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The oil price meltdown earlier this year and demand destruction wrought by COVID-19 forced Canadian crude oil producers to throttle back output. At the height of the cutbacks in May, almost 1 MMb/d of oil supply had been curtailed due to uneconomic prices and/or lack of downstream demand. With oil prices and demand having staged a partial recovery in the past few months, production is rising off the lows and producers are talking about even higher supplies in the months ahead, with the prospect of returning to pre-pandemic levels. Today, we begin a short series that reviews the recent production pullback and discusses how producers are positioning themselves for a resurgence of their oil supplies. Crude oil production in Western Canada never seems to be able to catch a break. Congested pipelines, government-imposed production curtailments in Alberta that started in 2019 (and still remain officially in place), and wild price swings in what routinely seem to be some of the cheapest heavy oil barrels around have dealt numerous crushing blows to an industry at the heart of one of the largest oil-producing regions in the world. Things came to a head (again) with the short-lived Saudi-Russia driven oil price crash in March of this year and subsequent COVID-led demand destruction as consumers followed shelter-in-place orders. The Canadian heavy oil price benchmark, Western Canadian Select (WCS), reached all-time lows in April, printing single digits for much of that month. The negative demand impacts from the sudden reduction in flying and driving arrived around the same time, and resulted in refineries rapidly cutting production runs. That meant less crude oil was needed from major producing regions like Western Canada.  The double whammy of lower prices and lower demand forced a rapid rationalization of costs and reductions in oil production levels across the region’s major producing regions. Alberta, being Canada’s largest producing region by far, took the brunt of the declines, with output falling 790 Mb/d from February, just before the downturn, to May, the month in which the cutbacks were at their peak (blue bar segments in left chart in Figure 1). We estimate that Saskatchewan’s oil output declined by about 140 Mb/d (red bar segments) and that of Manitoba’s fell by about 10 Mb/d (green bar segments). [British Columbia’s oil output is close to negligible and is not included.] That adds up to a total decline across the three provinces of 940 Mb/d between February and May (dashed black oval in left graph). [We’ll discuss the June production data in a moment.] Figure 1. Western Canada and Alberta Crude Oil Production. Sources: Alberta Energy Regulator, Government of Saskatchewan, Manitoba Petroleum Branch, Canada Energy Regulator Focusing in on Alberta (right graph in Figure 1), the pullback in bitumen production (prior to any upgrading) was almost evenly split between mined production (orange bar segments) and in-situ (formally known as steam-assisted gravity drainage, or SAGD) production (green bar segments), falling 340 Mb/d and 270 Mb/d, respectively, and 610 Mb/d collectively over the same three-month time span. Alberta’s conventional oil production fell 180 Mb/d (blue bar segments), while production of pentanes plus was largely unchanged (purple bar segments). The period over which the production cuts took place, with the peak of the cutbacks in May, is consistent with what would be expected based on the oil sands variable cost analysis that we carried out back in early April. The cuts in the oil sands formed the majority of the supply reductions (versus non-oil sands output, which has very different production costs), and therefore give us a good framework for connecting how production costs and output related to the fall in prices, their bottoming out, and their subsequent recovery. Figure 2. Oil Sands Variable Operating Cost vs. WCS Price. Sources: RBN Energy, Bloomberg Based on that prior cost analysis, we estimated that the average variable production costs for most oil sands producing sites were between $7/bbl and $11/bbl (all U.S. dollars; gray-shaded area in Figure 2), with the lowest cost site estimated at $6/bbl (dashed pink line) and the highest at $23/bbl (dashed teal line). When we compare these costs to WCS’s price path so far this year, it is no wonder that production cutbacks were so severe and rapid. WCS started March in the mid-$30s/bbl, only a few dollars below where it began the year (black line), but by the end of that month, it had fallen into the single digits — at or below our estimated average production cost range. Most of the month of April (red line) was spent with the WCS price in single digits, but then it staged a recovery back above the average cost range at the start of May (green line) as demand and major oil price benchmarks staged a turnaround. At that point, producers still had no idea if the WCS price recovery was going to last, so they were still battening down the hatches by reducing oil sands (and other) output into May.  Since those dark days of early spring, WCS oil prices have recovered further and have stabilized in a more narrow range between $30/bbl and $35/bbl (blue line), and well above the variable production costs of oil sands (and most conventional) producers. It’s no surprise that with better and more stable pricing, oil production has increased, with Alberta’s total June oil output rising 217 Mb/d versus May (rightmost bar in right graph in Figure 1). Preliminary data for Saskatchewan and Manitoba appear to show little upward movement for supplies from the depressed levels of May, however, meaning that Western Canada’s total oil production in June had recovered less than 25% of the total production losses of 940 Mb/d mentioned earlier, with the supply gains being focused in Alberta. Official government data only covers production statistics through June, but in their recent quarterly earnings announcements and conference calls, producers have been talking up more production recovery in July and plans for further growth in the remainder of the year. This suggests that higher production levels than what we have seen so far for June are likely once we get more data in the months ahead. To get some sense for the oil supply volumes that may have returned beyond the June data, we have updated the production cuts that we tallied for our Alberta Bound Studio Session in early June, and expanded this to include estimates of supply that has been returned post-June, based on what the producers have publicly announced or what we have been able to decipher from their production data. The total of 940 Mb/d of production cuts that were in effect during May are shown in the black highlighted column in Figure 3 by company and project, as best we can determine. Figure 3. Western Canada Oil Supply: Curtailed, Restarted, and Planned. Source: RBN Energy, company reports The previously mentioned recovery for WCS prices has clearly incentivized many producers to ramp up their output, with our estimate that 468 Mb/d of oil supply has been restarted (sum of green column in Figure 3). Note that this includes any production recovery that took place in June and producers’ estimates of additional volumes that have been reactivated or were on the verge of being reactivated during July. Although the increase in Alberta production of 217 Mb/d in June mentioned earlier does not necessarily cover all of the regions in which producers were operating, it does suggest that more than 200 Mb/d — and perhaps as much as 250 Mb/d — of additional supply has returned or is on the verge of returning to the market since June (i.e., 468 Mb/d less 217 Mb/d of Alberta gain in June). The amount of oil supply that producers are still planning to return adds up to just over 400 Mb/d (sum of red column), and the speed at which this production comes back is going to vary depending on each producer’s ability to have personnel return to production sites, scheduling of barrels for shipment, production costs, reactivation costs, etc. There are also several oil sands producers that will be undertaking maintenance on numerous sites in the third quarter or early fourth quarter, so this will act as a damper on the full return of all previously shut-in production (i.e. those oil sands-related volumes in the red column). Note that our estimates of the amount of conventional oil production (last row before total) that has been restarted and is pending a restart sums to less than the 230 Mb/d that was shut in due to losses associated with natural reservoir declines and potential reservoir damage after restart. The beauty, or perhaps the curse, of most of the production shutdowns that took place earlier this year is that the majority were related to the oil sands, a form of oil production which has no effective decline. As such, once production in the oil sands is restarted, all of the shut-in production rates can be recovered, resulting in little to no loss compared to pre-shut in levels. In other words, most of the 940 Mb/d of output that was taken offline could be back on at the prior rates by the end of this year, depending on the speed at which producers restart the remaining shut-in barrels. Moreover, several oil sands producers, such as Suncor and Canadian Natural Resources, are already talking up oil sands production capacity expansions that were deferred due to the downturn, but are now being planned for later this year or in early 2021. That means that overall oil production from Western Canada might very well be higher by early 2021 than before the shut-ins took place. That stands in direct contrast to several other regions of the world, such as the U.S., for which the lack of drilling and natural declines all but guarantee that oil production going into 2021 will be lower than it was before the downturn. It’s clear that Canadian oil production and producers have been knocked to the canvas over the past five or six months, but look to be getting back on their feet and more ready to slug it out than ever before. All of these various production swings have meant rapid adjustments for other parts of the oil supply delivery chain, such as pipelines. We’ll take a closer look at those in the next part of this series.  "Never Say Goodbye" was written by Jon Bon Jovi and Richie Sambora and appears as the ninth song on Bon Jovi’s third studio album, Slippery When Wet. Released as a single outside the U.S. in June 1987, the song still went to #11 on the Billboard Rock Tracks chart and #28 on the Hot 100 Airplay Survey. Personnel on the record were: Jon Bon Jovi (lead vocals, rhythm guitar), Richie Sambora (lead guitar, backing vocals), Alec John Such (bass, backing vocals), Tico Torres (drums, percussion), and David Bryan (keyboards, backing vocals). Slippery When Wet was recorded at Little Mountain Sound Studios in Vancouver, BC, with Bruce Fairbairn producing. The album was released in August 1986 and went to #1 on the Billboard Top 200 Albums chart. It has been certified 12x Platinum by the Recording Industry Association of America. Four singles were released from the album. Bon Jovi is an American rock band formed in Sayreville, NJ, in 1983 by Jon Bon Jovi, Richie Sambora, David Bryan, Tico Torres, and Alec John Such. Such was replaced by Hugh McDonald in 1994 and Sambora by Phil X in 2013. Bon Jovi has released 15 studio albums, three live albums, five compilation albums, five EPs, and 66 singles. The band has sold over 130 million records worldwide, and has won two American Music Awards, one Billboard Music Award, one Brit Award, one Grammy Award, two MTV Video Music Awards, and two World Music Awards. Bon Jovi was inducted into the Rock and Roll Hall of Fame in 2018. The band has completed a new album, but the release date and touring plans are on hold due to COVID. |
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