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Canada's cost cutters

In the race to lower costs, Alberta's in situ oil sands producers are beating the miners

Since the crude price collapse in late 2014, Canadian oil sands producers have managed to slash bitumen production costs, both at open-pit mining and thermal in situ operations. Some of these reductions are cyclical, reflecting falling costs across the industry. The weaker Canadian dollar has helped as well, driving down domestic costs in US dollar terms. However, while these cyclical reductions have been seen across the board, some operators have been able to achieve clear, structural cost advantages in the low-price environment. In situ projects in particular have shown more effective energy usage and efficiency gains in reservoir engineering, giving them a leg up in Alberta's heavy oil patch.

From a peak of nearly $20bn in 2014, oil sands operating costs decreased at a compounded annual rate (CAGR) of approximately 17%, to $13.8bn in 2016. In situ and mining operations saw opex reductions (CAGR) of about 23.5% and 22%, respectively, with 2016 mining numbers at $23.10 a barrel and in situ numbers at $11.60/b. Although exchange rate fluctuations somewhat dampened the effect in Canadian dollars, mining projects nevertheless saw compound annual reductions of around 16%, while in situ projects recorded a decline of 14.5%.

Thermal in situ projects have seen the clearest structural cost advantages. In contrast to mining projects, which target shallow bitumen deposits extractable by open-pit mining, thermal projects rely on wells and steam injection to coax ultra-viscous bitumen from deeper deposits in place—or "in situ". Steam-assisted gravity drainage (SAGD), which is the most widely-used in situ recovery method, employs horizontal well pairs. Producers inject steam through an upper well to heat the reservoir to around 350 degrees Celsius and increase the viscosity of the surrounding bitumen, which subsequently drains to a corresponding lower well and flows to the surface. A certain portion of thermal projects—accounting for approximately 10% of 2016 thermal volumes—use cyclic steam simulation, whereby steam injection and extraction occur through an array of single vertical wells in staggered cycles. Due to the steam-intensive nature of thermal extraction methods and the natural gas required to generate sufficient amounts of steam, operators often cite steam-to-oil ratios (SOR, defined as the ratio of steam generation to bitumen production, or m3 steam / cm bitumen) as a key metric of project efficiency and cost effectiveness. Generally speaking, SORs at or below 2.5 denote higher efficiency, and thus lower natural gas costs for steam generation.

The trend indicates not only an existing structural cost advantage among projects with SORs at or below 2.5 prior to the price collapse; it also illustrates more significant reductions once cyclical cost declines took effect after 2014. Accordingly, from 2013-2016 higher-SOR projects experienced opex reductions (CAGR) of 12% to $15.40/b on average, whereas their lower-SOR counterparts achieved reductions of 20% to around $7.10/b.

This SOR split is also evident in breakeven oil prices. For producing in situ phases in lower-SOR projects, the average breakeven Brent price currently stands at about $38/b, whereas producing assets in higher-SOR projects are over 60% higher at around $55/b.

Among in situ projects, six stand out for having average annual SORs close to, or below, 2.5 either now or in the past. Five projects achieved production costs in the range of $5.65/b to $8/b. Devon Energy's Jackfish project had slightly higher costs at $8.60/b, but still well below the in situ average of around $11.40/b.

Average annual SORs are also consistent with the opex trend highlighted above, with the Cenovus-operated Christina Lake project (210,800 barrels per day sanctioned capacity) consistently achieving a SOR below 2 and 2016 production costs of $5.65/b. MEG Energy's smaller Christina Lake project (60,000 b/d sanctioned capacity) is also notable, with annual SORs at or slightly below 2.5 and 2016 production costs of $6.30/b. Canadian Natural Resources (CNRL) Kirby South project (40,000 b/d sanctioned capacity) saw steep SOR and opex reductions following startup in 2013, while Pengrowth's Lindbergh project (16,000 b/d sanctioned capacity) saw a significant SOR and opex drop-off following startup of its Phase 1 expansion in 2015. Cenovus-operated Foster Creek (180,000 b/d sanctioned capacity) has low historical SORs with a slight increase in 2016, which is likely connected to the startup of expansion Phase G in October 2016.

Cost and SOR trends likewise appear consistent with reported engineering innovations. Cenovus-operated projects have deployed infill drilling, using a single horizontal well to target unrecovered bitumen between steam chambers, to improve recovery factors without needing additional steam injection. In addition to similar infill drilling, MEG Energy-operated Christina Lake features co-injection of non-condensable gas, which acts as a reservoir cap and helps injected steam maintain higher reservoir pressure over extended periods.

While such clear-cut efficiency metrics are less apparent for mining projects, some operators have been able to push production beyond project nameplate capacity, boosting performance on output costs. All projects recorded at least a 20% reduction from 2014-2015, with Kearl showing the most significant percentage decrease of over 50%, largely due to the ramp-up of its Phase 2 expansion.

Other projects showed cost optimisation against the backdrop of production maximisation and maintenance deferral. CNRL's Horizon project, which was scheduled for a major turnaround in Q3 2015, deferred turnaround activities to coincide with the startup of Phase 2B in the third quarter of 2016, recording a 2015 year-on-year opex reduction of 35% and further 2016 reduction of 6%. The fourth quarter saw a significant production ramp-up extending into January 2017, and CNRL's opex guidance for the year stands at less than $20/b. Likewise, Syncrude noted 2015-2016 year-on-year opex reductions of 36.5%, which coincided with record 2016 output often exceeding the facility's 350,000 b/d nameplate capacity on a monthly basis.

Improvements in production opex notwithstanding, egress issues and diluent purchases for in situ projects will continue to present significant additional costs for oil sands operators. Additionally, oil sands projects remain at the high end of the cost curve. According to data from Rystad Energy UCube, breakeven Brent prices for oil sands assets, which are currently producing or under development hover just below $50/b, compared to a range of around $33/b to $38/b for offshore, conventional, and shale assets.

Of course, bitumen supply will continue to increase in the mid- and long-term, largely from major projects sanctioned prior to the 2014 price collapse. Assuming an implied Brent price of $80/b, just under 2.8m b/d could be produced economically by 2020. Nevertheless, production cost competitiveness will continue to be driven by structural improvements and scale. Above all, low-SOR in situ projects demonstrate the clearest structural cost advantage in the segment; any new sanctioning will likely come from such projects in the form of smaller optimisation phases, or new in situ techniques that partially displace steam with solvent to facilitate bitumen viscosity. Mining operators have also shown some resilience through production maximisation and maintenance deferrals. However, if low prices persist, the deferral approach may reach its limits as the lack of maintenance raises reliability issues.

Thomas Liles is an oil and gas analyst at Rystad Energy, where he focuses on Canadian oil sands and shale production. He was previously based in Rystad's Moscow office and holds a M.A. from Harvard University.

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