Western Canada’s oil sands producers exited 2019 amidst continued market access issues and an inventory build that has sent WCS benchmark heavy crude differentials to their widest level against WTI since the end of 2018. Bottlenecks and depressed sentiment notwithstanding, Canadian oil sands players still plan on upping production in the long-term, but in order to do so, are increasingly shifting away from large-scale developments toward a growth model characterized by smaller incremental expansions with reduced facility requirements. Both thermal and mining projects will be key to this long-term growth trend, although the eternal infrastructure gridlock may well continue to serve as a near-term spoiler and punt meaningful additional production ramp-ups to the mid-2020s.
Rystad Energy expects overall crude production in the Western Canadian Sedimentary Basin (WCSB) to achieve compound annual growth of around 1.8% over the next decade (see Figure 1). Thermal projects are key to this trend and could account for upwards of 45% of total onshore Canadian crude production by 2030, dominated by expansion phases at existing schemes as well as greenfield projects such as Aspen (Imperial Oil) and Meadow Creek (Suncor) from the mid-2020s. Mining projects are also likely to post gains and could make up more than 30% of onshore supply by 2030, driven especially by debottlenecking opportunities of less than 50,000 bpd design capacity.
While egress and pricing challenges have slowed the pace of mid-term WCSB heavy oil development, operators have nonetheless adapted their growth strategies through the adoption of smaller incremental expansions, as opposed to more traditional expansion phases of 40,000 bpd or larger. Smaller development concepts, of course, are nothing new to the oil sands. Husky Energy pioneered the use of modular, repeatable 10,000 bpd thermal projects in Saskatchewan beginning in the early 2010s. A spate of additional design optimizations emerged in the years following the oil price collapse, as operators attempted to expand output while cutting costs and—in many cases—meet increasingly onerous debt service obligations.
The downscaling of expansion phases has only gained pace over the past 1-2 years. As such, Rystad Energy estimates that optimized growth concepts will account for at least half of incremental growth volumes by 2030 (see Figure 2). In this context, “optimized growth” is defined as either thermal in-situ expansions with design capacity of 30,000 bpd or less and minimal infrastructure requirements, or mining expansions of 50,000 bpd or less. Additionally, these trends will help grow contracting opportunities for service companies by $11 billion from 2019 to 2030.
Notably, Cenovus Energy in late 2019 revealed new development plans for its Narrows Lake in-situ project, which was initially envisioned as a three-phase scheme with standalone processing facilities and design capacity of between 40,000 and 45,000 bpd per phase. Cenovus now intends to develop Narrows Lake as a tieback to its neighboring Christina Lake scheme, with the initial phase being pared down to 15,000 bpd design capacity. Imperial Oil pivoted to a similar concept for an expansion targeting the Grand Rapids formation at its Cold Lake project. Originally approved as a single 55,000 bpd phase with standalone facilities, Imperial in Nov-19 indicated plans to develop the expansion in approximately 15,000 bpd increments and utilize existing Cold Lake facilities. These plans will see Imperial spend nearly $1.4 billion per year on the Cold Lake project through 2025, inclusive of operational costs.
In terms of oil sands mining, Canadian Natural Resources Ltd continues to advance engineering work on expansions at its Horizon Mine and Upgrader. These include a 40,000 bpd to 50,000 bpd paraffinic froth treatment (PFT) expansion—which would leverage excess capacity in the ore preparation process to produce diluted bitumen—as well as upgrader reliability improvements that could yield an incremental 35,000 bpd to 45,000 bpd of synthetic crude oil (SCO). Similarly, Imperial revised the development concept for Phase 3 of its Kearl mining project, halving design capacity to 40,000 bpd through enhanced mine planning with minimal infrastructure additions. These optimizations have significantly lowered civil costs, and will allow the project to be funded at a fraction of the $11 billion spent on Kearl’s Phase 2 development.
Such optimizations have had a very concrete effect on oil sands development breakeven prices, which we believe have declined by at least 35% over the past three years. In terms of projects to be sanctioned in the near-term, Rystad Energy estimates an average WTI equivalent breakeven price of around $46 per barrel for thermal FIDs over the next five years, with mining FIDs clocking in at about $53 per barrel during the same period. Amongst phases with the greatest chance of FID before 2025, we estimate that more than 55% of sanctionable resources—or about 2.4 billion barrels—can be developed at a go-forward WTI equivalent price of less than $50 per barrel. This assumes a longer-term WTI-WCS differential ranging between $11 and $17 per barrel.
The main impediments for oil sands expansion remain uncertainty over export capacity and the associated risks for WCS differentials. Many of the expansions in Figure 3 are essentially sanction-ready, albeit hindered by market access for the time being. In Mar-19, moreover, Imperial Oil delayed development of its approximately $2 billion greenfield Aspen Phase 1 (75,000 bpd design capacity), citing pipeline issues and the Alberta government’s mandated crude oil and bitumen production curtailments.
Perennially negative press over pipeline capacity notwithstanding, a slew of proposed midstream optimizations could potentially ameliorate export challenges prior to commissioning of major newbuilds such as Keystone XL and/or the Trans Mountain Expansion (TMX). A more optimistic export scenario would hinge on an optimization of Enbridge’s Mainline, which could allow up to 300,000 bpd of incremental export capacity beginning in the early 2020s. Similarly, the potential reversal of the Southern Lights pipeline—which currently moves condensate to Canada from the US Midwest and is operating below capacity—would entail an incremental ~150,000 bpd of export wiggle room closer to 2025 (see Figure 4). While near-term oil sands expenditures are expected to decline by 6% from 2019 to 2021, relieving mid-stream capacity constraints would help service companies realize a potential $28 billion of contracting opportunities in 2030.
In absence of such optimizations—and assuming a delay-riddled commissioning schedule for any major newbuilds—Rystad Energy expects flattish production for Canadian crude in the early 2020s and definitely a tight export situation throughout most of 2020, implying potentially heavier reliance on crude-by-rail exports until 2024-2025.