Brent traded above $84 a barrel after climbing more than 5% over the previous three sessions. West Texas Intermediate was near $79. An agreement with Oman to establish a shipping route through Hormuz was “very close,” Iran’s Foreign Minister Abbas Araghchi said over the weekend, ruling out direct talks with the US for now because of violations of an interim peace deal reached in June.

Still, he cautioned that any deal would not immediately reopen the waterway, tempering hopes for a swift restoration of disrupted energy flows. President Donald Trump signaled patience, telling Axios on Sunday that the US was now “low-keying it.” The remarks followed weeks of Trump threatening massive strikes on Iran only to pull back.

“The bias stays bullish as long as the market is pricing the ‘possibility’ of disruption rather than the certainty of normalization,” said Haris Khurshid, chief investment officer at Chicago-based Karobaar Capital LP. “Until we see actual flows normalize, I think geopolitical risk keeps a floor under crude.”

Washington has repeatedly said it is involved in talks over the management of Hormuz, a claim disputed by Tehran. On Saturday, Iran reiterated its conditions for fully reopening the strait, including an end to the US naval blockade, the removal of sanctions and compensation for war damage.

Prior to the war, about a fifth of the world’s oil and natural gas was shipped through Hormuz to global markets. The market has been spared an extreme squeeze by a number of factors, including soft Chinese demand and the release of emergency reserves, but supply buffers have been worn perilously thin.

The risk of a renewed flare-up across the Middle East remains high, keeping markets on edge. Another tanker operated by Abu Dhabi National Oil Co. was targeted in Hormuz over the weekend while Iran-backed Houthi militants in Yemen claimed an attack on Saudi Arabia’s Jazan refinery.

The kingdom’s energy ministry said a fire was extinguished at Jazan early Sunday, without providing details on the cause. The blaze is at least the second in the past month at the facility, after satellite images showed a fire at a tank in late July following Houthi claims of an attack.

©2026 Bloomberg L.P.

In an energy system that is increasingly interconnected, volatile, and fragmented, natural gas and LNG are moving to the centre of the global energy debate. They offer a reliable and flexible source of energy to meet rising demand, while also strengthening energy security. Asia is now the primary driver of global energy demand growth, offering a vantage point from which to consider the future of gas and LNG markets.

The challenge is no longer only to produce more energy but to build systems capable of providing continuity, competitiveness, and sustainability in a more complex geopolitical landscape. For Eni, addressing this challenge starts from a clear principle: diversification.

Diversification in a changing energy landscape

This begins with geography. A presence across multiple basins — from Africa and the Mediterranean to the Americas and Asia — reduces exposure to individual geopolitical contexts and strengthens portfolio resilience. But diversification also means connecting resources, infrastructure, and markets, and capturing synergies across the entire value chain, from upstream production and liquefaction to shipping and trading, supported by risk management capabilities. 

The latest investment decisions increase the company's targeted EBITDA growth to 60% by 2030 compared with 2023 levels. As part of this growth, ADNOC Gas said it aims to invest around $28 billion between 2026 and 2030.

Fatema Al Nuaimi, CEO of ADNOC Gas, said, “With the final investment decision and contract awards for the Rich Gas Development Project, we are not only accelerating one of the world's largest gas-processing growth programmes – we are raising our ambition, targeting 60% EBITDA growth by 2030.” 

Al Nuaimi added that these investments will safeguard the UAE’s energy security, while powering its industrial growth and meeting the rising global energy demand.  

EPC contracts for Phase 2 and 3

As part of its growth strategy, ADNOC Gas said it awarded a $3.9 billion EPC contract to Wison Engineering for Phase 2 of the project and a $4.3 billion contract to Tecnimont for Phase 3. The contracts build on Phase 1, announced in June 2025, which focused on expanding processing capacity and improving efficiency across existing assets.

Phase 2 will add a new natural gas processing train at the Habshan facility, increasing processing capacity and supporting the UAE's downstream and petrochemical sectors. Phase 3 will add a new natural gas liquids fractionation train at Ruwais, enabling greater recovery of higher-value liquids from rich gas streams for export. With an additional $5 billion already committed to Phase 1, total investment in the RGD programme now stands at $13.2 billion.

Investing in megaprojects

ADNOC Gas is also investing in the Ruwais LNG megaproject, alongside the Maximising Ethane Recovery and Monetisation (MERAM) and Estidama developments. Together with the RGD programme, the four projects are expected to generate $13.4 billion in In-Country Value (ICV), supporting the UAE's industrial growth and economic diversification goals.

Apart from this, ADNOC Gas is increasing the use of AI and robotics across its operations. Technologies including drones, four-legged inspection robots, and tank-climbing crawlers are being deployed to improve safety and efficiency. The company said some inspections can be completed up to 15 times faster while reducing costs by as much as 75%.

ADNOC Gas also reported that recovery efforts at the Habshan complex following security-related incidents in April are progressing ahead of schedule, with gas supply restored to 85%, surpassing the year-end target announced in May.

Supported by strong operating cash flow, the board approved a quarterly dividend of $940 million payable in September 2026, reaffirming its commitment to annual dividend growth of 5% through 2030. ADNOC Gas expects third-quarter net income of between $600 million and $800 million and forecasts full-year 2026 net income of $3.5 billion to $4 billion if maritime operations and pricing conditions normalise in the final quarter. 

Your Excellency, how is Thailand uniquely positioned to serve as a strategic energy hub for Asia amidst accelerating global energy demand?

As energy demand continues to rise alongside urbanisation and electrification, ensuring secure, reliable, and resilient supply is a shared global priority. Asia is no longer simply part of the global energy story — it is increasingly where the future of energy demand, investment, and infrastructure development is being shaped.

According to the International Energy Agency, Southeast Asia is expected to account for approximately 25% of global energy demand growth through to 2035. Meanwhile, ASEAN is on track to become the world’s fourth-largest economy, creating significant demand for reliable, affordable, and secure energy systems.

Energy security is therefore no longer an isolated challenge that each country can address independently, and Thailand is committed to strengthening supply resilience and accelerating energy delivery both at home and across ASEAN.

How critical is the role of natural gas and LNG in securing the future of energy?

Thailand looks to natural gas and LNG as not only transition fuels, but as strategic foundations of long-term energy security, industrial competitiveness, and regional stability. As economic development continues to transform the ASEAN landscape and fuel increased energy demand, securing reliable LNG supply and strengthening regional infrastructure is now essential to support the growth upon which billions depend.

Through supportive regulation, infrastructure expansion, and strategic regional positioning, Thailand is building an attractive environment for international energy investment. We are also committed to reviewing domestic electricity tariffs and creating a new data centre category to better reflect power costs and create more opportunities for global investors and partners across the energy value chain.

How will Gastech 2026 in Bangkok provide a strategic platform for the global energy industry?

As Asia’s energy demand accelerates, stronger regional cooperation, infrastructure investment, and long-term partnerships are essential to meeting the rapidly evolving needs of billions across the region. Gastech 2026 in Bangkok will provide a strategic platform to convene global energy leaders and help shape the next generation of energy systems that will support long-term energy security, economic growth, and industrial development across Asia.

It will define the region’s collective response to recent disruptions through coordinated long-term investments, cross-border project implementation, and increased regional connectivity. For four days, Thailand will host leading natural gas producers, LNG buyers, low carbon innovators, and investors from across the entire energy value chain, supporting future energy security, economic growth, and long-term resilience.

Your Excellency, as Thailand prepares to host Gastech 2026, what are the country’s key energy priorities you are looking to advance on the global stage?

Gastech 2026 provides Thailand with an opportunity to advance several strategic priorities important to the country’s long-term energy future. These include strengthening LNG supply security and supporting Thailand’s ambition to become a strategic LNG gateway for ASEAN. We are also keen to attract international investment into energy infrastructure, power generation, digitalisation, and future energy technologies.

We will also be showcasing opportunities arising from the 26th Petroleum Bidding Round and highlighting Thailand’s long-term commitment to strengthening domestic energy supply, as well as supporting electrification, grid modernisation, energy storage, and digital technologies that will strengthen system reliability and flexibility.

Advancing carbon capture and storage as part of Thailand’s practical approach to decarbonisation and regional industrial competitiveness is another critical part of our engagements at Gastech, as is accelerating the development of hydrogen and ammonia as future energy solutions that can support long-term energy diversification.

In May 2026, Thailand approved six major projects worth a combined 958 billion baht ($29 billion), led by large-scale data infrastructure expansion including data centre and data hosting services. Launching AixEnergy alongside Gastech 2026 will also convene leaders from the energy and technology sectors to address the growing energy demands associated with AI and digital infrastructure.

As the AI boom accelerates, these technical problems suggest added costs and unforeseen reliability problems, with even a few minutes of lost uptime hitting data-center developers’ revenue. They come at a time when investors and lenders are already jittery about hyperscalers’ hundreds of billions of dollars of spending, amid growing concerns that these facilities could be depreciating much faster than estimated. 

The problems are also a potential source of wider instability in power grids that are already straining to keep the lights on.

“AI does create very unusual power demand,” said Amber Villegas-Williamson, principal consultant at the Uptime Institute in the UK, which advises electricity suppliers and data centers on standards and reliability. “It’s like over-revving your car wears out the engine faster than keeping a constant speed.”

Data centers have been around for decades, gulping down electricity while they ensure that everything from your favorite streaming show to your online grocery order functions smoothly. But facilities designed for AI computing are different because their demand is so large and swings much more dramatically. 

Power increments equivalent to the consumption of factories, towns or even cities can appear and disappear within seconds, creating repeated shocks that connected equipment struggles to absorb. 

A gigawatt data center is equivalent to a city the size of Boston, half of which can flicker on and off every few seconds, said Shannon Miller, founder and president of Mainspring Energy Inc., which works on micro-grid projects for industrial and data-center customers. Some AI campuses planned in Texas, the Midwest and other states are more than five times bigger, consuming nearly as much power on average as New York City.

AI data centers put particular strain on their power supply when they are training new models — a process that mobilizes all of the graphics processing units in unison. Like the digital equivalent of bees swarming or a school of fish changing direction, hundreds of thousands of GPUs can power up and down on a millisecond basis.

AI at times sees power usage spike as much as 50% above its design capacity, "so a 1 gigawatt facility may use 1.5 gigawatts for a split second,” said Drew Baglino, a former Tesla Inc. executive who started Heron Power Electronics Co. The company is developing equipment to manage power fluctuations for Nvidia Corp.’s even more energy intensive next-generation of servers, due in 2027. 

Most equipment isn’t designed for such big swings in power consumption. Jon Parrella, chief executive officer of energy-storage developer Terraflow Energy, likens it to driving a Ferrari and shifting straight from sixth gear to first. “You can’t swing that fast,” he said. 

This story is based on interviews with more than three dozen power experts in the US and Europe, including generators and other power suppliers, data-center developers, grid operators, utilities, investors, standards developers, insurers and regulators, almost all of whom said the physical stresses on the facilities were evident. 

Cranks on small natural gas combustion engines used to generate power at data centers have broken off, several of those people said. At xAI’s Colossus computing facility in Memphis, Tennessee, gas-fired turbines had developed cracks, one of the people said. Batteries were installed within the system to help smooth out power swings and reduce the strain on spinning turbines, the person said.

SpaceX, the parent company of xAI, didn't respond to requests for comment.

Turbines have also cracked at much smaller data centers in the UK, said Andrew Cunningham, CEO of GeoPura Ltd., which is providing hydrogen for use in fuel cells that smooth out power flows at some sites.

Cracks or wear on devices can cause electrical arc flashes — when a current jumps between conductors — potentially damaging AI chips, said Jennifer Scanlon, CEO of UL Solutions Inc., which tests and certifies new technology.

There is a suite of equipment such as batteries, capacitors, transformers and flywheels that can help stabilize power flows. However, in the bid to build AI computing capacity quickly not enough of these technologies are being used at new data centers, several of the people said. Batteries that have been installed for this purpose have sometimes needed to replaced within months or even weeks due to the high strain, according to the Uptime Institute and other people working with operators.

This problem is seen at data centers around the world, from the Middle East and Africa, to Europe and the US, said Villegas-Williamson of the Uptime Institute. 

Reliability Issues

These issues are already causing delays or curtailing operations – and therefore revenue – at some AI computing facilities. 

Extra time was baked into the schedule for engineering at a planned 2.67-gigawatt AI campus in West Texas, said Chris James, CEO of Joulent Inc., which is developing the facility with energy giant Chevron Corp. This means power delivery will begin in 2028 instead of 2027, he said. "Data centers and the power supply cannot be built independently," he said in a subsequent statement. "The load, generation, storage, controls and grid connection all affect one another. As AI infrastructure scales, the projects that perform best will be the ones that account for those interactions early, rather than trying to solve them after construction."

If essential equipment breaks down prematurely, “the financial consequence is not primarily replacing a pump or a breaker or some power component — it’s the the value of that expensive compute capacity not generating revenue because it’s offline,” said Jason Hoffman, chief strategy officer at data-center builder and operator Switch.

The cost of downtime in terms of lost revenue varies widely, with estimates ranging from thousands to hundreds of thousands of dollars per minute, depending on the type of facility and its workload.

Data centers are built on the assumption that, once they are online, they will operate around the clock 365 days a year, said a person involved in the financing of such facilities. In reality, some are seeing uptime closer to 80%, and unless resolved this could hit investors in certain projects in the next 12 to 24 months, the person said. 

Any issues with reliability add to wider concerns about the returns generated from hundreds of billions of dollars of planned AI investments. The rate of depreciation of another crucial piece of equipment at data centers, the GPU racks themselves, has raised questions about whether the industry can be as profitable as it promises. 

These problems with reliability also have the potential to destabilize the wider power grid. This sprawling web of high voltage lines, transformers and power plants requires constant calibration, something that has become more challenging with each passing year due to aging equipment, rising demand and extreme weather.

The expansion of intermittent wind and solar generation, which often result in big swings in supply from one hour to the next, are already a destabilizing force. AI data centers can put this volatility on steroids. 

“These loads are extremely dynamic or fluctuating, which causes grid instability and can lead to, if not corrected, potential blackouts or power outages,” said Sreemant Roy, a power-quality expert and global offer manager at Schneider Electric in Nashville, Tennessee. Of particular concern is a data center’s ability to cause sub-synchronous oscillations in the power flow, which can damage equipment connected to other parts of the network, he said. 

“That has made utility companies globally very worried,” Roy said. 

Within the last two years, the North American Electric Reliability Corp. — the top US regulatory body establishing standards aimed to keep the lights on — has repeatedly warned and issued alerts that data centers are one of the greatest risks to grid stability.

NERC evaluated more than 33 gigawatts of operational data centers in the US an found about three quarters of their load models “are insufficient to represent data-center dynamic behavior,” according to a September report. Earlier this year, the agency issued a rare level-three alert requiring big data centers to address these immediate risks and submit their responses by Aug. 3.

From top to bottom, the AI industry is aware of these issues and actively working on solutions. 

Nvidia started working more closely with power experts when it developed Blackwell GPUs, which were first released in 2024 and have become pervasive in data centers, said Dion Harris, senior director of hyperscale infrastructure solutions at the chipmaker. 

“We’re building the chips and processors” but also using them in the company’s own data centers, Harris said. Nvidia is working to make its deployments a lot smoother “both on the data-center build out, design and engineering phase, as well as on the power delivery.” 

Data-center users have deployed techniques to smooth out the power fluctuations of AI workloads by running side computations — essentially dummy math that isn’t part of the training process — to keep GPUs operating steadily. However, this approach has been criticized for wasting electricity at a time when power demand is surging. 

Last year, the National Laboratory of the Rockies near Denver, Colorado set up a test-bed on behalf of the US Department of Energy to figure out how to integrate AI safely onto the grid, said Martha Symko-Davies, the NLR’s program manager for the DOE’s office of electricity. 

The site has GPUs and power generation on site that developers can use to figure out if their setup can handle the variability of AI. One power supplier said they will use the facility to test batteries, software and other equipment intended to smooth out oscillations between the data center and grid that can cause damage on either side.

“We have the opportunity right now to get it right,” said Symko-Davies.

(Corrects story originally published Aug. 6 to remove reference to reliability of plant in 19th paragraph and add a fresh statement from Chris James.)

©2026 Bloomberg L.P.

No injuries were reported, the ministry said in a post on X, without providing details on the cause of the fire. Authorities “are completing necessary procedures to deal with the incident,” it added. Yemen’s Iran-backed Houthi rebel group subsequently claimed an attack on Jazan, the group’s military spokesperson said in a post, also on X. 

One crude storage tank at the refinery was impacted in the incident, according to a person familiar with the matter, who asked not to be identified because the information isn’t public. Large refineries like Jazan have multiple tanks to hold the oil that they ultimately process into fuel products like gasoline and diesel.  

The blaze would be at least the second in the past month at the Aramco facility, after satellite images showed fire at a tank in the 400,000 barrel-a-day complex in late July after the Houthis claimed to have attacked the plant. Jazan is located on the Red Sea in southwest Saudi Arabia.

The Houthis in July said they would blockade Saudi Arabia’s oil flows in response to a Saudi blockade of Yemeni territory. The group has also claimed sporadic attacks on Saudi energy facilities over that period. Aramco said last week that the Houthi threat was yet to materially impact the company’s oil output. 

(Updates with detail of damage in third paragraph.)

©2026 Bloomberg L.P.

Disruptions in the Strait of Hormuz and damage to Gulf refineries, as well as a wave of Ukrainian attacks on Russian plants have severely constrained exports from regions that together accounted for around a third of global diesel exports last year. 

Europe — which lacks processing capacity and relies most heavily on imports — is the most vulnerable area to a shortfall. Refiners in the US and Asia are running flat out, but with demand set to rise and stockpiles dwindling the situation will intensify in the coming months. Buyers typically stock up on diesel — a workhorse fuel that’s used in transport, industry and heating - before the temperature cools.

To make matters worse, there’s likely to be more consumption of diesel this year by some Asian power generators, who are turning to the fuel as they can’t get enough liquefied natural gas due to the war in the Middle East. Barring a breakthrough in either of the conflicts, Asian and US refiners will also probably cut down on diesel exports as winter approaches to meet growing demand in their own regions.

“Europe has a tremendous diesel problem,” said Eugene Lindell, head of refined products at consultancy FGE NexantECA. “It will get ugly in the sense that you will probably see extremely high flat prices” and this will feed through to freight costs, inflation and political pressure on governments, he said. 

Price gains are already running well ahead of oil. The ICE Futures Europe diesel price, a global benchmark, has risen almost 40% from a low on June 18, while Brent crude has climbed around 5% over the same period. Given diesel’s vital role in transport, construction and industry, there’s set to be a major inflationary impact, which could happen even if oil prices remain relatively stable.

Diesel stockpiles in key importing areas have fallen over the last few months, and are well below seasonal averages. European inventories are down the most, dropping around 30% since the end of March. 

Europe’s supply challenges are also being compounded by sanctions, according to Rachel Ziemba, an adjunct senior fellow at the Center for a New American Security, a Washington-based think tank. Restrictions on buying Russian refined products remain in place, while tighter European Union sanctions are increasingly limiting imports of fuels refined from Russian crude in third countries, she said. 

US refiners shipped a record amount of distillate fuels, a category dominated by diesel, last week, with much of it going to Europe. That’s unlikely to continue, though, as American demand rises. 

Little Relief Coming

“Gulf Coast refiners can’t keep exporting diesel to Northwest Europe indefinitely. They have their own fish to fry,” said Zameer Yusof, head of clean petroleum products analytics at Kpler. Coming up to the first quarter of next year, they would typically start channeling cargoes toward the East Coast states for the winter heating demand season, he said.

There’s also not likely to be much relief for Europe from Asia. Refiners there will have to meet their own region’s demand and may prioritize making kerosene, a heating fuel for countries including Japan, reducing the amount of diesel they can export, according to June Goh, a senior oil market analyst at Sparta Commodities.

While most traders say there are signs that Europe will face high diesel prices this winter, there are still several weeks before that buying begins. Much will depend on the temperatures later in the year, as well as whether high processing rates from the world’s oil refiners will be enough to take the sting out of the market between now and then. How much diesel China exports over the next few months will also be critical.

The situation highlights how regions that don’t have enough of their own refining capacity are especially vulnerable to global energy supply shocks. Europe is likely to be particularly hard hit relative to the other two major short markets, Africa and Latin America, which all compete for Atlantic Basin diesel, FGE’s Lindell said. 

“We never fully recovered from refining losses in the Middle East, and have also lost Russian capacity,” Goh said. “The misery of Europe is not an immediate crisis, but one down the line,” she said, referring to the diesel crunch.

©2026 Bloomberg L.P.

Trump announced a plan to impose tariffs and minimum prices on imported polysilicon used in semicondictors and solar panels. The levy comes a week after the Federal Communications Commission tightened curbs on inverters, another vital component of solar-powered energy.

Such protections can encourage the growth of domestic manufacturing — but as multiple economies have found over decades, restrictions often come at a financial and technological cost.

In the near term, curbs will drive up the price of solar panels in the US, a country that already pays more than double the global level thanks to years of tariffs on imports - and where Trump has pursued an anti-renewables policy during his second term.

If domestic manufacturing doesn’t establish a foothold quickly, it could put the US further behind in technological and power terms as the rest of the world presses ahead with cheap Chinese alternatives.

“The US is limiting this source of energy when the country so desperately needs more electricity to scale up high tech and AI,” said Li Shuo, director of the China Climate Hub at the Asia Society Policy Institute in Washington DC. “It looks so different from solar markets you’ll see anywhere else in the world.”

Trump’s directive, which takes effect Dec. 4, subjects derivatives including silicon wafers, photovoltaic cells and solar modules to 15% tariffs, and sets minimum price floors for each product that are higher than current costs in the US. 

For example, the new minimum price for imported solar modules will be 38 cents per watt. That compares to 27 cents per watt for modules currently shipped to the US, according to BloombergNEF, while the global average is 11 cents. 

Trump, who has pushed the revival of US industry since his first term in office, is also offering a carrot, however. If companies commit to starting construction of US factories to build the solar products by Jan. 20, 2029, they can avoid the higher costs.

“America cannot be reliant on foreign countries for the polysilicon that’s the key base material underpinning semiconductor and solar-power supply chains,” White House spokesman Kush Desai said in a statement. 

“President Trump pledged to safeguard our national and economic security, and in addition to reshoring critical manufacturing back to the United States, the Trump administration remains focused on unleashing America’s already-abundant sources of reliable and affordable energy for families and businesses, from natural gas to coal,” Desai said. 

Advocates for reshoring — effectively bringing home US manufacturing capability — have feted the news. According to Jon Toomey, president of the Coalition for a Prosperous America, global import barriers can put an end to circumvention, when companies set up facilities in third-party countries to avoid tariffs. 

The directive also applies all parts of the supply chain, which should help solve the problem of investing in downstream assembly plants only to find they are still dependent on other countries for upstream inputs.

“For the first time, the United States is protecting the entire solar supply chain with a single action,” Toomey said.

In the solar supply chain, ultra-refined polysilicon is shaped into rectangular ingots, which are in turn sliced into ultra-thin squares known as wafers. Those wafers are wired into cells and pieced together to form solar panels.

Building a complete chain from the ground up could have enormous benefits for the US, JPMorgan analysts including Mark Strouse said in a research note. It could “reduce pricing, reduce geopolitical risks, and improve long-term investor sentiment for the space.”

Green technology has been at the heart of global efforts to boost industrialization, including in the US. But the clean-energy race, accelerating along with the scramble for computing power, has increased the divide between the US and economies open to using Chinese technology — with one side benefiting from rock-bottom prices and existing, advanced technology, and the other seeking to build its own.

As recently as 2012, the US was the world’s largest producer of polysilicon. That year, President Barack Obama kicked off a tariff war over solar products that saw Beijing slap duties on US production. China revved up its domestic industry in response and now controls more than 95% of global output of the material.

The US has made some strides in recent years, and the country now has the world’s third-largest capacity for assembling solar modules. Still, it remains reliant on overseas suppliers for cells, wafers and polysilicon, meaning it could struggle to catch up even if US solar manufacturing gains a foothold, according to Youru Tan, a BloombergNEF solar analyst in Hong Kong.

“US production is much more expensive than China,” Tan said. “Plus, most US factories rely on equipment from China.”

Investors in new factories will have to weigh the support offered from Trump’s new directive against messages that have created uncertainty around long-term appetite for clean energy. 

So far in his second term, Trump’s policy moves also including ending tax credits for solar installations, eroding federal policies encouraging emission-free power and green energy permitting delays have done more to hold back the deployment of US renewables. 

And if the manufacturing boom fails to materialize, US solar developers will be hit by a steep hike in module prices, which will amount to about a 12% hike to the overall cost of solar systems, according to Guggenheim Securities analysts. The question of who ends up absorbing the increased costs, whether it’s developer profit margins or higher power tariffs, remains open. 

The AI boom should help users cope with short-term risks. Rising demand and higher-than-normal prices for competing sources of power will counter the extra cost, according to JPMorgan. Even while paying more than the rest of the world, solar remains among the cheapest options for electricity in the US, according to BloombergNEF data.

That doesn’t account for the opportunity cost of not embracing cut-price modules. Countries from Nigeria to Pakistan have taken advantage to radically reshape their undersupplied power grids in a matter of months. Sales of solar panels to the Philippines are booming. Even Europe, which is battling Chinese trade negotiators over other areas of clean tech like EVs and wind power, has all but waved the white flag when it comes to solar.

“Solar is arguably the fastest energy you can deploy, and in a free and open market it’s one of cheapest power sources,” said Asia Society Policy Institute’s Li. “The US is not going to enjoy those two advantages.”

©2026 Bloomberg L.P.

Brent traded above $83 a barrel, after surging almost 4% in the previous session. Futures have been highly sensitive to headlines around the terms and timing of a potential pact on the waterway that could restore millions of barrels of Middle Eastern supply.

Even as a resolution appeared more imminent, threats to shipping persisted. Abu Dhabi National Oil Co. said three of its vessels were attacked while transiting Hormuz this week. Prices were already up earlier following a report that Iran attacked “hostile targets” in the strait on Thursday following explosions near Qeshm Island in Hormuz, according to the semi-official Fars News Agency.

Crude pared some of the declines from earlier in the week as optimism faded that a full reopening of Hormuz would see an uptick in energy flows from the Persian Gulf. While US President Donald Trump reiterated that he thinks the war will end “pretty soon” and things are “moving along good” on the strait, the parties in the conflict appear to remain far apart on conditions for an accord.

Some Iranian politicians are advocating provisions that would bar US and Israeli vessels from the waterway and a fee structure, Fars reported. Such conditions would clash with Washington’s demand for free passage and a return to the pre-war status quo.

“Deals to reopen the Strait of Hormuz remain elusive, with investors teetering in the balance,” said Rob Haworth, senior investment strategy director at US Bank Wealth Management. “For now, traffic remains low and the path to a durable deal remains unclear.”

The conflict in the Middle East appears to be widening, with Iran-backed Houthis saying they conducted a “large-scale” attack against forces from Yemen’s Saudi-aligned government. The militant group earlier this week claimed to have attacked a Saudi tanker in the Gulf of Aden and threatened shipping in the northern Red Sea.

Elsewhere, Bureau of Labor Statistics data released Friday surprised investors after US employers unexpectedly trimmed jobs in July, and previous months were revised lower — a sign the labor market may be facing challenges after surprising resilience earlier this year.

©2026 Bloomberg L.P.

The proposed investment, in an equal joint venture with state-owned KazMunayGas National Co., would tap the undeveloped western part of the massive Kashagan oil reservoir, potentially producing as much as 600,000 barrels a day, the people said, asking not to be named because the information is private.

In talks with Kazakh officials, the US oil major has linked this potential investment to the resolution of disputes between the Kashagan partners and the government, the people said. This relates to the state’s claims for about $150 billion mostly for lost revenue during development delays, which is subject to international arbitration, and a $5 billion environmental fine.

While KazMunayGas has agreed with Exxon’s proposal, the plan would still need to get political approval, which is not certain, the people said.

Exxon, KazMunayGas and Kazakhstan’s Energy Ministry declined to comment for the story on Thursday. 

KazMunayGas Chairman Askhat Khassenov told reporters in Astana on Friday that “this is inaccurate information,” and “we at KazMunayGas do not confirm what was reported by Bloomberg,” according to Kursiv media.

When the Kashagan deposit was found in 2000 it was the largest oil discovery in decades. Italy’s Eni SpA, the field’s operator at the time, expected it to eventually pump as much as 1.5 million barrels a day, but there were numerous delays and cost overruns during the complicated development process.

Output from the developed eastern portion of Kashagan is currently about 450,000 barrels a day. The North Caspian Operating Co., the joint venture that operates the project, expects to boost production to about 500,000 barrels a day this year and as much as 710,000 barrels a day by 2031.

About 1 billion barrels out of an estimated 16 billion barrels of total recoverable reserves have been extracted from Kashagan in its first decade in operation, according to the government. Exxon is seeking to unlock about 10 billion of these barrels from the western Kashagan development, according to people familiar with the matter. Bloomberg first reported the company’s initial proposal last year. 

In Exxon’s plan, other oil majors that are currently partners in Kashagan would be offered minority stakes in the new joint venture, the people said. Companies that joined the new development would be released from the claims related to the sulfur fine when the venture was formed, and from remaining claims at the final investment decision, the people said.

Any company that declined the offer would be released by Kazakhstan from the claims, provided they do not dispute the new joint venture’s right to develop the western portion of the field, the people said. These firms also wouldn’t be able to extend their part of the existing license for eastern Kashagan after it expires in 2041, the people said. 

The development concept for an Exxon-led project to commercialize western Kashagan may cost $250 million, the people said. The front-end engineering and design would require further spending of about $2 billion from 2028, they said, adding that the plan implies start of development after the final investment decision in 2030.

Exxon is one of the major partners in NCOC alongside Eni, Shell Plc, TotalEnergies SE, KazMunayGas, China National Petroleum Corp. and Inpex Corp.

Eni has separately approached Kazakhstan’s government sending signals it wishes with some other unnamed partners to develop western Kashagan’s oil resources, the people said.

Shell, TotalEnergies, Inpex and NCOC declined to comment. CNPC didn’t respond to a request for comment. Eni didn’t immediately respond to a request for comment. 

(Adds KazMunayGas chairman’s comment in fifth paragraph.)

©2026 Bloomberg L.P.

Pipeline and seaborne flows rose to 35.73 million tons in July, according to customs data released Friday. That’s up 22% from June, when shipments hit the lowest since October 2016. The volume for last month is equivalent to 8.45 million barrels a day, well below the pace in the same period last year.

Oil flows from the Gulf had ramped up following an interim peace deal between the US and Iran in June, but a recent escalation of hostilities has snarled Hormuz traffic once again. There’s also been a spillover to the Red Sea, crimping exports from Saudi Arabia, one of the Asian nation’s top suppliers. Beijing has been snapping up cargoes from Russia to fill the gaps.

Meanwhile, coal imports totaled 42.73 million tons in July, up 20% on an annual basis, after a deadly accident in Shanxi province in late May crimped domestic production. Natural gas imports fell 0.9% on-year, as liquefied supplies from the Middle East continued to be impacted by the war.

©2026 Bloomberg L.P.

Beyond the separate budget lines, they are genuinely separate worlds within organisations: separate teams with different skills, tools, and incentive structures, following separate financial treatments and accounting logics.

This model became standard practice because it matched the industrial era it served: large capital projects built once, handed over cleanly, and then run steadily for decades. However, as GCC Vision programmes place unprecedented pressure on capital projects to convert investment into durable industrial capacity, it is important to understand its weaknesses, the blind spots it can create and the need to adapt the model to the region’s new industrial age.

Delivering plants that deliver value

The problems caused by the divide between projects and assets in asset-intensive industries have been evident and documented for some time. In fact, leading actors in the region, such as national oil companies, have challenged that model in the past decade, through stronger integration mandates, shared platforms, and digital twins that connect projects to assets. 

Here are the three main places the classic model breaks:

First, the divide rewards project delivery over value, leading to facilities failing to achieve the expected return on investment even a decade after commissioning. The average upstream oil and gas project fails to return as much as 40% of its value estimated at sanction, according to research by the Independent Project Analysis (IPA).  A similar gap has been found in other key industries for GCC ambitions, such as metals and mining.

Second, the delivery-led model reduces handover to a compliance exercise. Success is measured by whether large volumes of information have been transferred, usually through PDFs, emails, document registers, and close-out packages. That may satisfy a contractual requirement, but it does not necessarily prepare an operating team to run, maintain, and improve the asset. 

Recent research by consultancy Hatch on project ramp-up performance identifies a consistent pattern among projects that do achieve their expected value: strong attention to the quality of information handed over, not just the quantity; integrated teams that include operations staff during construction, not just at handover; and technology used to create genuine understanding of how the plant works; not just a document repository. 

What does that look like in practice? What we see more and more in successful projects across the Middle East is a common digital backbone connecting design, construction, and operations. It is often built around a digital twin platform implemented during construction, with an EAM platform ensuring that maintenance plans are live and accurate from day one of operations. The thread of intelligence that runs from engineering model to operational asset is what separates successful ramp-ups from those that struggle for years.

STOs: the risk of blind spots and siloed tools

Third, the divide is most damaging when capital projects happen inside an existing plant: not to build something new, but to transform something already running.

The standard model assumes a clean sequence: design, build, commission, operate. However, modern plants evolve continuously through upgrades, retrofits, and compliance modifications while remaining in operation.

Across the GCC this decade, major refineries and petrochemical facilities have undertaken precisely such transformations: shifting toward higher-value product slates, integrating new process units, meeting cleaner fuel standards, or otherwise altering the asset mid-life, long after the original handover occurred.

Even without transformation, the challenges caused by fragmented data and disconnected teams across the project/assets fault line are already visible during Shutdown, Turnaround, and Outage (STO) events that see maintenance work and modernisation happen side by side.

Without end-to-end supervision and a common platform such as an Enterprise Project Performance tool to coordinate work, these moments are prone to miscoordination between teams and scope creep, with predictable results: according to BCG, two-thirds of STOs fail to achieve their objectives, incurring high direct costs and significantly impacting long-term value.

Why this matters more in the Middle East, and why it matters now

This challenge exists across asset-intensive industries globally. But two converging forces make it particularly consequential for the Middle East today.

First, the scale of investment is unprecedented. Energy investment in the Middle East reached approximately $175 billion in 2024. Infrastructure construction is forecast to grow from $204 billion in 2025 to $267 billion by 2030. At that scale of investment, the value that can be created by better transitions from project to plant cannot be overstated.

Second, the reconstruction context creates a categorically different risk environment. Across the region, dozens of major industrial facilities, including refineries, petrochemical complexes, power generation assets, and water infrastructure, have sustained damage requiring reconstruction.

What makes this categorically different from a standard capital project is that reconstruction does not happen in a clean, sequential environment. It happens in parallel with ongoing operations: project teams and operations teams must work side by side on the same physical asset, often sharing the same infrastructure, the same utilities, and the same safety perimeter.

The CAPEX-OPEX divide, already a structural inefficiency in normal conditions, becomes an acute operational risk when the two worlds are literally co-located and interdependent.

The triple continuity resilient organisations need

The disconnect between CAPEX and OPEX is ultimately a problem of continuity: of knowledge, data, and people. Closing it requires different capabilities and accountabilities than the ones that created it.

First, organisations need the ability to carry engineering intent forward across the lifecycle, so that what was designed and built remains accessible to those who must operate and maintain it. Successful operators will connect fragmented data across design, construction and operations into a unified foundation - not as a one-time integration exercise, but as an ongoing discipline.

With that foundation in place, operators gain capabilities that matter in a more volatile environment. They can anticipate risk with fewer blind spots, assess the impact of change, reconfigure operations, and optimise performance with greater confidence than those who treat projects and assets as separate worlds.

Just as importantly, continuity of data and process supports continuity of accountability. Rather than one team being accountable for project delivery, another for asset performance and value falling in between, organisations can create a shared basis for value across the lifecycle.

That is precisely what the region needs to deliver on its ambitions for economic leadership, diversification, and infrastructure fit for the future. GCC countries are doing this in a period that does not tolerate inefficient practices and value that takes a decade to materialise. That means reducing the blind spots and silos of the past, and the CAPEX/OPEX divide is among the most consequential.

This reinforces a fundamental principle: the future of energy must be guided by the Energy Trilemma. Achieving this requires secure and reliable energy supplies, affordable energy that supports long-term economic competitiveness, and continued progress toward lower-carbon solutions. These priorities are not competing objectives — they must advance together.

ASEAN’s opportunity in the energy transition

While every region faces the Energy Trilemma, ASEAN’s challenge is unique. Unlike many other regions, ASEAN’s demand for natural gas continues to grow faster than domestic production as economies expand and electricity demand rises.

This widening supply-demand gap makes regional cooperation not simply beneficial, but essential. This challenge also presents a strategic opportunity. ASEAN has already developed one of its greatest strengths: an increasingly interconnected regional gas network, supported by cross-border gas pipelines and LNG infrastructure. By leveraging this connectivity, countries can share supply, strengthen system resilience, and collectively enhance regional energy security.

Energy security should therefore no longer be viewed solely as a national responsibility. For ASEAN, it is increasingly a shared regional responsibility built on interconnected energy infrastructure, trusted partnerships, and collective resilience.

Advancing the energy transition responsibly

Hydrocarbons will continue to play an important role in the global energy mix for decades to come. The challenge is therefore not to eliminate fossil fuels overnight, but to produce and use them more responsibly while accelerating practical decarbonisation.

At PTT, we are advancing an integrated portfolio of methane emissions reduction, carbon capture and storage (CCS), hydrogen development, lower-carbon fuels, and nature-based solutions to reduce emissions while maintaining energy security, affordability, competitiveness, and sustainability.

Natural gas and LNG, as destination fuels, will continue to play a strategic role in enabling a balanced and practical energy transition. Within an integrated energy system, LNG serves as a strategic enabler that strengthens long-term energy security while supporting an orderly transition toward a lower-carbon future.

Collaboration will shape the future

The future of energy will not be determined by a single technology or a single fuel. It will be shaped by stronger partnerships among governments, industries, and communities, together with responsible investment and continuous innovation.

Gastech demonstrates that meaningful progress in the energy transition is achieved not through individual action, but through stronger international collaboration.

At PTT, we believe the future of energy must be guided by the Energy Trilemma — balancing energy security, affordability and competitiveness, and sustainability. These are not competing priorities, but mutually reinforcing objectives that must advance together.

We firmly believe natural gas and LNG are destination fuels that will continue to play a vital role for decades to come. The challenge is not to move away from fossil fuels overnight, but to produce and use them more responsibly by accelerating practical decarbonisation solutions.

Together, we can deliver the Energy Trilemma, strengthening energy security, enhancing affordability and competitiveness, and advancing sustainability through trusted partnerships, responsible investment, and practical innovation.

The AI boom, fueled in part by the success of DeepSeek, has prompted more Chinese firms to use Hong Kong as a springboard to test models and expand overseas. Deals for digital infrastructure accelerated in the last quarter, driving up prices for data center capacity on a per-kilowatt basis, according to Structure Research, a data center consultancy. 

Chinese hyperscalers, including Alibaba Group Holding Ltd. and Tencent Holdings Ltd., are increasing their capacity in the city, said Jason Zhou, senior analyst with the research firm. Some Chinese independent boutique AI firms are also entering the market to expand their overseas presence, he added.

“I would say 90% Chinese and 10% Western” for data center leasing deals in the past few months in Hong Kong, Zhou said. “It’s almost entirely a Chinese market now.” 

AI usage has drastically increased tech giants’ demand for capacity, as opposed to the lower requirements needed for cloud services in the past, he said. “Chinese players are very open to deploy inference AI in Hong Kong, so they need to buy a lot of capacity.”

As a result, wholesale pricing bands offered to hyperscalers have increased by 90% from the beginning of the year, one of the largest rises in Asia. Wholesale prices are now as much as $180 per kilowatt, still far behind the $300-$490 range in Singapore, where supply is constrained, according to Structure Research.

For these fast-growing tech firms, Hong Kong offers advantages over the mainland. Its free flow of data and direct access to the international market stands in contrast to China’s tightly controlled internet environment. 

“If you want to train some of your AIs and compete in an international space, Hong Kong is a nice cocoon to test some of your AIs and see how you fare,” said Zhou.

Major data center operators including SUNeVision Holdings Ltd., DayOne Data Centers Ltd. and Equinix Inc. are among those benefiting from the AI boom and raising billions of dollars in debt to fund their expansion plans.

Still, financial firms remain a key source of demand for digital infrastructure in the business hub.

“It’s important not to ignore the size of the customer base here in terms of traditional finance — it’s big,” said Dauwood Malik, managing partner in Hong Kong at law firm Clifford Chance, who has worked on data center deals. The rise of algorithm trading also results in higher demand for capacity, he added.

In a recently opened HK$1 billion ($127 million) facility by Equinix, financial services, together with tech companies, make up most of the demand.

For finance customers who care about latency, Hong Kong’s location near major markets like Singapore and Tokyo makes it hard to miss, said Simon Lockington, senior director at Equinix. 

“Just from a geolocation point of view, Hong Kong really has some advantages, plus the momentum and weight of being a financial hub is too big to ignore,” Lockington said.

©2026 Bloomberg L.P.

The US and global benchmark futures contracts climbed more than 1% in post-settlement trading Thursday. Those moves followed the first gain in three days for West Texas Intermediate as signs mounted that a potential Iran-Oman deal won’t lead to a full-fledged resumption of oil shipments through the strait.

The contracts earlier surged to intraday highs after Iranian media reports that Tehran will seek to bar US and Israeli vessels from the waterway and require compensation from hostile countries before they’re allowed to use it. Traders interpreted the report to mean Gulf exports will remain restricted in the near term. 

European natural gas futures rocketed as much as 12% on the Fars news agency report of strikes as traders priced in increased risks to natural gas tankers.

Even before the latest developments, the outlook for an agreement had been growing murkier. Iran said a pact on proposed shipping lanes was in the final stages. But the country has insisted that the US isn’t part of the agreement with Oman and hinted a normalization of the strait will depend on the lifting of an American blockade on Iranian ports. 

“Crude traders remain focused” on the status of a potential pact, said Dennis Kissler, senior vice president for trading at BOK Financial Securities Inc. “The longer the delays, the more prices will fade back to the upside.”

The White House didn’t respond to a request for comment on the announcement of a pending deal. US President Donald Trump said at a rally in Las Vegas on Wednesday evening that the US is talking to Tehran and he will “see what happens” in negotiations.

Even so, prices are holding most of this week’s slump after Iran and the US indicated a resolution was close for shipping through the crucial energy chokepoint. A return to normalized flows through Hormuz would unlock millions of barrels of oil shipments disrupted by the now five-month-old conflict.

Other risks also emerged, reinforcing traders’ reluctance to fully unwind long positions for fear of being wrong-footed by a sudden escalation. In a sign of persistent threats to shipping in the Middle East, the UK Navy reported on Thursday a tanker hearing two explosions while transiting the strait. 

Earlier, Iran-backed Houthi militants in Yemen said they targeted a Saudi oil tanker in the Gulf of Aden. 

Elsewhere, oil loadings at the key Caspian Pipeline Consortium terminal on the Black Sea resumed after being halted by the risk of drone attacks nearby.

©2026 Bloomberg L.P.

In addition to RWE, the Trump administration has reached agreements with five other developers, including TotalEnergies SE, to surrender offshore wind leases and redirect reimbursed funds to fossil fuel projects and other investments favored by President Donald Trump. More than 20 leases valued at nearly $2 billion remain outstanding, according to estimates from ClearView Energy Partners, making more agreements likely in the coming months.

“The Trump administration is pulling all the levers it can to constrain the offshore wind industry to the few projects already under construction or in service,” said Timothy Fox, an analyst at ClearView Energy. “And they seem likely to succeed.”

Since returning to office last year, Trump has followed through on his campaign pledge to block wind power, a source of renewable energy he has derided for years. He issued an executive order that halted leases and project reviews for wind on federal lands and waters, a move that was declared illegal by a federal judge in December.

Some of the announced lease buybacks involved projects that were already struggling to advance, said Seth Kaplan, a vice president at Grid Strategies LLC. More than 15 gigawatts of offshore wind capacity across 16 projects was withdrawn from grid operators’ interconnection queues last year alone, according to the consulting firm.

“Companies saw the way things were going and made decisions accordingly,” Kaplan said. “If a developer sees the handwriting on the wall about where things are going they will pullback on spending.”

The administration’s latest strategy appears to be paying companies to walk away from their offshore wind leases for projects that haven’t started yet.

“Rather than waiting years for the projects to materialize, the Trump administration is prioritizing investments in existing infrastructure and functioning supply chains that can create jobs now and deliver economic benefits faster,” said an Interior Department spokesperson.

In March, the department agreed to pay TotalEnergies and its partners almost $1 billion to redirect funds from wind farms off the coasts of New York, New Jersey and North Carolina to oil and natural gas investments in the US.

In return for focusing on fossil fuels, the US will reimburse TotalEnergies “dollar-for-dollar, up to the amount they paid in lease purchases for offshore wind,” according to the Interior Department’s statement.

New York along with six other Northeastern states filed suit in June against the Trump administration to challenge the TotalEnergies settlement.

TotalEnergies Chief Executive Officer Patrick Pouyanné said in the statement that considering “the development of offshore wind projects isn’t in the country’s interest, we have decided to renounce offshore wind development in the United States.”

California said in June it plans to challenge the administration’s agreement to pay $120 million to Golden State Wind for a lease off the state’s coast with the funds to be reinvested in fossil-fuel projects. Golden State Wind said it has decided not to pursue any new offshore wind projects in the US.

“The real question is what happens to the progress that was made before Trump came into office,” Fox said. “After he leaves, there may be few, if any, projects to follow.”

©2026 Bloomberg L.P.

“We’re bringing our own power,” Riley Trettel, who oversees energy and data center development for SpaceX, said Wednesday during a public meeting in Grimes County, Texas. “We’re going to be building natural gas fired power plants, and we’re going to be building very large battery arrays in order to store energy.”

The comments offer fresh insight into the plans by Elon Musk’s two biggest companies for the new plant, known as Terafab. SpaceX and Tesla on Thursday confirmed that the chip factory will be built in Grimes County, with an initial phase expected to cost $16.8 billion.

The project, which is expected to create 3,000 new jobs, will receive a Texas Enterprise Fund grant of $30 million. The 100 million-square-foot facility will be constructed in phases on a footprint of roughly 3,000 acres, but SpaceX has over 13,000 acres currently under its control.

Musk, the chief executive officer of both SpaceX and Tesla, has said the semiconductor industry is moving too slowly to keep up with the amount of chips needed for his initiatives and that of the broader tech industry, and he has warned of geopolitical risks. 

Intel Corp. joined the project in April and is expected to lend its expertise in designing, fabricating and packaging. Musk expects the facility to make two kinds of chips: one for use in Tesla’s Optimus humanoid robots and electric cars, and another designed for use in space. 

Surging power demand from data centers and new factories has driven demand for new gas plants, and Musk has long been a fan of vertical integration. 

Musk and his companies are not strangers to the Texas energy market. Tesla makes utility-scale battery energy storage devices known as Megapacks, and has a Megapack factory west of Houston.

“We are going to be moving nearly immediately to get going on the project,” Trettel said. “We need to get our civil work started. We need to start to get foundations in place, and we’re going to get cracking.”

©2026 Bloomberg L.P.

Supertanker Romania Prosperity appeared in the Gulf of Oman on Tuesday after switching off its transponder in late July, laden with crude from the UAE’s Abu Dhabi National Oil Co., according to Kpler. It’s one of dozens of such exits from the Gulf as the state-run producer embarks on a novel marketing drive.

Individual ships spotted on ship-tracking databases give clues about the trade, but the real number is likely larger due to these dark crossings. Since the start of June, Adnoc has sold over 130 million barrels in an unprecedented seven tenders, according to traders familiar with the matter, asking not to be identified as they’re not authorized to speak publicly.

That’s equivalent to more than a month of crude demand from Japan, Asia’s third-largest consumer. 

Workarounds like Adnoc’s have been vital to limiting losses from the conflict and have helped keep oil markets in check, countering expectations of far more acute shortages and price spikes. The global benchmark, Brent, was trading around $79 a barrel on Thursday.

The UAE has been so successful in getting its crude out of the Gulf that Vortexa estimates it was the only Middle Eastern producer to reach pre-war levels of seaborne exports in June and July. Most of those barrels have been picked up by Asian refiners, including in Japan and China.

That milestone was achieved even after the US ramped up a bombing campaign against Iran last month, and the Islamic Republic attacked more ships around the strait. The practice of shuttling barrels out of the gulf — dark crossings that supply waiting vessels outside Hormuz — has picked up again after those strikes, people familiar with the matter said last week. 

A comprehensive deal to reopen the strait — should one be reached — would likely boost the volume of oil leaving the Gulf, but the stop-start nature of negotiations over recent months means analysts and traders expect shuttling to continue in some form. 

An Adnoc spokesperson said the company doesn’t comment on positions, movements or routing of its vessels as a matter of policy.

“Adnoc’s barrels have helped stabilize supply into Asia,” said June Goh, senior oil market analyst for Sparta Commodities SA. Refineries in the region can’t easily replace the medium-sour crude that’s typically produced in the Middle East, making any oil exiting the gulf so essential, she added.

It’s not just oil the UAE has managed to ferry out successfully, the producer has also been getting vital supplies of liquefied natural gas to global customers. An Adnoc tanker called the Mubaraz loaded with LNG recently appeared near India after turning off its transponder inside the gulf last month.

The UAE splurged on logistics to make its workaround possible. The nation snapped up tankers at exorbitant rates to embark on daring shuttle runs through Hormuz. Iraq and Kuwait have also been able to ferry out some supplies, but volumes have been smaller.

Once tankers carrying UAE crude exit Hormuz, the cargo is typically transferred to another vessel in the Gulf of Oman before being exported to buyers around the world. At times, this process has been delayed by escalating hostilities in the region. 

The UAE has also been able to make use of a pipeline stretching across the country to get extra barrels out, bypassing Hormuz.

Adnoc has made the most of its dominant position. When traders submitted crude bids last month below the regional Dubai oil benchmark after wider prices fell, the company told some of them to raise their offers. 

However, that has not advanced the UAE’s efforts to build a benchmark futures contract around its flagship crude, Murban.

Saudi Arabia has also kept large volumes of its crude flowing during the war by piping oil to its Red Sea port of Yanbu, allowing the kingdom to bypass Hormuz. Recent threats and attacks from Iran-backed Houthi militants have disrupted that trade, according to Xavier Tang, senior market analyst for Vortexa, potentially prompting refiners to lean even more on the UAE for barrels.

©2026 Bloomberg L.P.

The Chinese company has began operation of the Galaxy Campus project in Ulanqab — a city about 350 kilometers (217 miles) northwest of Beijing with abundant wind power resources, it said in a statement. The initial 120-megawatt phase has already been allocated to two local tech giants, with plans to eventually scale the project to 2 gigawatts, which would make it one of the largest in China, the company said.

Envision’s push is part of a broader race among Chinese firms to secure a foothold in the booming data center sector. The segment has to date been dominated by telecom operators, specialized developers, and internet giants including Tencent Holdings Ltd., Alibaba Group Holding Ltd. and China United Network Communications Ltd., according to BloombergNEF.

AI company DeepSeek is also planning a 1 gigawatt data center in Ulanqab, according to people familiar with the matter. The city’s cold climate, with an average annual temperature of 4C (39F), helps reduce the energy required to cool power-hungry AI servers. Z.AI, formerly Zhipu, is also working on a 1 gigawatt project that it plans to fill with only domestically made chips.

Envision will benefit from its wide renewables portfolio, which ranges from wind turbine manufacturing to battery production. That will give it a unique advantage, especially after the government required four-fifths of data center power to come from green electricity. 

The Galaxy project is a cornerstone of Envision’s ambitions to develop 5 gigawatts of AI data center capacity globally by 2030. It will get 80% of its power from the company’s nearby wind farms through dedicated transmission cables, it said. Battery storage will be used as backup — stepping away from the traditional data center model of relying on diesel generators.

Envision will provide the power infrastructure and supporting system, but won’t handle the actual data processing. Tech companies will effectively act as tenants, leasing the facilities and installing their own chip clusters, the energy firm said.

©2026 Bloomberg L.P.

If there is one lesson from the past decade, it is that the global LNG industry has repeatedly been tested and proven its value in delivering flexible and reliable energy worldwide. Whether during the COVID-19 pandemic, Europe’s gas crisis following Russia’s invasion of Ukraine, or this year’s Middle East crisis, the LNG industry has faced immense challenges over the course of less than a decade. Yet each shock has helped to build greater industry resilience and flexibility to meet the next one.

This year marks the 10th edition of Shell’s LNG Outlook, an annual report compiled using data from third party providers. Every year it analyses where the market is heading and this anniversary gave us the opportunity to assess how far it has come. The numbers tell their own story. Since 2016, global LNG trade has expanded by around 60%, rising from 264 million tonnes to more than 420 million tonnes in 2025. The number of importing countries has grown from 36 to 49, while LNG-fuelled vessels in operation have increased from just 77 ships to more than 900.

A global energy shock

The disruption to the Strait of Hormuz removed around one-fifth of the world’s monthly LNG supply at its peak. The global LNG market was quick to adapt. More supply from North America, stronger performance from existing facilities, rerouted cargoes, and deferred maintenance helped cushion the impact on the supply side. On the demand side, a combination of fuel switching, slowing imports, and gas storage withdrawals helped to balance the market.

While prices were higher, the market response has been significantly more measured than during previous crises, showing its ability to respond to disruptions and move energy to where it is needed most. Over the long term, the LNG Outlook forecasts that global LNG demand could grow by around 65% by 2050, nearly 700 million tonnes per year as countries continue to prioritise the energy security gas offers. 

Asia is at the heart of that growth story. As economies develop and urbanise across South and Southeast Asia, demand for power and industry will continue to rise. By 2050, these regions are expected to account for around 40% of global LNG imports as countries turn more to gas to support economic growth while reducing dependence on more emissions-intensive fuels.

The demand forecast for LNG in Asia is also supported by declining domestic gas production, creating a structural supply gap that LNG is expected to fill. By 2050, without further exploration and production, that gap could approach 300 million tonnes annually. At the same time, LNG’s role is expanding beyond its traditional markets. In the shipping industry, more than 900 LNG-fuelled vessels are now in operation, with hundreds more on order.

Significantly, demand for LNG bunkering is forecast to increase sevenfold by 2035 to around 27 million tonnes per year, which is more LNG than India imported in 2025. Around 180 million tonnes per year of new LNG supply is expected to enter the market by 2030, improving the availability and affordability of gas. 

Progressing the energy transition 

Not to be overlooked as a catalyst for continued growth is LNG’s wide-ranging role in the transition to a lower carbon energy system. Switching from coal to gas has had a notable effect on reducing CO₂ emissions globally as it emits about 50% less carbon than coal when used to produce electricity. And the trend continues. In some places around the world, new gas-fired power plants are replacing coal-fired ones. Gas is an increasingly important partner to renewable energy and the rapid roll out of renewable energy projects in recent years has highlighted this trend.

When the wind doesn’t blow or the sun doesn’t shine, gas-fired power plants can ramp up quickly to play a crucial role in maintaining a reliable power supply to meet demand. While the roll out of renewable energy has been rapid in recent years, it still faces limitations, especially in meeting the needs of hard-to-abate industries. As an industry, we need to make more progress on curbing methane emissions, bringing down the carbon intensity of the natural gas and LNG value chain through innovation and incremental blending of LNG with bio-LNG, to offer a pathway to net-zero emissions.

As a trusted LNG supplier to both long-established and new customers, Shell’s core focus is on continuing to expand our global LNG portfolio and capability to deliver cargoes around the world to best support our customers. Through recent investments and acquisitions, namely Singapore-based Pavilion Energy, LNG Canada, the Ruwais LNG project in the United Arab Emirates and the Manatee gas field off the coast of Trinidad and Tobago, Shell is working to bolster LNG supply volumes in the years to come and helping to meet the energy security needs for people around the world.

Nigerian Upstream Petroleum Regulatory Commission (NUPRC) Chief Executive Oritsemeyiwa Eyesan said the projects are expected to come online between 2026 and 2030, supporting higher oil and gas output, job creation, and infrastructure development.

Speaking at an event in Lagos, Eyesan said, “Since 2024, the NUPRC has approved over $57 billion in Field Development Plans, some of which have already translated into Final Investment Decisions.”

Nigeria ramps up crude production

Eyesan said the planned offshore developments could generate between $30 billion and $50 billion in investment. 

“Beyond increasing production, these investments will create jobs, expand infrastructure, strengthen energy security, and reinforce Nigeria's position as a leading global upstream investment destination,” Eyesan said.

The announcement comes as Nigeria pursues a target of raising crude oil production to 3 million barrels per day by 2030 through a combination of new project approvals, exploration activity, and reforms aimed at attracting fresh capital.

Alongside advancing existing discoveries, the regulator said Nigeria is maintaining a strong exploration pipeline through successive licensing rounds designed to unlock prospective oil and gas acreage.

According to the NUPRC, 31 companies were awarded 37 oil and gas blocks during the 2025 Licensing Round following what it described as a transparent, data-driven evaluation process. Preparations for the 2026 Licensing Round are already underway.

“With preparations already underway for the 2026 Licensing Round, Nigeria is demonstrating that investment certainty is no longer an aspiration; it is becoming an enduring feature of our regulatory framework,” Eyesan said.

Expanding oil and gas infrastructure 

Eyesan also outlined measures to address infrastructure challenges that have constrained upstream development, including expanding gas gathering systems, processing facilities, pipelines, and export infrastructure.

“We are expanding gas gathering systems, processing facilities, pipelines and export infrastructure, while promoting shared facilities, open access, third party access and field tiebacks to reduce costs, speed up project delivery, maximise the use of existing infrastructure, and help bring stranded oil and gas resources into production,” she added. 

The NUPRC said it is promoting shared facilities, open-access infrastructure, third-party access arrangements, and field tiebacks to help reduce development costs and accelerate project timelines.

Eyesan added that greater collaboration among government agencies, operators, host communities, and private-sector partners, together with the implementation of the Host Community Development Trust, has improved the protection of critical energy infrastructure and strengthened the resilience of Nigeria's upstream sector.

President Cyril Ramaphosa has endorsed the creation of an independent transmission system operator, or TSO, outside Eskom as part of efforts to open the electricity market to greater private-sector participation. But carving out the utility’s most profitable division has raised concerns about Eskom’s long-term financial viability and the treatment of government guarantees backing its debt. 

“The transaction is being carefully designed to ensure that Eskom is left no worse off, and that Eskom remains sustainable,” Treasury Director General Duncan Pieterse said in an interview in Cape Town on Tuesday. “The TSO itself also has to be sustainable.”

Pieterse, who Ramaphosa this year appointed to head a team in charge of Eskom’s restructuring, faces a complex balancing act in ensuring that all the company’s units remain viable after the split, and that Eskom’s bondholders accept the changes. 

“There are ways of designing this transaction to achieve all of that,” he said. “We have no interest in running a process where lenders are not brought along.”

The process will require engaging the market and careful planning with transparency playing a key role, said Raphi Rootshtain, lead portfolio manager at Otto1890 Asset Management in Johannesburg.

“There’s a whole lot of covenants that exist currently and agreements in place with current existing debt,” he said by phone on Wednesday. “From what I understand, there will be need to somehow restructure that debt in order to be able to move ahead.”

The government has guaranteed about 330 billion rand ($20 billion) of Eskom’s debt, according to Pieterse.

Eskom itself this week warned that the process will have to be managed carefully as establishing the transmission operator as a separate business would entail a material event — a significant development that fundamentally alters the risk profile of its credit.

Pieterse declined to say whether Eskom or the government may need to secure bondholder consent for the split, saying the first step would be hiring a transaction adviser.

“Of course the process will be managed properly,” he said. 

©2026 Bloomberg L.P.

The New Delhi-based explorer’s net income more than doubled in the quarter ended June to 170.34 billion rupees ($1.8 billion), according to a stock exchange filing. That compares with 152.67 billion rupees average of estimates compiled by Bloomberg. Revenue jumped 45% from a year earlier to 464.60 billion rupees.

The state-run oil and gas producer’s earnings mirror bumper profits posted by global energy supermajors as they reaped gains from the biggest supply disruption in history caused by the US-Iran war. Benchmark Brent crude prices in the June quarter averaged almost 50% higher year-on-year as the US-Iran war choked most of the Gulf flows.

Stronger earnings are crucial for ONGC as it needs to ramp up spending on high-risk exploration to help reverse India’s declining domestic oil and gas production. The company is central to the government’s efforts to curb India’s growing reliance on imports, which meet almost 90% of oil demand and about half of gas consumption. Acute shortages of cooking fuel during the Middle East war had further exposed that vulnerability.

The firm, which accounts for two-thirds of India’s oil and over half of gas output, has been struggling to stem the decline in production from its ageing fields, while new assets have been slow to contribute. ONGC’s standalone oil and gas production declined 3.4% on year to 9.4 million tons of oil and equivalent gas.

ONGC is investing more than 400 billion rupees ($4.2 billion) in projects across its Western Offshore assets to reverse the production decline, it said in a statement. The company has also hired BP Plc as a technical services partner to boost output from these fields.

“We expect their benefits to progressively materialize from FY 2027-28 onwards, leading to enhanced production, improved recovery, and sustained value creation in the years ahead,” ONGC said.

The company’s earnings on every barrel of crude oil sold in April-June was 50.4% higher than a year earlier. Earnings from gas produced from old legacy fields were up 5.4% but that from new deepwater acreage rose 61.5% on year.

©2026 Bloomberg L.P.

The platform is powered by SLB’s DrillOps intelligent well delivery and insights solutions. It provides a unified environment to monitor, analyse, and manage drilling activities across ADNOC’s onshore and offshore assets. It can also process large volumes of real-time drilling data through automated dashboards and AI-driven analytics. 

By consolidating multiple existing tools into a single system, ADNOC said the RTOC can cut engineering effort by 30-40%. This enables engineers to oversee two to three times more rigs simultaneously.

Reducing downtime 

DrillOps combines operational data, advanced analytics, and AI-driven insights, meaning that tasks that previously took days can now be completed within hours, while some analytical tasks have been reduced from a full day to just a few minutes.

The system also helps identify potential operational issues before they escalate. According to ADNOC, this can shorten incident response times by four to 12 hours and help avoid up to two days of rig downtime.

“The Real-Time Operations Center creates value across ADNOC's drilling operations every minute by embedding AI into the heart of our drilling operations, helping our teams make faster, smarter decisions at scale,” said Musabbeh Al Kaabi, CEO of ADNOC Upstream.

A “sovereign cloud environment”

ADNOC said that with this implementation, it is putting intelligence to work across its operations, incorporating AI into fundamental workflows, and driving the shift to more autonomous and efficient operations.

“Built securely here in the UAE, it is further proof that ADNOC is moving from AI ambition to real-world impact as we become the world's most AI-enabled energy company,” Al Kaabi said.

The platform, which is deployed across ADNOC Drilling’s fleet and supporting ADNOC Onshore and ADNOC Offshore, gives business, asset, and drilling teams a live view of operations, improving coordination, and risk management across the company’s portfolio.

“DrillOps transforms real-time drilling data into operational intelligence that helps teams make faster, more informed decisions,” said Rakesh Jaggi, President, Digital, SLB.

“Deployed within ADNOC's sovereign cloud environment, the technology provides the scalable digital foundation for AI-enabled workflows across one of the industry's largest rig fleets and supports the continued progression toward more autonomous operations,” Jaggi said. 

ADNOC added that maintaining sensitive information within the UAE jurisdiction would strengthen data security and operational resilience, helping push the region towards more autonomous drilling operations and enhance its long-term digital independence. 

PETRONAS offers the clearest case. Malaysia's national oil company, producing 2.4 million barrels of oil equivalent a day, runs a predictive-analytics programme across its LNG and deepwater assets that AVEVA has documented over several years: around $33 million in savings and a twenty-fold return, with the system flagging 51 equipment warnings, twelve of them high-risk, before they became failures. This is AI working where a wrong call can shut down a platform. The payoff shows up as avoided outages.

While AI adoption has accelerated rapidly, turning it into profit is the harder task. Economy-wide, more than six in ten organisations across the region direct 11% to 40% of their technology budgets to AI, while around 60% report under a 5% gain in EBIT. Energy has a structural advantage in closing that gap. In asset-heavy operations, the highest-value use cases, predicting a compressor failure, trimming a refinery's energy draw, forecasting turbine output, produce returns a CFO can price to the dollar. 

Measurable returns

Energy leaders see it: in EY's December 2025 AI Pulse survey, 78% of energy executives whose AI investments delivered productivity gains called those gains a catalyst for strategic transformation, against a 55% cross-industry average. The physical complexity that makes energy hard to digitise is what makes its AI returns legible.

Southeast Asia's energy sector carries a second role that raises the stakes. The same operators adopting AI must also supply the round-the-clock power for the region's AI buildout, and the capital is arriving from every direction. AWS, Google, and Microsoft have committed over $50 billion to regional AI infrastructure as of mid-2025. In May 2026, Thailand's Board of Investment approved a $25 billion data-infrastructure expansion by a local TikTok unit, its single largest approval, alongside a $1.4 billion, 200-megawatt data centre from Dubai's DAMAC. 

Industry coordination

Data centres need firm, continuous power, which presses on grids still balancing legacy baseload with rising intermittent renewables. Thailand's board now treats power readiness, its Power Development Plan and direct renewable purchase agreements as decisive to winning the next facility. Grid capacity has become the gating factor for AI investment.

Scaling AI on both sides of that equation, inside operations, and across the power system, is a coordination challenge as much as a technical one. Value at scale needs grid operators, hyperscalers, technology vendors, capital, and regulators aligned on shared standards, across six markets that rarely coordinate by default. Cross-border groundwork has started: PETRONAS, Malaysia's TNB, Singapore's Sembcorp and PetroVietnam have formed a consortium to trade clean power under the ASEAN Power Grid plan.

This is the coordination AixEnergy in Bangkok during 14-17 September is built to enable. It brings the region's energy operators, AI and cloud providers, power developers, and policymakers together at the point where a promising pilot becomes a scaled standard, shortening the path from adoption to measurable value.

Southeast Asia's energy companies have shown they can scale AI above the global benchmark and put it to work in demanding operations. The advantage now goes to those who scale it across the enterprise, and who build the partnerships to power and coordinate that growth before the buildout is complete.

• AixEnergy is co-located with Gastech 2026, taking place from 14-17 September at BITEC, Bangkok, Thailand. Make sure to register for your All Access Pass to AixEnergy.

Sources:

• McKinsey, EDB Singapore & Tech in Asia, "AI in Southeast Asia: An Era of Opportunity"
• Thailand BOI approvals, TikTok $25B / DAMAC $1.4B
• PETRONAS predictive-analytics figures, AVEVA case study
• EY US AI Pulse Survey
• PETRONAS/TNB–Sembcorp–PetroVietnam ASEAN Power Grid consortium
• AixEnergy

Ahead of Gastech 2026 in Bangkok, Hans Neidig, P&GA Manager, ExxonMobil, highlights the growth of the company’s Low Carbon Solutions business and how leveraging technologies can help diversify energy supplies while supporting customers’ emissions-reductions goals. 

What is ExxonMobil’s presence at Gastech 2026?

ExxonMobil returns to Gastech as a Co-Host sponsor, underscoring our commitment to global energy dialogue and collaboration. At booth J80, leaders from our LNG and Low Carbon Solutions businesses will engage with potential and existing customers and stakeholders on market developments and emerging opportunities. Our senior executives will also participate in panel discussions across a broad range of industry topics.

What is top of mind for ExxonMobil?

ExxonMobil sees the energy future as an “AND” equation: we need to provide the energy the world needs AND reduce emissions. LNG is key to meeting rising global energy demand. As the world grows and prospers, we project natural gas demand to rise 20% by 2050.

Consequently, ExxonMobil’s ongoing focus is to bring online stable and reliable LNG supply that can help provide security as well as flexibility to meet growing global energy demand. LNG is expected to play a central role in enabling countries to diversify their energy supply, reduce dependence on single sources, and enhance resilience against market disruptions.

Brent crude traded near $85 a barrel, after losing almost 5% in the previous session, while West Texas Intermediate was above $81. “We’re talking about the strait, the opening of the strait, having it open literally by tomorrow,” Trump told reporters in the Oval Office on Monday.

“This is a last chance for them to sign a good document,” he said, without clarifying what negotiations he was referring to or who was involved. “I want to give them every last chance before decapitation.” 

Tehran denied it was talking with the US, but said discussions with Oman to get more ships moving through Hormuz are making progress. Washington must “take the first step and change its behavior,” Mohsen Rezaee, adviser to Iran’s Supreme Leader, said on state TV.

Oil has swung wildly in recent weeks as fighting resumed following the collapse of a June truce and the conflict expanded to the Red Sea. Trump has repeatedly cited diplomatic efforts when he backed off threats of military escalation only to see talks fail, and on Monday called off an attack on Iran that he said would have been the biggest since World War II.

“As long as there are these openings to move barrels around, I think this on-off can continue,” said Carolyn Kissane, associate dean at New York University’s Center for Global Affairs. “Iran doesn’t want to escalate but does want to keep up the tension, and there will be more attacks after this market retreat. We have been here before.”

Commodity flows through the Strait of Hormuz — which carried about a fifth of the world’s crude oil and liquefied natural gas before the war — have slowed to a trickle. In the latest incident, a cargo vessel northeast of Al Khasab, Oman, broadcast that it had been hit by an unknown projectile on Monday, according to UK Maritime Trade Operations.

Meanwhile, the key Saudi export port of Yanbu on the Red Sea appeared to have its busiest day since Houthi threats upended shipping in the region, as more vessels transited dark through the Bab el-Mandeb chokepoint. Saudi Arabia’s observed crude exports edged lower in July as threats to vessel traffic in the Gulf and Red Sea held back the kingdom’s shipments.

With global energy markets under pressure from the Iran war, Ukraine’s shifting strikes across Russia’s oil supply chain increase the risk of further disruptions to global flows. Large refineries, oil tankers, and sea and major pipeline infrastructure were hit at least 30 times in July — the second-highest monthly number of attacks since Russia’s full-scale invasion in 2022.

In recent days, four ships have completed loadings at the Caspian Pipeline Consortium terminal, a Black Sea port on Russia’s coast crucial to Kazakhstan’s crude exports. Recent attacks on oil tankers in the area have made some vessel owners cautious about loading there. 

©2026 Bloomberg L.P.

The country’s biggest data center operator, which is owned by government-backed NTT Inc., intends to add roughly 750 megawatts of capacity over the next seven years to meet soaring demand from companies seeking to catch up in AI, people familiar with the matter said.

That would mean spending at least ¥1.5 trillion ($9.6 billion) for construction and equipment installations, estimated the people, who asked not to be named as the discussions are private. That’s based on the assumption that each megawatt of data center capacity installed in Japan costs ¥2 billion to ¥2.5 billion, excluding the cost of AI accelerators such as Nvidia Corp.’s. 

The scale of the investment is subject to changes in pricing and demand for computing capacity, the people said. An NTT Data spokesperson said the company does not disclose investment plans, citing company policy. Computational demand is expected to grow in tandem with the size of the economy, the fourth largest in the world, according to Yasuo Suzuki, who headed NTT Data’s data center operations in the Asia Pacific through July.

NTT Data, which competes globally against the likes of Digital Realty Trust Inc. and Equinix Inc., is fielding interest from companies seeking to secure around 100 MW of capacity for AI inferencing, Suzuki said. 

The company now plans to add a total 42 MW of capacity this year and begin construction on a 100 MW data center next year in Tochigi, a prefecture just north of Tokyo. NTT Data expects its spending on data centers to grow about 33% to around $3.3 billion this fiscal year to March. 

“From where we stand, we don’t see much competition,” Suzuki said in an interview earlier this year. “There aren’t many players building data centers due to a number of reasons, leaving limited supply against high demand.”

Shares of parent NTT fell about 1% in Tokyo morning trading. A ¥1.5 trillion investment may weigh on the stock, potentially putting it at a disadvantage against global rivals with access to deep pools of capital, said Yasuhiro Ono, chief executive officer of infrastructure investment firm Deepstone Partners.

“It’s difficult to gauge how much of the data center capacity will end up being used,” Ono said. “But because the power constraint is real, the gap between high demand and low supply will likely persist.”

Questions about long-term demand and growing fears that big tech firms are building more data centers than they need have been pummeling AI-related shares around the world. But NTT Data has seen little sign of slowing demand.

Companies like Amazon Web Services and Microsoft Corp. are racing to expand their own data centers in Japan while also seeking more capacity from NTT Data, according to Suzuki. Global cloud providers comprise more than 80% of the Japanese unit’s data center business revenue, he said.

The bigger issue is the country’s longstanding shortage of grid capacity, making it difficult to connect power-hungry data centers quickly. NTT Data relies on its partnerships with utilities such as Tokyo Electric Power Co.

Some regions of the country — such as Inzai, Chiba prefecture, just east of Tokyo — suffer from chronic shortages in transmission capacity. In those areas, it will likely take 8 to 10 years to secure the necessary approvals to meet data centers’ electricity needs, according to Suzuki. Due to such bottlenecks, data center capacity is taken up by customers as soon as it becomes available, he said. NTT’s rival SoftBank Corp. is eyeing an investment in Tepco to secure the electricity required for its aggressive data center plans.

©2026 Bloomberg L.P.

Britain’s offshore oil and gas sector has become uninvestable. Labour and Conservative governments alike have delivered years of poor — and what is worse, inconsistent — policy on a crucial national asset. No exploration wells were drilled last year, for the first time since 1964. New licensing rounds have been blocked.

The price of uncertainty

The ‘energy profits levy’ imposes punitive levels of taxation. The headline rate of tax — 78% — may be the same as Norway’s. But that overlooks the Nordic state’s far superior policy consistency, active ongoing licensing programme, greater remaining resource base, and the more favourable fiscal allowances.

This is a failure across the political spectrum. Shadow Energy Secretary and Aberdeenshire MP Andrew Bowie claimed, “Only the Conservatives have a plan to get Britain drilling again by ending the licence ban, scrapping the energy profits levy paid for by cancelling net zero projects.” He conveniently omits the party that introduced the levy under Prime Minister Boris Johnson in 2022.

The cost of decline

From 370,000 workers in the offshore oil and gas sector in 2015, only 110,000 remained by 2025. Many of these were high-skilled, well-paying positions. Scotland has been particularly hard-hit. For all the crocodile tears shed over the coal miners left on the scrapheap by Margaret Thatcher, left-wing activists have shown less sympathy for oil and gas workers. Notwithstanding its success, the UK wind power industry employs about 55,000, estimated to rise to 112,000 by 2030. Fewer than 14,000 work in solar power, a large part of that in London.

The most successful firms on the UK continental shelf are now looking elsewhere. As capital flees, Enquest announced a major acquisition in Malaysia in June; in July, Serica Energy agreed to buy Pharos, a company operating in Vietnam and Egypt. Of the basin’s mainstays, Shell has already combined its assets with Norway’s Equinor; TotalEnergies merged its UK E&P unit with Repsol, and private equity-backed NEO Energy. bp was the last supermajor to retain a standalone business.

Why the North Sea still matters

Declining production in the North Sea is inevitable, but the rate of decline is not. The 2010 discovery of the Johan Sverdrup field, one of the largest ever found in Norway, shows that even mature basins can spring surprises. The 500 million barrels in the UK’s largest undeveloped field, Rosebank, have sat around off the west of Shetland since it was discovered in 2004.

The good reasons for reviving UK oil and gas exploration and production have been well-rehearsed. It would sustain employment, especially in Scotland, generate badly needed tax revenues, and improve the balance of payments. It would almost certainly be lower carbon than importing hydrocarbons, especially liquefied natural gas. The extra production will add only minimally to global emissions; most will displace oil and gas that otherwise would have been imported.

Maintaining North Sea infrastructure is crucial for future uses, particularly for carbon capture and storage (CCS). Once decommissioned, it will be very expensive to reconstruct. CCS is an essential part of any realistic path to net zero for the UK, for dealing with unavoidable industrial emissions from sources such as chemicals and cement plants. Skilled petroleum professionals are essential for future low-carbon industries such as CCS, geothermal, and hydrogen.

A political opportunity

As the turmoil in the Gulf continues, Russia remains an adversary, and oil and gas prices stay rather high, the economic and energy security benefits of more domestic production should be an easy political win for Mr Burnham. He campaigned on re-industrialising left-behind parts of the country. Energy secretary Ed Miliband has been appointed foreign secretary; his replacement, Miatta Fahnbulleh, may be equally supportive of net zero but is less politically influential.

Labour has also gained in the polls recently against the Greens, solidifying Mr Burnham’s left flank. As a record heatwave and drought sweep Britain, and apocalyptic wildfires overshadow France in smoke, it is easy to make the case for stronger climate policy too. Done right, low-carbon policies will deliver economic growth and investment and, eventually, reduced energy bills.

There is no need to fall prey to the “lump of money” fallacy and assume that promoting low-carbon energy is in opposition to domestic oil and gas production. Private companies fund offshore petroleum exploration and production. Solar and wind are mature technologies that should not require large subsidies. The UK has more than enough finance and talented people to make a success of all viable energy sources.

Reconciling climate and hydrocarbons

Mr Burnham could draw on a few creative options to manage the apparent tension between tackling climate change and supporting oil and gas development. One, promoted by Oxford University climatologist Myles Allen in a recent Financial Times article, is the carbon take-back obligation. Companies producing hydrocarbons in the UK would be required to capture a rising share of the resulting emissions, reaching 100% by 2050.

An alternative, or complement, would be to hypothecate offshore petroleum taxation to green objectives — for instance, funding the conversion of the UK building stock to heat pumps and high levels of energy efficiency. That would tackle emissions at the source and give the public a very visible benefit in the shape of lower bills.

A Britain overloaded with debt, struggling for growth, burdened by high bills, and sweltering in endless heatwaves, needs bold and creative climate and energy solutions. The North Sea is not what it was in the heyday of bp and Sir Ian, but it is not dead yet.