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Alberta shelves crude curtailments

The province’s decision to unwind restrictions hopes for better days ahead. But economics may be against it

The Albertan government will suspend its almost two-year-old crude curtailment programme as of December but include a one-year regulatory extension to the end of 2021 to allow the province to again restrict production if need be. But, with the economics against oil sands production, inserting this caveat may be optimistic.

Oil companies in the Canadian province have been producing substantially below mandated levels of 3.81mn bl/d since the Covid-19 pandemic threw a wrench into the global economy earlier this year.

By suspending crude quotas, Edmonton is hoping to improve investor confidence and boost capital spending from the dismal levels seen over the past five years, ultimately kick-starting oil drilling and job creation in the economically hard-pressed province.

Word of caution

Alberta has nevertheless hedged its bets by extending the timeline for the crude curtailment programme, warning provincial production could again exceed available pipeline capacity by the second half of 2021. That could, though, prove wishful thinking.

Provincial production could again exceed available pipeline capacity by the second half of 2021

A lack of pipeline and rail egress from Western Canada in the face of rapidly rising oil sands production led crude inventories to hit maximum regional storage capacity of almost 40mn bl in late 2018, causing the differential between WTI and local benchmark Western Canadian Select to balloon to over $50/bl. This in turn led Edmonton to restrict production at the beginning of 2019 to try to help reduce this discount.

With Alberta now producing 3.4mn bl/d, and only 3.1mn bl/d as recently as August, regional crude inventories had declined to roughly 20mn bl on 16 October, based on data from US energy research firm Genscape.

The Albertan government appears to have switched back to focusing on pipeline routes to market rather than crude-by-rail, with the latter uneconomic for more distant export markets in a low oil price environment. Crude exports by rail to the US collapsed to roughly 40,000bl/d in July after hitting an all-time high of 412,000bl/d in February, according to the Canada Energy Regulator.

Another round?

The numbers might suggest Alberta is correct to keep the door open for another possible round of export quotas in the second half of next year. When former premier Rachel Notley announced output restrictions in December 2018, her government estimated the province’s production capacity exceeded pipeline and rail capacity by 190,000bl/d. Original cuts of 325,000bl/d were made, allowing just 3.56mn bl/d to be produced in the province in the first quarter of 2019, with sporadic increases until January 2020.

In the interim, two factors have added to Alberta’s potential egress deficit—an increase in oil production capacity and the uneconomic nature of most rail exports—while another factor could subtract from it, although has not yet—namely, boosted oil pipeline capacity.

Oil production capacity has increased by roughly 140,000bl/d over the past two years, with Canadian producer Suncor Energy’s Fort Hill oil sands mining project coming fully onstream alongside several steam-assisted gravity drainage projects in 2019. Crude production capacity growth has since stagnated due to the collapse in capital spending.

320,000bl/d – Projected pipeline capacity shortfall

Crude-by-rail export capacity has, in effect, declined by 310,000bl/d—taking into account average exports of 350,000bl/d in the fourth quarter of 2018 minus July’s export figures.

On the flip side, Canadian midstream firm Enbridge’s Line 3 pipeline replacement was originally expected to bring an end to Alberta’s crude curtailment programme by the end of 2019. The replacement was projected to add 370,000bl/d of incremental pipeline capacity, but, as of now, will be online in the fourth quarter of 2021 at the earliest. Five small-scale expansion projects, involving either anti-drag agents or optimisation, should add 320,000bl/d of pipeline capacity, but only by mid-2021.

These numbers could leave Alberta short of 320,000bl/d of pipeline capacity in the third quarter of next year when compared with the province’s production capacity of slightly more than 4mn bl/d.

However, simple economics means not all of Alberta’s spare production capacity is likely to return to market over that timeframe. The WTI breakeven price for major oil sands producers ranges from $30/bl to almost $40/bl, with local producer Canadian Natural Resources at the bottom end and domestic peer Cenovus Energy at the top.

Since these are average figures for each company, it suggests some oil sands production will remain uneconomic in the current low oil price environment. And this is unlikely to change much over the coming year, despite recent euphoria over the relative success of Pfizer’s Covid-19 vaccine trials.

Opec+ will still need to continue to withhold several million of barrels per day from the market to prop up prices due to pandemic-related demand destruction. And Canada’s highest-cost production will likely have to join it on the sidelines, no matter how many confidence-boosting measures the Alberta government might take.

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