Energy market analysis Aug. 13, 2025

“The average breakeven price for producers in the Permian Basin is now falling back toward $65, down from around $55 two years ago.” – Standard Chartered

Standard Chartered sees higher long-term prices as shale costs rise.

Oil prices will trend higher in coming years as the cost of U.S. shale has shifted significantly upward, according to Standard Chartered Bank. This reports OilPrice.com. While crude oil prices hover around $70 per barrel, near the 20-year average of $73.38, Standard Chart notes that break-even costs in the shale patch have risen sharply. According to the bank, the average break-even price for these producers is creeping toward $65. Two years ago, that level was around $55 per barrel. The increase is caused by higher costs for steel, labor and frac materials, in part because of U.S. tariffs.

Analysts at Rystad Energy and Wood Mackenzie share the view that current oil prices are unsustainably low for the shale industry. Rystad estimates break-even prices for new horizontal wells at about $68 per barrel. Wood Mackenzie warns that without a firmer price floor, the number of wells will absolutely decline. Both companies point to tight capital budgets, cautious reinvestment and a continued investors’ focus on returns rather than growth.

According to OilPrice this outlook appears as crude oil prices hit a six-week high, fueled by geopolitical tensions and trade developments. President Trump extended the deadline for Russia to implement a cease-fire with Ukraine by more than two weeks. This unexpected extension surprised many analysts. If the measure is actually enforced, it could limit the supply of Russian crude oil and fuels on the global market, BOK Financial Securities expects.

Oil prices also found support from a trade agreement between America and the EU that prevented escalation into a full-blown trade war. Under the agreement, EU exports to the Americas will not see tariffs higher than 15%. This gave calm to markets worried about a broader slowdown in trade.

The price rise was tempered somewhat by a better-than-expected increase in U.S. oil inventories, reported by the Energy Information Administration (EIA). Although stocks remained 6% below the five-year seasonal average, the weekly increase was much larger than the figures previously reported by the American Petroleum Institute (API). This also surprised traders.

With U.S. shale production under pressure and increasing global geopolitical risks, Standard Chartered’s bullish view reflects a tightening supply picture. Many analysts see maintaining prices above current levels as essential to stabilize U.S. production. A dynamic that could harden the Trump administration’s stance toward Russia.

Brent October price trades below daily cloud, now resistance. The lagging line is still above the cloud. The peak above $77.50 was at the height of the Iran-Israel conflict.

Price Crude oil – Brent October 2025 ($/barrel) – day cloud candle, log scale

“Aging grid infrastructure, new renewable energy generation, increasing electrification, more electric vehicle charging stations and new data centers are all contributing to the rising demand for these machines.” – IEEE Spectrum

An undetected vulnerability that could cripple the U.S. power grid

Waiting times for US transformers have more than doubled, from 1 to nearly 2.5 years. This puts the resilience of the power grid at risk during emergencies such as wildfires, storms or attacks. The “Build America, Buy America Act (BABAA)” and global demand for transformers have limited supply. Domestic production covers only 20 percent of the need. Experts warn that the grid remains dangerously unprotected which could lead to major blackouts.

Transformers are typically used to bring down the voltage. Utilities use high voltages to transport electricity over long distances because it is more efficient. The electricity voltage is then reduced to the level suitable for customers.

U.S. trade policy complicates matters for the American grid. The provisions of the BABAA, part of the Infrastructure Investment and Jobs Act passed under Biden, require substantial, and in some cases 100% domestic content for goods and services. These are used in a wide range of nationally funded infrastructure projects, including grid maintenance and expansion. And few infrastructure projects are undertaken without some form of U.S. government funding.

America itself produces only 20% of the equipment needed for its electricity and transmission system. Even if America did not restrict the supply of these goods through the requirements of BABA, the wait times would also be long. The waiting time for a new transformer was 50 weeks when the Infrastructure Act was passed. Today, the wait is more than 2 years for most transformers. For specialized transformers even 4 years.

There has been a perfect storm for manufacturers due to the rapidly increasing demand for transformers. According to IEEE Spectrum, this rising demand is driven by aging grid infrastructure, new renewable energy generation, expanding electrification, more EV charging stations and new data centers. This demand is global, including from fast-growing Asia, the European Green New Deal and America’s significant spending on infrastructure to expand green energy and for grid readiness to enable this expansion.

World’s largest transformer manufacturers are stepping up production, but this will take years. In addition, many transformers are customized for a specific installation. Obviously, these more complicated ones take longer to build. By definition, these cannot be standardized for mass production.

Another danger lurks in the background. Transformers are vulnerable to electromagnetic pulses. Whether caused by a solar storm or by an atomic weapon. The ability to detonate an atomic weapon high in the sky, creating a powerful electromagnetic pulse, has forced military armies around the world to fortify their war equipment, including air power and communications equipment, to be resilient to an electronic blackout that can take an aircraft out of the sky and shut down communications.

Nothing similar has been arranged for civic infrastructure. That means that, even without a nuclear war, an intense solar storm could one day cause similar devastation that could knock out most of the power grid. In that case, new transformers would be needed. But there simply aren’t millions of spare copies available to replace the damaged ones. We can no longer imagine a world without electricity.

The last major solar storm that would have been capable of this occurred in 1859, even before the emergence of our modern electrified society. Even as the current grid is expanded to meet the assumed needs of artificial intelligence and green energy production, it is advisable to take additional precautions to protect against known catastrophic dangers of electromagnetic pulses.

How much electricity do data centers use?

Data center demand is growing at breakneck speed, with little sign of slowing.

If AI’s electricity consumption increases, a projected 12% of U.S. electricity demand could be driven by data centers by 2028. Outside America, countries are putting billions into AI sovereignty efforts that require data centers to run facilities 24/7 and thus require permanent electricity.

The following analysis of IEA data shows current demand from data centers as a share of total electricity consumption.

Demand from U.S. data centers leads the list with 8.9% of national electricity consumption. In the U.S. state of Virginia, data centers account for 26% of the state’s total electricity consumption, nearly three times the national average. This year, the state’s largest utility expects to connect 15 new data centers, given the increasing demand. By comparison, European data centers use 4.8% of total electricity consumption in the European Union, in China 2.3%.

By 2025, global data center capacity will have grown to 114.3 GW.

Now big tech’s AI investments is increasing, a significant portion is being redirected to large-scale data centers, along with the energy resources needed for them. Demand for nuclear in particular is expanding at the fastest pace in decades.

In both America and Europe, digitalization, AI and the energy transition continue to put great pressure on aging power grids. Without massive investment and reform, both continents risk rising costs, supply uncertainty and conflict over who should pay these new energy costs.

The weekly chart of electricity delivery year 2026 already shows a large horizontal range from April 2024, after the sharp bottom of February 2024. The upward or downward trigger will have to come from the gas market.

Price Baseload Electricity supply year 2026 (eur/MWh) – week cloud candle, log scale

“US oil flows would have to be diverted entirely to the EU to meet the target, or the value of LNG imports from America would have to increase sixfold.” – Arturo Regalado, LNG analyst Kpler

Beyond realistic: Europe’s promise to buy $750 billion U.S. energy is impossible.

As part of the trade agreement between America and the EU, the latter is obliged to buy US energy products to the unimaginable value of $750 billion over 3 years. Including LNG, oil and nuclear fuel. This is just the big picture. Neither side has detailed what exactly is covered by this energy agreement. Nor whether it involves energy services, components for power grids or power plants.

There is only one problem: this amount is unrealistic because in that case virtually all U.S. energy exports would have to go toward Europe. This while the EU has little control over the energy imported by European companies. As Rabobank explains, that number remains beyond any realistic expectation unless energy prices rise sharply.

The EU imported roughly €65 billion in energy products from the Americas in 2024. Including €20 billion (35 million tons) of U.S. LNG and €44 billion of oil and oil products. To reach the required $250 billion per year, the EU must import roughly 67% of its energy needs from America, based on Eurostat data from 2024.

Even if the EU got its LNG entirely from America, the total would increase to only €40-50 billion, based on 2024 prices. This would require countries like Russia, Algeria, Qatar, Nigeria and even Norway to give up their entire market share in the EU. The U.S. government should require its LNG exporters to give Europe priority. The shift in crude oil and refined product flows would have to be even more substantial to meet the $250 billion annual target, since the EU currently imports only 17% of its needed volume from the Americas. Existing suppliers in the Middle East and India are unlikely to want to give up market share without significant economic incentives when U.S. refining and export capacity is already well stretched.

Capacity, cost and competition will continue to determine energy flows regardless of political intent.

Looking at it the other way around produces a similarly unrealistic picture. Total U.S. energy exports worldwide were $318 billion in 2024. Of this, the EU imported a combined $76 billion of U.S. petroleum, LNG and solid fuels such as coal in 2024, according to Reuters.

America is currently the largest supplier of LNG and oil to the EU, accounting for 44% and 15.4% of needs, respectively. The war in Ukraine and the sabotage of Nordstream have increased dependence. According to Aurora Energy Research, a significant expansion of U.S. LNG capacity would be needed to meet European demand, but the required investment of $250 billion makes is unrealistic in the short term. Europe could import as much as $50 billion more of U.S. LNG annually if supply increases.

It is also notable that higher fuel purchases by the EU are diametrically opposed to predictions that EU demand is decreasing due to the shift toward clean energy. European oil demand peaked several years ago, according to analysts.

The most plausible outcome of the energy provisions within the trade agreement is increased European participation in U.S. LNG projects , according to Rabobank. That, incidentally, would have been achieved even without the agreement. Unlike crude oil and refined products, LNG offers scalable, long-term opportunities through joint investments in so-called liquefaction capacity and infrastructure. Liquefaction stands for the liquefaction of LNG transported in a frozen state of about -150 degrees.

European companies are likely to commit capital toward U.S. terminals for securing future supply and diversity away from Russian gas. However, this will not significantly change the market balance over the next 5 years.

The TTF gas price for delivery year 2026 seems to have found support around €32.50. With this move, the gap from early May can be considered filled. Gaps, the space between candles up or down, occur when the opening price falls outside the area of the previous day’s range. These price gaps often act as a magnet for price by first attracting and then repelling the price. Either way, the market will decide.

Price TTF gas supply year 2026 (eur/MWh) – day cloud candle, log scale

“These types of regulatory measures are hampered by the nature of data centers themselves, which need power 24/7 and have little need to reduce demand during peak periods.” – Abbe Ramanan, Clean Energy Group project director

Coal and gas power plants have a new best friend: data centers.

In 2020, the Virginia Clean Economy Act was passed, a law that required the state’s largest utility, Dominion Energy, to produce all electricity from renewable sources by 2045. However, Dominion has found a useful loophole to get out from under this requirement, namely data centers.

Virginia is host to the largest data center market in the world. This state is home to at least 150 hyperscale data centers, with more in the pipeline. In its recent integrated resource plan, Dominion predicted demand from these data centers as the primary reason for delaying the retirement of existing power plants, including Clover Power Station, a coal-fired peaker plant in Halifax County. In addition to this retirement postponement, Dominion has proposed building new gas-fired power plants. Such as a 1-GW peaker plant in Chesterfield, a community already burdened by a huge environmental burden from existing natural gas and coal production.

Similar stories are playing out as data centers become more ubiquitous, especially in the Southeast. Utilities in Virginia, Georgia and North and South Carolina have announced plans to build a total of 20,000 MW of new gas-fired power plants by 2040. This expansion is justified primarily by growing electricity demand from data centers. In Virginia, Georgia and South Carolina, data centers account for at least 65% of the projected increase in power consumption.

Growth in data centers is also delaying the closure of fossil fuel power plants across the country. With at least 17 fossil fuel generators, originally scheduled to be closed, now seeing their retirement postponed.

The gas bonanza is especially worrisome because the predicted demand growth of data centers could be significantly exaggerated. Many potential customers will make speculative interconnection requests, sometimes in multiple states at once. This inflates demand figures and makes accurate forecasts difficult. A study last year by Lawrence Berkley National Lab highlights these discrepancies between future demand forecasts. The low side forecasts in the report estimate that data centers will use 6.7% of all U.S. energy by 2028, while the high side estimate is 12%. A difference of 255 terawatt hours of energy, equivalent to the energy consumption of more than 24 million households.

Besides the well-known problem of speculation, utilities have an incentive to use exaggerated demand claims to justify building new infrastructure. Regulated utilities like Dominion are guaranteed a healthy return for power plant construction. They can pass on the cost of this construction to customers through higher rates. In many cases, these customers will also be billed for the transmission upgrades needed to serve large customers.

Aging peaking power plants, which are among the most expensive and polluting energy producers, remain operational and impose additional costs on customers. In several U.S. states, energy bills are expected to increase by $40 to $50 per month due to grid investments driven by the growth of data centers.

To control these costs, utilities are looking for solutions. Dominion in Virginia has proposed a new rate structure for large consumers such as data centers. This structure requires a 14-year contractual commitment, with customers paying for requested capacity regardless of actual usage.

In Ohio, American Electric Power has a similar model implemented. Data centers there must pay monthly for 85% of their forecasted energy needs and demonstrate that they are financially stable enough to meet this obligation. If a project is cancelled, an exit fee applies, intended to limit speculative requests for grid connections.

Steps are also being taken at the policy level to reduce the impact of data centers. In California, lawmakers have proposed offering tax breaks to data centers that get at least 70% of their energy from renewable sources. In addition, these centers must disclose their energy consumption.

In North Carolina, a Duke Energy green rate proposal has been approved that would allow data centers to accelerate their solar power projects to meet future demand. The proposal is controversial because Duke is required by law to reduce its carbon emissions by 50% by 2050. Critics argue that the fee may amount to a subsidy for projects that otherwise would have been built.

Regulation around data centers is complicated by their constant energy demands and limited flexibility during peak hours. Large technology companies with ambitious decarbonization goals are therefore taking their own initiative to make their power supplies more sustainable and secure carbon-free electricity. Microsoft, for example, signed a Power Purchase Agreement (PPA) last year to restart a nuclear facility on Three Mile Island.

Read here more about Power Purchase Agreement options.

The pursuit of nuclear-powered data centers has also raised greater concerns about the impact on the grid. Nuclear power plants provided nearly half of the carbon-free electricity produced in America in 2023. The more nuclear capacity bought up by tech companies, the greater the risk of energy being replaced by more polluting forms of generation.

Unlike gas and electricity for delivery year 2026, coal’s price and lagging line are both below the weekly cloud. So currently resistance from this area.

Price ICE Coal delivery year 2026 (usd/t) – week cloud candle, log scale

“It is rare that scientists of this caliber (with backgrounds at NASA, IPCC and major universities) have the opportunity to directly challenge prevailing policy narratives with government resources behind them.” – Anthony Watts

Devastating report reveals abuse of ‘established’ climate science and role in net zero.

A recent US Department of Energy report fundamentally criticizes the scientific basis and policy assumptions behind net-zero climate goals. The report, prepared by five independent scientists, argues that climate models are not sufficiently reliable and that many predictions about extreme weather events and sea level rise are not supported by empirical data.

The report emphasizes that natural climate variation is often ignored and that models were originally designed with legal purposes in mind. It also criticizes the use of the extreme emissions scenario RCP8.5, which the authors say is no longer plausible but is nevertheless widely used in policymaking and media.

In addition, the report points to positive effects of higher levels ofcarbondioxide, such as global greening and improved crop growth, which receive little attention in official climate publications. The authors criticize the role of organizations such as World Weather Attribution, which they say publish methodologically weak and legally motivated analyses.

Finally, they conclude that the wide variation among climate models and the lack of historical weather data make it difficult to make reliable statements about future climate changes. The authors call for a review of scientific and policy approaches to climate issues.

The daily chart of CO2 rights looks robust for a potential upside move. Price and lagging line are above the daily cloud. Apart from a few dips, the price remains neatly above €70 per tonne in a range well above the low around €60 in April this year. It is almost a textbook pattern for forming a higher bottom. The outlook is bullish for now.

Price Emission Rights – Dec-25 contract EEX (eur/t) – day cloud candle, log scale

The green hydrogen hype is ebbing away.

The global green hydrogen market is under pressure due to high costs, limited demand and regulatory uncertainty. More and more billion-dollar projects are being postponed or cancelled, while major energy companies are pulling back and shifting their focus to oil and gas. Policies are proving as yet insufficient to stimulate the necessary market demand.

According to the International Energy Agency (IEA), low-carbon hydrogen, including green hydrogen produced via electrolysis with renewable energy, remains only a small part of total hydrogen consumption. Most of the demand still comes from the refining and chemical sectors and is largely met by fossil-produced hydrogen.

The IEA points to a series of obstacles that impede scale-up: unclear demand signals, financing problems, permitting processes and operational challenges. Without strong government intervention and targeted incentives on both the supply and demand sides, large-scale adoption of green hydrogen remains unfeasible.

By 2025, the number of cancelled projects worldwide accelerated. Major players such as Shell, Equinor, BP and Fortescue withdrew from ambitious plans in Europe, America and Australia, among others. In the U.S., the “One Big Beautiful Bill Act” tightened regulatory pressure by accelerating the phasing out of tax breaks. In Australia, the $36 billion AREH project was abandoned by BP, dealing a sharp blow to national hydrogen ambitions.

The key message: the promise of green hydrogen remains great, but economic realities and lack of market demand make large-scale investment unattractive for now without robust government support.

The recent Dutch subsidy of €700 million for 11 green hydrogen projects is in sharp contrast to the global situation. The money comes from the MRA subsidy scheme opened last year with the aim of reducing the price differential between fossil and renewable hydrogen and increasing domestic production capacity. A total of €3.2 billion in subsidies was applied for, of which more than €700 million was awarded to 11 companies.

The subsidized projects account for some 602 megawatts of electrolysis capacity. That is more than three times the production volume of the currently largest hydrogen plant under construction, the Holland Hydrogen 1. Intended hydrogen customers include refineries, the chemical industry or gas stations.

The subsidy will close the price gap between renewable and fossil hydrogen. A total of €998 million in subsidies was available. The Cabinet is currently investigating whether companies can subscribe to the remainder of the subsidy budget. The feasibility depends on European state aid rules.