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China’s crude buying and storage strategy sets the bounds of oil prices

This article was written by Clyde Russell and was published in the Globe & Mail on December 24, 2025.

Conventional wisdom in the crude oil market is that producers such as OPEC+ largely determine the price by altering output levels to achieve a desired outcome.

That shibboleth was challenged in 2025 by China, which used its status as the world’s biggest oil importer to provide an effective price floor and ceiling by either increasing or decreasing the volume of crude it sent to storage tanks.

Production cuts in 2022 by OPEC+, which groups the Organization of the Petroleum Exporting Countries and allies led by Russia, did shore up prices. Those gains faded once it began reversing the cuts in April this year. Now, facing a looming oil glut, OPEC+ has decided to sit tight and hold production levels steady in the first quarter of next year.

That leaves China to mop up the excess.

What China does in 2026 is now the biggest known unknown in crude markets. Other participants are likely to set their strategies in response to Beijing.

What was clear in 2025 is that China was buying more crude than it needed for domestic consumption and exports of refined products.

China does not disclose the volumes of crude flowing into or out of its strategic and commercial stockpiles, but an estimate can be made by subtracting refinery throughput from the total crude available from imports and domestic output.

It is worth noting that not all of the surplus crude was likely to have been added to storage, with some being processed in plants not captured by the official data.

For the first 11 months of 2025, the surplus crude amounted to about 980,000 barrels per day (b/d), given that imports and domestic output combined were 15.8 million b/d, while refinery processing amounted to 14.82 million b/d.

The surplus has been built up since March and came after refiners made a rare draw on inventories in January and February, when processing rates exceeded available crude by about 30,000 b/d.

There is a solid correlation between the volume of surplus crude and the price of oil, with China adding barrels when prices dip but cutting back when they rise.

This was in evidence in September, when the surplus crude dropped to 570,000 b/d after hitting 1.10 million b/d in August.

Cargoes arriving in September would largely have been arranged at the time of the IsraelIran conflict in June, when crude prices were elevated. Global benchmark Brent futures spiked to a six-month high of US$81.40 a barrel on June 23.

With prices easing since June, China’s refiners resumed buying excess crude, with a surplus of 1.88 million b/d seen in November, the biggest since April and up from 690,000 b/d in October.

It could be argued that China’s storage flows are the main reason that crude prices were locked in a fairly narrow range in the second half of 2025, with Brent anchored either side of US$65 a barrel.

The key question for 2026 is whether China will, and can, continue to buy excess crude when prices drop, effectively providing a floor.

Estimates vary as to how much crude China already has stored, with a range from around 1 billion barrels to as much as 1.4 billion barrels.

If the assumption is that a country should have 90 days of import cover, and China’s base imports are around 11 million b/d, then 1 billion barrels would be sufficient.

But at least 700 million barrels are likely commercial inventories, implying a strategic reserve closer to 500 million barrels.

That in turn suggests that Beijing may wish to add about another 500 million barrels to the strategic stockpile, though the timeline is uncertain.

China is building more storage, with state oil companies including Sinopec and CNOOC adding at least 169 million barrels across 11 sites in 2025 and 2026.

Assuming a storage flow of somewhere around 500,000 to 600,000 b/d, this would add in the region of 200 million barrels over the course of a year.

If Beijing does continue to add to strategic inventories at this rate, it would imply that much of the forecast surplus of supply in 2026 will simply go into Chinese tanks.

If this does happen, then it is likely that crude prices will once again enjoy a Chinese-supported floor, but also a cap as China will simply trim imports if prices rise too high.

Of course, there are a number of “ifs” in the above paragraphs, but the recent history suggests that China will continue to build inventories in 2026, and probably into 2027 as well.

What is also clear is that China is quite prepared to use inventory flows as a pricing mechanism.

Given China’s seaborne crude imports of around 10 million b/d are about a quarter of the global seaborne total, it is possible that Beijing’s policies are now the most important factor in oil markets.

China doesn’t release public information on its strategic or commercial stockpiles, making it challenging not only to assess physical flows, but also to determine what policies are likely to be followed. What was clear in 2025 is that China was buying more crude than it needed for domestic consumption and exports of refined products.

Premier Ford, we’ll still see you in court

These seven Ontarians are fighting Ontario's climate inaction in court. Back row from left: Shelby Gagnon and Madison Dyck, both 29. Middle row from left: Zoe KearyMatzner, 19, Beze Gray, 30, Sophia Mathur, 18, and Shaelyn Wabegijig, 28. Front row: Alex Neufeldt, 29.

This article was written by SOPHIA MATHUR, SHELBY GAGNON, SHAELYN WABEGIJIG, BEZE GRAY, MADISON DYCK, ALEX NEUFELDT AND ZOE KEARYMATZNER and was published in the Toronto Star on December 2, 2025.

This week was supposed to be the week.

We had it circled in our calendars for months — rearranging exams, shifting work schedules and postponing plans. We told our professors, bosses and families: we’ll be in court on Dec. 1 to hold the Ford government accountable for its climate record.

We were ready.

In fact, we’ve been ready for this courtroom showdown since we launched our groundbreaking case six years ago.

But instead of our day in court, we’re staring down yet another cynical move by a government that seems more afraid of having to answer before the courts than of one of the greatest threats to humanity.

Just weeks before our historic Charter challenge was set to be heard, the Ford government scrambled to repeal the very climate legislation our case was focused on.

No, not because they made a better plan. More likely, because they saw the writing on the wall.

Last year, Ontario’s highest court ruled that government climate targets must comply with the Charter of Rights and Freedoms. The science was settled. The law was clear. In what we hoped would be a final, decisive hearing, we were ready for a groundbreaking victory for climate justice.

But rather than face us in court, the Ontario government repealed the law requiring it to set climate targets altogether.

Ontario seems to be saying if you don’t like our climate target, we just won’t have a target. Rather than facing accountability on an issue that risks the lives of thousands of Ontarians, Premier Doug Ford is taking his toys and going home.

He didn’t even have the guts to say it out loud. It was buried in a 200page Fall Economic Statement without consultation, meaningful debate, or an Environmental Registry posting.

This has every indication of a lastminute attempt at a political escape hatch, not an informed policy shift. How else can you explain Finance Minister Peter Bethlenfalvy claiming Ontario was doing this because the federal government had also dropped its target, before immediately backtracking after being corrected?

It’s not the first time they’ve tried to avoid us in court. They’ve tried before and yet they lost every time.

But this latest move is bigger than our case.

Back in 2018, the world’s leading scientists said emissions needed to drop 45 per cent by 2030 to avoid catastrophe. Since then, Ontario’s emissions have stagnated.

Quietly, the Ford government has scrapped renewable energy projects and cancelled Cap and Trade. According to the courts, it is “indisputable” that climate change risks the lives and wellbeing of Ontarians on a massive scale.

These impacts aren’t just environmental — they’re economic and they’re placing an unfair burden on all Ontarians. The 2024 flooding in Toronto is projected to cost us over $4 billion. This is just a taste of our future, with recent studies projecting climate change will cost the global economy $38 trillion per year by 2049.

Now, they’ve officially legislated climate denial. It leaves Ontario with no plan, no targets and no accountability. We’re sailing into the storm of climate catastrophe with no compass, no map and no leadership. And it will cost us all.

But here’s the thing: our case was never just about one law. It’s about whether the government has a constitutional responsibility to not harm the lives and futures of young people in this province. Ontario’s highest court has already said yes — climate action must comply with the Charter. Charter rights don’t disappear because the government repeals a law.

So no, this case isn’t over. Justice has just been delayed.

But we’ll be back in court — stronger and more determined than ever because we aren’t just fighting for a climate plan, we are fighting for the right to have a future.

We’re not asking for miracles, just accountability and leadership. So, to Ford and his government: if you truly believe Ontarians don’t deserve a climate plan, then say it. Stand up in the legislature and tell us that our lives, our health and our futures aren’t worth planning for. Don’t hide behind budget bills and procedural tactics. Don’t run from the courts and don’t run from us. Because we’re still here.

And we will have our day in court.

SOPHIA MATHUR, SHELBY GAGNON, SHAELYN WABEGIJIG, BEZE GRAY, MADISON DYCK, ALEX NEUFELDT AND ZOE KEARYMATZNER ARE SEVEN YOUNG ONTARIANS TAKING THE FORD GOVERNMENT TO COURT OVER ITS CLIMATE INACTION.

B.C. backs increased capacity for Trans Mountain pipeline

This article was written by Justine Hunter and Emma Graney, and was published in the Globe & Mail on November 20, 2025. Y

A tugboat guides a crude oil tanker in Burrard Inlet on Wednesday, en route to the Westridge marine terminal in Burnaby, B.C. Currently, Aframax tankers loading at the terminal can only fill to 70-per-cent capacity, limited by the confines of the Second Narrows waterway.

Once firmly opposed to expansion, province now supports move to boost flow of Alberta oil

The British Columbia government is backing a proposal to move more Alberta crude oil to the West Coast. The plan aims to increase the capacity of the Trans Mountain pipeline system by more than half a million barrels a day, with results as early as 2026.

It is a sharp reversal from a government that once fiercely opposed the initial Trans Mountain expansion, arguing when it was proposed that increased shipping traffic would put B.C.’s marine environment at risk.

The turnaround is part of B.C.’s effort to counter pressure from Alberta for an entirely new pipeline. While Alberta Premier Danielle Smith and Ottawa appear close to a deal that would pave the way for an oil pipeline from Alberta to the northwest coast of British Columbia, B.C. Energy Minister Adrian Dix says the plan would be economic folly.

Instead, Mr. Dix is now championing the Trans Mountain optimization plan, and has urged his Crown-owned utility, BC Hydro, to engage in talks with the pipeline company to support the project. The province has also given a green light to the Vancouver Fraser Port Authority to dredge the Second Narrows waterway to allow tankers to load more oil at the Trans Mountain marine terminal in Burnaby.

“I actually thought this proposal [to optimize Trans Mountain] would be more meaningful to Alberta and to the federal government, because it’s demonstrably better in every possible way,” Mr. Dix said in an interview Friday.

Canadians paid $34-billion to expand the existing Trans Mountain pipeline, and now can make it far more efficient for around $4-billion.

The cost of a new northern pipeline has not been determined – it has neither a proponent nor a route – but it would be more complex than the Trans Mountain expansion, which followed the route of the existing pipeline.

“We just finished a pipeline. It’s paid for by the Canadian taxpayer, and we’re trying to make it better for them,” Mr. Dix said.

Alberta’s Energy Minister, Brian Jean, said in an e-mailed statement that the province is “extremely supportive” of Trans Mountain’s efforts to maximize capacity, because the United Conservative government wants to see oil production double in the province by 2035.

Since the taps for Trans Mountain were turned on in May, 2024, the space crunch has eased on all of Canada’s largest export pipelines. The difference between the price paid for Western Canadian crude versus product from the United States has also fallen sharply, and Canadian crude oil exports to countries other than the U.S. have more than tripled, with most of it headed to Asia.

“Optimizing TMX, including dredging the port of Vancouver to allow tankers to operate at full capacity, is critical to maximizing the benefits that Alberta and Canada receive from accessing Asian and West Coast U.S. markets,” Mr. Jean said.

“The best time to build a pipeline was 10 years ago, the next best time is today,” he said.

Trans Mountain has a threepart wish list of projects to improve flow on the line. Together, they would increase the system’s capacity by roughly 510,000 barrels a day (b/d).

Chief executive Mark Maki told The Globe and Mail earlier this year that Canada needs to “do the easy things first” – like boosting capacity – before it pursues an entirely new pipeline. (Mr. Maki was not made available for an interview ahead of the company’s quarterly earnings next week.)

“We need to optimize the system that we have. That has to be a priority for us so we can get more capacity as early as 2026, and then more a little bit later in the decade,” he said in May.

The largest optimization project would bump capacity on Trans Mountain’s main system by roughly 360,000 b/d, by adding 30 kilometres of new, 36-inch diameter pipe adjacent to existing lines and small improvements to infrastructure along the route.

The project would also see 11 new pump stations added along the route and increased power to the line to make existing pump stations more effective.

Earlier this year, Mr. Maki estimated that the mainline optimization project would cost between $3-billion and $4-billion, and take a few years to complete.

The second capacity-boosting project would introduce drag-reducing agents into the pipeline system to reduce friction between the oil and the line itself. It wouldn’t require much construction, making it a relatively cheap exercise with the potential to increase capacity by up to 10 per cent, or 90,000 b/d.

Western Canadian producers could start to face transportation problems as soon as 2027 if pipeline capacity remains where it is today, according to a recent report by analysts at TD Cowen.

Mr. Maki said in May he expected to have the drag-reducing agents in service by the end of 2026. However, that project will only proceed if shippers confirm they want to secure additional volumes on the pipeline.

The third project is still in its conceptual phase. It would increase the volume of oil going through the 111-kilometre Puget Sound pipeline between Abbotsford, B.C., and Skagit County, Wash., by up to 60,000 b/d by upgrading terminal infrastructure.

Trans Mountain has not yet submitted any formal applications to regulators for the proposed projects.

Alongside work on the pipeline system are dredging plans to help relieve a pinch point in Vancouver’s harbour.

Currently, Aframax tankers loading at Trans Mountain’s Westridge marine terminal in Burnaby can only fill to 70-percent capacity, limited by the confines of the Second Narrows waterway. The Vancouver Fraser Port Authority is leading a proposal that would dredge the deep-sea navigation channel.

There is no budget yet for the project but the plan would remove up to six metres of material below the seafloor – an estimated 30,000 cubic metres – which would allow the tankers more draught, and therefore the ability to load more oil at Westridge. The B.C. government has given tentative approval for the plan.

Looming large over Trans Mountain’s plans is the question of whether Western Canada’s oil and gas sector will even need more pipeline space in the coming years.

Those on the clean-energy front argue that reliance on fossil fuels will soon dry up, negating the need for a new pipeline. But analysts and oil companies counter that new or expanded pipelines are crucial to ensure Canadian crude can access the global market to get full price for its products.

Western Canadian producers could start to face transportation problems as soon as 2027 if pipeline capacity remains where it is today, according to a recent report by analysts at TD Cowen.

On the flipside, if pipeline capacity grows by between 820,000 b/d and one million b/d – by adding a new pipeline, for instance – the analysts wrote that they “envision a long, sustained oil price tailwind for all western Canadian producers, well into the next decade.”

The most likely scenario, however, is roughly 270,000 b/d of additional capacity coming online through 2030. In that case, pipelines don’t become constrained until the third quarter of 2028.

Enbridge announced last week it would spend US$1.4-billion to increase capacity on two pipeline networks that connect the Alberta oil sands to U.S. refiners.

Colin Gruending, president of liquids pipelines at Enbridge, told reporters that Western Canadian crude production is likely to grow by around 500,000 to 600,000 b/d through the end of the decade.

Capacity additions on Enbridge lines and the Trans Mountain optimization projects should take care of that, he said, but “beyond that, it gets probably a little fuzzy.”

Regardless, Mr. Gruending said the oil and gas sector should ideally always have extra wiggle room in pipelines to get product to market.

Trans Mountain highly utilized but still has capacity

This article was written by Emma Graney and was published in the Globe & Mail on September 4, 2025.

**Crude oil tankers SFL Sabine, left, and Tarbet Spirit are seen docked at the Trans Mountain Westridge Marine Terminal, in Burnaby, B.C., in June, 2024.**

The system has been more than three-quarters full every month since June, 2024: Canada Energy Regulator analysis

As Alberta, Saskatchewan and the oil and gas industry push for a new pipeline to transport fossil fuels to coastal ports for export, a new analysis from the Canada Energy Regulator shows there is still excess capacity on the expanded Trans Mountain system.

Over all, however, oil export pipeline capacity from Western Canada continues to be highly utilized, the CER says. And oil production from the oil sands is only projected to increase.

Shippers with long-term contracts make up the bulk of Trans Mountain’s customers. Numbers from the CER show they have taken advantage of the newly opened capacity, filling roughly 99 per cent of their allotted space each month.

The Trans Mountain expansion, the most expensive infrastructure project in Canadian history, began as an attempt to provide a simple transport route to the West Coast for growing oil production. A dozen years and $34-billion later, the government-owned pipeline can carry an additional 590,000 barrels a day from Edmonton to Burnaby, B.C.

Since the taps for Trans Mountain were turned on in May, 2024, the space crunch has eased on all of Canada’s largest export pipelines. And Canadian crude oil exports to countries other than the United States have more than tripled, with most of it headed to Asia.

Meanwhile, crude-by-rail exports have fallen to levels not seen in more than a decade – and even so, there is still spare pipeline capacity, according to the CER.

Still, the system has been more than three-quarters full every month since it came online, aside from the ramp-up period in May, 2024. From the next month through to this June, utilization averaged 82 per cent, ranging from a low of 76 per cent in December, 2024, to a high of 89 per cent in March.

Roughly 80 per cent of Trans Mountain’s capacity is reserved for committed shippers with long-term contracts. The rest is available on a monthly basis for uncommitted (also known as spot) shippers.

While Trans Mountain historically transported mostly light oil before its expansion, heavy oil is now close to matching light oil volumes, according to the CER.

Light oil and refined products are being delivered to Burnaby, mostly to serve Parkland Corp.’s refinery there and Suncor Energy Inc.’s Burrard Products Terminal. The system’s Sumas delivery point in Abbotsford, B.C., which connects with the downstream Puget Sound Pipeline for deliveries of crude oil to Washington State refineries, has continued to be at capacity, the CER said.

The Trans Mountain system has also boosted Canadian crude prices, relative to international benchmarks, with the value of Western Canadian Select rising by about US$6.70 a barrel.

The difference between the price of West Texas Intermediate (a North American benchmark) and heavy Canadian oil has narrowed significantly by about US$12 a barrel since the expanded pipeline system came online, the CER said.

Despite the “significant economic benefits” provided by the expanded system – including revenues for government coffers –a further reduction in the differential would be unlikely with a new pipeline, according to a recent report by the research arm of Alberta Central, the central banking facility and trade association for the province’s credit unions.

Thus, “it would be a mistake to suppose that another pipeline would provide benefits in the same order of magnitude,” that report noted.

“WCS will always sell at a discount relative to WTI because of the difference in grade. The main benefit of the new pipeline would be to prevent a rewidening of the oil price differential, as oil production increases.”

OPEC+ agrees on large oil output hike in push for market share

This article was written by Olesya Astakhova, Ahmad Ghaddar, and Alex Lawler, and was published in the Globe & Mail on August 4, 2025.

OPEC+ agreed on Sunday to raise oil production by 547,000 barrels a day for September, the latest in a series of accelerated output hikes to regain market share, as concerns mount over potential supply disruptions linked to Russia.

The move marks a full and early reversal of OPEC+’s largest tranche of output cuts plus a separate increase in output for the United Arab Emirates amounting to about 2.5 million b/d, or about 2.4 per cent of world demand.

Eight OPEC+ members held a brief virtual meeting amid increasing U.S. pressure on India to halt Russian oil purchases – part of Washington’s efforts to bring Moscow to the negotiating table for a peace deal with Ukraine. President Donald Trump said he wants this by Friday.

In a statement after the meeting, OPEC+ cited a healthy economy and low stocks as reasons behind its decision.

Oil prices have remained elevated even as OPEC+ has raised output, with Brent crude closing near US$70 a barrel on Friday, up from a 2025 low of near US$58 in April, supported in part by rising seasonal demand.

“Given fairly strong oil prices at around $70, it does give OPEC+ some confidence about market fundamentals,” said Amrita Sen, co-founder of Energy Aspects, adding that the market structure was also indicating tight stocks.

The eight countries are scheduled to meet again on Sept. 7, when they may consider reinstating another layer of output cuts totalling around 1.65 million b/d, two OPEC+ sources said following Sunday’s meeting. Those cuts are currently in place until the end of next year.

OPEC+ in full includes 10 nonOPEC oil producing countries, most notably Russia and Kazakhstan.

The group, which pumps about half of the world’s oil, had been curtailing production for several years to support oil prices. It reversed course this year in a bid to regain market share, spurred in part by calls from Mr. Trump for OPEC to ramp up production. The eight began raising output in April with a modest hike of

OPEC+ in full includes 10 non-OPEC oil-producing countries, most notably Russia and Kazakhstan.

138,000 b/d, followed by largerthan-planned hikes of 411,000 b/d in May, June and July, 548,000 b/d in August and now 547,000 b/d for September.

“So far the market has been able to absorb very well those additional barrels also due to stockpiliing activity in China,” said Giovanni Staunovo of UBS. “All eyes will now shift on the Trump decision on Russia this Friday.”

As well as the voluntary cut of about 1.65 million b/d from the eight members, OPEC+ still has a two-million-b/d cut across all members, which also expires at the end of 2026.

“OPEC+ has passed the first test,” said Jorge Leon of Rystad Energy and a former OPEC official, as it has fully reversed its largest cut without crashing prices.

“But the next task will be even harder: deciding if and when to unwind the remaining 1.66 million barrels, all while navigating geopolitical tension and preserving cohesion.”

Canadian oil production forecast to rise amid possible drop in global prices

This article was written by Emma Graney and was published in the Globe & Mail on June 10, 2025.

Growth in global oil demand for the rest of the year is expected to fall to one of its weakest levels since 2001, says research firm S&P Global, which has revised its price outlook for benchmark crude down to as low as the upper-US$40 mark.

The United States in particular will face a sharper year-on-year decline in production than expected, S&P forecast in its latest research paper, released Monday. That’s in part owing to limping demand growth; only the 200809 financial crisis and COVID-19 pandemic in 2020 saw lower numbers.

S&P’s price outlook for West Texas Intermediate for the rest of the year is now in the US $40s to low-US $60s range.

“The oil price is currently defenceless,” wrote Jim Burkhard, S&P’s global head of crude oil research.

“Seasonal demand in the Northern Hemisphere summer may obscure the impact for a bit, but eventually there will be too much crude oil in the market absent a change in production trends.”

The good news for Canada? The United States is expected to bear the brunt of the effects from an oversupplied market, because U.S. shale production is more responsive to price shifts compared with other sources of non-OPEC supply, such as Canada, Guyana and Brazil.

By the end of 2026, U.S. oil production could be down 640,000 barrels a day from what it was in mid-2025. However, such a decline could set the stage for a future price recovery, the analysis says.

Canada posted a $7.1-billion merchandise trade deficit in April – the largest on record – as exports fell sharply in the face of U.S. tariffs.

The value of exports to the U.S. fell 15.7 per cent from the previous month, Statistics Canada reported. The decline was led by a sharp pullback in autos, consumer goods and crude oil exports.

Although April crude exports fell compared with the first three months of the year, analysts cautioned that the numbers need to be taken in context.

The volume will come back. But we do anticipate, right now, a weaker price in the back end of the year.

“If you look at trade with the U.S. in January, February, March, it was actually really quite high because there was this push to get as much out of the country and into the U.S. before the tariffs took effect,” said Susan Bell, the senior vice-president of downstream research with Rystad Energy.

And April is generally a low point in Canadian oil production, said Kevin Birn, S&P’s chief analyst for Canadian oil markets. That’s because it’s peak turnaround season, when companies lower production to perform necessary maintenance at their facilities.

The swing between production during turnaround and in winter is huge, he said – usually around 300,000 barrels.

“The volume will come back,” he said.

“But we do anticipate, right now, a weaker price in the back end of the year.”

That’s because of a range of factors, including OPEC pumping more oil into the market and a slip in demand associated with lower global economic growth. Together that will push the world into oversupply, Mr. Birn said, putting downward pressure on prices and the value of oil exports, including in Canada.

On the flipside, Rystad is forecasting a small price bump in the summer, Ms. Bell said. Even if OPEC does follow through on its planned production increase, Rystad believes the market has capacity to absorb the incremental barrels.

Regardless, Mr. Birn expects production will continue to grow in Western Canada, with export volumes to the U.S. hitting record levels even as prices slide.

That’s because oil sands companies are making their operations as efficient as possible, and because 90 per cent of the pipelines coming out of Western Canada still point south.

“The biggest consumer for Canadian crude – Canadian heavy sour, specifically – is the Midwest and then the Gulf Coast, because those refiners are configured to process Canadian heavy crude,” he said.

“They will continue to buy Canadian heavy crude, and Canada will continue to sell it to them.”

Global oil supply to rise faster than expected, IEA says

This article was written by Robert Harvey and Enes Tunagur, and was published in the Globe & Mail on May 16, 2025.

**Saudi Arabia, which is home to Aramco’s refinery, above, is the only country with room to add oil barrels back to the global market based on current production levels.**

Lower prices from trade tensions, rising output are affecting U.S. shale growth

World oil supply will rise more rapidly than previously expected this year as Saudi Arabia and other OPEC+ members unwind output cuts, the International Energy Agency (IEA) said on Thursday, despite a lower forecast from U.S. shale producers.

The IEA expects global supply to rise by 1.6 million barrels a day (b/d) this year, up 380,000 (b/d) from the previous forecast, the agency, which advises industrialized countries, said in a monthly report.

OPEC+ is adding more crude to the market after the group decided to unwind its most recent layer of output cuts in May and June more rapidly than earlier scheduled. The extra supply, along with concern about President Donald Trump’s tariffs, helped send oil prices to a fouryear low earlier this month.

Even though the IEA made a small 20,000 b/d increase to its forecast for oil demand growth this year to 740,000 b/d, the pace of growth will slow in the rest of the year to 650,000 b/d, it said, from 990,000 b/d in the first quarter.

“Signs of a slowdown in global oil demand growth may already be emerging,” the IEA said, adding that economic headwinds combined with record sales of electric vehicles (EVs) are dampening demand.

Saudi Arabia is the only country with room to add barrels back to the market based on current production levels, the IEA said, after the OPEC+ group agreed to a second monthly accelerated output increase for June at its last meeting.

Total oil demand will average 103.90 million b/d this year, the IEA said, an upward revision from 103.54 million b/d last month, citing updates to historical demand estimates for some countries including Egypt and Nigeria, in addition to the 20,000 b/d hike in its demand growth forecast.

Even after these changes, the IEA’s projection of the surplus in the global market does not change much, rising to about 730,000 b/d based on Reuters calculations in the report, slightly larger than last month’s 710,000 b/d.

Next year, IEA sees demand growth averaging 760,000 b/d, with supply growth rise by 970,000 b/d, also implying a surplus.

Also in the report, the IEA revised down its forecast for U.S. shale oil growth by 40,000 b/d in 2025, and by 190,000 b/d in 2026 citing lower prices.

“One of the most immediate impacts of the recent slump in oil prices is expected to fall on U.S. shale output,” it said.

“We expect more activity cuts over the coming quarters,” it said, adding that large independent shale players have already announced 14 rig cuts for this year.

On Wednesday, the Organization of Petroleum Exporting Countries trimmed its forecast for oil supply growth from the U.S. and other producers outside the wider OPEC+ group for 2025.

Lower oil prices are also affecting Russia, the IEA said, as monthly oil revenues declined to their lowest since June, 2023, at US$13.2-billion in April.

Russia’s revenues fell despite production rising by 170,000 b/d on the month to 9.3 million b/d, and exports by 150,000 b/d to 7.6 million b/d, according to the IEA.

Electric car sales will exceed 20 million in 2025 and account for around a quarter of global car sales, the IEA said, marking backto-back annual records on surging sales in China.

EV sales in China alone will hit 14 million in 2025, the IEA said.

Despite rising EV sales, the IEA reduced its forecast for oil demand displacement to five million b/d by 2030 in its 2025 EV outlook report, down from six million b/d in the previous report. EVs’ oil displacement was around 1.3 million b/d in 2024.

Drillers shift to natural gas as trade war hurts oil prices

This article was written by Robert Tuttle and was published in the Toronto Star on April 29, 2025.

Drillers in Canada’s energy heartland of Alberta are shifting their focus to natural gas as the global trade war and an OPEC Plus plan to increase output hammer crude prices.

The number of licences for new gas wells issued in the first quarter rose 26 per cent from the previous quarter to 308, the highest quarterly total in two years, Alberta Energy Regulator data show. For oil wells, the number fell 24 per cent to 293, the lowest since 2021. Licences for bitumen wells fell by six to 37.

Canada is the world’s fourthlargest oil producer and the fifthlargest gas producer, according to the International Energy Agency. Nearly all of its oil and much of its gas is exported to the U.S.

West Texas Intermediate oil prices have fallen to near $63 (U.S.) a barrel since U.S. President Donald Trump was inaugurated and started threatening tariffs on trading partners. In recent weeks, OPEC and its allies added to the headwinds by surprising the market with plans to revive curtailed production earlier and faster than expected. On top of that, Heavy Western Canadian Select crude typically trades at a discount to WTI, currently about $9.65 a barrel.

By contrast, natural gas in Canada has risen to around $2 (Canadian) per gigajoule from about $1.50 during that time as the country’s first liquefied natural gas export plant prepares to start operation later this year on the British Columbia coast.

The pricing swings have producers in the Montney formation, which straddles the border of Alberta and British Columbia, shifting toward more natural gasrich areas and away from pure oilproducing regions, Trevor Rix, Canadian oil and gas research team leader for Enverus, said.

The drillers aren’t just seeking natural gas, but rather the associated liquids such as condensate, which is blended with oilsands bitumen to allow it to flow through pipelines and commands stronger pricing than Canadian crude, Rix said. Oilsands production is growing after the start of the expanded Trans Mountain pipeline last year.

The trend may be playing out in the U.S. as well, where Precision Drilling Corp. — a drilling rig contractor operating in Canada, the U.S. and the Middle East — is seeing interest in gasdirected drilling in the Haynesville formation and Marcellus, chief executive officer Kevin Neveu said on an earnings call last week.

U.S. Energy Secretary Chris Wright said at an energy conference in Oklahoma City last week that oil at $50 a barrel wouldn’t be sustainable for American producers.

In Alberta, Canadian Natural Resources Ltd.’s oil and gas licences rose to 88, the highest on a quarterly basis in more than a decade, with 59 targeting gas versus 29 for oil. ARC Resources Ltd. was second with 54.

Alberta’s oil sector projects calm as it prepares to ride out falling prices

This article was written by Emma Graney and was published in the Globe & Mail on April 15, 2025.

The Suncor Oil Refinery on Edmonton’s east side is seen on Monday. Each US$1 swing in the per-barrel price of West Texas Intermediate, a North American oil benchmark, means $750-million more or less for Alberta’s coffers.

Falling oil prices are a perpetual worry for Alberta’s resource-heavy economy, but the province’s fossil fuel industry has some factors working in its favour as U.S. shale producers struggle to break even.

Between relatively strong balance sheets, lower break-even costs for oil production and an unusually narrow difference between the benchmark prices of U.S. and Canadian oil, sector players are relatively upbeat despite current market turmoil caused by U.S. President Donald Trump’s constantly fluctuating trade war.

Jon McKenzie, chief executive of Calgary-based oil giant Cenovus Energy Inc., said in a recent interview that the dramatic oil price drop of US$10 last week was “far from an existential crisis” for the industry.

“It’s not necessary to go tools-down on projects or think about cutting dividends and those kind of things like we did in the past, simply because we have taken care of our balance sheets and taken care of our cost structures and we’re able to get through the cycle,” he said.

The expansion of the Trans Mountain pipeline system and conversations about building more pipelines to access markets other than the United States also have Canadian companies feeling encouraged, said Randy Ollenberger, head of oil and gas research at BMO Capital Markets.

“Their balance sheets are so strong, no one’s particularly stressed about the dropoff in oil prices,” he said in an interview.

“I think most companies – and investors, for that matter – would look at the gyrations in the market right now as probably temporary.”

Each US$1 swing in the per-barrel price of West Texas Intermediate, a North American oil benchmark, means $750-million more or less for Alberta’s coffers. And every US$1 change in the differential (WTI versus Western Canadian Select heavy crude) represents a $740-million variation in Alberta’s bottom line.

The discount of WCS to WTI narrowed on Friday to US$9.60 a barrel, according to brokerage CalRock. It rose to just over US$12 on Monday, but continues to be historically tight because of U.S. sanctions on heavy crude-producing countries such as Venezuela, as well as lower heavy crude exports from Mexico.

Alberta forecast an average WTI price of US$68 in its February budget. Finance Minister Nate Horner said in an e-mail that the province will provide an updated fiscal outlook at the end of August.

“We calculate revenues on a quarterly basis, as daily or weekly fluctuations in the price are common. For example, while the current price of WTI is between US$61 and US$62, with the current differential of US$9 the deficit would be approximately the same as that projected at budget,” he said.

Eric Nuttall, senior portfolio manager at Ninepoint Partners, said in a recent interview that Canadian oil and gas sector balance sheets are by far the strongest he has seen in his career, with no debt, low cost structures and low operating costs. But U.S. shale companies are “in the death zone” with prices hovering at or under US$60 a barrel.

Mr. Trump promised during the election campaign that American energy producers would “drill, baby, drill” under his leadership, but that seems to have fallen flat.

Energy producers in the country last week cut the most oil rigs since June, 2023, according to a report released by Baker Hughes on Friday. It marked the third week in a row that the total number of oil and natural gas rigs has fallen, and the biggest weekly decline since June, 2024.

In the Permian Basin in West Texas and eastern New Mexico, the U.S.’s most productive oil shale basin, the rig count hit its lowest point since December, 2021.

Fears of a global recession – and a resulting drop in oil demand – continue to dog markets.

The U.S. Energy Information Administration this month reduced its expectations of global oil consumption growth.

And the Organization of the Petroleum Exporting Countries forecast in a report this month that world oil demand would rise by less than expected: by 1.30 million barrels a day in 2025 and by 1.28 million b/d in 2026, down 150,000 b/d from last month’s figures. It also lowered its 2025 world economic growth forecast.

Goldman Sachs said it expects oil prices to decline through the end of this year and next year because of the rising risk of a recession and higher supply from OPEC+. The bank expects WTI to edge down to US$59 a barrel for the remainder of 2025, and US$55 in 2026.

Fears of a global recession – and a resulting drop in oil demand – continue to dog markets.

Plunging oil prices threaten Trump’s beloved U.S. shale production industry

This opinion was written by Eric Reguly and was published in the Globe & Mail on April 12, 2025.

If there is one industry beyond Big Tech that defines American business success, innovation and dominance, it is oil and natural gas, especially oil. Donald Trump may be about to blow that status despite his cherished “drill, baby, drill” mantra. For most of the Oil Era, the United States has been a huge importer of hydrocarbons, making it a slave to the OPEC cartel. Then came dazzling technology that allowed oil to be extracted from layers of shale, a sedimentary rock, handing the U.S. a new career as an energy superpower, much to the dismay of Saudi Arabia, OPEC’s leader.

In 2010, domestic oil production was about five million barrels a day. Last year, more than 13 million barrels a day came gushing from the prolific Permian Basin straddling Texas and New Mexico and other big shale reserves, putting the U.S. well ahead of Saudi Arabia’s 8.9 million barrels a day. Since 2020, the U.S. has been a net exporter of oil and oil products. Its oil and gas industry, anchored by shale producers, directly employs two million workers and supports some 10 million others, according to the American Petroleum Institute.

By now, we know that Mr. Trump is the master of unintended consequences. He adores the U.S. oil industry but seems to be doing his best to sabotage it by demanding low energy costs. What he appears to forget is that shale’s worker, technology and drilling costs are extremely high compared with those of Saudi Arabia. In that country, you can poke a hole just about anywhere in the desert and pump out a barrel of oil for a few bucks. Not so with shale.

During his election campaign, Mr. Trump vowed to lower energy prices. He wanted to see US$50-a-barrel oil. At that price, energy inflation would be smashed and votes would be won when Republicans and Democrats alike rolled their pickup trucks, some with 130-litre gas tanks, into service stations. The good news for Mr. Trump is that he may get his wish; the bad news is that US$50 oil could wreck the shale industry.

In January, when Mr. Trump returned to the White House, Brent crude, the international benchmark, was trading north of US$80. In Early April, when he unleashed his global tariff assault, the price sank and kept on sinking. Oil even failed to rally along with global equities earlier this week, when Mr. Trump suspended his “reciprocal” tariffs on every country other than China. On Friday, Brent was trading at US$63 for a 12-month loss of 30 per cent.

The price slumped for two reasons.

The first was pure economics. The tariffs, now as high as 145 per cent on imports from China, and 10 per cent on other countries, as well as 25 per cent on cars, triggered a flurry of growth slowdown and recession forecasts. Low or negative growth translates into less demand for energy. Prices fall (during the early months of the pandemic, in 2020, when oil demand collapsed, prices briefly turned negative).

The second seems to be retaliatory geopolitical moves from OPEC, specifically Saudi Arabia. Since the U.S. shale boom and the rise of production in other non-OPEC countries, including Canada, Brazil and Norway, the cartel has been losing influence, reducing its ability to change prices – and maximize profits or market share – at will through production cuts or increases.

But that power has not completely disappeared. Starting this month, OPEC will unwind 2.2 million barrels a day of previously announced production cuts. The reasons given were vague. It could be that the White House wants OPEC to boost output to cover expected shortfalls in exports from Venezuela and Iran, two countries that rank high on America’s list of nasties. Or it could be that the OPEC countries, angered by the tariff war and the relentless rise of U.S. shale production, want lower prices to damage the shale industry and win back market share.

OPEC has gambled with this strategy before. In 2014, Saudi Arabia flooded the market to punish U.S. shale and other non-OPEC producers. Prices fell 50 per cent. The gambit was only partly successful. When OPEC ended the price war in 2016, the battered shale industry came roaring back.

It’s not certain that OPEC will keep the spigots open to try to drown the shale producers, but the effects of the price plunge are already being felt. Drilling is falling, and the high costs mean many producers will struggle to make a profit at today’s prices. Rystad Energy put the break-even cost at US$62 a barrel when dividend payments and debt-servicing costs are included. S&P Global Commodity Insights this week said US$50 oil could cut back U.S. production by one million barrels a day.

Falling prices present the biggest threat to the U.S. oil industry in more than a decade. At the same time, tariffs are lifting the prices for steel used in pipelines and other equipment. The rising costs and falling revenue could trigger bankruptcies and another round of consolidation, with the strong picking off the weak. Mr. Trump’s beloved oil industry may have humbled OPEC, but its high costs make it vulnerable. Be careful what you wish for, Mr. President.