Oil sands projects face difficult, hyper-inflationary environment

Developing Canada’s oil sands is far more complex and expensive than conventional oil and gas production. Multi-billion dollar upgraders are needed to convert the raw bitumen, a heavy, viscous material, into synthetic crude oil.

But the prohibitive cost of local Greenfield projects in the hyper-inflationary oil sands of Alberta is causing some companies to cast about for alternatives to building the costly upgraders in the province.

Citing a combination of inadequate project returns and a higher cost of capital than some of its peers, Synenco Energy (SYN-T) announced last year that it would have to put the upgrader portion of its Northern Lights oil sands project on hold while the company undertook a strategic review of alternativeswhich included selling the company.

Synenco estimated that the capital cost for the upgrader portion of the project would come in at about $6.3 billion. “The expected rates of return for any of the examined upgrader options are incompatible with Synenco’s weighted average cost of capital, which is higher,” Synenco told shareholders in a statement on May 1 2007. Since then, France’s Total has made a bid for the Canadian junior.

Synenco’s Northern Lights project consists of an oil sands mining and bitumen extraction project to be built about 100 km northeast of Fort McMurray. Synenco holds 60% of the Northern Lights project, with China’s state-controlled oil giant Sinopec holding the remaining 40%.

Escalating costs mean larger companies have a competitive advantage in oil sands development and returns for the smaller players “are getting squeezed to the point where project hurdles are no longer being met,” Blackmont Capital writes in a 2007 research report entitled: “Oil Sands Squeeze Play: Managing Growth in a World of Diminishing Returns.”

Synenco isn’t alone. Inflationary pressure was one of the main reasons why Husky Energy (HSE-T) decided to buy a US$1.9 billion Ohio-based refinery from Valero (VLO-N) instead of building Greenfield capacity in Alberta, Blackmont notes.

The Ohio refinery will give Husky additional downstream capacity for its steam-assisted gravity drainage (SAGD) production out of Sunrise and Tucker.

An overheated operating environment coupled with Alberta’s uncertain regulatory regime also prompted Canadian Natural Resources (CNQ-T, CNQ-N) to postpone its decision about whether to build the second of two upgraders it had slated for development.

Canadian Natural Resources decided to defer its proposed Canadian Natural Upgrader in early 2007 after the results of a scoping study showed the costs would be extremely high.

“Based upon the results of the scoping study, which identified growing concerns relating to increased environmental costs for upgraders located in Canada, inflationary capital cost pressures and narrowing heavy oil differentials in North America, the company decided in early 2007 to defer pending clarification on the cost of future environmental legislation and a more stable cost environment,” a company spokesman told The Northern Miner.

Blackmont Capital argues that development costs, now “amongst the highest in the world,” are “causing some of the major players to reconsider their development plans.”

“Inflation in combination with a more stringent regulatory environment will eventually erode returns to the point where companies can no longer justify moving forward with their development plans,” it contends.

Some companies saw the writing on the wall early. In October 2006, EnCana Corp (ECA-T, ECA-N) decided to set up a joint-venture with ConocoPhillips (COP-N) in which EnCana received a 50% working interest in ConocoPhillips’ Borger (Texas) and Wood River (Illinois) refineries in exchange for a 50% working interest in its Christina Lake and Foster Creek oil sands projects in northeastern Alberta, its most developed steam-assisted gravity drainage (SAGD) projects.

The prime reason for integrating EnCana’s upstream resources with refineries downstream was to reduce the price and market risk of major capital investments that are planned over many years, the company explains. With the partnership, EnCana was able to capture value all along the production chain, from the reservoir in Alberta to the wholesale fuel markets in the U.S.

But another reason was the comparative high cost of building greenfield upgrading capacity in Alberta. “If you add capacity to upgrade the bitumen and refine it into gasoline and diesel fuel, the cost of doing that with a brownfield addition to an existing refinery is estimated to be about half the cost of building an upgrader in Alberta,” says Alan Boras, EnCana’s manager of media relations.

“One of the challenges in the oil sands is that there is a very busy environment because of the major amounts of investments here,” Boras adds. “Other jurisdictions don’t face the same stresses with respect to the capacity of labour and the economy to build large industrial installations. It’s not uncommon for major projects in Alberta to take five and six years to bring online.”