The application was submitted Thursday through Nucore Energi, wholly owned by Fortum and established for the project. The reactors would be built adjacent to the existing nuclear plant in southeastern Sweden, which is operated by Uniper SE and in which Fortum is a significant minority owner.

Sweden’s nuclear new-build push sits at the heart of the government’s energy agenda. It has designed a comprehensive support package that includes a minimum electricity price, state-backed construction loans and a mechanism for sharing project risks.

Fortum is planning a facility with capacity ranging from 1.2 gigawatts to 3.4 gigawatts, Nucore Energi Chief Executive Officer Laurent Leveugle said in an interview. The eventual size will depend on the technology, expected demand growth and the terms of any risk-sharing arrangement with the state, he said.

“In order to justify such a project, we really need to eventually agree with customers on offtaking the electricity and to make sure that it will be used,” he said. 

The technology will be selected from three potential candidates, two large-scale reactors and one small modular reactor, from suppliers including Westinghouse Electric Co., Electricite de France SA and GE Vernova Hitachi Nuclear Energy.

The new capacity may come online in the second half of the 2030s at the earliest, Leveugle said, adding that “some discussions” have been held with Uniper regarding the site. The German company has said that it has no plans to invest in new nuclear in Sweden. 

Johan Svenningsson, Uniper’s Sweden head, reiterated that point and said by email that the company is looking forward to continuing the dialogue with Fortum about the potential project. 

The site houses Sweden’s biggest reactor, the 1,400-megawatt Oskarshamn-3, as well as two older units that were decommissioned in 2015 and 2017.

Fortum has been assessing options for new nuclear power in Sweden since 2022. The application doesn’t constitute an investment decision, but formally starts discussions with the Swedish state over potential support for the project.

If the plan goes ahead, Fortum would eventually look to be a minority holder. 

“Even though we are a major utility in the Nordics, these projects are just too big for us to take alone, even at 51%,” said Leveugle. 

Other firms including Videberg Kraft AB, Blykalla AB and Studsvik AB have also applied for state aid for new nuclear. 

©2026 Bloomberg L.P.

Brent traded near $87 a barrel, and is down more than 7% this week, while West Texas Intermediate was near $82. Crude rose Wednesday on a report that Russian President Vladimir Putin was planning an escalation of the war in Ukraine, before reversing those gains after Iran’s military said it reached a revenue-sharing agreement with Oman on Hormuz.

Oil has slipped this week on optimism over the agreement between Iran and Oman and after US economic measures against Tehran and its trading partners weren’t as harsh as anticipated. Prices are still up more than 40% this year after the six-month conflict crimped flows from the Persian Gulf.

“The market has started pricing in the possibility of another ceasefire emerging,” said Saul Kavonic, senior energy analyst at MST Marquee, referring to talks between Oman and Iran that are seen as a precursor to an agreement between Tehran and Washington. 

But crude is now in a holding pattern as traders await confirmation that a deal can be reached, he said. “There have been many false starts to ceasefires already, so the market is hesitant to move prematurely.”

Tehran has repeatedly said an agreement on navigation would not equate to an immediate re-opening. Nevertheless, crude appears to be flowing from the Persian Gulf, with US President Donald Trump claiming that 10 million barrels of oil had exited Hormuz on Tuesday. 

Satellite images show Saudi Arabia appears to be ramping up oil loadings inside the Persian Gulf. That’s a sign the world’s largest crude exporter is reorienting shipments amid threats from Yemen’s Houthi militants to its Red Sea exports.

Still, risks remain. A tanker was hit by an unknown projectile in Hormuz, the UK Maritime Trade Operations said. The incident, reported on Aug. 25, is being investigated by local authorities, it said. 

Meanwhile, an escalation in the Russia-Ukraine conflict may further threaten global energy supplies. Recent strikes by Kyiv on refineries and ports have prevented Moscow from diverting crude into exports, compounding disruptions from the Iran war. 

“Frequent attacks on Russian oil and refining infrastructure are starting to make a dent in overall Russian oil supply by up to around 10%, with an even larger impact on refined products,” Kavonic said. 

Signs of a broader fuel squeeze are also evident in the US, where diesel supplies have fallen to the lowest seasonal level ever, according to the Energy Information Administration. The situation in Europe is so tight that the region has tapped Mexico for the workhorse fuel for the first time in seven years.

©2026 Bloomberg L.P.

The Southeast Asian nation aims to generate 60% of its electricity from clean energy sources like solar, wind and hydro in 25 years time, said Energy Minister Akanat Promphan. That’s double the previous goal. The targets will be officially announced in an updated 25-year national power plan to be released in October, Akanat said.

“The ongoing conflict in the Middle East demonstrates that we must urgently reduce imports of LNG and other fuels,” he said in an interview at the Thai parliament late on Wednesday. “We need to build a cleaner and more self-reliant power system.”

Thailand currently generates more than 60% of its electricity from natural gas, most of which is imported, leaving it exposed to events like the Middle East conflict that spurred a surge in the price of seaborne liquefied natural gas. Increasing renewable capacity — around 15% of the power mix at the moment — would curb the need for imported fuel and also support the nation’s goal of getting to net zero by 2050.

The doubling down on renewables — which will require a rapid buildout — comes as Thai power demand is expected to increase sharply. The country has attracted billions of dollars of investment in data centers, cloud computing and advanced manufacturing. The government has been taking steps to ensure it has enough generation capacity to accommodate the rising demand to limit the impact on household power bills.

“The next wave of investment — from data centers to advanced manufacturing — will require enormous amounts of electricity,” Akanat said.

The new power plan will include nuclear energy for the first time, a significant shift in Thailand’s energy strategy, Akanat said. The government has been studying small modular reactors as a potential source of stable, low-carbon electricity to complement intermittent renewable, he said. 

Akanat defended a government proposal to spend 200 billion baht ($6.1 billion) on renewable energy, including rooftop solar for villages, in parliament this week.

Thailand last revised its 25-year power development plan in 2023, which was before the Iran war and the artificial intelligence boom.

©2026 Bloomberg L.P.

The stakes are substantial. China has more than tripled its annual operational capacity since the end of 2024, and now hosts nearly 250,000 tons — over twice that of the rest of the world combined, according to BloombergNEF. Beijing’s latest five-year plan calls for an eightfold increase to 2 million tons a year by the end of the decade.

China is outstripping rivals that have seen major projects shelved due to ballooning costs and anemic demand. Its success hinges on two distinct advantages over places like India and Europe: a massive industrial base that’s proving tough to decarbonize, and a surplus of clean energy that needs to find a home.

“China is making a strategic bet on renewable hydrogen as a way to carry clean electricity into the sectors electrification struggles to reach,” said Muyi Yang, a Sydney-based analyst at energy think tank Ember.

Two hours north of Beijing by bullet train, Chifeng in Inner Mongolia straddles China’s past and future. Home to nearly four million people, the city is dotted with smokestack chimneys. On the outskirts, one square kilometer has been given over to a project that promises to clean up a local economy founded on mining and powered by coal. 

The Envision Group facility — all sharp-angled white facades, floor-to-ceiling glass walls and minimalist interiors — is the world’s biggest green hydrogen plant. At a cost of $2.6 billion, it began operating in 2024, employing electrolyzers that use wind and solar to split water into an element that its boosters say will transform efforts to lower emissions.

China’s extraordinary expansion of clean power has created wind and solar power in abundance, to the degree that an increasing amount is simply being wasted. Diverting the excess to green hydrogen solves the problem of under-utilization. When converted to chemicals such as ammonia, it also allows renewables to be stored for future use, much like a liquid battery. 

The issue has become more pressing for policymakers because wastage undermines the economics of renewables projects at a time when they’re already grappling with excess capacity and fierce price competition.

Projections on how much green hydrogen capacity the world will add have been scaled back in recent years. If plants like Chifeng succeed, it would reaffirm China’s dominance as a clean-tech powerhouse, and offer a path to cutting emissions in the stubbornest industries. But failure would throw into doubt whether green hydrogen can achieve commercial liftoff anywhere in the near term.

The share of electricity in China’s final energy use has risen steadily, reaching 30% in 2025. The government is targeting 35% by 2030. The gains so far have been smoothed by the country’s vast coal reserves, ever-cheaper wind and solar, and the electric vehicle boom. 

The next five percentage points, which also need to take account of the country’s gradual shift from coal to renewables, will be harder to capture without a new approach. Adopting the playbook that delivered its world-beating wind, solar and EV industries, Beijing is focused on shoring up supply first. The hope is that demand will follow.

“With the rollout of China’s new five-year plan, the industry’s growth will increasingly depend on how China, and economies linked to China, can foster demand for green hydrogen,” said Yimin Lou, Envision’s chief product officer and head of its hydrogen business.

But challenges abound. The green version of the fuel is still more expensive than the gray and black hydrogen that comes from gas and coal, and the blue hydrogen that combines fossil fuels with carbon capture.

Green hydrogen producers have access to subsidies from both central and local governments and via national carbon credits. But even combined, the savings fall short of matching gray hydrogen’s cost, BNEF says.

Moreover, the subsidies don’t necessarily feed directly into consumption. “The most important thing is whether demand-side policies can be implemented, and whether they can stimulate some real demand and support the price premium,” said BNEF analyst Kathy Gao.

Pole position

Still, China’s advantages are considerable. 

Its electrolyzers cost about four times less than those made in Europe, according to BNEF. In addition to its lead in clean energy, the country dominates global production of highly polluting industries like steel, cement and chemicals, which have been slow to cut emissions but must decarbonize if Beijing is to meet its climate goals. For other countries to get to the same level on hydrogen, they’d need to invest a lot more and rely on exports for future demand.  

“It’s fair to say that, from virtually every perspective, China is the most favorable market for the development of this industry,” said Gao.

Inner Mongolia exemplifies the opportunity. It boasts some of the world’s richest wind and solar resources, yet electricity demand is concentrated in faraway coastal cities. Grid infrastructure is lagging, which has led to rising curtailments of renewable power.

Hydrogen offers a remedy. At Envision’s facility, nearby wind and solar farms supply all the electricity. The plant’s electrolyzers are specifically designed for the variable levels of power delivered by the wind and sun.

“The key consideration is how to unlock greater demand for renewable energy,” said Envision’s Lou. “Historically, the ability of the market to absorb renewable power, particularly from wind and solar, has been constrained. Products such as green hydrogen and green ammonia create entirely new sources of demand.”

©2026 Bloomberg L.P.

Given an edge by its shale revolution that was decades in the making, the US became the world’s leading natural gas producer by volume with an output of 110 billion cubic feet per day and the largest LNG exporter in the first quarter of 2024. 

According to the US Energy Information Administration (EIA), the country exported over 15 bcf/d or 111 million metric tonnes of LNG in 2025, becoming the first ever producing nation to exceed the 100 million-mark in a single year. 

It’s an attractive number for a market that’s servicing an exponential growth in energy demand driven by power-hungry hyperscale data centres, proliferation of artificial intelligence, and rising electrification in the high-growth markets of Asia. 

Asia demands, US supplies

If last year was a record-breaking one for US LNG, this year might turn out to be even better. According to Reuters data, the US has already exported just over 73 million metric tonnes of LNG from January through to July; a 23% increase on an annualised basis.

This is welcome news for Asia’s importers who took in a world leading volume of nearly 170 million metric tonnes last year from global suppliers. The volumes in question are visibly firming up an LNG cargo corridor from the US to Asian markets, gradually shifting American exports from Europe. 

More so, as Asian markets see lower volumes from Qatar in the wake of outages caused by the Iran war and transit disruptions in the key maritime artery of the Strait of Hormuz. Indeed, in a bidding war to secure LNG cargoes, the Asians are more than holding their own.

In particular, South Korea, Japan, India, and China took around 40% all US LNG available in a competitive spot market at the height of the Iran war in March and April, according to trading sources. If anything, the development has amplified the investment case for US LNG.

And everyone wants in given market forecasts indicate the US may account for more than one-third of global LNG supply in the early 2030s, and demand expansion looks set to continue into the 2050s, according to Shell’s 2026 LNG Outlook.

An amplified investment case

EIA data points to the US adding 12.7 bcf/d of LNG export capacity between 2016 and 2024. It is projected to add a further 13.3 bcf/d by 2030. Given that US President Donald Trump’s ambition is to double the country’s LNG production by the end of the decade, many forecasters as well as industry insiders say a trillion-dollar opportunity potentially beckons over the next 15 years.

For instance, S&P Global Energy currently estimates the US LNG supply chain valuation to exceed $1 trillion through 2040, and future export activity to generate more than $2.9 trillion in total revenues for American businesses.

But this ‘made in America’ story has a distinct global flavour that will likely come to the foreground at Gastech 2026 in Bangkok, Thailand. It would not be lost on delegates at one of the world’s leading natural gas industry events that around 80% of peak export capacity from currently operational US LNG export facilities is either financed or backed by foreign equity investors.

Among them are QatarEnergy, Japan’s JERA and JAPEX, Australia’s Woodside Energy, Saudi Aramco, Abu Dhabi’s state-owned energy company ADNOC, and its investment arm XRG. As are European majors Shell and TotalEnergies, with American heavyweights ExxonMobil, Chevron, ConocoPhillips, Venture Global, and Cheniere Energy joining the ride on their home patch. 

All have partaken in multi-year supply deals and direct investment commitments for projects. Thailand's state-owned energy company PTT might soon become the latest entrant seeking both long-term LNG supply as well as equity investments in export terminals.

Expectations of a benign regulatory climate

Most international and US investors can take confidence from a relatively benign regulatory climate, resulting from the Trump Administration’s candid support.

Since Trump came to power and dispensed with developmental pauses introduced by his predecessor Joe Biden, the Federal Energy Regulatory Commission (FERC) has streamlined and improved approval processes for LNG terminals, granted market-based rate exemptions, and reduced red tape.

FERC Chair Laura Swett – who is scheduled to speak at Gastech – may likely allude to this changed approach in Bangkok. An ‘open for business’ sign certainly goes a long way in improving investor confidence. 

As things stand, eight terminals are under construction stateside alongside nine operational terminals. Another dozen projects have FERC approval but haven’t been built and six terminals are awaiting approval.

Of course, the wider price environment will dictate both the progress and viability of these projects, and ultimately the strength of the US-Asia LNG corridor. But the business case remains strong based on medium to long-term market permutations.

Energy security is no longer just about having enough. It’s about having options. Four years after the energy crisis reshaped Europe’s gas market, resilience has increasingly moved from ambition to reality. The focus is no longer just on securing supply, but on building an energy system that delivers security, affordability, and sustainability at the same time. Europe has made significant progress. It has diversified supply sources, expanded LNG infrastructure, strengthened market integration, and improved its ability to respond to disruptions. As a result, the continent is far better prepared to respond to disruptions. But resilience should not be mistaken for certainty. 

The climate research company, basing its estimates on Chinese exports of solar panels to Africa in the year to June, forecasts that a record 17 gigawatts of solar power will be installed across the continent in 2026. Notably South Africa’s role as the dominant importer will shrink as installations accelerate in countries such as the Democratic Republic of Congo, Zimbabwe and Zambia. 

Still, Ember said in a report published Thursday, three-quarters of the growth is in the form of distributed solar, primarily panels installed on rooftops, which is hard to track and makes it difficult for governments to plan their own grid expansions. 

“Across Africa distributed energy resources are rapidly expanding and in many cases overtaking grid capacity,” Joel Nana, a research director at African Tech Futures Lab, said in the report. “This transition is chaotic and disruptive and far from the orderly model planned in national strategies.”

Falling costs are driving rapid adoption of solar power in Africa, where about 563 million people, or more than four-fifths of the global total, lack access to electricity. The World Bank and African Development Bank are leading a push to bring power to 300 million people by 2030.

The $2.4 billion spent across Africa on panels in the year through June is equivalent to what it would have traditionally cost to run diesel generators for three months, Ember said. 

While South Africa, which has the continent’s largest utility-scale solar industry, accounted for 52% of imports from China in 2023 that proportion fell to 20% in the latest period. 

Even though Ember estimates that 36 of Africa’s 54 countries will install record amounts of solar in 2026, South Africa will remain the biggest buyer with 3.3 gigawatts expected to be added. 

©2026 Bloomberg L.P.

“The sort of Silicon Valley model is running into a real-world infrastructure constraint,” Ben Dell, managing partner and co-founder of Kimmeridge, said in an interview on Wednesday at Bloomberg News headquarters in New York.

Kimmeridge holds stakes in natural gas producers and in Commonwealth LNG, a planned terminal to export the fuel from Louisiana. Though US gas demand is expected to climb as new power plants are built to provide electricity for the artificial-intelligence boom, Dell said delays to data-center projects would likely result in cuts to those forecasts.

US gas producers have high hopes that AI will drive up consumption of the fuel, which has traded at relatively low prices domestically for most of the past decade as supply from fracking swamped demand. But investor skepticism over Big Tech’s spending and public opposition to data centers are creating additional headwinds for gas bulls.

While most of the 30 billion cubic feet a day of expected US gas demand growth is from liquefied natural gas exports, Dell said about 5 billion to 10 billion a day could be driven by data centers — though delays could mean AI-related consumption is at the lower end of that range. 

Data centers are rapidly becoming a political issue for the upcoming US midterm elections, and growing pushback and litigation at the local level will add to the risk of postponements or cancellations, Dell said. Bipartisan opposition to data centers is rising in states including Pennsylvania, Texas and Ohio, which were once seen as friendlier to the projects, he added.

In Dell’s view, the ideal data center proposal would be “zero impact,” with no net effect on water usage, land, emissions or power prices, he said.

©2026 Bloomberg L.P.

That’s where a federally funded field laboratory just began a vanguard test that may show whether fracking techniques used to produce oil can also tap underground heat to produce energy.

At the moment, there are scant places around the globe with the right properties to generate geothermal electricity; the current test, however, could make a case for geothermal plants virtually anywhere.

Kristie McLin, manager of Utah FORGE, the Energy Department field laboratory, said she was excited and nervous as her crew starting pumping water into the ground. “It’s butterflies really,” she said. “With geothermal technology, we have seen that initial liftoff and we’re advancing significantly what we can do economically.”

A new era for geothermal

The new drilling techniques are expensive, the industry is still tiny and the sole public player, Fervo Energy Co., has had a chilly reception on public markets. 

However, if the new strategies work, the upside is immense, proponents say — a gusher of electricity that is cheap, constant and nearly emission-free. And while the Trump administration has severed federal support of solar and wind farms, it is still spending to try to make green energy happen in the Utah desert. 

Geothermal energy is nothing new; engineers have been tapping the Earth for steam for decades, but only in relatively rare regions where they could find underground reservoirs of water. At the moment, there are about 100 geothermal plants in the US, supplying somewhere around 0.4% of the country’s electricity. 

Recently, however, engineers and entrepreneurs have started working on a new approach: using the same drilling techniques for oil and gas fracking to create underground reservoirs where there were none. Water pumped down the well expands little cracks in the rock and then returns to the surface via another well, a so-called closed-loop system, essentially a subterranean steam plant that can spin power turbines up top for extended periods of time, if not indefinitely. 

From pilot to potential

FORGE, which stands for Frontier Observatory for Research in Geothermal Energy, was launched during the Obama administration, primarily to test the thesis. More recently, Fervo and other startups have joined the push.

Preliminary tests from FORGE and Fervo, which has drilled in the desert nearby, were promising. The goal, according to McLin, is to make geothermal energy possible pretty much anywhere the Earth burbles at 200°C within five or so kilometers of the surface. This would put much of the American West on the map for geothermal electricity, theoretically precluding a host of new fossil fuel plants. 

But McLin and other scientists have a few concerns. The test at FORGE, which may last up to four months, is designed to figure out if the regurgitated water will stay hot for an extended period or cool to the point where it won’t generate electricity. Scientists also fret over whether all the drilling and pumping will trigger earthquakes and how much water will be lost in the process, a sensitive issue given the extended drought in much of the American West. 

Growing geothermal potential in the US

“There’s potential,” said Annick Adjei, a senior research analyst at Wood Mackenzie, an energy analytics firm. “But the risk is really in repeatability. We need a bit more in the way of milestones to see how things will go.”

While there are geothermal hotspots around the world, namely in Iceland and Kenya, the US has two critical ingredients: an abundance of open space and a glut of fracking know-how. The Energy Department reckons there’s enough potential geothermal energy to power the country five times over.

Perhaps because of those things, geothermal is arguably the only renewable energy technology garnering widespread bipartisan support. Since 2020, the government has committed $328 million to FORGE and the Trump administration has kept incentives for geothermal largely intact. 

In part because of that funding, the cost of building new geothermal capacity in the US is now on par with other renewable sources and cheaper than coal plants, offshore wind farms and nuclear, according to a recent report from Lazard Inc.

The AI boom, meanwhile, has improved economics on the demand side, as developers hustle to lock up pretty much any power generation they can get. Geothermal is a less volatile source than solar and wind, a major plus for those in the business of running large language models 24 hours a day. 

Fervo already has an agreement to feed power to Alphabet Inc., though it doesn’t expect to generate any geothermal electricity in Utah until the fourth quarter. Its shares have fallen by nearly 40% since it went public in May on fears revenue may lag expectations.

“Anyone that wants to wait around for other project results is going to find themselves in a very disadvantaged position,” Fervo CEO Tim Latimer told analysts. “Because we have a huge set of customers who are certainly not waiting for any other additional milestones on top of what we’ve already demonstrated.” 

If the FORGE test goes well, McLin said focus will shift to drilling farther into the Earth — where temperatures are hotter — and more efficiently. “Being able to go deeper for cheaper is how I say it,” McLin explained. “Eventually, we could unlock geothermal to be everywhere.”

©2026 Bloomberg L.P.

Natural gas and LNG remain essential components of the global energy system. At the same time, developers are under increasing pressure to reduce the carbon intensity of new facilities, accelerate project delivery, and improve capital efficiency. Global gas demand is expected to grow by around 380 bcm between 2025 and 2030, while approximately 345 bcm/year of new LNG export capacity is expected to come online by the end of the decade, led primarily by the US and Qatar.

How can projects reach Final Investment Decision faster, reduce execution risk, secure reliable energy supply, and lower emissions while remaining economically competitive over decades of operation? Increasingly, the answer lies not in choosing one technology over another, but in integrating proven solutions that deliver performance across the entire project lifecycle. 

Delivering lower-carbon LNG 

LNG has entered a new phase of development. The focus is no longer solely on adding export capacity, but on delivering projects that combine competitive economics with lower emissions, greater flexibility, and higher execution certainty. 

The priority today is to improve the performance of existing assets while designing the next generation of LNG facilities. Electrification, carbon capture, modularisation, and digital engineering are enabling LNG projects that are more efficient, more resilient, and better positioned to meet increasingly ambitious environmental objectives. 

Given that LNG facilities are among the most energy-intensive assets in the hydrocarbon value chain, the opportunity for improvement is considerable. Lower-carbon power, optimised process design, and carbon capture can substantially reduce operational emissions while preserving the reliability and competitiveness that global energy markets require. 

Designing for faster delivery 

One of the most significant changes shaping the LNG industry is the move toward standardised, modular and electrified solutions. Project developers are no longer optimising only for production capacity; they are seeking greater schedule certainty, lower execution risk, and improved carbon performance. 

Modular LNG solutions, such as SnapLNG by T.EN™, illustrate this evolution. By combining repeatable design, pre-assembled modules, and full electrification, these solutions can shorten project schedules, improve cost predictability, and reduce emissions while providing greater flexibility for deployment. Approximately 250 Mtpa of new LNG capacity is expected to enter the market by 2030, owners are increasingly looking for repeatable engineering approaches that accelerate project delivery while maintaining high standards of safety, quality, and performance. 

Hydrogen: building on existing strengths 

While LNG will continue to play a central role in meeting growing energy demand, hydrogen represents an important opportunity for industrial decarbonisation over the longer term. 

Global hydrogen demand reached nearly 100 million tonnes in 2024, yet low-emissions hydrogen still accounts for less than 1% of total production. Scaling production will require not only technology, but also coordinated infrastructure development, supportive regulatory frameworks, and integrated industrial ecosystems. 

Blue hydrogen offers one practical pathway by leveraging existing gas infrastructure while capturing a high proportion of CO₂ emissions. Solutions such as BlueH2 by T.EN™ are enabling industrial players to reduce emissions today while creating foundations for broader hydrogen economies tomorrow. 

Projects already operational, under construction, or having reached Final Investment Decision could enable more than 4 Mtpa of low-emissions hydrogen production by 2030, with a further 6 Mtpa achievable through supportive policies and infrastructure development. Ultimately, hydrogen’s success will depend on how effectively it is integrated with carbon capture, transportation and storage infrastructure, industrial clusters, and evolving energy systems, rather than being developed as a standalone solution. 

From projects to integrated energy systems 

What ultimately emerges is not a competition between different energy vectors, but a more integrated energy landscape. LNG, carbon capture, hydrogen, electrification, and digital technologies each have a role to play: their greatest value lies in how they work together to improve project performance, reduce emissions and strengthen energy security. Through its portfolio spanning LNG, hydrogen, CCUS, and digital solutions, Technip Energies is helping clients develop integrated energy infrastructure that responds to today’s market realities while remaining adaptable to tomorrow’s opportunities. 

As the industry gathers at Gastech 2026, one thing is becoming increasingly clear: the next chapter of the energy industry will be defined not by a single breakthrough technology, but by the ability to integrate proven solutions more effectively, execute projects with greater certainty, and continuously improve their environmental performance. 

In that context, LNG, gas, and hydrogen are not competing pathways. They are complementary elements of an evolving energy system designed to meet growing global demand while progressively reducing its carbon footprint. The pace at which these solutions are integrated, and projects are successfully delivered, will help define the pace of the energy transition in the years ahead. 

The request for proposal process started on Wednesday for 2 gigawatts of offshore wind, able to provide enough energy to power around 1.5 million homes, the state government said in a statement. The auction will close in August next year, with contracts to be awarded later in 2027.

“Victoria has some of the best offshore wind resources in the world,” Victorian Energy Minister Jaclyn Symes said. “This auction is a giant leap toward getting Australia’s first offshore wind projects built — attracting billions in investment, creating thousands of jobs and delivering the reliable power we need as coal retires.”

Australia has been a global leader in the uptake of solar and batteries as the nation seeks to replace an aging fleet of coal-fired power plants, but households have driven much of the transition. BloombergNEF forecasts no offshore wind projects will come online by 2035, meaning Victoria would miss its legislated targets for 4 gigawatts by that year.

Twelve offshore wind projects in Victoria received feasibility licenses in July 2024. Three — by companies including RWE AG and AGL Energy Ltd. — have since surrendered theirs.

©2026 Bloomberg L.P.

In the four weeks through Aug. 23, overseas crude flows fell to 3.46 million barrels a day, tanker-movements data compiled by Bloomberg show. Shipments had previously risen as the strikes on Russia’s refineries left more crude available for export, but that increase is now unwinding, after drone hits on oil tankers cut shipments from the Black Sea.

That’s led Moscow to redirect Kazakh barrels to its Black Sea port at Novorossiysk in order to free up space for its own crude at the Baltic Ust-Luga terminal, which is seen as less vulnerable to Kyiv’s attacks. 

Meanwhile, strikes on Russian oil and gas processing plants continue to be an almost nightly occurrence, sending crude processing rates tumbling and creating domestic gasoline supply issues. Falling Russian crude shipments come on top of Kremlin-imposed bans on overseas shipments of key refined products, including most gasoline, diesel and jet fuel supplies, which are further reducing inflows to Moscow's war chest.

During previous periods of heightened strikes on refineries, Russia was able to divert crude that couldn’t be processed domestically into the export stream. But that doesn’t appear to happening this time around, with production rates taking the strain.

Output fell to 8.89 million barrels a day last month, the lowest in six years, according to secondary source estimates published by the Organization of the Petroleum Exporting Countries. That was almost 1 million barrels a day below the country’s permitted production level under a long-running agreement with its OPEC+ allies.

Even after the recent plunge, however, Russia’s seaborne crude exports remain relatively strong. Shipments so far in 2026 are running about 9% above the highest average for any year since Russia invaded Ukraine in 2022.

Crude Shipments

In the week to Aug. 23, some 33 tankers loaded 24.79 million barrels of Russian crude, vessel-tracking data and port-agent reports show. The volume compared with a revised 23.84 million barrels on the same number of ships the previous week.

Shipments resumed at Novorossiysk, but loading operations remained well below normal levels.

Weekly shipments can be volatile, affected by weather, maintenance work, sanctions, military activity and the timing of departures.

There was one shipment of Kazakhstan’s Kebco grade from Ust-Luga and two from Novorossiysk during the week.

The amount of Russian crude at sea fell further in the week to Aug. 23, dropping to about 83 million barrels, the lowest in a year. With voyage times of at least a month for Baltic Urals cargoes to reach India, deliveries continue to reflect higher levels of shipments in past weeks, drawing more crude off the water than is being loaded. 

The amount of Russian crude on the water is now back at levels seen before the surge that began with tougher US rhetoric on possible sanctions against buyers of Moscow’s oil late last year.

Export Value

On a four-week average basis, the gross value of Moscow’s exports slipped to $1.65 billion a week in the 28 days to Aug. 23, down by $80 million a week from the revised figure for the period to Aug. 16. The drop was driven by lower crude flows, with only small changes in prices for Russia’s key crudes.

On a weekly basis, the value of exports rose by about $100 million, driven by a combination of increased flows and higher prices. 

Flows by Destination 

China and India remain the biggest buyers of Russian crude by a considerable margin. But it’s not always possible to assign a final destination to individual cargoes until well into their voyage, leaving many of the more recent shipments on tankers showing interim destinations, such as Suez or Port Sudan, marked as “Unknown Asia.”

Observed shipments to Russia’s Asian customers, including those showing no final destination, slipped to 3.29 million barrels a day in the 28 days to Aug. 23, down from 3.43 million in the period to Aug. 16.

Flows to Turkey, Russia’s biggest buyer west of Suez, in the period to Aug. 23 slipped to about 100,000 barrels a day, down from a revised 130,000 barrels a day for the period to Aug. 16.

Flows to Syria averaged about 40,000 barrels a day, unchanged from the period to Aug. 16, while shipments to Egypt, Russia’s newest east Mediterranean customer, were also unchanged, at about 30,000 barrels a day, in the four-week period, half the level seen during the 28 days to Aug. 9.

©2026 Bloomberg L.P.

The computing facilities are expected to use 34 terawatt-hours of the National Electricity Market’s power by 2035-36, boosting their share to 13% from 3%, the Australian Energy Market Operator said in its annual Electricity Statement of Opportunities. However, a more-than-doubling of last year’s record generation and storage connections has helped improve the reliability outlook. 

“A significant amount of new capacity is expected to be delivered between now and the early 2030s, helping to replace retiring generation and support growing electricity demand,” AEMO Chief Executive Officer Daniel Westerman said in a statement. “Beyond 2030, the next wave of investment will be critical to maintaining reliability.”

Australia is seeking to capture the economic benefits of a data-center buildout that Commonwealth Bank of Australia estimates could reach A$150 billion ($108 billion) by 2030, while limiting the strains on its grid and water supplies. 

The federal government will legislate a national standard on data centers’ use of electricity and water as the government aims to harness the technological development to bolster the economy without provoking a backlash from people who live near the proposed sites. 

Prime Minister Anthony Albanese will tell a meeting of the leaders of all the states and territories on Wednesday about the plan, which is opposed by two of the regions. 

“You need social license as one thing, so you need to make sure that on energy, that they’re adding to the grid, not just coming along and using energy that can be used for other purposes, that would therefore lift power bills for others,” Albanese said on radio on Tuesday. 

“We need to make sure that’s got right, we need to make sure that water is got right, and we need to make sure that location is right as well.”

Demand from the facilities can also come online far faster than major energy infrastructure can be built to power it. That risks bottlenecks, higher prices for consumers and an increased reliance on fossil fuels. 

“Data centers are particularly influential because they operate relatively consistently throughout the day and across seasons, similar to large industrial loads,” AEMO said in its report. That puts pressure on the grid during periods when consumption is typically lowest, it said.

However, the sector’s expansion hasn’t been without challenges. More than a third of the projects AEMO listed last year have since been canceled, according to the report. 

Meanwhile, 13 gigawatts of coal-fired plants and almost 2 gigawatts of gas generation are now slated for retirement within the decade. About 9 gigawatts of new generation and storage reached full output in 2025-26, double the previous year. 

©2026 Bloomberg L.P.

Policy reforms that have undercut profits on renewables are creating opportunities in trading, Chairman Li Wenxuan said in an interview in Beijing. The company, which also supplies energy storage and manages electricity purchases for large industrial users, is targeting transactions of 10 billion kilowatt-hours in 2027, enough to power a small European country for a year. 

Although China is the world’s largest electricity consumer, it lags the US and Europe when it comes to free-market transactions that set prices by matching supply with demand. The government is looking to change that by establishing a unified national market by the end of the decade.

PCG’s more immediate trigger is a policy that went into effect last year, known as Document 136, which forces wind and solar projects to sell their electricity on the open market instead of guaranteed purchases from the grid. 

“Document 136 ended guaranteed volume and guaranteed pricing, but at the same time it opened the door to market-based operations,” Li said. “If we can operate generation well, the asset doesn’t just retain investment value, it gains upside.”

Octopus Venture

The Hangzhou-based company was founded in 2022 and has developed about 3 gigawatts of mostly rooftop solar for large industrial customers. Earlier this year, it formed a joint venture with the UK’s Octopus Energy Group, which will bring in “trading experience from power markets around the world,” Li said.

For decades, China has relied on a top-down approach to its power market, with government setting prices and grid operators deciding which plants generate electricity and when. The system has paid dividends, helping to keep prices stable and coordinate the massive build-out of infrastructure that has underpinned the country’s rapid growth. 

In recent years, Beijing has pivoted to less regulation, part of a broader push under President Xi Jinping to allow market signals to guide the economy. 

Progress has been slow. Last year, more than 60% of power consumption was delivered via private transactions, according to the National Energy Administration. But the vast majority of those were term contracts and not the next-day deals that would more efficiently match supply and demand. 

Short-term trading is showing signs of growth. More than half the country’s provinces now have markets, and 12% of all power transactions were of the spot variety in the first half, the NEA said.

Growth doesn’t automatically mean profits, though. Given China’s size, Li expects thousands of players to enter the market. But only those with the best forecasting abilities and grasp of evolving market rules will succeed. 

“Everyone sees a huge market, but the technical difficulty is extremely high,” Li said. “Maybe only 10% of companies will truly be profitable.”

©2026 Bloomberg L.P.

From LNG and petrochemicals to hydrogen, carbon capture, and sustainable fuels, Ebara Elliott Energy is applying its turbomachinery expertise across an evolving energy landscape. Chairman and CEO Nobu Miyaki explains how the company is supporting a balanced approach to energy security and sustainability.

How does Ebara Elliott Energy’s portfolio align with the industry’s push toward decarbonisation and building a sustainable energy ecosystem? 

The conflict in the Middle East, combined with Russia’s invasion of Ukraine, severed Europe’s historical energy lifelines. Now, the continent “has practically no major alternative besides the US” for fuel imports, according to Adam Sikorski, co-owner and chief executive officer of Unimot. 

As in the rest of the world, European fuel prices have climbed this year, forcing several nations, though not Poland, to tap into their reserves to meet demand.

For Sikorski, whose firm also makes money on electricity and gas sales, the structural deficit in European refining capacity makes rapid electrification an economic imperative. 

“There is an ongoing debate in Europe about slowing down the energy transition, but I believe we should accelerate it in light of global risks,” Sikorski said in an interview. “This time, the worst-case scenario didn’t materialize and we didn’t run out of fuel, but Europe is paying a high price for its dependence on external energy sources.”

The European Union saw a push among some of its members to put less emphasis on climate goals and more on rebuilding the bloc’s industrial capacity. Still, the European Commission has doubled down, proposing higher electrification targets to reduce dependence on foreign oil and gas. 

Rising Profile

Unimot has aggressively expanded its footprint in Poland’s fuel market, snapping up assets spun off during the state-orchestrated merger of Grupa Lotos SA and Orlen SA earlier this decade. The Warsaw-listed company has also diversified into natural gas, renewables and asphalt, driving a revenue surge to 14.8 billion zloty ($4 billion) last year from 4.77 billion zloty in 2020. 

Unimot shares have jumped 39% so far this year, while Warsaw’s WIG20 gauge has risen 25% in the same period. The stock added 0.2% on Monday, giving the firm a market value of 1.42 billion zloty.

In a milestone move this year, Unimot delivered crude to Germany’s PCK Raffinerie GmbH in Schwedt and booked capacity at a planned floating liquefied natural gas terminal on the Polish Baltic coast.

The Schwedt deal is highly strategic. Germany is a “very important” supplier to Poland, which relies on imports for about 40% of its fuel needs. When the German facility lost Kazakh oil deliveries in May, Berlin held talks with Warsaw to help replace the transit via the Polish port of Gdansk to sustain output.

“We are the largest, but not the only, buyer of fuel from Schwedt in Poland, which is why we have a vital interest in ensuring that this refinery is utilized to the fullest extent possible,” Sikorski said. “Today, Poland has the same amount of fuel as it did before the crisis, and this refinery is operational—which is truly important for the Polish market today.”

Poland, currently the EU’s most coal-dependent economy, is adding two new LNG terminals to ensure more diversified supplies for its growing gas-fired power plant fleet and position itself as a hub for central and eastern Europe. Unimot is one of four companies to book capacity at one of the terminals as it is gearing up to challenge Orlen’s market dominance.

“The gas market remains highly concentrated and if Poland is to become a regional gas hub, we need more competition, easier market entry for private suppliers, and open infrastructure,” Sikorski said. 

However, he noted that the company will wait for global markets to “return to normal” before signing LNG import contracts.

Still, despite his vocal support for a shift toward electrification, Sikorski is holding off on building an electric-vehicle charging network at Unimot’s Avia gas stations. While Poland’s EV market is growing, it trails far behind the rest of the continent. For the time being, the CEO sees better returns in heat and power generation.

“If electromobility becomes a profitable business in the future, we might buy a charging station operator,” Sikorski said. “For now, we don’t have such plans.”

©2026 Bloomberg L.P.

Among the potential bidders to have expressed interest are ExxonMobil Holdings Corp., LyondellBasell Industries NV, Apollo Global Management Inc. and the chemicals arm of Kuwait Petroleum Corp., according to the FT report, which cited unnamed people familiar with the matter.

The portfolio includes major facilities in Louisiana, Texas and Pennsylvania, including the Monaca petrochemicals complex capable of producing as much as 1.6 million tons of polymers annually, the FT said.

The interested parties submitted non-binding indicative offers for the assets last month, including proposed acquisitions of both the whole business and parts of it, according to the report. Cumulatively, the assets could fetch as much as $8 billion, a steep discount to what Shell has invested, the FT said.

Shell declined to comment. The potential bidders listed in the FT report did not immediately respond to requests for comment.

©2026 Bloomberg L.P.

Brent fell to around $93 a barrel, after adding around 13% over the past two weeks, while West Texas Intermediate was near $86. Treasury Secretary Scott Bessent is set to unveil details of the plan in a press conference, and sought to ratchet up pressure on US allies to join the effort in an interview with CNBC. 

Oil has rallied more than 50% this year, with the US-Iran war — now in its sixth month — choking global supplies of crude and refined products. It’s not clear exactly how the US could meaningfully ramp up economic pressure on Tehran, other than going after China — the main buyer of the OPEC producer’s crude — and risking blowback.

“Iran’s enablers purchase and transport its petroleum,” Bessent said in an opinion piece in the Financial Times. “They would do well to consider the consequences of sustaining it.”

The article has laid out the contours of the plan to target Iran’s economy, said Chris Weston, head of research at Pepperstone Group Ltd.

“Calling his op-ed piece ‘D-Day is coming for Iran’ hardly suggests he is there to make friends, and we should expect a defiant message,” he said. “Any defiant plan to materially disrupt the import of Iranian crude comes with significant execution and reaction risk.”

In an indication of how higher prices may be reducing fuel demand, China’s top refiner Sinopec said gasoline consumption fell almost 8% and diesel use 12% in the first half of the year because of high prices and increased use of electric vehicles.

While visible maritime shipping through Hormuz remains curbed, the Islamic Republic permitted a number of Iraqi oil tankers to transit the critical waterway following a request from Baghdad, Iranian media reported. Washington and Tehran have both repeatedly said that they control the strait.

Still, flows in the Middle East remain disrupted. Saudi Arabia has been forced to shuttle oil loaded in the Red Sea via a safer but longer northern route after Iran-backed Houthi militants in Yemen targeted shipping through the Bab el-Mandeb chokepoint in the south.

Elsewhere, Russia rejected a truce Ukraine offered on attacks against ships carrying agricultural commodities through the Black Sea because Moscow wanted guarantees against strikes on its energy infrastructure, Ukrainian President Volodymyr Zelenskyy said on Saturday. While some refineries have recently completed maintenance, Russia hasn’t yet decided whether to lift its diesel export ban in force through Sept. 1, Interfax reported.

©2026 Bloomberg L.P.

Following the 2 July announcement of a trilateral memorandum of understanding (MOU) between the Government of Canada, the Government of Alberta, and the Pathways Alliance on the Pathways carbon capture project, the sector has moved beyond years of open-ended policy uncertainty toward a period focused on execution, commercial structuring, and investment decisions. Definitive agreements on the Pathways project are expected this fall, placing Carbon Capture Canada directly between the July MOU and the next stage of decision-making.

“The timing of this year's convention could not be better,” said Nick Samain, Senior Vice President, dmg events. “We're meeting in September, directly between July's Pathways MOU and the definitive decisions expected this fall — and against the backdrop of a real resurgence in new projects across Canada's energy sector. That's why Carbon Capture Canada is drawing policymakers, and companies from across the country and around the world to Edmonton: to work together, commit capital, and move projects forward.”

Advancing CCUS at scale

Now in its fifth year, Canada's only national convention dedicated exclusively to CCUS will bring together leaders from across industry, government, investment, and technology to explore the opportunities shaping the sector's next chapter. More than 5,000 attendees, over 100 exhibiting companies and representatives from more than 50 countries are expected to participate in this year's event. The convention will showcase emerging technologies while fostering collaboration, investment, and knowledge sharing across the CCUS value chain.

The strategic conference will feature more than 150 speakers from across government, industry, and academia, offering insights into the policy, investment, and commercial realities shaping the future of CCUS. Featured speakers include:

• Honourable Danielle Smith, Premier, Government of Alberta
• Frank Des Rosiers, Assistant Deputy Minister, Energy Efficiency and Technology Sector, Natural Resources Canada (NRCan)
• Purnomo Yusgiantoro, Special Advisor to the President for Energy, Government of Indonesia
• Kendall Dilling, President, Oil Sands Alliance
• Alex Petre, Chief Executive Officer, Deep Sky
• Chana Martineau, Chief Executive Officer, Alberta Indigenous Opportunities Corporation

Charting the next generation of CCUS projects

The conference programme reflects the industry's rapidly evolving landscape, with sessions exploring the policy, investment and commercial realities shaping the next generation of CCUS projects, spanning carbon markets, infrastructure development, financing, technology commercialisation, direct air capture, industrial decarbonisation, and Canada's competitiveness in the global energy transition.

“The conditions for investment are lining up, but nothing is predetermined,” said Samain. “That's what makes this year's convention matter — the industry is gathering to work through the commercial, policy and partnership questions that decide what happens next.”

Beyond the conference programme, attendees can explore a trade exhibition showcasing the latest technologies, products and services from across the CCUS value chain, alongside technical conference sessions, networking opportunities, and programming connecting project developers, policymakers, investors, and technology providers. Additional events throughout the convention include the Carbon Capture Canada Awards Gala and industry networking opportunities designed to strengthen collaboration across the sector.

As governments and industry continue advancing major carbon management projects, Carbon Capture Canada provides a national forum for the conversations, partnerships and innovations helping shape the future of Canada's CCUS sector. With policy frameworks becoming more established and commercial decisions increasingly taking centre stage, the convention offers attendees an opportunity to engage directly with the leaders driving the next generation of carbon capture projects.

For more information or to register, visit Carbon Capture Canada.

Two of the three nuclear reactors that had been shut down in the past month were turned on over the weekend, raising electricity output to more than half of capacity from one-tenth at its low point. The Paks plant will be running at its full output of 2,000 megawatts by Wednesday, Prime Minister Peter Magyar said on Sunday at a briefing from the facility.

Rolling heat waves over the summer dried up waterways across Europe, severely impacting Danube river flows and hindering the cooling systems at nuclear reactors. That strained power grids, forcing Hungary to boost electricity imports and to ask both households and factories to voluntarily cut back on energy use.

The crisis triggered emergency steps, including the sinking of two barges as well as the construction of an underwater barrier at Paks to raise the level of the Danube. While they helped avert a full nuclear shutdown, they also shone a light on the urgent need for long-term solutions as a warming planet risks making such drought conditions the new normal.

Paks generates around 40% of Hungary’s electricity output.

The government needs to pivot quickly to modernize water management, Magyar said, adding it was essential to “save” agriculture and prevent the country’s rivers and lakes from drying up. He said the cabinet planned a comprehensive climate law.

“If we do nothing then we’re headed for annihilation,” Magyar said.

©2026 Bloomberg L.P.

The top exporter is sending tankers thousands of miles all the way around Africa. Millions of barrels of the kingdom’s crude are being shuttled north across the Red Sea, avoiding a narrow strait near Yemen at the southern end of the Red Sea. China, meanwhile, is being offered Middle East shipments for collection just outside the Arabian Gulf.

Saudi Arabia’s ability to switch crude exports to its west-coast facilities has been critical in blunting an oil price surge and shielded economies from an inflation spike as Iran effectively shut the Strait of Hormuz. Now, with Yanbu also under threat from the Iran-backed Houthis, the kingdom and its customers are having to make new arrangements.

The sprawling and costly workarounds are another illustration of the ongoing trade friction imposed by a war that’s expanded more widely, and dragged on far longer, than initially envisioned. 

Double distance

The key issue has been the threat that the Houthis pose to tankers in the Bab el-Mandeb, the narrow waterway at the southern exit of the Red Sea.

After the militants announced a blockade of Saudi ports in July, many tankers collecting barrels at the country’s Yanbu installations on the Red Sea began avoiding the waterway, choosing instead to sail north through the Suez Canal to Egypt’s Mediterranean port of Sidi Kerir. 

For those then sailing onward to Asia, it’s meant going all the way around Africa — more than doubling voyages to roughly 17,000 miles. 

That’s still a popular option among many Asian buyers. Over the past week, several of the continent’s refiners pushed back against a Saudi Aramco request that they collect cargoes from Yanbu, citing the difficulty of finding ships willing to go there, and asked to pick them up at Sidi Kerir instead.

To facilitate that, Saudi Arabia needs to get its crude across the Red Sea and through Egypt — either via the Suez Canal or a pipeline that crosses the country. However, the waterway is too shallow to take fully laden supertankers, while the pipeline can’t handle all the Saudi oil that Asia would normally buy, compounding the logistics headache.

Over the past month, vessels controlled by South Korea’s Sinokor Group, Greece’s Dynacom Tankers Management Ltd., and Norway’s DHT Management AS have been seen shuttling cargoes from Yanbu to Ain Sukhna at the southern end of the pipe. 

Empty oil supertankers are also avoiding the Bab el-Mandeb. Six Saudi ones that diverted away from the strait at the end of last month have taken the long way around Africa, and are now skirting the continent’s western coast as they head for western entrance of the Mediterranean. 

New strategies

While many Asian refiners have been prepared to collect from Sidi Kerir, Saudi Arabia has started offering to sell to its Chinese customers from the Gulf of Oman, just outside Hormuz. 

Satellite images and ship tracking show a large cluster of Saudi oil tankers waiting in the Gulf of Oman and, simultaneously, a pickup in activity at the kingdom’s side of the Gulf. The country’s state tanker company has a longstanding reputation in the shipping market for being a careful, risk-averse operator.

That points to the possibility the country might arrange for oil to be shuttled from the Gulf and through the strait near Oman or the United Arab Emirates. 

Such a tactic has already emerged as a lifeline for the UAE and some other gulf producers. It has been synonymous with one player in particular: Sinokor, and the intensely private Korean shipping tycoon at its heart, Ga-Hyun Chung. 

The firm is once again involved as Saudi Gulf flows pick up. Three of four supertankers that have carried approximately 8 million barrels of crude from Saudi’s gulf ports since Aug. 11 have been owned by Sinokor, according to shipping data compiled by Bloomberg. 

Sinokor didn’t respond to an emailed request for comment.

Allocations 

The logistics revamp is adding to the strain on Saudi Arabia as it attempts to keep the global market supplied. 

The kingdom notifies countries’ weeks in advance about how much crude they’ll get under so-called term-allocation contracts. 

For the key Asian market, those overall volumes remain well below what customers would normally receive before the Iran war began, according to traders. Saudi Arabia’s overall exports remain below pre-war levels.

The logistics challenges increase the cost of delivering barrels, an expense that has to be borne somewhere in the supply chain. At least one East Asian refiner is considering dropping its loading of Saudi oil for next month due to the added expense.

Still, Japanese and South Korean refiners are largely set to collect their oil next month that’s loaded from the Sidi Kerir, traders said, as concerns about energy security trump the higher costs.

Despite the Gulf of Oman sales, China’s contractual oil-buying is likely to remain solidly below pre-war levels as shipping disruptions around Middle Eastern routes add to transport costs.

By contrast, European oil refineries may benefit from the extra expense that Asia is incurring. Over the past week, several of them received their full allocations of Saudi Arabian crude for September, allaying concerns when the supply-nominations process was delayed by about a week. 

Saudi Aramco declined to comment. The country’s energy ministry didn’t respond to a request to do so. 

©2026 Bloomberg L.P.

Several Russian refineries have recently completed maintenance and started supplying additional fuel, Novak said. 

Russia imposed bans on most exports of gasoline, diesel and jet fuel to protect domestic supplies as Ukrainian drone attacks against the country’s energy infrastructure continue on an almost daily basis. 

The government in Moscow hasn’t yet decided whether to lift its ban on diesel exports by producers currently in force through Sept. 1, Interfax said, citing Novak. “We will monitor the situation and make prompt decisions as needed,” he said. 

Novak chaired a meeting on the domestic fuel market situation on Friday, according to a government statement reported by Interfax. Among other things, he requested optimizing the schedule for planned refinery maintenance to ensure continued domestic fuel supplies.   

©2026 Bloomberg L.P.

Authorities in the Black Sea country will continue emergency dredging near the power plant after its two nuclear reactors were shut down in late July and earlier in August, respectively, because of low water intake for cooling. They’ll also try to build a structure to redirect more water toward the canal that serves the Cernavoda plant. 

The country’s emergency department is also preparing high-capacity pumps to maintain the water level required at the plant. 

Decades-low water levels across Europe’s major rivers, including the Danube, have caused traffic disruptions and forced countries to shut down nuclear plants and reduce power output, boosting energy prices. Romania’s neighbor, Bulgaria, was the latest to announce plans for the first-ever reduction of output at its Kozloduy nuclear plant. 

In Romania, Hidroelectrica, the country’s largest hydro-power producer, will release an additional average of 50 cubic meters of water per second from reservoirs on the Olt River for five days to help bolster the Danube’s flow. The extra water will also be used to generate electricity, the government said in the statement.   

©2026 Bloomberg L.P.

The Houston-based engineering firm had net income of $35.4 million on revenue of $308.3 million in the six months ended June 30, compared with net income of $43.2 million on revenue of $451.4 million in the same period in 2025, according to its filing Friday with the US Securities and Exchange Commission.

Signal Energy, the company’s solar and battery energy storage unit, was founded in 2005, the filing shows. The business and Applied High Voltage, a high-voltage electrical contractor, were together rebranded in May as CoVolt Power, with the two units becoming the main subsidiaries of the combined business.

The company had a $3.6 billion backlog of utility-scale solar, battery energy storage and high-voltage transmission and distribution projects as of June 30, up 410% from a year earlier, according to the filing. It counts independent power producers, utilities, industrial facilities and data center operators among its customers.  

The filing named competitors including Solv Energy Inc., which raised $589.4 million from its IPO in February and closed 13% above its IPO price on Friday.

The company’s backers include investment firms Davidson Kempner Capital Management, Man Group Plc, Eyre Street Capital and Marc Lasry’s Avenue Capital Group.

CoVolt’s offering is being led by JPMorgan Chase & Co. and Jefferies Financial Group Inc. The company expects its shares to trade on the New York Stock Exchange under the symbol KVLT.

©2026 Bloomberg L.P.

Treasury Secretary Scott Bessent said Thursday the administration would give details of the initiative next Monday after President Donald Trump described the push as an “economic D-day.” The measures will target Tehran, and could also ensnare countries that deal with the Islamic Republic, possibly including China.

West Texas Intermediate settled just above $87 to notch a six-session run of gains. Global crude benchmark Brent closed higher as well, ending above $94 a barrel. 

Asian buyers are picking up more US crude shipments, providing a key piece of demand support. Still, elevated oil prices are prompting China’s refiners to keep crude purchases below the high levels seen before the Iran war, even as analysts and industry consultancies estimate imports are edging back toward 10 million barrels a day.

“Asia looks to be back in the buy mode for oil, re-stocking for seasonal needs in front of winter demand,” said Dennis Kissler, head of energy trading at BOK Financial Securities Inc. “While not at the pace of past years it will be a price positive to crude in the near term.”

Beijing — by far the largest importer of Iranian oil — said sanctions and pressure wouldn’t work and called for a diplomatic resolution. In his remarks, Bessent noted that China got much of its energy from the region, while adding that “it would do them a big service to get with the program.” 

Oil has rallied more than 50% this year after the US-Iran war threw the Middle East into turmoil, with the two sides vying for control of the Strait of Hormuz. Bessent said Washington controlled the waterway and ships could exit via a southern lane, according to an interview on CNBC. Still, Tehran has repeatedly insisted it retains authority over the conduit, which saw more vessel attacks this week.

Trump’s threat of increased economic pressure comes after months of military strikes and a full naval blockade of Iran’s ports failed to force Tehran to capitulate. But the Islamic Republic has long faced sanctions, and it’s not clear what further pain the US could inflict on its economy.

“The market narrative is: ‘Iran has been under sanctions for 50 years and will not give in — this will just prolong the crisis further’,” said Arne Lehman Rasmussen, chief analyst at AS Global Risk Management.

Global fuel supplies are also being affected by Russia’s war against Ukraine. Dozens of Ukrainian attacks on Russian refineries and ports have disrupted the country’s energy industry, triggering shortages in some regions and prompting the government to ban exports of most types of road fuel.

That’s contributed to tightness in the global diesel market, with price gains far outpacing the advances seen in crude oil.

In the US, average nationwide retail diesel prices surged above $5.55 a gallon this week, the highest since late May, according to figures from the American Automobile Association. Meanwhile, the margin for making diesel from crude oil in the country recently topped $100 a barrel to hit a record.

Commodities priced in the US dollar including crude have also been supported this week by a further decline in the currency. On Friday, a gauge of the greenback headed for the lowest close since May.

©2026 Bloomberg L.P.

Projects that are not equipped with battery storage are unlikely to find buyers, with almost 42 gigawatts of planned capacity yet to sign offtake contracts, Renewables Secretary Santosh Kumar Sarangisaid on Friday.

Among the most at risk are about 18 gigawatts of solar-only projects and another 14 to 15 gigawatts of capacity awarded at high prices, he said at the BNEF Summit in New Delhi. 

In India, renewables additions have been led by photovoltaic, causing a day-time supply glut, particularly during summers when radiation is stronger. About 11% of solar power generated in India during the hottest months this year was lost to grid curtailments, even as demand hit a record. 

Grids around the globe are struggling to keep pace with the rapid expansion of solar and wind fleets, creating periods of excess electricity that force operators to shut down a portion of generation capacity to protect equipment and prevent blackouts. 

India’s transmission system failed to absorb more than 8 billion kilowatt-hours of power in April to June, when 63 billion actually reached the system. Peak curtailment was seen in May, when scorching heat sent electricity use to all-time high.  

Solar developers are now adding battery storage to attract buyers that need supplies throughout the day, Sarangi said.

Almost 21 gigawatts of the country’s renewable energy projects have only part-time access to the grid, putting them at a greater risk of curtailments, which is hampering expansion and threatening to slow energy transition.

States in the northern and western regions have struggled to build grid networks that match the expansion in solar energy.

©2026 Bloomberg L.P.

The busy Gulf Coast-to-Asia LPG trade typically relies on wider Neopanamax vessels, but these ships are facing increasingly punitive costs to get through the canal. The rates for narrower Panamax tankers, which go through a separate set of locks, haven’t risen as much, traders said. 

Two Neopanamax tankers chartered by Chevron, the Fritzi N and the Pacific Yantai, are slated to receive cargoes of LPG off the port of Balboa, located on the Panama’s Pacific coast, according to shipping fixtures seen by Bloomberg. That is likely to come from Panamax vessels that have passed through the waterway. 

The Neopanamax vessels will then take the fuel — used as cooking gas and in some types of manufacturing — across the Pacific. 

The move underscores how the market is turning to workarounds to cope with maritime congestion due to the Iran war and an intensifying El Niño, which prompted the Panama Canal Authority on Thursday to limit daily slots for September transits. The weather pattern is bringing drought to Central America, which is lowering water levels in the canal, while the conflict in the Middle East has led to an increase in US-to-Asia energy flows.

Around 60% of US LPG exports have gone to Asia so far this year, according to Kpler, up from 55% for the whole of 2025. 

Ships seeking to sail through the Panama Canal typically pay a flat rate via a reservation process. But lengthening waiting times for larger vessels are spurring some shippers to swap reservations, effectively paying more to bypass the regular queue. 

The fee for a Neopanamax tanker that arrives at the canal without booking a slot and wants to transit immediately spiked to an all-time high of $4.6 million last week.

Chevron declined to comment. Anglo-Eastern Ship Management, which is the ISM ship manager for the Fritzi N, didn’t respond to calls and emails seeking comment. SPDBFL No Two Hundred & Twenty-Two (Tianjin) Ship Leasing, which is the owner of the Pacific Yantai, didn’t respond to calls seeking comment. Pacific Gas, the vessel’s ship manager, declined to comment on the matter. 

©2026 Bloomberg L.P.

The energy industry has always operated in cycles. Demand rises. Demand slows. Investment accelerates, then pauses. Supply chains tighten and recover. Priorities shift as markets evolve and technologies mature.

What feels different today is the sheer number of forces moving at once. Electricity demand continues to grow across much of the world. Data centres and artificial intelligence are creating new requirements for reliable power. Geopolitical tensions are reshaping energy security priorities while economic growth and industrial development remain powerful drivers across the board.

Together, these trends are creating one of the most dynamic periods the energy sector has experienced in decades. Too often, energy companies are portrayed as passive observers to these market developments as they unfold, and resilience is viewed as the ability to respond to disruption after it occurs. But the reality is far more nuanced than that. Preparation must start long before demand materialises, and resilience has to be built into the system from the start. 

Building resilience before demand arrives

This requires a shift in mindset. Instead of asking how we react to uncertainty, we should ask how we prepare for it. The answer lies in creating flexibility across the entire energy value chain.

For technology providers, that means maintaining broad portfolios capable of supporting different customer needs, market conditions, and regional requirements. It means investing in manufacturing capacity, strengthening supply chains, developing skilled workforces, and helping customers maximise the value of existing assets through modernisation and long-term service solutions.

These decisions often happen years before market conditions change. Yet they determine how effectively companies can respond when they do. In that sense, resilience is built through choices. A broad technology portfolio creates options. A strong service business creates options. A diversified manufacturing footprint creates options. Long-term customer partnerships create options. Those options become particularly valuable during periods of rapid change.

A broader demand story beyond AI

Much of the public discussion today focuses on artificial intelligence and data centres. Their impact is real and significant. Yet they represent only part of the story.

At Siemens Energy, data centres account for roughly a quarter of our gas turbine demand. The majority still comes from utilities, industrial customers, and countries investing in economic growth, electrification, and energy security. What we are seeing is not a single trend driving the market.

Demand is emerging across sectors, regions, and customer groups simultaneously. That diversity matters. It provides confidence that extends beyond the next project cycle. Today, demand for gas turbines remains visible well into the next decade, extending toward 2035 and beyond. For the gas industry, this has important implications.

Gas-fired power generation continues to play a critical role in modern energy systems. In many regions, it remains one of the fastest pathways to add dependable power at scale, rapidly reduce CO₂ emissions by replacing coal, and maintain security of supply as renewable energy continues to expand. At the same time, flexibility is becoming just as important as capacity.

Some customers require new-generation assets. Others are looking to improve efficiency, modernise existing fleets, extend operating lifetimes, or strengthen performance through long-term service agreements. Supporting these different needs requires more than a single solution. It requires the ability to adapt. This is where scale becomes an advantage.

Companies with diversified capabilities across technologies, manufacturing, service, and regional markets are better positioned to navigate changing conditions than those dependent on a single product, geography, or demand trend. They have more ways to respond when markets shift and more opportunities to support customers through periods of growth, constraint, and transformation.

The lesson for our industry is clear

Uncertainty is unlikely to disappear. Demand patterns will continue to evolve, and technologies will continue to advance. Success will not depend on predicting every market shift correctly. It will depend on building the flexibility, capability, and capacity to respond when those shifts occur. That is resilience by design. And it is becoming one of the defining requirements of the energy future.

The Spring, Texas-based supermajor is seeking to invest billions of dollars in a new oil project at the nation’s Kashagan development, a step that would help to cushion a slide in production at Tengiz, its top deposit.

Tengiz output is set to plateau next year before sliding to about 500,000 barrels a day by 2035 — a slump of about 40% from its high, according to part of a company presentation made to authorities in Astana that was seen by Bloomberg.

Exxon has told Kazakhstan a potential $80 billion joint investment to expand the Kashagan field is contingent on resolving a long-running $150 billion dispute between the government and international companies and a $5 billion environmental fine, Bloomberg reported previously.

The proposed investment, in an equal joint venture with state-owned KazMunayGas National Co., would tap the undeveloped western part of the vast Kashagan reservoir, potentially producing as much as 600,000 barrels a day, Bloomberg reported. KazMunayGas contests Bloomberg’s reporting.

Exxon’s production estimates for Tengiz were based on no large investments being made to boost output — something that may not be the case in reality, people with knowledge of the matter said, asking not to be identified because the presentation was private.

Exxon declined to comment on the presentation. Kazakhstan’s Energy Ministry and Kashagan operator North Caspian Operating Co. didn’t comment.

Chevron Corp., the biggest shareholder in Tengiz, and Tengizchevroil LLC, the development’s operating company, said they are focused on maintaining “safe and reliable operations.” Both Chevron and TCO declined to comment on future production plans. 

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