While it’s no secret that COVID-19 has created unprecedented crude demand destruction, determining which sources of production will be the first to flinch is a difficult task. Over the last week, in-basin Western Canadian Select pricing has fallen into the single-digit range, forcing oil sands producers to decide if operating at a loss is preferable to shutting in production for an extended period. Today’s energy market commentary will explore the profitability of Canadian oil sands production and its bearings on global crude balances in a market scrambling to react to COVID-19.
In-basin prices have approached dangerously low levels in most regions, but WCS prices for heavy oil have breached the threshold of profitability for producing wells. With in-situ operating costs ranging between US$7-$15/bbl, sub-$5/bbl realized crude prices fail to maintain profitability. Current crude pricing weakness is especially problematic for oil sands producers because shutting in their production carries more downsides than shale production. In-situ production is facilitated by injecting steam into the reservoir. When heat and pressure injections cease during a shut-in scenario, it can take anywhere from six to 12 months to resume production in addition to incurring substantially higher operating costs than currently producing assets. Despite the downsides of shut-in production, how long can oil sands producers keep pumping oil out of the ground at a loss on each barrel?
Mined oil sands production, which has even higher operating costs than in-situ production, is already in decline based on recent operator updates. Last week, Suncor Energy announced it is shutting in all but one of the three trains at its Fort Hills mine, a 50-year, 194 Mb/d capacity mine that started producing just two years ago. Despite this, Suncor chose to curtail this asset’s production to prioritize assets that can scale with changing market conditions more easily.
Canadian crude production stands at 4.35 MMb/d today. Of this, crude produced from oil sands has become a larger segment of total Canadian production in recent years, climbing from an average of 63% of total production in 2010 to 74% in March 2020. As such, a significant portion of Canadian crude production falls into this “produce it or lose it” category for determining where shut-ins need to occur based on pricing dynamics.
The global liquids balance grows longer by the day as supply and demand shocks worsen. As US refiners adjust their utilizations to account for reduced domestic fuel demand, the distribution of shut-ins becomes a question of quality as well as in-basin pricing. The need for heavy crude in US refining resulted in an average of 3.8 MMb/d of Canadian imports in 2019. US refining utilization is expected to drop by nearly 20% in April 2020 in response to COVID-19, signaling a reduced demand for heavy Canadian crude. Such an extreme reduction in US refining demand would dictate that about 1.2 MMb/d will need to be consumed within Canada on average in 2020, which is nearly double the ten-year average of 700 Mb/d. This is an annualized estimate, with a much larger impact in the immediate months to come. Canadian refining demand will also be reduced in the near-term due to measures to slow the spread of COVID-19, so production curtailments may need to average more than 500 Mb/d in 2020.
Oil-sands producers are trapped between a rock and a hard place as liquids markets face supply and demand shocks putting downward pressure on pricing. Single-digit in-basin crude prices do not support the operating costs for oil sands production, but shutting in production risks reservoir damage as well as lengthy periods of high operating costs to resume flows. To stay informed on the latest market dynamics, we are currently offering our existing clients one-on-one webinars with our latest thoughts on the outlook for gas and oil markets. If you are not currently a client but would like to schedule a one-on-one presentation, please submit an inquiry HERE.
