Testing times for Alberta's oil sands
With project costs rising and credit hard to secure, forecasts for oil-sands production are being scaled back, writes WJ Simpson
RISING capital costs are threatening the economics of several Alberta oil-sands projects. The cost for a new production facility has reached at least C$160,000 ($148,000) per flowing barrel, compared with industry standards of C$100,000 two years ago and C$45,000 in the late 1990s.
Without factoring in the full effect of the global credit crisis and the unknown costs of carbon-emissions-reduction policies planned by the Canadian government (see p10), the chances of raising the estimated C$170bn of capital required to keep projects on track over the next decade are evaporating.
Aside from what happens to crude prices, says FirstEnergy Capital analyst William Lacey, the "broader financial outlook [for the oil sands] is now more questionable ... the cost of gaining access to capital has changed, at least in the near-term."
Andrew Potter, an analyst at UBS Securities Canada, says rising labour costs and declining labour productivity in Alberta – a weak point for the industry for some time – have "eroded value in the oil sands to the point where the economics of most projects have become challenging". He expects projects will be modified, deferred or cancelled, especially those with plans to build expensive upgraders or refineries. The end result is almost certain to be the disappearance, through mergers and acquisitions, of smaller independents whose only assets are in the oil sands.
The first significant test is due this quarter, with a final-investment decision expected from the partners in the Petro-Canada-operated Fort Hills mining and upgrading venture. Just 15 months after setting a preliminary cost estimate of C$14.1bn, the group (Petro-Canada, with 60%, and UTS Energy and Teck Cominco each holding 20%) issued a hasty update in mid-September of C$23.8bn – anxious to disclose the numbers ahead of market rumours – although they concede even their latest budget is far from final.
Based on initial synthetic crude production of 140,000 barrels a day (b/d) in 2011 (doubling by 2015), Potter translates the cost of the Fort Hills mine and upgrader into C$181,000 per flowing barrel. UTS sets the range at C$160,000-170,000, based on what it rates as an "acceptable netback" within five years if oil prices remain above $100 a barrel and within 10 years with oil at $80/b.
Despite 0.6bn barrels of reserves and 1.7bn barrels of contingent oil-sands resources, UTS has no production to generate cash flow, leaving it dependent on capital and equity markets to retain its place in Fort Hills. Chief executive Will Roach pleaded for market understanding while UTS tries to raise C$3bn over the next 18 months, or hunts for a new partner. Roach describes the credit crisis as "terrifying". Access to capital has "changed over the past year," while a 75% drop in the value of UTS' shares in just two months has "left us in a dangerous place".
Potter says that, although there is "good return potential" in UTS, "it has little in the way of short-term catalysts other than the potential for a hostile bid."
Already, a 50:50 venture by Nexen and Opti Canada has stalled expansion of its Long Lake project, which has just come on stream and is planned to grow in six stages of 60,000 b/d each. Opti has only limited cash flow while the initial phase builds towards peak output in 2010 and no access to equity and debt markets. Chief executive Sid Dykstra says funding the second stage is out of the question today, but he is certain the opportunity will return "in the future".
A host of other junior oil-sands players, many of them backed by technical innovations that could reduce greenhouse-gas emissions, natural gas consumption and water usage, face a similar plight – little hope of accessing debt or equity markets, despite vast land and resource holdings. MEG Energy, Laricina Energy, Bronco Energy, Grizzly Oil Sands, Rochester Energy, Oilsands Quest and Patch International are on the list of possible take-over targets.
Michael Tims, chairman of Peters & Co, an investment dealer, says the only hope is for companies to explore financing alternatives as investors weigh project costs against uncertainties stemming from commodity prices, the cost of equity and the cost of debt.
A game for the big boys
Michael Borrell, president of Total's Canadian unit, says the latest Fort Hills cost increase suggest the oil sands will increasingly be a game for larger, well-capitalised firms, notably the majors. "These are large, complex projects with huge investment levels and you need a certain size to carry those investments forward," he says. "Total is convinced there is value in the oil sands, but they are long term."
UTS suggests the best option for Fort Hills is to persuade Petro-Canada and Teck Cominco to reduce or defer capital costs by phasing various elements of the project, notably a planned upgrader to convert raw bitumen into synthetic crude, the cost of which alone has risen to almost C$10bn. Whatever the outcome of those discussions, Petro-Canada has retreated from its original plan for a 400,000 b/d upgrader, settling for a first-phase project of about 170,000 b/d.
Other upgrader projects to support increasing Albertan bitumen production are in a similar fix. In September, BA Energy, a unit of Value Creation (VCI), stopped construction of a half-completed merchant upgrader after spending up to C$0.5bn. The 77,500 b/d unit was scheduled to start up in 2011 and expand in two stages to 260,000 b/d.
BA Energy has indicated that the Heartland upgrader needs either new partners, or will be postponed for four years until cash flow is available from VCI's planned oil-sands operations. Supported by leases containing an estimated 29bn barrels of bitumen, VCI hopes its Terre de Grace project will come on stream at 80,000 b/d (translating into 70,000 b/d of synthetic crude) as its first step towards target production of 400,000 b/d. But its initial costs were estimated in early 2007 at C$45,000 per flowing barrel, a figure that is almost certain to face drastic revisions.
Other projects are at risk or under review:
- North West Upgrading's heavy-oil processor, which is targeting capacity of 77,000 b/d in 2010 and 231,000 b/d by 2016. So far, C$300m has been spent on engineering and design, and site clearing has started, but full-scale construction is on hold for a year while North West tries to arrange feedstock supplies and customer contracts, and seeks financing;
- StatoilHydro has delayed, until 2016, construction of a planned 163,000 b/d upgrader for its production. It has cited a tight supplier market, cost pressures and new environmental regulations; and
- Shell Canada, with Chevron Canada and Marathon as minority partners, is wavering over plans to add a second phase to its Scotford bitumen refinery, adding 100,000 b/d by 2009 to its existing 200,000 b/d, with four more phases of 100,000 b/d each scheduled by 2021 at a total cost of C$35bn. Shell says approval of the second phase hinges on the outcome of regulatory processes, market conditions, final project costs and consultations with stakeholders.
This uncertainty is set against a backdrop of shrinking expectations for the oil sands, with the Canadian Association of Petroleum Producers predicting peak output of 2.8m b/d, more than double volumes today.