Saturday, May 16, 2026

StanChart Warns Physical Oil Premium Collapse May Be Temporary

By Alex Kimani - May 13, 2026

Physical oil premiums have fallen sharply after spiking during the Hormuz crisis, as buyers delayed purchases, drew down inventories, reduced refinery runs, and relied on alternative non-Middle Eastern supplies.
Analysts at Standard Chartered expect physical crude prices to rebound once reserve releases end and refinery demand rises again, unless a geopolitical deal eases supply disruptions.
U.S. crude exports reached an all-time record high of 6.4 million barrels per day (bpd) for the week ending April 24, 2026, eclipsing the previous high of 5.3 million bpd set in late 2023.

Over the past couple of months, physical oil cargo premiums have surged as markets reacted to the threat of physical supply disruption, forcing buyers to pay significantly higher prices for guaranteed, prompt delivery of crude oil. As the conflict escalated and Iran blocked the Strait of Hormuz, buyers scrambled to secure immediate, non-Middle Eastern "prompt barrels", driving up the spot price premiums for available cargoes. North Sea Forties crude spiked to nearly $150 a barrel by mid-April, exceeding the 2008 peak. Many commodity experts predicted that oil futures would eventually trade up to the physical; however, we have lately been seeing just the opposite, with the physical trading down to the futures. Whereas physical prices still indicate market tightness, they have recently returned to a more normal range. Dated Brent (the primary physical benchmark for crude oil in the North Sea) settled just $0.43/bbl higher than front-month Brent on 11 May, good for a w/w fall of $11.31/bbl. Saudi Aramco’s official selling price (OSP) remains historically high; however, June saw m/m reductions to both Europe (~2/bbl) and Asia (~4/bbl) after May’s OSP recorded the largest ever m/m price increase. And now commodity experts at Standard Chartered have predicted that this downward adjustment will reverse before long.

According to StanChart, physical oil cargo premiums have collapsed--with some grades dropping 90%--due to a combination of intentional buyer restraint, increased reliance on inventory and increased supplies from non-disrupted regions.

The sharp fall in the price of physical oil can be chalked up to buyers remaining hopeful the Iran conflict would be resolved rapidly, at least in terms of the Strait of Hormuz blockades, and were dissuaded from purchasing cargoes at extremely elevated prices. High volatility and regular price swings in excess of $10/bbl in a day (front-month Brent traded in a $35/bbl intraday range on 9 March ) have increased the risk of a VaR shock i.e., an acute increase in Value at Risk.

Deferring purchases in the near term has also allowed buyers to benefit from strategic reserve and inventory drawdowns, reduced refinery run rates (and adjustments to maintenance schedules), and alternative supply sources, which have cushioned oil price spikes.

StanChart says physical prices are likely to rise once more when purchases can no longer be deferred, refinery runs pick up and strategic reserve releases are complete, unless a deal to end the conflict can be agreed. This will likely eventually pull futures prices up towards elevated physical benchmarks.

U.S. producers continue to be among the primary beneficiaries of the ongoing energy crisis. According to the latest data from the U.S. Energy Information Administration (EIA), U.S. crude exports reached an all-time record high of 6.4 million barrels per day (bpd) for the week ending April 24, 2026, eclipsing the previous high of 5.3 million bpd set in late 2023. Combined U.S. crude oil and refined petroleum product exports hit a record peak of 12.9 million bpd in the same week. International refiners, particularly across Asia and Europe, are aggressively buying American light sweet shale oil to replace stranded Persian Gulf barrels.

Asian buyers, particularly in Japan, South Korea, and Taiwan, have sharply increased purchases. To meet this massive international demand, the U.S. has drawn heavily from commercial storage and the Strategic Petroleum Reserve (SPR), pulling down domestic inventories by over 2 million bpd. The Trump administration has initiated the sale of ~53 million barrels of crude oil from the SPR to nine energy companies, and is working toward a total release of 172 million barrels. This move is part of a coordinated international effort with the IEA to release roughly 400 million barrels worldwide following supply disruptions in the Middle East.

The European Union Aviation Safety Agency (EASA) recently authorized the broader use of US-grade Jet A fuel in Europe, over the standard Jet A-1 specification with “no regulatory obstacles”. By allowing the use of US-grade jet fuel, the supply pool has been effectively enlarged, removing some of the reliance on imports from the Middle East. However, Jet A has a higher freezing point than Jet A-1, meaning it’s mostly useful for lower altitude, short-to-medium haul flights. The development has allowed Jet fuel differentials to come off recent highs while front-month contracts are now in contango. The U.S. has maintained healthy jet fuel inventories, remaining above seasonal norms and in excess of the five-year range at 43.57 million barrels on 1 May. Meanwhile, inventories in Europe, as evidenced from measures in the larger Amsterdam-Rotterdam-Antwerp (ARA) region, have tightened quickly, falling from ~1.1 million metric tonnes (Mt) held from September to end-December 2025, to just 0.56Mt in the latest weekly data.

By Alex Kimani for Oilprice.com

Permian Gas Glut Means Producers Are Paying Buyers to Haul It Away

By Andrew Topf - May 14, 2026

While Europe and Asia face gas shortages, rationing, and soaring prices due to the Iran conflict, the U.S. Permian Basin is flooded with natural gas, with prices turning deeply negative because pipeline capacity cannot keep up with production.
Cheap U.S. gas is hurting producers like Diamondback Energy and EQT Corporation, but benefiting the broader U.S. economy.
Analysts expect U.S. gas prices to remain relatively low for years as production keeps rising.

The war in Iran has choked natural gas supplies across Europe and Asia, leading to fuel rationing and blackouts, but in the heart of US shale country, the market is swimming in supply.

Gas in the Permian Basin of West Texas and New Mexico is so plentiful that producers are having to pay buyers to get rid of it. Bloomberg reports that there is so much inventory that it exceeds available pipeline capacity. “Prices aren’t merely cheap, they’re negative,” states the April 29 article, noting that Permian gas hit an all-time low of -$9.60 per million British thermal units on April 24.

In the Permian, gas prices have dipped below zero intermittently since 2019 as pipeline construction failed to keep pace with soaring production. But this year, negative pricing has been more pronounced than ever.

US natural gas futures have slipped 10% since the Middle East conflict began, a situation that contrasts sharply with Europe, where prices are up about 40%, and Asia, where they’ve jumped more than 50%.

The gas glut is creating winners and losers.

For Permian producers like Diamondback Energy (NASDAQ;FANG), low prices have been a drag on profits. In an earnings call, executives said they are “consciously moving away from Waha,” the Permian pricing hub, and increasing their exposure to higher-priced markets near population centers, export facilities and planned data centers.

EQT Corp (NYSE:EQT) has curtailed output due to persistently low spot prices.

The silver lining in this low-priced cloud? The US economy. Not only are lower natgas prices insulating the United States from war-driven energy shocks, but they are also creating an economic tailwind.

Cheap supplies of gas — a key manufacturing input and a major player in meeting power demand from artificial intelligence — stand to give the US an edge over countries facing fuel shortages.

Petrochemical producers like Dow are among the companies benefiting from low-cost industrial gas, Bloomberg reports.

While Americans are facing inflation across most goods and services, electricity prices would be higher if it wasn’t for the natural gas glut. In March’s CPI inflation numbers, utility gas prices fell 0.9%.

Anna Wong, chief economist at Bloomberg Economics, believes The divergence between gas prices in America and the rest of the world “could mean the US economy will prove more resilient than expected this year. Natural gas is more important to the manufacturing sector — particularly chemicals, fertilizers, electricity — than crude oil is.”

Of course, the gas glut won’t last forever.

Forward prices for Waha gas are shown flipping to positive in October, around the time that the Blackcomb Pipeline enters service, with five new Permian conduits set to bring about 11 billion cubic feet a day of capacity by the end of 2028. While that amounts to roughly 10% of US gas production, Bloomberg concludes that abundant shale production and limited export capacity mean US gas prices are poised to remain low relative to the rest of the world for years to come. Gas will average well below $4 through 2027, American government forecasts show, while production is poised to hit fresh records.

According to Barchart, on Tuesday the Energy Information Administration (EIA) raised its forecast for 2026 US dry natgas production to 110.61 bcf/day from an April estimate of 109.60 bcf/day.

US nat-gas production is currently near a record high, with active US nat-gas rigs posting a 2.5-year high in late February.

On April 17, nat-gas prices tumbled to a 1.5-year nearest-futures low amid robust US gas storage. EIA nat-gas inventories as of April 24 were +7.7% above their 5-year seasonal average, signaling abundant US nat-gas supplies.

The EIA forecasts Lower 48 natural gas production will increase 3% this year compared with 2025, largely because of rising production in the latter part of the year. The increase is driven mainly by the Permian region, which the EIA expects to produce 29.2 bcf/d in 2026, or 6% more than in 2025.

It expects L48 production to steadily increase throughout its forecast period, averaging 118.9 bcf/d in 2026 and 124.0 bcf/d in 2027.

By Andrew Topf for Oilprice.com

Big Oil Reconsiders Previously Unattractive Destinations

By Irina Slav - May 13, 2026

Middle East supply disruptions and Hormuz tensions are pushing major oil companies back toward politically stable regions like Alaska, reviving interest in projects once seen as too costly or unattractive.
Exxon, Shell, and Repsol placed record bids in Alaska’s latest lease sale, while projects like Willow and Pikka are expected to help reverse Alaska’s long-term production decline.
Beyond oil, Alaska’s LNG ambitions are gaining momentum as Asian buyers seek secure non-Middle East gas supplies, reinforcing energy security as a top global priority.

The Middle Eastern crisis has prompted a reprioritization among international oil companies. Previously unattractive drilling destinations are suddenly looking quite attractive—even Alaska.

The oldest oil and gas producing part of the United States has for years been out of the spotlight as the industry moves to cheaper and faster-growing locations. The only news of any substance about Alaska recently was the Biden administration’s approval of the Willow project, led by ConocoPhillips, which was set to boost the state’s oil output by 160,000 barrels daily, and Australian Santos’ Pikka project, set to start commercial production this year. That was years ago. Now, Big Oil is eager to drill in Alaska.

Earlier this month, a lease sale in the National Petroleum Reserve in Alaska attracted record bids, worth a total $163 million. Among the bidders were Exxon, Shell, and Repsol, with the latter already partnering with Santos on the Pikka development. And this may be just the beginning.

The Bureau of Land Management offered 625 tracts across about 5.5 million acres for bid in the sale, revived at the end of last year by the Trump administration. No lease sales were held in the National Petroleum Reserve in Alaska under President Biden. Yet under Trump’s One Big Beautiful Bill, there will be a total of five lease sales in Alaska over the next ten years.

“With the imminent start-up of the Pikka project on the North Slope, the reversal in the decline of oil production in the great state of Alaska is going to help put more oil in the Pacific area at an important moment,” Repsol’s head of upstream operations, Francisco Gea, said as quoted by the Financial Times. Gea called Alaska “a fantastic opportunity”. The Pikka project, which has a price tag of $4.5 billion, will produce up to 80,000 barrels daily.

It is indeed a fantastic opportunity, at the very least because it is nowhere near the Middle East and as such is a highly secure energy exploration destination. Canada is in a similar position, by the way: the head of the International Energy Agency earlier this month told an industry event Canada had a golden opportunity to step in as a secure energy supplier in a world that’s currently 14 million barrels daily short on supply because of the Middle Eastern crisis.

Security, then, is what has prompted Big Oil to return to the North—even Shell, which left in 2015 after writing off as much as $7 billion on an unsuccessful drilling campaign hampered, among other things, by strong environmentalist opposition. According to the Financial Times, the supermajor’s decision to partake in the latest Alaska lease sale was surprising for analysts.

However, according to chief executive Wael Sawan, the lease sale concerns a different part of the state. “It is a very, very, very different part of Alaska that we have gone to,” he told the Financial Times. “This is an onshore exploration opportunity in a very well-established basin that has been producing for some time… So this is not offshore Alaska where we have had the challenges in the past.”

Crude oil is not the only thing drawing the energy industry to Alaska in these times of oil and gas trouble. Gas is also a magnet—in this case, in the form of the Alaska LNG project. Interest in the Alaska LNG export project has spiked since the war in the Middle East choked 20% of global LNG supply and sent Asian buyers scrambling for expensive spot cargoes.

Glenfarne Group, the majority owner and developer of the facility, aims to sign binding offtake agreements with buyers soon and advance final investment decisions to later in 2026 and early 2027, company executives told media earlier this year on the sidelines of an energy conference in Tokyo.

“There's a real interest, particularly with everything happening in the Middle East right now. Everyone would like to get those (preliminary deals) turned into long-term agreements,” Adam Prestidge, president of Glenfarne Alaska LNG, told Reuters in March.

Alaska LNG is designed to deliver North Slope natural gas to Alaskans and export LNG to U.S. allies across the Pacific. An 800-mile pipeline is planned to transport the gas from the production centers in the North Slope to south-central Alaska for exports. In addition, multiple gas interconnection points will ensure meeting in-state gas demand.

The latest Alaska developments show clearly how the Middle East war has put energy security back in the spotlight, making previously challenging locations desirable again. With an estimated 1 billion barrels of oil supply wiped out of markets since the war began, according to Aramco’s Amin Nasser, alternative supply sources have become urgently needed, and not just for the short term. Even if the Strait of Hormuz reopens soon—which at the moment seems unlikely—energy security will in all probability remain a top priority both for energy producers and for consumers.

By Irina Slav for Oilprice.com

Canada’s LNG Ambitions Grow as British Columbia Warms to Gas Exports

By Irina Slav - May 15, 2026
The British Columbia government is eager to see the LNG Canada project expand to Phase 2 as soon as possible, in a marked departure from earlier political sentiment towards hydrocarbons that were strongly negative.
LNG Canada is due to make the final investment decision on Phase 2 of the same-name facility in Kitimat soon, and British Columbia Premier David Eby this week said he hoped the decision comes by the end of this year, describing it as the “largest private sector investment in Canadian history,” as quoted by CBC.
Backed by Shell, Petronas, PetroChina, Mitsubishi, and Kogas, LNG Canada has redirected a portion of Canadian gas exports—previously flowing almost entirely to the U.S.—toward global markets. The price tag of the project is $40 billion. Construction of the first train took seven years. The first cargo set off from Kitimat in June last year.
Since then, the terminal has been ramping up shipments, with the bulk going to South Korea. Although the previous Canadian federal government had claimed there was no business case for LNG exports, the LNG Canada partners apparently begged to differ—and now so does the provincial government of British Columbia.
Indeed, the B.C. government is so happy with LNG Canada that it announced an “enhanced cooperation agreement” with the company this week. The final investment decision on Phase 2 depends on the agreement of all partners.
Meanwhile, political enthusiasm bout Canadian liquefied gas is not being shared by environmentalists, who are calling for a reversal of the industry’s growth, enforced by the government. Most recently, a group called the Canadian Association of Physicians for the Environment claimed LNG Canada was flaring more gas than it was allowed to, releasing “health-harming chemicals, including black carbon and benzene, a potent carcinogen for which there is no safe exposure level.”
The chief executive of LNG Canada responded by saying that higher flaring rates were normal during start-up and that the company was “monitoring, very carefully, the emissions levels in the community.”
By Irina Slav for Oilprice.com

Australia Rules Out LNG Export Curbs as East Coast Gas Supply Fears Ease

By Tsvetana Paraskova - May 15, 2026
Australia will not be imposing controls on exports of natural gas during the third quarter of 2026, as industry and experts have assured the government that the most vulnerable east coast will not see any supply shortages between the winter months of July and September.
“Following confirmation from industry and experts that Australia’s east coast market has sufficient gas supplies, Minister for Resources and Northern Australia Madeleine King will not implement gas market export controls,” the government said on Friday.
Early last month, Australia’s government said it intended to consider using emergency powers to protect the domestic natural gas supply in case of a shortfall on its east coast in the third quarter of 2026.
Minister King last month gave notice of her intention to consider using powers under the Australian Domestic Gas Security Mechanism (ADGSM) to protect Australian energy supplies in the event of a possible east coast domestic gas shortfall in the third quarter of 2026.
However, following a month of consultations with industry and experts, Australia has now decided no gas export controls would be necessary.
“Minister King said she had now received assurances from exporters that there will be more than enough gas to meet the demand of Australians,” the government said today.
Australia is also implementing, as of July 1, 2027, the so-called gas reservation scheme that requires gas exporters to supply a proportion of their total production to the Australian market, equivalent to 20% of exports.
“The reservation will build Australia’s energy sovereignty, grow gas reserves and ensure more Australian gas stays in Australia,” Minister King said.
Australia’s decision not to implement gas export controls in the third quarter is good news for the global LNG market, which suddenly found itself in a major shortage after the Iran war crippled the Middle East’s LNG exports, with tight markets now expected to last much longer than previously thought.
By Tsvetana Paraskova for Oilprice.com

Commonwealth LNG Approves $13 Billion Louisiana Export Project

By Tsvetana Paraskova - May 15, 2026
Developers of the Commonwealth LNG project have taken the final investment decision to build the $13-billion U.S. export plant in Louisiana, underpinned by investments from Kimmeridge, Abu Dhabi-based Mubadala Energy, and Canada Pension Plan Investment Board, the UAE energy investor said on Friday.
The Commonwealth LNG facility in Cameron Parish, Louisiana, will have an annual capacity of 9.5 million tons of liquefied gas and is expected to become operational in 2030.
Phase 1 development of the export facility on the west bank of the Calcasieu Ship Channel is expected to generate more than $3 billion in annual export revenue when operations commence in 2030, according to the proponents of the project.
The FID includes the successful closing of $9.75 billion in project financing for the construction of the export project, marks the start of full construction, and advances one of the most cost-competitive and efficient LNG projects in the United States, Mubadala Energy said.
The transaction attracted strong interest from both equity and debt investors, resulting in total commitments of $21.25 billion.
Kimmeridge, Mubadala Energy, and CPP Investments provide new financing for Commonwealth LNG and continue as equity investors in Caturus. Mubadala Energy, which already holds a 24.1% stake in the Caturus platform, comprised of Commonwealth LNG and Caturus’ upstream operations, is also an equity participant in the project’s financing.
“Global gas demand is unquestionably accelerating, and Caturus is positioned to be a differentiated leader across the value chain from upstream production to LNG export,” Caturus CEO David Lawler said.
The final investment decision for the new U.S. project comes as the Middle East conflict upended global LNG supply and demand balances. Contrary to earlier forecasts, the market is now expected to be tight in 2026 and 2027, amid curtailed output from Qatar and the UAE, and Qatar announcing it could need up to five years to repair the damage to its key Ras Laffan LNG complex from Iranian missile attacks in March.
By Tsvetana Paraskova for Oilprice.com

Canada’s Economy Caught Between Oil Windfalls and Trade Wars

By Alex Kimani - May 12, 2026

The Bank of Canada says Middle East geopolitical tensions and U.S. trade risks are now the biggest threats to Canada’s economy, replacing tariffs as the top concern.
High oil prices are boosting Canadian exports, government revenues, and the trade balance, but are also fueling inflation and raising the risk of higher interest rates.
Uncertainty around the future of United States-Mexico-Canada Agreement and potential new U.S. tariffs could slow growth and even push Canada into recession if trade relations worsen.

A recent Bank of Canada Market Participants Survey has flagged geopolitical and trade tensions as the biggest risks facing the Canadian economy. Leading the downside are geopolitical risks led by the Middle East war, with 82% of respondents identifying it as the biggest risk, while 79% and 57% of respondents picked growing trade tensions and tightening global financial conditions, respectively. The shift from trade tensions dominating headline risks to Canada’s economy amid Trump tariffs is largely attributed to the Iran war, which has disrupted global supply chains and impacted the shipping of oil, gas, and fertilizer through the Strait of Hormuz.

Governor Tiff Macklem has warned that persistent high energy prices resulting from these conflicts could necessitate interest rate hikes to maintain the 2% inflation target. However, like many oil producers, Canada is also experiencing an "oil paradox" with high oil prices driving up domestic fuel costs and inflation while simultaneously generating significant government revenue windfalls.

Canada posted its first trade surplus in six months, with the country’s merchandise trade balance swinging to a $1.78 billion surplus in March against expectations of a shortfall of $2.88 billion, while total exports rose 8.5% to $72.8 billion, the second-highest level on record. Energy exports surged 15.6% to $17.1 billion, the highest level since September 2022, helped by a 18.9 % jump in crude oil exports thanks to a 33.1% spike in prices. Exports of metal products increased 24.0% to a record $15.3 billion, led by a $3 billion rise in gold exports thanks to a surge in safe-haven demand. Meanwhile, total imports fell 1.6% to $71.0 billion, driven by lower volumes of consumer goods, pharmaceuticals, and aircraft.

That said, trade tensions between Canada and the United States remain a major headwind, with 82% of respondents saying easing of the tensions is the leading upside risk to Canada’s economy. That’s significantly higher than 57% of respondents who identified a larger-than-expected fiscal stimulus as the top upside or 43% who listed decreasing geopolitical risks and higher commodity prices.

Currently, there’s plenty of uncertainty surrounding the review of CUSMA (USMCA). CUSMA is a trade agreement between Canada, the United States and Mexico that came into effect on July 1, 2020 during Trump’s first term, replacing the 26-year-old NAFTA. The agreement requires, among other things, that 75% of automobile components to be manufactured in North America to qualify for zero tariffs, aiming to boost regional production. The Trump administration is required to outline its new position by July 1; however, negotiations are likely to drag into the fall, influenced by U.S. midterm election politics. While a 16-year extension is the base case, there is a risk of a severely fragmented scenario where the U.S. imposes up to 35% tariffs on all Canadian exports, potentially inducing a Canadian recession. Further, there are reports that the White House is considering splitting the agreement into separate bilateral deals rather than maintaining it as a single trilateral agreement.

Canada is already doing much less business with its northern neighbor, with the U.S. accounting for just 66.7% of total exports in March, the lowest level ever, in large part due to Trump’s tariffs. Canada’s trade surplus with the United States widened to $7.1 billion in March, its highest level since September 2025, largely driven by a 8.3% increase in shipments of passenger cars and light trucks to $48.51 billion. In contrast, imports from the U.S. dropped by 1.2% to $41.44 billion.

The Trump administration has imposed significant tariffs on Canadian goods, including a 50% tariff imposed on Canadian steel and aluminum; 35.2% combined anti-dumping and countervailing duties on soft lumber, 25% tariffs on auto exports and 50% tariffs on copper and copper products, among other levies. Canada initially announced reciprocal, dollar-for-dollar tariffs on $30 billion worth of U.S. goods but removed many of them in September 2025 after some U.S. exemptions. However, it still maintains retaliatory tariffs on specific U.S. steel, aluminum and auto products.

The results of the survey came just two weeks after Canada’s federal Finance Minister François-Philippe Champagne tabled the spring economic update, which revealed that Canada’s GDP growth is projected to slow down to 1.1% in 2026, down from 1.7% in 2025. However, the economy is expected to perk up again, growing 1.9% in 2027. Canada's deficit for FY 25/26 was reduced by $11.5 billion to $66.9 billion (2.1% of GDP), thanks in large part to higher oil revenues.

Last month, Canada unveiled the Canada Strong Fund, its first ever sovereign wealth fund. The federal government has pledged to seed the fund with $25 billion over three years on a cash basis. CSF will focus on achieving market-rate commercial returns by investing alongside private capital in strategic sectors. The investments will target nation-building projects in both clean energy and fossil fuels, transportation infrastructure, telecommunications, advanced manufacturing and critical minerals. However, the sovereign wealth fund’s unique feature is a planned retail investment product that will allow individual Canadians to directly invest their own money into the fund and share in the financial returns.

By Alex Kimani for Oilprice.com

Canada Rethinks Selling Its Crown Jewel Pipeline

By Charles Kennedy - May 14, 2026

The Canadian federal government may reconsider a plan to privatize the Trans Mountain oil pipeline.
Since the expanded TMX pipeline launched in 2024, exports to Asia—especially China—have surged, with up to 70% of shipments from British Columbia heading to Asian buyers by late 2025.
Officials now see TMX as a highly profitable “strategically important asset,” with potential for further expansion

The Canadian federal government may reconsider a plan to privatize the Trans Mountain oil pipeline and keep it state-owned amid a surge in appetite for Canadian crude to replace lost Middle Eastern barrels.

“The prior narrative had been that this should be returning to private hands,” the head of the government entity that owns Trans Mountain said at an event this week, as quoted by the Financial Post. “That was in a different market and that was in a different time,” Elizabeth Wademan also said.

Indeed, this is a very different market from what it was when the government in Ottawa had to step in and buy Trans Mountain from Kinder Morgan, which quit the project under relentless pressure from climate activists who used environmental regulations to strangle the expansion project. The price tag for the nationalization deal, which took place in 2018, was about $3.3 billion, and the Trudeau government quickly signaled it would start looking for buyers as soon as possible.

By 2024, the cost of the pipeline expansion project had swelled to about $23 billion, but the project, somewhat surprisingly, was completed, and the expanded pipeline launched in May of that year, running at three times its original capacity or a total of 890,000 barrels daily.

The destination for these barrels was the vast Asian market, as a way to diversify away from the U.S., which has for decades been pretty much the only foreign market for Canadian crude—and an export conduit, with the oil transported from Canada to the U.S. Gulf Coast, and from there, to markets overseas. With the new TMX, Canadian crude producers got a new, more convenient channel to Asian energy buyers.

It did not take long for the effect to be felt: between the launch of the expanded pipe and spring 2025, the average flow rates for shipment to China reached 207,000 barrels daily. That compares with an average of 173,000 barrels daily pumped to the United States. Since spring, the shift has become even more marked. By October 2025, as much as 70% of Canadian crude exported from the British Columbia coast was going to China. Now, everyone else in Asia is also interested.

The Trans Mountain pipeline is a “strategically important asset”, Trans Mountain Corp.’s Wademan said this week, suggesting the project could be expanded further, with more “energy corridors” that would add value for Canadians, the Financial Post reported.

“Let’s look where we are, and look how important energy security is, and look how incredibly profitable this asset is; there’s a lot,” Wademan said. “There’s a lot of merit to holding onto it and realizing that full value.”

Indeed, it would be profitable for the federal government to hold on to the infrastructure as the price of Canadian crude inches closer to $90 per barrel—a level hardly seen as possible just five years ago, and even more recently. TMX has turned into a game-changer for the Canadian oil industry and it will be in the center of the “golden opportunity” that Canada has to become a bigger global player in both oil and gas.

Canada has a “golden opportunity” to become a major global oil player as the war in the Middle East limits sources of crude and natural gas, the head of the International Energy Agency, Fatih Birol, said earlier this month, adding that “The cost of missing this train will be incredible.” It seems the Canadian government is acutely aware of that risk and plans to avoid it and make the best of the country’s resources in a fascinating departure from the previous government’s focus on emission reduction and alternative energy.

By Charles Kennedy for Oilprice.com

UK Moves to Ban New North Sea Oil and Gas Licences Permanently

By City A.M - May 15, 2026

The UK government will introduce legislation banning new North Sea oil and gas exploration licences as part of its Energy Independence Bill.
Critics argue the policy will increase Britain’s reliance on imported fossil fuels while damaging Scotland’s oil and gas industry.
Rising oil prices and disruptions tied to the Iran conflict have intensified political pressure on Labour to reconsider the ban.

The government will make it illegal to grant new oil and gas licences in the North Sea, the King said at the state opening of Parliament, in a sign ministers are refusing to buckle in the face of a barrage of criticism that the policy is depriving the UK of billions of pounds in tax receipts without helping the environment.

As part of an Energy Independence Bill announced in the King’s Speech, the government will bake into law its pre-election pledge not to explore new oil and gas fields in a bid to “take control of our energy security”.

In its 2024 manifesto, the Labour Party made a ban on all new exploration and drilling licences in the North Sea a key pillar of its promise to turn Britain into a “clean energy superpower” by 2030.

But since entering government, the party has come under growing pressure to renege on the promise, with critics arguing it strangles one of Scotland’s most vibrant industries and fails to improve the UK’s environmental footprint.

Backlash against ‘deluded’ North Sea policy

Oil and gas still accounts for three-quarters of the UK’s energy mix. And the majority of those fossil fuels are now shipped in from abroad, meaning other economies benefit from the job creation and tax receipts that are derived from the lucrative drilling and refining processes.

Calls for the ministers to rethink the ban have grown louder since the outbreak of war in Iran led the price of crude oil to nearly double in a month. Last week, Norway, which drills for oil in the same area of the North Sea as Britain, approved plans to reopen three gasfields that had been shut for decades to help sate the global demand for fossil fuels caused by the closure of the Strait of Hormuz shipping lane.

Two of Labour’s main political opponents – Reform UK and the Conservatives – have both vowed to overturn the ban, in a move they say would help increase the UK’s tax take and inoculate it from any acute supply shocks.

The ban, which the government claims will help Britain off the “roller-coaster of fossil fuel markets”, has also drawn criticism from the US’s ambassador to the UK, who has used multiple interviews to urge Britain to make more of its reserves.

Shadow energy secretary Claire Coutinho accused her opposite number Ed Miliband of being “utterly deluded” for seeking to put the ban into the statute book.

“He is not making us more independent. He is making us more reliant on foreign imports,” she said.

By City AM

Friday, May 15, 2026

Motsepe says partnerships boosting South Africa’s mining sector

Bloomberg News | May 12, 2026 |

Patrice Motsepe. Credit: Council for East and Central Africa Football Associations

South Africa has regained competitiveness in mining because of partnerships between the public and private sector to tackle regulatory issues and structural bottlenecks, according to billionaire Patrice Motsepe.

Policy uncertainty together with vandalism, power outages and logistics bottlenecks have weighed on South Africa’s mining industry for more than a decade. President Cyril Ramaphosa’s government partnered with business groups including B4SA to address the nation’s sub-standard transport and energy infrastructure and operations.

“They’ve done very well over the last few years in ensuring” South Africa becomes a destination for investments, Motsepe said at the sidelines of a conference in Kenya’s capital, Nairobi. “Part of what should take place in those partnerships is for the CEOs of the mining industry to keep telling the government what are the changes, the improvements and the areas that will ensure that South Africa is a globally competitive destination.”

The end of rotational blackouts and improvement in transport logistics have put South Africa in a better place to capitalize on higher commodity prices. Johannesburg’s industrial metals and mining gauge has climbed 30% this year, compared with just a 2.4% increase in the benchmark FTSE/JSE All Share Index.

Still, South Africa’s investment in mineral exploration dropped for a seventh straight year, despite the government’s ambitions to arrest the decline.

Exploration spending in South Africa fell 5.3% to 738 million rand ($44.8 million) in 2025, according to data published in March by the government’s statistics agency using 2015 constant prices. Investment in prospecting has slumped more than 85% in the past three decades, the data show.

Motsepe, South Africa’s wealthiest Black person who made his fortune in gold mining in the 1990s and 2000s, said his company plans to invest several billion dollars in the country’s mining sector, without providing any time line.

His African Rainbow Minerals Ltd. has interests in coal, iron ore and platinum group metals. The firm also owns 10% of Harmony Gold Mining Co., a top producer of the precious metal in his home nation.

Motsepe is the South African president’s brother-in-law.

(By Prinesha Naidoo and Jennifer Zabasajja)

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