Canadian natural gas producers are going to keep their biggest industrial customer as thermal oilsands plants weather the fourth global oil price storm since commercial production of the northern Alberta resource began 47 years ago.
Gas use for bitumen separation with heat is still on the rise as the industry sticks to the pattern that evolved through the oil price crashes of 1985-1986, 1998-1999 and 2008-2009.
The consensus among Canadian industry and government forecasters, as recorded by the National Energy Board in a lengthy scenarios report, agreed that a prolonged spell of weak oil prices will slow down but not stop bitumen production growth.
Even in a low-price case, with oil consistently averaging US$30/bbl below the “reference” or most likely range of $90-100, oilsands output is expected to double to 4.4 million b/d as of 2020, pulling up associated industrial gas use at about the same pace.
Alberta industry veterans point to a critical difference from other supply sources to explain how oilsands output grew nearly 10-fold through the market crises to the 2013 average of 1.9 million b/d from 218,000 b/d in 1985.
The northern bitumen belt plants are manufacturing sites. Their histories are sagas of constant expansion and retooling. There is no exploration risk. Recoverable reserves in every oilsands lease are measured in billions of barrels. Once established, production continues at steady rates plus periodic “plant de-bottlenecking” gains.
Output jumps with applications of new engineering and technology, rather than following the standard liquid reserves pattern of swiftly hitting peak flows then rapidly tapering, with fresh investments at best slowing the rate of shrinkage.
Companies in oilsands development are almost all big enough to ride out market lows in order to recover construction costs and reap windfalls during the highs. Alberta’s oilsands royalty regime cushions plants by automatically reducing rates during spells of poor prices, over a wide range of 1% to 40% of net production revenues after expenses. The rates fall to the minimum when oil slips to US$55/bbl and rise gradually to the maximum at $120/bbl.
Oilsands producers think and plan in years rather than financial quarters. The pattern continued as current prices dropped by nearly 50% in the second half of 2014, although growth developments were obscured by the market squalls of the period.
Husky Energy, for instance, announced on Dec. 11 the start of steam injections into the estimated 3.7 billion bbl of recoverable reserves in its Sunrise oilsands lease. Bitumen output is scheduled to reach 30,000 b/d in 1Q2015 then gradually double to 60,000 b/d over a two-year period.
In announcing budget cuts Wednesday for other, more exciting international drilling, Husky CEO Asim Ghosh said, "We continue to steer a steady ship through stormy waters." He described Sunrise as building a reliable platform that will enable the firm to resume higher-risk, higher-reward operations when prices recover.
Cenovus Energy Inc., the oilsands specialist spun off from Encana Corp., has announced a 15% budget cut that will slow down expansion. The paring could go deeper if market conditions and prices worsen.
But the reduced capital commitment for next year’s share of multi-year growth projects was still C$2.5-2.7 billion ($2.2-2.3 billion) and production was forecast to increase by up to 16,000 b/d in 2015 alone, into a range of 197,000-214,000 b/d.
At the smaller, younger company end of the oilsands spectrum, MEG Energy announced a 75% budget cut to C$305 million ($262 million) in 2015 that puts off plant construction. But engineering and operational improvements are still forecast to increase output by 20% from established sites, into a 2015 range of 78,000-82,000 b/d from the current level of 65,000-70,000 b/d.
From gas producers’ point of view, a trend inside the northern bitumen belt adds luster to the silver lining of continuing oilsands development. Shaky oil prices encourage acceleration of a switch to the most heat energy-intensive form of production.
Overall, the oilsands sector consumes about 1 MMBtu of gas for every barrel of production, according to the Alberta Energy Regulator (AER), which tracks efficiency as a conservation watchdog over provincial government-owned and -leased resource rights. But the average is poised to rise.
The richest, shallowest bitumen deposits are produced by open-pit mining, surface separation and upgrading plants that only use 0.4 to 0.6 MMBtu of gas per bbl of production. But about 80% of the 140,000 square kilometers (56,000) of oilsands are too deep to dig up and are tapped with in-situ, underground steam injection and bitumen separation systems that consume up to 2 MMBtu of gas per bbl of output, AER said.
Installation costs of in-situ plants are half or less of the mines’ C$100,000-plus ($86,000-plus) price/bbl of production capacity. In-situ bitumen extraction was growing about twice as fast as mine output even before the current price storm, and the gas-fired underground steam-injection systems did 53% of oilsands production.
The current bottom line of the oilsands for gas producers is sales of 2.7 Bcf/d. As of 2023, bitumen projects currently approved and under construction are forecast to increase oilsands gas consumption to 5.3 Bcf/d.