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Growing pains for Alberta oil sands National Energy Board bets on C$94B in capital spending and 3-fold production increase by 2015, but sees mountain of challenges Gary Park For Petroleum News
Whether it’s 3 million barrels per day as forecast by Canada’s National Energy Board or 3.5 million bpd as predicted by the Canadian Association of Petroleum Producers, the outlook for oil sands production over the next 10 years is both bullish and bearish.
In simple terms, the two organizations are agreed that output of bitumen and synthetic crude will reach at least 3 million bpd, close to triple last year’s 1.1 million bpd.
Casting a shadow over those numbers is a wide array of uncertainties and challenges that compound the risks of an already dicey business.
Currently, 46 major mining and thermal projects are under construction or proposed, and 135 expansion phases are in the works for the 2006-2015 period.
In total they carry a combined price tag of C$125 billion, but the base-case projection by the NEB forecasts capital spending is likely to fall short of that grand total by C$31 billion.
The federal regulator believes there are too many hurdles — such as pipeline and refining capacity, choosing what crude types will succeed, opening up new markets, the costs of materials and labor, the availability of natural gas to fuel the oil sands sector, possible constraints on the use of water and the pressure to lower the intensity of greenhouse gas emissions — standing in the way for all of the ventures to survive.
NEB estimates up 40% since 2004 However, regardless of a 25 percent hike in the sector’s capital costs over the past two years, the NEB has still raised the production bar by 40 percent since its 2004 outlook.
“With oil sands production increasing, Canada is poised to be a world leader in oil production,” said NEB Chairman Ken Vollman.
The latest forecast is based on a number of key assumptions, including West Texas Intermediate crude prices of US$50 per barrel (compared with US$24 per barrel in the 2004 report), Nymex gas prices of US$7.50 per million British thermal units (vs. US$4) and a light/heavy price differential of US$15 per barrel (vs. US$7).
Estimated operating costs range from C$6-$14 per barrel for bitumen and C$18-$22 per barrel for synthetic crude, with estimated supply costs of C$14-$24 per barrel for bitumen and C$36-$40 per barrel for synthetic crude. Supply costs cover operating costs, capital costs, taxes, royalties and the rate of return on investment.
The NEB says integrated mining and steam-assisted gravity drainage operations are economic at US$30-$35per barrel WTI, but the continuing surge in materials and labor costs put those numbers at risk.
Higher gas prices and blending costs could further raise the estimate, but advances in recovery and upgrading technologies have the potential to improve the economics, the report said.
Total output expected to reach 3.9 million bpd in 2015
Overall the NEB is predicting total oil supply, including conventional crude, from the Western Canada Sedimentary basin will grow to 3.9 million bpd in 2015 from 2.4 million bpd in 2005.
Gas consumption to produce steam to melt deeply buried bitumen deposits and produce steam to run machinery and operator refineries represents one of the greatest worries to oil sands operators.
Currently about 1,200 cubic feet of gas is needed to produce 1 barrel of bitumen from in-situ projects, while an average 700 cubic feet is consumed by integrated mining projects.
Current gas use averages 70 million cubic feet per day, or 5 percent of the WCSB’s production; by 2015 that could climb to 2.1 billion cubic feet per day, or 12 percent of production assuming that level remains close to 17 bcf per day.
But the NEB holds out hope that operators, concerned about the future of gas supply and prices, will achieve technological breakthroughs to reduce or eliminate gas.
CAPP estimates 3.5 million bpd by 2015 The NEB report comes only two weeks after the Canadian Association of Petroleum Producers set a mid-range target of 3.5 million bpd of oil sands production by 2015 (800,000 bpd higher than its forecast of only a year ago) and 3.9 million bpd by 2020.
One of the toughest guessing games for producers is to select pipelines to carry their supplies to existing and new markets, as well as decide what crude types they will opt for — synthetic-bitumen blend, condensate-bitumen blend, bitumen or synthetic crude — the NEB said.
Along with those choices they have to weigh the markets that can process those crude types and which offer the best netback.
Compounding those considerations, the NEB noted that international heavy crude output is on the rise, which means the heavy/light price differential is likely to persist to ensure the volumes can be marketed.
The report suggested market expansion for growing oil sands production could unfold in three stages: 1) Fill existing markets, including Washington state, PADD II (Midwest), and PADD IV (Rockies) as well as adding some volumes in Canada; 2) Build penetration to PADD II and PADD III (southern U.S.), refinery expansions and conversions in northern PADD II, PADD IV and PADD V (West Coast); 3) Open new markets, which will need new or expanded pipelines to the West Coast to reach California and Asia.
Current pipelines could reach capacity by 2007, putting pressure on the industry to decide which markets hold the great prospects and which pipeline projects they favor.
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