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Canada’s oil sector recovery to lag behind price surge

Oil prices have taken flight, but industry is still ailing from a historically bad year
The Trans Mountain pipeline expansion will provide Alberta oil producers new market access | Submitted

Oil prices may have recovered to pre-pandemic levels, but for Canada’s oil and gas industry, recovering from what was arguably the worst year in its history is going to take a couple of years, analysts say.

The International Energy Agency (IEA) estimates global demand for petroleum products won’t be back to pre-pandemic levels until 2023 and may never return to “normal.”

By then, Alberta oil producers should have a new outlet for their product through Vancouver and the Trans Mountain pipeline expansion, which has a scheduled in-service date of December 2022. Two or three years later, the LNG Canada plant in Kitimat is expected to begin shipping its first liquefied natural gas (LNG) exports.

Until then, drilling of new wells in B.C.’s Montney region in northwest B.C. is likely to increase only modestly over the next couple of years, although recent M&A activity underscores just how important oil and gas producers consider the Montney to be, since some of those deals appear designed specifically to increase their B.C. footprint.

“There is a bit of an uptick since last year obviously, with the prices, but we’re not expecting a large uptick,” said Michael Muirhead, director of consulting for IHS Markit (NYSE:INFO). “What we’ve heard from industry is that, right now, the prices are good, but you have to recover their cash flow.”

Even before a global pandemic brought economies and car and air traffic to a screeching halt, Alberta oil producers struggled with low prices, due to an oil price war between Russia and Saudi Arabia, and pipeline capacity constraints.

When the pandemic hit, oil prices crashed, forcing Alberta oil producers to take 750,000 barrels per day out of production and cancel new project investments.

“I think when we look back, in 2020 we see potentially the greatest shock to the oil sector maybe in its entire history,” said Kevin Birn, North American crude analyst for IHS Markit. “We saw prices collapse, and we saw upstream producers in Western Canada turn down production the likes of which we’ve never seen in their history. By the end the year, we were back to about pre-pandemic levels [in production], which is astounding.”

As of mid-week last week, Western Canadian Select (WCS) was trading at about $52 per barrel, compared with $66 per barrel for West Texas Intermediate (WTI), which are pre-pandemic prices. Natural gas prices were not nearly as affected by the pandemic.

It will take some time before improved oil prices translate into improved balance sheets and debt repayment.

“They’re generating positive cash flow, but they’ve had to deal with increasing pressures from shareholders to turn more cash over to them,” Birn said.

The pandemic wiped out $12 billion in planned spending in 2020, according to the Canadian Association of Petroleum Producers (CAPP).

Capital spending by the oil and gas sector is expected to be around $27 billion in 2021. By contrast, total investments in Canadian oil and gas in 2014 was $81 billion.

A good chunk of the spending in 2021 is on major infrastructure projects in B.C. like the Trans Mountain pipeline expansion, the LNG plant in Kitimat and Coastal GasLink pipeline.

One gauge of how the oil and gas sector is doing is the number of new oil and gas wells drilled. There are signs of some recovery in the upstream sector in B.C., but in Western Canada in general, activity is likely to be muted for a few years.

“Realistically we’ve got a very marginal incremental growth in our forecast for the next three to five years,” Muirhead said.

CAPP estimates upstream spending in B.C. in 2021 will be $3.9 billion – nearly $1 billion more than what was spent in 2020.

There were 370 new oil and gas wells drilled in B.C. in 2019 and 383 in 2020, according to the BC Oil and Gas Commission (BCOGC). There were 143 wells drilled in the first quarter of this year – slightly higher than the first quarters of 2019 and 2020.

“In 2020, more wells were plugged and decommissioned than drilled,” said Jordan Van Besouw, supervisor of drilling and production for BCOGC.

That is largely due to both provincial and federal policies aimed at keeping some crews working by decommissioning dormant and abandoned wells and restoring the sites to a natural state.

A boom in upstream development in northwest B.C. was initially driven by the discovery of vast amounts of “wet” gas such as light oil, condensate and propane. That is still the main attraction for oil and gas producers. Recent M&A activity shows how much value oil and gas companies are placing on B.C. Montney acreage.

Last year, Canadian Natural Resources Ltd. (TSX:CNQ) bought Painted Pony, which operated exclusively in the B.C. Montney. In April, when ARC Resources Ltd. (TSX:ARX) and Seven Generations Energy Ltd. completed an $8 billion merger, it was billed as a “strategic Montney combination.” 

The prospect of new liquefied natural gas projects being built in B.C. was expected to amplify the Montney upstream boom, which it did, though not on the level that was expected.

Only one large LNG project is being built in B.C.: LNG Canada. All other proposals have been shelved or abandoned. It may be that LNG Canada will be the only large LNG plant ever built in B.C., although several smaller projects, like Woodfibre LNG and a number of “micro” LNG plants are being built or planned.

Two new propane export terminals have also been built in Prince Rupert.

The partners behind LNG Canada have already proven up the natural gas resources they will need to feed its Kitimat plant for its first phase, which is a two-train plant that will liquefy about two billion cubic feet of gas annually.

So there will not be a big demand for new upstream production, unless LNG Canada’s partners decide to double its capacity.

“Most of the companies have that [gas] stockpiled behind pipe already,” Muirhead said. “So there won’t be a significant increase of drilling or anything. If they do the next two trains, that’s when we would see an increase in some drilling activity to get the other two billion cubic feet.”

The LNG Canada plant is expected to be in production by 2025 with two liquefaction facilities or trains. Muirhead said it makes economic sense to sanction two additional trains around the time the first phase is nearing completion. He also thinks other LNG proponents could be lured back to B.C., once LNG Canada has blazed a path.

“Once the first two trains and all the modules are done, you’ve got all the crews there, the site’s prepped, so it would be very easy just to continue on,” Muirhead said. “From a corporate perspective, I think it makes the most sense to just continue on and put the next two trains in.”

The addition of two trains would double the amount of natural gas needed, which would require a considerable amount of new upstream activity.

“If they go with the third and fourth train,” he said, “that’s significant.”

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