million to its fourth-quarter profits of US$543 million.
Overall production in Canada, where the company has 27 percent of its operations, edged down during 2003, with gas volumes for the year at 267.4 billion cubic feet vs. 278.9 billion in 2002, oil dropping to 13.5 million barrels from 15.8 million and natural gas liquids slipping to 5 million barrels from 5.2 million.
Total proved reserves increased to 2.3 tcf from 2.28 tcf in 2002 and oil reserves dropped by 1 million barrels to 148 million.
The objective this year is to boost output, which averaged 1.04 billion cubic feet equivalent per day in 2003.
With its company-owned rig fleet growing to 35 from 32, Devon boosted its exploration wells to 244 from 233, with the success rate improving to 86 percent from 84 percent.
Development wells climbed to 606 from 428 and the success rate grew to 97 percent from 95 percent.
Devon’s plans for the current winter include some 400 wells costing approximately C$360 million, with its primary focus on the Deep basin, northeastern British Columbia and the northern Plains.
Vince White, vice president of investor relations, told a conference call that Deep basin will see some 106 wells, up from 71 last winter, northeast British Columbia 100 wells, up from 76, and the northern Plains 93 wells, up from 73.
The U.S. independent closed out the year by filing regulatory applications for its Jackfish heavy oil project that is expected to produce 35,000 bpd from reserves of 300 million barrels, starting in late 2006 or early 2007. Murphy Oil: Murphy Oil production last year averaged 51,767 bpd, up from 48,239 bpd in 2002, while gas nosedived to 123.49 million cubic feet per day from 197.85 million in 2002, with the rapidly declining Ladyfern field in northeast British Columbia cited as the main reason.
For the fourth quarter, crude oil, condensate and natural gas liquids generated 52,416 bpd, but gas continued its sharp decline to 104.17 million cubic feet per day.
Murphy’s 25 percent interest in a well planned for the Annapolis block offshore Nova Scotia is bogged down in wrangling over which rig will be used.
The prospect was to have followed up a 2002 discovery, which operator Marathon estimated could unlock 5 tcf to 15 tcf, and was scheduled for drilling last summer in partnership with EnCana and Marathon.
Murphy President and Chief Executive Officer Claiborne Deming told a conference call Murphy doubts the well can start in the second quarter and is now looking to the third quarter, without ruling out a delay to 2005. Pioneer Natural Resources: Pioneer Natural Resources is in a low-profile mode in Canada, with reserves and production on the decline in 2003.
The Canadian unit saw oil and natural gas liquids output drop slightly to an average 1,017 bpd from 1,070 bpd in 2002, while gas eased to 41.67 million cubic feet per day from 48.37 million.
However, realized prices climbed to $29.10 per barrel for oil from $22.26 and gas rose to $3.90 per thousand cubic feet after hedges from $2.50.
The company ended the year with proved Canadian reserves of 93.83 billion cubic feet of gas, 2.35 million barrels of gas liquids and 53,000 barrels of crude oil vs. 119.33 billion cubic feet of gas, 2.28 million barrels of liquids and 77,000 barrels of crude entering 2003.
But Pioneer Chairman and Chief Executive Officer Scott Sheffield is upbeat that current drilling will yield results in March.
The company has one rig working on exploration wells in Alberta and two development rigs in northeastern British Columbia. New pool and new field wildcats are at various stages of licensing and completion.
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