Alberta's oil output set to grow in 2025 with new projects, market access

Alberta's conventional crude and oil sands production has been on an upward trend this summer, with that trajectory likely to be maintained until the year end and beyond, as healthy market fundamentals boost heavy and light oil prices and additional basin egress opens up new markets, industry participants said.

Oil sands and condensate production will drive most Western Canadian crude supply growth over the next 18 months, S&P Global Commodity Insights analysts said in a report.

New well pads have started up at several in-situ facilities, including MEG Energy's Christina Lake, Cenovus' Sunrise and Foster Creek, ConocoPhillips' Surmont and Imperial Oil's Grand Rapids Phase 1, the analysts said, adding overall Canadian production [that includes NGL, butanes and pentanes] reached 5.3 million b/d in December 2023 and is expected to hit 5.4 million b/d in December 2024 and 5.6 million b/d in December 2025.

In another report, the Alberta Energy Regulator said Sept. 3 that combined conventional and oil sands production posted a record high of 4.137 million in July.

This is the second time in 2024 that crude oil output crossed the 4 million b/d mark, with March production at 4.174 million b/d, the AER data showed.

Alberta's oil production in January was 3.931 million b/d, but output in April, May and June decreased to 3.925 million b/d, 3.805 million b/d and 3.888 million b/d, respectively, due to planned and unplanned maintenance work and also the wildfires.

"At over 4 million b/d in July, that was the highest ever July production and the ninth year-on-year increase in a row," ATB Financial said in a research note in early September. "YTD [year to date] production was 200,000 b/d, or 5%, higher than the previous record set last year. Fourteen years is not a blink of an eye, but it is a relatively short time for crude oil production to double in Alberta. Back in July 2010, production was 2 million b/d and development of the oil sands has been a driving factor in this historical trend," the ATB report said.

In July 2010, conventional oil production (including condensate) was 500,000 b/d compared with 600,000 b/d in July 2024. But oil sands production, conversely, has increased dramatically going from 1.6 million b/d in July 2010 to over 3.4 million b/d in July 2024, with the more recent increases due to additional transportation capacity brought by the 590,000 b/d Trans Mountain Expansion pipeline that supported pricing with the heavy Western Canadian Select barrels being priced at an average $65/b, the report said.

TMX start up, crude flows

The Western Canadian Select discount to WTI has ranged between roughly $11/b and $16/b since TMX began operations on May 1, Platts assessments show. WCS was last assessed at a $13.70/b discount to WTI on Sept. 4, compared to a roughly $18/b discount the same time in 2023.

Platts is part of S&P Global Commodity Insights.

TMX exports have averaged about 360,000 b/d in July and August, with cargo destinations about evenly split between US West Coast and Asian destinations. Heavy crudes continue to dominate the export slate and some Aframax cargoes continue to move directly to Asia, while others are consolidating their cargoes on VLCCs, the Commodity Insights report said, noting there are preliminary signs that TMX is shifting Latin American crude trade flows, as USWC imports of Latin American heavy crude have declined sharply since May.

"Alberta's oil production growth will happen not through mega projects, but incremental capacity additions in existing facilities and occasionally a few greenfield developments," Greg Stringham, former vice president for markets with the Canadian Association of Petroleum Producers said Sept. 5. "The resource is there and so are the fundamentals on pricing and TMX has opened up a new market."

A new trend in Alberta's producers to seek a new market with TMX start up has been a growing demand for their heavy barrels in Asia, Stringham said.

"Asian refiners continue to test WCS and AWB [Access Western Blend] barrels and there is a significant interest coming out of China, Taiwan and partially Japan. As long as the heavy/light differentials are in that $9/b range, there will be a growing Asia pull," he said.

Mainline, Trans Mountain apportionment

Leading Western Canadian crude infrastructure providers Enbridge and Trans Mountain continue to add new capacity to move more barrels in markets on the US Gulf Coast, USWC and Asia resulting in pipeline apportionments.

However, for September there is no apportionment on the light or heavy systems on the Mainline, Enbridge spokesperson Gina Sutherland said Sept. 5.

"This is due to upstream and downstream sector maintenance, which we expect this time of year," Sutherland said. "We anticipate the Mainline to be well utilized for the remainder of the year."

The 3,000-mile Mainline pipeline system transports Canadian barrels from Edmonton to Gretna on the Canadian-US border, where the volumes flow onto the Lakehead system that supplies crude oil to refineries in the US Midwest and further on to the USGC.

"We continue to estimate we will transport 3 million b/d of product on the Mainline, for the remainder of the year. We are exploring potential expansions in the 2026-2027 timeframe and are currently having conversations with customers to determine their long-term transport, including the potential to add 150,000 b/d day of expansion capacity," Sutherland said.

Separately, Trans Mountain spokesperson Allison Penton said that total system nominations for the 300,000 b/d Trans Mountain Pipeline system has no apportionment for September.

A zero apportionment on a crude oil pipeline implies available crude transportation capacity.