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No time to procrastinate in oil sands Report by Macquarie Capital Markets Canada expects no letup in revival of oil sands development; 590,000 bpd under construction Gary Park For Petroleum News
The rewards will go to those who are quickest out of the starting blocks while those who dither will pay a price, says an investment banker’s assessment of the sudden rebound in Alberta oil sands development, which it estimates carries a current capital investment of about C$38 billion.
Macquarie Capital Markets Canada believes foreign participation will help ensure there is no letup in the revival of oil sands development, with the emergence of new technologies and exploitation of previously untapped resources giving added momentum to the current trend.
Chris Feltin, co-author of Macquarie’s report, estimates 590,000 barrels per day of incremental production is currently under construction, of which 486,000 bpd is raw bitumen that will need upgrading through other sources, leaving only 104,000 bpd at Shell Canada’s Jackpine project that is directly linked to a company upgrader.
He said a combination of high oil prices relative to natural gas, a narrow gap between heavy and light oil price differentials and readier access to labor and materials have “dramatically” improved oil sands economics over the past year.
Feltin said those companies which pull their projects off the shelf could benefit from reduced costs; those which stall could face stiff competition for labor and materials.
Large producers have edge He said the edge belongs to large producers which have easier access to capital and have free cash flow from other assets, ensuring they will be dominant players over the long term.
That affirms the view of Suncor Energy Chief Executive Officer Rick George, who has said companies such as Suncor, Imperial Oil, Royal Dutch Shell and Canadian Natural Resources are likely to dominate the sector.
But Macquarie also expects smaller players are likely to sanction projects this year, including Connacher Oil and Gas (which expects to double output at its Great Divide project to 20,000 bpd in April), Petrobank Energy and Resources’ May River commercial project and Laricina Energy’s Germain pilot and commercial projects targeting the Grand Rapids formation, along with Canadian Natural’s Kirby thermal recovery project.
Combined these projects could contribute 172,000 incremental bpd, the report said.
Moving beyond McMurray It said the industry is also poised to move beyond the McMurray formation, which has claimed the bulk of development so far, with pilot-phase projects leading the way into untapped bitumen reservoirs.
The largest is the Grosmont carbonate, estimated to have 318 billion barrels of oil in place, with Laricina and Osum Oil Sands expected to launch the first pilot operation this year.
Macquarie said it is counting on the Grosmont and Leduc carbonates receiving greater attention in 2010.
Meanwhile, Laricina and BlackPearl Resources are advancing test programs in the established Grand Rapids formation on the western edge of the Athabasca region.
Feltin said his firm is confident that technological gains will reduce supply costs in the same way that horizontal wells and hydraulic fracturing have resulted in a breakthrough for shale gas.
He pointed to Petrobank, E-T Energy and Ivanhoe Energy as companies that could provide a “step change” in the valuation of oil sands projects.
More nationals expected The report suggested the C$1.9 billion acquisition last year by PetroChina of 60 percent stakes in two Athabasca Oil Sands’ properties could be the “first of several similar partnerships” involving state-run foreign companies, which could strike deals with the full range of oil sands players.
Feltin said it is possible the national oil companies will take aim at defined, higher quality bitumen leases and some producing ventures.
Because so many leases have been locked up, companies looking to enter the play will likely have to pay a premium.
However, Feltin cautioned that oil price differentials will be affected by whatever climate-change measures are adopted in the United States and could be a drag on heavy oil, affecting the timing and cost of oil sands projects.
Otherwise, operators are benefiting from higher crude prices and lower natural gas prices, which reduce operating costs.
Macquarie calculates that a typical thermal-recovery project needs long-term oil prices of US$61 per barrel to break even, which means a 10 percent after-tax rate of return, while standalone mines have a break-even point of US$85 per barrel and mines integrated with upgraders have a US$71 per barrel threshold.
Macquarie said the most recent steam-injection projects carry capital costs of C$30,000-$35,000 per barrel of production, compared with less than C$20,000 five years ago.
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