Oil sands take smaller steps

Hunt for cost controls in Alberta projects turns to phased projects

Gary Park

Petroleum News Calgary Correspondent

The think-big approach that has ruled development of Alberta’s oil sands over three decades is getting shrunk.

Instead of the multi-billion-dollar schemes that have dominated exploitation of a 180 billion barrel resource, operators are finding greater virtue in phased developments as they wrestle with out-of-control costs.

Shell Canada, Petro-Canada, Canadian Natural Resources, Husky Energy and Nexen have all identified project scale as an important piece of the budget puzzle.

For Shell Canada the search for an alternative follows a harsh lesson.

Its Athabasca scheme, which came on stream in January, was originally budgeted at C$3.8 billion. The final price tag was C$5.7 billion, reflecting delays, a critical shortage of qualified workers and runaway overtime.

Neil Carmata, Shell Canada’s vice president of oil sands, offers a blunt assessment. “If there’s going to be another oil sands megaproject we have to break the back of the (cost overrun) problem,” he said.

In fact, he told a May investment conference that soaring costs represent a far greater threat to the oil sands than the restrictions on greenhouse gas emissions contained in the Kyoto Accord, which a few months ago was seen by some as the death-knell of projects.

With Athabasca as a constant reminder of what can go wrong — Carmata describes it as a “C$6 billion education” — the oil sands sector is faced with a possible scaling back of plans.

Almost half of projects could be scrapped

The slowdown has already started, with TrueNorth Energy shelving a C$3.5 billion proposal and Petro-Canada calling a time-out to rethink its C$5.8 billion oil sands strategy.

Soaring capital costs are the overriding concern. But other uncertainties loom, ranging from the costs of reducing greenhouse gas emissions to comply with the Kyoto Protocol; the market outlook for bitumen and synthetic crude; the availability of export pipelines to the United States; the need to find alternatives to natural gas as a fuel source for oil sands processing; and a growing clamor from environmentalists to charge oil sands producers for the water they use.

Three possible scenarios

High-case: If all projects being contemplated are built, investment would run to C$50 billion by 2015, boosting output to 3.3 million barrels per day from 700,000 bpd and pushing Canada’s total oil output to 4 million bpd.

Mid-case: Rated the most likely outcome, it would see spending of C$27 billion by 2010 and production climbing to 2.3 million bpd.

Low-case: With no new projects, but continued expansion of existing plants, production would grow by 5 percent a year and reach 1.8 million bpd by 2015.

“It just doesn’t seem possible that all projects are going to go ahead as planned,” FirstEnergy analyst Steve Paget told The Globe and Mail — a prediction that comes as no surprise to the Canadian Association of Petroleum Producers, which says no one in the industry ever thought all projects would go ahead.

For now, the emphasis among established and emerging oil sands players is to take smaller steps, finding ways to curb labor costs and using cash flow to finance each successive stage.

Three-stage developments

Horizon is targeted to grow from a 110,000 barrel-per-day start-up in 2008 to 233 bpd in 2012; Kearl, pending regulatory filings in the next 12 months, is tentatively planned to grow in phases from 25,000 bpd to 100,000 bpd.

Husky President John Lau said in May that Kearl will have the added benefit of utilizing cash flow from his company’s 30,000 bpd Tucker project, due to come on stream in 2005 or 2006.

There was a similar message from Petro-Canada Chief Executive Officer Ron Brenneman who said his company’s review, expected to take the rest of 2003, will examine both scale and timing. He said that simply lowering the capital outlay “doesn’t necessarily improve the economics.”

But not all the players are backing away from grand-scale schemes. Sister companies, Imperial Oil and ExxonMobil Canada, are investigating the development of adjoining leases to bring a 200,000 bpd project on stream by about 2012 — an undertaking analysts estimate could cost C$7 billion.

Oil sands deposits now recognized

A stroke of the pen this year by the U.S. Energy Information Administration elevated the oil sands deposits of northern Alberta to the category of proven reserves, catapulting Canada over every oil-producing country except Saudi Arabia.

Based strictly on deposits that can be recovered using current technology, the EIA — endorsed by Cambridge Energy Research Associates — credits Canada with proven reserves of 180 billion barrels, compared with its previous 5 billion barrels, a figure that covers all oil deemed to be recoverable with current technology and economic conditions. The ultimate oil sands potential, relying on known technology, has been rated as high as 315 billion barrels.

Whatever the debate over the extent of the resource, the long-coveted recognition makes the oil sands a potential ace-in-the-hole of North American energy security, provided it opens the door to greater U.S. investment.

EnCana chief executive officer Gwyn Morgan, after a meeting in May with U.S. Energy Secretary Spencer Abraham, said growing awareness of the oil sands in Washington builds confidence that the U.S. “wants ...and needs our energy.”

If there was any doubt, Paul Cellucci, the U.S. Ambassador to Canada and a close confident of President George W. Bush, hammered home Washington’s desire to tap further into Canada’s energy resources in a series of speeches.

He said the U.S. is placing greater emphasis on the role of an unfettered continental market as a key dimension of America’s overall security.

The EIA recognition of the oil sands “makes it clearer than ever, in hard numbers, that Canada will remain our country’s No. 1 energy partner,” Cellucci said.

Introduction

In a three-part series beginning in the June 29 issue, Petroleum News’ Canadian correspondent Gary Park examines the main planks in Canada’s petroleum platform and their ability to support increased exports to the Lower 48.

• Part I — Arctic natural gas, issue of June 29

• Part II — Alberta oil sands, this issue

• Part III — East Coast oil and gas, issue of July 13

Who’s who in the oil sands line-up

• Syncrude Canada — Currently producing 250,000 bpd of synthetic crude, the consortium is working on a multi-stage C$8 billion expansion, adding 100,000 barrels in 2005 and ultimately reaching 535,000 bpd by 2015. To keep itself on the right side of the environmental balance sheet, Syncrude has just announced plans for a C$400 million project to reduce sulfur dioxide emissions by up to 60 percent, ensuring air quality in the region is unaffected by expansion. Syncrude has set long-term all-inclusive operating costs of C$11-$12 per barrel, which is seen as vital to cushion the operation against sudden oil price crashes. Canadian Oil Sands Trust at 31.74 percent and Imperial Oil at 25 percent are dominant partners, with smaller holdings in the hands of Petro-Canada, ConocoPhillips Canada, Nexen, Mocal Energy and Murphy Oil.

• Suncor Energy — The first company to produce synthetic crude, Suncor is no less ambitious than Syncrude, despite a staggering cost overrun of about C$1.4 billion on its latest 110,000-barrel-per-day expansion. It is aiming to more than double output to between 500,000 and 550,000 bpd by 2010-2012. It has just given the green light to a C$3 billion expansion, boosting output by 50 percent to 330,000 bpd by late 2007. It estimates the Kyoto Protocol will add no more than C$0.27 per barrel to its cash operating costs which it is confident will exit 2003 in the range of C$10-$11 per barrel.

• Shell Canada — Unfazed by a 50 percent cost overrun on the C$5.7 billion Athabasca project — which includes minority partners, Chevron Canada and Western Oil Sands, each with a 20 percent stake — Shell Canada is laying the groundwork for continued growth beyond the 155,000 bpd it expects to be pumping by the end of 2003. While still engaged in a “look back” at its initial foray into the oil sands, the company is working on three additional phases that would take it to 525,000 bpd. Phase I would increase Athabasca output by 70,000 bpd by 2010; Phase II would be a stand-alone project costing more than C$2 billion and producing 200,000 bpd; Phase III is targeted at 100,000 bpd.

• Canadian Natural Resources — Despite nagging doubts about cost implications of the Kyoto Protocol, Canadian Natural is pressing ahead with its C$8.5 billion, 40-year Horizon project, slated to produce 110,000 bpd in 2008 and growing to 233,000 bpd by 2012. The company owns and operates leases covering 236,000 acres with an estimated 16 billion barrels of bitumen in place, of which 6 billion barrels are recoverable using existing mining technologies.

l Imperial Oil and ExxonMobil Canada — The subsidiaries of ExxonMobil Corp. have just announced they are working on the engineering and environmental details of a project to exploit their adjoining Kearl Lake leases. Drilling is expected this winter to evaluate the reserves and the economic viability of a possible C$7 billion project, although the cost hinges on where 200,000 bpd of bitumen would be upgraded.

• ConocoPhillips Canada — Having obtained regulatory approval from the Alberta Energy and Utilities Board, ConocoPhillips is now scrutinizing the economics of the C$1 billion Surmont project before making a final commercial decision. It is operator of the 5-billion-barrel lease and has a 43.5 percent stake, with partners TotalFinaElf 43.5 percent and Devon Canada 13 percent. Surmont is designed to proceed in stages, starting at 25,000 bpd in 2006 and increasing to 100,000 bpd, and using steam-assisted gravity drainage to recover the bitumen.

• Petro-Canada — Faced with cost projections soaring at least 50 percent beyond its original estimates of up to C$5.8 billion, Petro-Canada has hit the brakes while it rethinks its oil sands strategy. The major delay involves a two-phase conversion of its Edmonton refinery to handle 170,000 bpd of bitumen from its MacKay River and Meadow Creek projects. The C$290 mi