Mega projects facing mounting costs

Developing Canada’s oilsands is far more complex and expensive than conventional oil and gas production. Multibillion-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 oilsands of Alberta is causing some companies to cast about for alternatives to building the costly upgraders.

Citing a combination of inadequate project returns and a higher cost of capital than some of its peers, Synenco Energy (SYN-T, SYEYF-O) announced last year that it would have to put the upgrader portion of its Northern Lights oilsands project on hold while the company undertook a strategic review of alternatives — including 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,” the company said in a statement in May last year. Since then, France’s Total (TOT-N) has made a bid for the Canadian junior.

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

Escalating costs mean larger companies have a competitive advantage in oilsands 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 Husky Energy (HSE-T, HUSKF-O) decided to buy a US$1.9- billion Ohio-based refinery from Valero Energy (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 its Sunrise and Tucker oilsands leases.

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 upgrader last year, 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 plans for growth.

“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,” Blackmont contends.

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

The main 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 key 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 brown-field addition to an existing refinery is estimated to be about half the cost of building an upgrader in Alberta,” explains Alan Boras, EnCana’s manager of media relations.

“One of the challenges in the oilsands 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 on-line.”