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Providing coverage of Alaska and northern Canada's oil and gas industry
October 2008

Vol. 13, No. 40 Week of October 05, 2008

Startup gets caught in cost squeeze

Privately held Value Creation’s move in September to halt work on its Heartland project in Edmonton points to upgrader troubles

Gary Park

For Petroleum News

For a quick lesson in the hazards of breaking into Alberta’s oil sands business you don’t have to go beyond the story of privately-held startup Value Creation and its subsidiary BA Energy.

From its origins a few years ago, the company has raced ahead under the astute leadership of Columba Yeung, a Hong Kong native who holds a Ph.D in chemical engineering from the University of Toronto and has guided refinery and petrochemical projects by Royal Dutch Shell in China and Alberta.

But, through no fault of Yeung’s, the company appears to be backpedaling on one aspect of its ambitious plans to escape the runaway costs that are plaguing oil sands players of all sizes, especially those with upgrader plans on their plates.

Emphatic that Value Creation is a builder, not a promoter, Yeung has cautioned investors against counting on a quick profit, while assuring them the company will be “very significant.”

Its credentials are already impressive, with leases containing 29 billion barrels of oil resource and the promise of new technologies that will reduce capital and operating costs, energy consumption and greenhouse gas emissions.

In early 2007 the company rolled out plans for a possible in-situ project costing up to C$4 billion, with initial bitumen production of 80,000 barrels per day (translating into 70,000 bpd of refinery-ready synthetic crude), with an eventual production goal of 400,000 b/d.

Value Creation estimated then that the Terre de Grace project – named after Yeung’s wife Grace – would cost C$45,000 per flowing barrel to build, about half the budgets of other developers at that time. (The latest budget update by the Petro-Canada-led Fort Hills project has been calculated at C$181,000 per flowing barrel, although Canadian Association of Petroleum Producers President David Collyer said he would not automatically link Fort Hills’ cost escalation to the overall sector.)

In February Value Creation took over BA Energy, which was building the Heartland upgrader near Edmonton – a merchant bitumen upgrader using proprietary technologies and scheduled to come on stream at 77,500 b/d and grow to 260,000 b/d, with first-stage costs estimated at C$2.9 billion.

“Fully committed” to upgrader

Yeung said at the time that his company was “fully committed to the successful completion” of the Heartland project, which insiders said at the time was in need of an equity infusion and a new partner.

On the surface, it had all the ingredients for a successful, fully-integrated operation.

But, like so many others, Value Creation has stumbled over the upgrader, after investing an estimated C$300 million-C$500 million and brought the facility almost halfway to completion.

Without any public announcement, the company halted construction work in mid-September, disappointing industrial and municipal officials in Strathcona County, one of four jurisdictions on the northern outskirts of the Edmonton area that are home to Canada’s largest hydrocarbon processing region for petroleum, petrochemical and chemical products.

And, given current runaway inflation in the oil sands sector, it may not be the last.

Gerry Gabinet, economic development manager for Strathcona, told Petroleum News that Heartland officials have indicated the upgrader – with a cost now estimated by observers at closer to C$5 billion – could be shelved for three or four years.

He said the owners are looking for two ways to overcome their financing problems: Either find new partners, or proceed with development of Terre de Grace to generate the cash flow needed to finish the upgrader.

A spokeswoman for the Northeast Capital Industrial Association said generating cash is logical for oil sands developers because “everything is contingent on financing for them to proceed.”

Councilor Jacquie Fenske, representing the area where the upgrader is located, said the decision to halt work is “too bad because it was a merchant upgrader, meaning it would take anybody’s bitumen and be able to refine it.”

Chasing a U.S. solution

Upgraders are rated as the most cost-heavy, riskiest aspect of oil sands development, which explains why producers EnCana and Husky Energy have taken their upgrading to the United States by forming joint-ventures to gain access to the refining facilities of ConocoPhillips and BP, respectively.

Husky also has acquired Valero Energy’s refinery in Lima, Ohio, aiming to reconfigure and expand the plant to process heavy oil and bitumen. In the process, it has delayed further additions to its Lloydminster upgrader in Saskatchewan.

Despite risking the displeasure of the Alberta government, which is committed to keeping as much as possible of the value-added upgrading and refining in the province, EnCana and Husky made it obvious they want to limit their downstream risks.

The question now is whether other upgrader projects may be in jeopardy, none more than the Fort Hills Sturgeon Upgrader as part of Petro-Canada’s Fort Hills project.

Announced in early 2006, the plant is designed to come on stream in 2012 handling 165,000 b/d of blended crude bitumen, growing in two more stages to 350,000 b/d in 2016.

But the first phase costs are now estimated at C$9.9 billion, according to junior partner UTS Energy, which is calling for a possible “re-phasing” of the project, which could mean deferral of the upgrader.

Among other upgrader proposals on the at-risk, or under-review list:

• A merchant heavy oil plant being developed by privately-owned North West Upgrading, with project capacity of 231,000 b/d of blended feedstock, originally scheduled to start in 2010 at 77,000 b/d and add two more equal phases by 2016.

The plan is to produce low-sulfur diesel and other products and an arrangement has been made with Enhance Energy to provide two-thirds of the upgrader’s carbon dioxide offgas for injection to improve oilfield production.

To date, C$300 million has been spent on engineering and design and major components are ready for shipment from Japan, but the cost estimate has surged to C$4.2 billion.

Although site clearing has started, full-scale construction is still at least one year away, while North West attempts to line up supply and customer contracts, and then seek financing.

• Earlier this year, Norway’s StatoilHydro postponed a planned upgrader for its oil sands operation by two years to 2016, citing a tight supplier market, cost pressures and new environmental regulations in Alberta.

The facility is now targeting 80,000 b/d of capacity in 2016 and another 163,000 b/d in 2022, at an estimated capital cost of C$16 billion.

• Total E&P Canada is facing corporate decisions on a projected C$8 billion upgrader coming on stream at 150,000 b/d in 2014 and growing by 95,000 b/d in 2018, with de-bottlenecking adding 50,000 b/d in 2020.

• Shell Canada (with minority partners Chevron Canada and Marathon Oil) has shown some doubt over proposals to add a second phase to its Scotford refinery near Edmonton, that would add 100,000 b/d by 2009 to its initial capacity of 200,000 b/d (after 45,000 b/d of de-bottlenecking this year). Four more phases of 100,000 b/d each are scheduled by 2021 at a total cost of C$35 billion.

Approval of the second phase hinges on the outcome of regulatory processes, market conditions, final project costs and consultation with key stakeholders, the company said.






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