Baker Hughes Co has reported record orders of $14.87 billion from its industrial and energy technology (IET) business for 2025, including $4.02 billion for the fourth quarter. “IET achieved a record backlog of $32.4 billion at year-end, and book-to-bill exceeded 1x”, chair and chief executive Lorenzo Simonelli said in an online statement. “For the second consecutive year, non-LNG equipment orders represented approximately 85 percent of total IET orders, which highlights the end-market diversity and versatility of our IET portfolio”. IET delivered $3.81 billion in revenue for October-December 2025, up 13 percent from the prior quarter and nine percent year-on-year. “The increase was driven by gas technology equipment, up $189 million, or 11 percent year-over-year, [and] gas technology services, up $86 million, or 11 percent year-over-year”, Baker Hughes said. Q4 2025 IET orders totaled $4.02 billion, down three percent against the prior three-month period but up seven percent compared to Q4 2024. “The [year-over-year] increase was driven by continued strength in climate technology solutions, industrial technology, and gas technology services”, the Houston, Texas-based company said. Segment EBITDA came at $761 million, up 20 percent sequentially and 19 percent year-on-year. “The year-over-year increase in EBITDA was driven by productivity, volume, price and FX [foreign exchange], partially offset by inflation”, Baker Hughes said. Its other segment, oilfield services and equipment (OFSE), logged $3.57 billion in revenue for Q4 2025, down two percent quarter-on-quarter and eight percent year-on-year. That was driven by declines in its main markets, North America and the Middle East/Asia, with both regions registering quarter-on-quarter and year-on-year drops in revenue. OFSE orders in Q4 2025 totaled $3.86 billion, down five percent quarter-on-quarter but up three percent year-on-year. OFSE EBITDA landed at $647 million, down four percent quarter-on-quarter and 14 percent year-on-year. IET “more than offset continued macro‑driven softness in OFSE, where margins remained resilient

In separate exclusive interviews with Rigzone on Tuesday, Phil Flynn, a senior market analyst at the PRICE Futures Group, and Art Hogan, Chief Market Strategist at B. Riley Wealth, explained today’s U.S. natural gas price drop. “Natural gas is pulling back after the worst of the cold has passed,” Flynn told Rigzone. “We’ve lifted some of the winter storm warnings, and this should allow some of the freeze-offs in the basins to get production back up,” he added. “We saw [a] significant drop in production because of the cold weather and now some of that will be coming back online,” he continued. In his interview with Rigzone, Flynn warned that the weather is still going to be “key”. “Some forecasters are predicting a warm-up, but then after that another blast of the cold,” he said. “If that’s the case … these huge moves in natural gas may be far from over”, Flynn told Rigzone. He added, however, that, “at least in the short term, [a] return to more moderate temperatures from what we had experienced should allow for the market to recover as far as production goes, and exports”. When he was asked to explain the U.S. natural gas price drop today, Hogan told Rigzone that “trees don’t grow to the sky”. “U.S. natural gas prices dipped today amid profit-taking by traders, after soaring by over 117 percent in the five days to Monday,” he said. “The benchmark jumped by 30 percent on Monday alone. Last week, gas prices went up by as much as 70 percent amid frigid weather that apparently took gas traders by surprise,” he added. “This surprise led to frantic short-covering and position exits at a hefty loss. Currently, natural gas is trading at over $6.60 per million British thermal units [MMBtu], which is the highest in

Listen to the article 13 min This audio is auto-generated. Please let us know if you have feedback. Rising demand and new technologies are forcing utilities to coordinate distributed energy resources on an unprecedented scale, a trend likely to continue in 2026, analysts and stakeholders say. But intimidating demand forecasts from power-hungry data centers, coupled with aggressive policy shifts away from renewables and efficiency standards, are turning power providers toward large-scale generation like nuclear, geothermal, gas and coal — possibly to the detriment of aggregation and demand response programs, they say.  “Utilities are shifting away from DER to focus on [utility-scale] wind and solar in the near term and then new natural gas, [extending the life of] aging coal, and [restarting] shuttered nuclear plants,” said Sally Jacquemin, vice president of power and utilities at AspenTech Digital Grid Management, Emerson.  Investment in distribution system modernization is also growing, but DER “is a lower priority,” she added. But grid advocates and utility leaders say distributed resources could provide crucial benefits at a time of rising prices and accelerate the interconnection of large loads, which is a priority of the Trump administration. In order to do that, virtual power plants must evolve and scale more rapidly or skyrocketing electricity demand and costs will force attention to traditional resources, industry sources say. The value of DER to the system will be determined by policies set by states, grid operators, federal regulators and officials in the Trump administration. Allison Wannop, vice president of regulatory affairs and wholesale markets for Sparkfund, predicted that demand growth and affordability challenges will drive innovation to make the most of distribution system resources. “20th century solutions will not build a 21st century grid,” she said.   ‘Visibility will be key to VPP proliferation’ 2025 was a good year for distributed energy

3D Energi Ltd said Tuesday it has voluntarily halted trading on the Australian Securities Exchange (ASX), having defaulted on the payment of its share of costs in a ConocoPhillips-led exploration campaign in the Otway basin offshore Victoria. “Joint venture cash calls for the drilling program are higher than originally forecast and a balance of approximately $2.5 million remains outstanding by the company which it does not currently have”, Melbourne-based 3D Energi said in a stock filing. “A default notice has been issued by the joint venture operator to the company with a remedy period to 6th February. “Additional forecast company drilling program expenditure subject to cash calls due on 6th February is currently estimated at approximately $5.3 million, which if not paid by that date may well become the subject of an additional default notice and remedy period. “Consequently, the company is implementing a suspension of the trading of its shares on ASX while it addresses its funding position and the implications of payment default on the level of its ongoing interest in the permit”. 3D Energi plans to resume ASX trading in the first week of February. Earlier this month it announced the Charlemont-1 gas discovery, the joint venture’s second discovery under the VIC/P79 exploration after Essington-1. The newest well targeted the penultimate prospect in the Charlemont trend, which culminates with the La Bella discovery, according to 3D Energi. “Phase 1 of the Otway Exploration Drilling Program has identified important new natural gas resources close to existing offshore gas production and processing infrastructure in the Otway basin, supplying the Australian domestic gas market”, 3D Energi executive chair Noel Newell said in a statement January 14 announcing the second discovery. “This enhances the strategic significance of the discovery and supports future development optionality, subject to further technical and commercial evaluation,

The U.S. Energy Information Administration (EIA) projected that the U.S. natural gas Henry Hub spot price will drop this year and rise next year in its latest short term energy outlook (STEO). In the EIA’s January STEO, which was released on January 13 and completed its forecast on January 8, the EIA forecast that the commodity will average $3.46 per million British thermal units (MMBtu) in 2026 and $4.59 per MMBtu in 2027. The U.S. natural gas Henry Hub spot price averaged $3.53 per MMBtu in 2025, the EIA’s latest STEO showed. According to a quarterly breakdown included in its latest STEO, the EIA sees the U.S. natural gas Henry Hub spot price coming in at $3.38 per MMBtu in the first quarter of 2026, $2.75 per MMBtu in the second quarter, $3.42 per MMBtu in the third quarter, $4.28 per MMBtu in the fourth quarter, $4.78 per MMBtu in the first quarter of 2027, $4.30 per MMBtu in the second quarter, $4.43 per MMBtu in the third quarter, and $4.84 per MMBtu in the fourth quarter of next year. Last year, the Henry Hub spot price averaged $4.15 per MMBtu in the first quarter, $3.19 per MMBtu in the second quarter, $3.03 per MMBtu in the third quarter, and $3.75 per MMBtu in the fourth quarter, the EIA’s January STEO showed. “On an annual basis, U.S. natural gas prices are relatively flat in 2026 before rising in 2027 as market conditions tighten,” the EIA said in its latest STEO. “We expect the Henry Hub natural gas spot price will average just under $3.50 per million British thermal units (MMBtu) this year, a two percent decrease from 2025, and then rise by 33 percent in 2027 to an annual average of almost $4.60 per MMBtu,” it added. In its STEO,

(Update) January 26, 2026, 9:39 PM GMT: Article updated with pricing details in first three paragraphs. Saudi Aramco priced a $4 billion bond sale, its first note sale this year, as the world’s largest oil producer steps up borrowing to fund investment and dividends. The government-owned oil producer sold four bonds maturing in three to 30 years, according to a person familiar with the matter. The longest portion of the deal will pay 1.3 percentage point above Treasuries, said the person, who asked not to be identified because they are not authorized to speak publicly. That’s roughly a quarter-point less than initial pricing discussions. Overall, the sale attracted more than $22 billion of bids at the peak, with final books over $14 billion, the person said. Aramco is a key contributor to Saudi state finances, with large dividend payments supplementing royalties linked to crude sales. As oil prices have dipped and OPEC+ policy limited Saudi production, cash flows lagged payouts before a rebound in the third quarter. Aramco’s $17 billion in debt sales over the last two years helped support payouts. Saudi Arabia’s budget remains heavily dependent on oil revenue as the kingdom pursues an ambitious modernization drive. Crude prices remain well below levels needed to balance the state budget, forcing the government to project spending shortfalls for the coming years. Aramco has turned to debt to augment its cash flow and plans to invest more than $50 billion this year in oil and natural gas production, while maintaining its high base dividend of $21 billion. In November, the company reported a surprise jump in third-quarter profit as rising production outweighed lower crude prices. Earnings are set to slip for the full year, estimates compiled by Bloomberg show. While Brent crude has risen this year amid geopolitical tensions, including US attacks on