Oilsands Growth Fuelled Pipeline Bottleneck, But Conventional Crude Helped Drive Production Curtailment

While the growth in Canadian crude production has come primarily from the oilsands—which set new production records annually for over a decade as production soared over 120 per cent—it is the conventional producers that employ more Albertans and have been unintentionally impacted by the transportation bottleneck that helped prompt the province to rein in production next year, according to Sproule.

The risks posed to the winter drilling season, for which Canadian light oil producers were in the midst of setting drilling and capital budget commitments, factored largely into the Alberta government’s decision to cut production by about 325,000 bbls/d, or 8.7 per cent, as of Jan. 1, said Christoffer Mylde, Sproule vice-president, Corporate Development.

“The Canadian light sweet differential was also [along with the heavy oil differential] at an historically wide level relative to WTI, which was just not sustainable to support the level of investment that many companies had planned on for this winter drilling season. In part, this precipitated the government’s decision to act now.”

While the focus of the production curtailment has been primarily on the oilsands, conventional producers and the supply sector that serves them — a major driver of oilpatch employment — have been inadvertently sideswiped by the backlog created by oilsands producers.

“It’s the same issue — the backlogs that are affecting the oilsands producers are also affecting the light oil producers and to some extent these production cuts were more necessary to support the light, conventional producers, versus the oilsands players,” said Liam O’Brien, Sproule petroleum engineer and market analyst.

“The majority of capital spent in 2018 went toward developing the light oil plays, and the majority of working Albertans in the oilpatch work outside of the oilsands, so the government would have considered the greater impact on these producers outside of oilsands,” O’Brien said.

Where production has increased over the last several years, it has overwhelmingly been from the oilsands, which now constitute over 80 per cent of Alberta oil production. As of October, oilsands output was up 18.3 per cent year-over-year while much smaller conventional oil output rose 15.1 per cent, according to the province.

According to the Canadian Association of Petroleum Producers, oilsands production swelled to over 2.65 million bbls/d in 2017, from 1.07 million bbls/d in 2005. Production is expected to rise another seven per cent annually to 2020 as those projects that were committed to years ago enter their production phases and ramp up.

Canadian heavy crude exports to the U.S. have more than doubled in just six years, to almost 2.8 million bbls/d this year. Total U.S. imports of Canadian crude now eclipse that from all OPEC nations combined.

“We have seen, even in the last three years, significant growth in production, primarily coming from the oilsands, from investment decisions made through the 2011-2014 time frame, and that has been the fundamental issue creating these differentials — the growth in infrastructure hasn’t kept pace with the growth in supply coming from those projects,” said O’Brien.

The failure of pipeline expansion to keep pace with that explosive growth “has created essentially an inevitability of significant backlog that’s blown out these differentials in the last two and a half months,” he said, prompting the necessity of production curtailment.

In short, “it’s been a market failure precipitated by policy failure, and now we need policy to fix it,” said Mylde. “There weren’t really a lot of good options on the table, because there is not going to be a short term fix on pipeline capacity, so there was that short-term issue that became very acute.”

The fact the province has now committed to purchasing rail cars to ease the bottleneck was not enough to deal with the backlog, since they will take at least six to nine months to come on stream. “We still had these differentials going into the winter drilling season, where capital budgets are getting revisited and committed to, and where those differentials would drive significant cutbacks in capital budgets,” noted Mylde.

“So it needed a shorter term solution and the production curtailment was arguably the only option left on the table. And if you look at the immediate response of the market it just shows the power of price signals, because we are still in December and none of these cuts will actually come into effect until January. So we haven’t cut any bbls yet, yet the differential has narrowed significantly.”

Curtailment strategy working

“We have also seen the market react to the production curtailment on the Canadian light sweet differential, to the point it is now very close to WTI. It will take some time for the differential to stabilize, but it’s certainly a much more favourable picture now for companies looking to commit to the winter drilling season,” said Mylde.

By mid-December, the Western Canada Select differential to WTI had already moved to a near normal US$12 per bbl, from US$29 before the announcement, and down from a high of over US$50 in October.

Though a painful pill to swallow, the medicine has therefore generally performed as hoped, Mylde said. “I think most Albertans might not like the idea that the government is intervening at this level, but when you look at the impacts, you could see how the policy has to some extent already been vindicated by the way that the market has responded to it.”

Mylde expects the curtailment to have the intended consequence of narrowing the differential throughout 2019 as well. The province predicted it would narrow the differential at least $4 per bbl relative to where it otherwise would have been without the cuts. It estimates each dollar narrowed equates to about a quarter billion dollars to the province’s bottom line.

“We see going into next year that the differentials are going to be more balanced and more in line with what we have seen historically in a more balanced market. We see it in the $16-$18 range going into next year as a more realistic level, which is closer to what we would see in a more normalized market,” he said.

There will be some unintended consequences with spillover into other subsectors as well, such as liquids production where it is blended with bitumen as diluent to facilitate oilsands pipeline shipments. “With the production cuts impacting oilsands production, there will be a bit of a hit to demand for liquids in the Edmonton market. That is going to put some downward pressure on the liquids market, and we are not seeing production cuts on the liquids side because that is coming from liquids rich plays like the Montney which is not captured by the production curtailment policy.”

Supports global pricing

Another inadvertent consequence of the mandated production cut has been its assistance to OPEC producers, who had been planning a larger production cut of their own before Canada lent them a helping hand to reduce a growing worldwide glut of oil. Prior to Alberta’s curtailment announcement, OPEC had been discussing a production cut of up to 1.5 million bbls/d. After the announcement, OPEC decided on Dec. 6 its cut would be only 1.2 million bbls/d, a difference almost equal to the announced Alberta reduction, said Mylde.

“They did at least have the information [of the Alberta cuts] at hand, so I think we can surmise that they dialed that into their thinking around their reduction. Some 325,000 bbls per day [Alberta is cutting] is quite significant even in a global context. It would represent more than a quarter of that OPEC [reduction] amount. So on a global level, it is actually contributing to a more balanced and tighter supply-demand equation for global crude, which will support Brent and WTI pricing.”

Crude-by-rail an enduring fixture

In the meantime, Sproule anticipates a large role for crude-by-rail shipments going forward. Shipment by rail had already surpassed a record 200,000 bbls/d this fall, up from under 30,000 bbls/d just six years ago, before the province announced in November it would buy enough rail cars to ship an additional 120,000 bbls/d in 2019.

While it may not ramp up as aggressively as would have been seen otherwise, crude-by-rail will still continue to grow upwards of 400,000 bbls/d by the second quarter, O’Brien said. “We expect those commitments to go forward because, even with the cuts, rail is still the answer for producers in the short term to facilitate growth.”

Added Mylde: “We will need that capacity even looking toward the end of next year with [Enbridge Inc.’s] Line 3 replacement [adding 375,000 bbls/d export capacity] coming on stream because you always need a little bit of slack in the system, and it’s still pretty tight. You also get the benefit with rail that you have more flexibility on where you want to get your product to. So we see crude-by-rail continuing to be an important feature of the market even as some of those pipeline bottlenecks are resolved, and even with the production curtailment policy in place.”

To be sure, the temporary Alberta production curtailment represents a short-term fix that does little by itself to resolve the underlying challenge of securing long-term market access for mounting crude oil production. This will get addressed over time both through crude-by-rail, pipelines and new market access. “Assuming we can develop regulatory clarity for proponents and resolve infrastructure constraints, the Canadian oil and gas sector offers a resource that will continue to be a sustainable and responsible contributor to fueling the world’s energy needs in coming decades,” Mylde said.

Sproule is a global energy consulting firm providing technical and commercial knowledge to help clients discover value from energy resources around the world. Sproule is headquartered in Calgary, Canada, and has offices in Brazil, Colombia, Mexico, and Netherlands. Learn more at Sproule.com.