Ameren’s Missouri utility subsidiary plans to construct an 800-MW simple-cycle gas plant alongside a 400-MW battery storage facility in Jefferson County to meet rising electricity demand, the company announced last month. The Big Hollow Energy Center is designed to “efficiently meet increased energy demands while ensuring grid resiliency,” Ameren said. The lithium-ion battery will be Ameren’s first first large-scale storage facility, though the utility is planning to have 1 GW of battery storage online by 2030 and 1.8 GW by 2042. “This is the next step to deliver on our strategy to invest in energy infrastructure for our customers’ benefit and provide a balanced generation portfolio,” Ameren Missouri President and Chairman Mark Birk said. The gas plant and battery storage “will operate independently,” leveraging energy infrastructure on land Ameren already owns to reduce construction time and cost, the utility said. “It is crucial to have a balanced mix of generation technologies and equally important to strategically locate them across the region,” said Ajay Arora, senior vice president and chief development officer at Ameren Missouri. “This approach maximizes the energy output from these resources.” The Big Hollow project could be online by 2028, Ameren said, “with timely regulatory approval.” Ameren in February announced a shift in its preferred resource plan to provide for 1.5 GW of anticipated new energy demand by 2032. Along with storage, Ameren is planning to build 1.6 GW of gas generation resources by 2030, with a total planned addition of 6.1 GW by 2045. “Building off the success of bringing in nearly two dozen new economic development projects in 2024, Ameren Missouri has construction agreements with potential large load customers for new energy demand,” the utility said. Ameren also filed an updated Smart Energy Plan with the Missouri Public Service Commission in February. The $16.2 billion, five-year plan calls for

The world’s biggest oil product market is hungry for barrels as traders grapple with a summer supply squeeze. US stockpiles of diesel products have dropped to the lowest for the time of year since 1996, while in Europe benchmark futures are signaling a tighter market than during the height of the Israel-Iran conflict. The cost of the fuel relative to crude — a key trading metric known as the crack — is well above seasonal norms in both regions. The pressure on supplies has been driven by refinery closures on both sides of the Atlantic and a slew of recent outages, as well as the impact of production curbs by key OPEC+ producers. Last month, diesel accounted for just 31.4% of global output of oil products, well below the seasonal average, according to figures from Energy Aspects Ltd. The shortage is driving up prices for diesel, used in everything from construction to transport to heating. In northwest Europe, the premium for more immediate supplies over the following month surged to $44 a ton on Friday; excluding the often volatile days when futures contracts expire, that’s the strongest since late-2022. “The Atlantic Basin diesel balance is looking increasingly tight into autumn refinery maintenance season and peak winter demand,” said Natalia Losada, an oil products analyst at Energy Aspects. “European inventories may not build in July, which leaves them in a very fragile position.” Diesel markets spiked last month when the fighting between Israel and Iran threatened millions of barrels of fuel exports from the Persian Gulf. That risk has now receded, but supplies remain under pressure. The biggest of the OPEC+ output cuts came from Saudi Arabia and Russia, both of which pump crude at the heavier end of the spectrum. Meanwhile, Kazakhstan boosted output of its very light Tengiz crude earlier this year. “OPEC+

British energy giants BP Plc and Shell Plc signed agreements with Libya’s National Oil Corp to study new opportunities, joining international majors accelerating their return to the oil-rich African nation. BP, which has pivoted away from its failed low-carbon strategy to focus more on fossil fuels, signed a memorandum of understanding to study reviving two huge oil fields in Libya, it said in a statement on Tuesday. The document outlines a framework for how the energy companies might work together and assess a range of technical data.  Separately, a Shell spokesman confirmed the company has signed a MOU with NOC “to study potential opportunities in the country’s oil and gas sector.” The focus on Libya, a member of the Organization of the Petroleum Exporting Countries, comes as the North African nation tries to bring back oil majors that left. Libya has struggled to quell unrest since the 2011 fall of longtime dictator Moammar Qaddafi. The country, which has the biggest-known crude reserves in Africa, is split between two governments that frequently feud over control of under-invested oil resources. Ever since the civil war, which led to a slump in Libya’s production by about 18-fold to around 100,000 barrels a day in 2011, output has been volatile. The North African nation has pumped about 1.2 million to 1.3 million barrels a day in recent times, though that has had some wild variations. It has a goal of boosting output to 2 million barrels a day in a few years. Starting last year, international companies, including BP, Italy’s Eni SpA, Spain’s Repsol SA and Austria’s OMV AG, resumed drilling in Libya, ending pauses in place since 2014. Libya is currently running its first tender for energy exploration contracts since the 2011 civil war. BP’s agreement “reflects our strong interest in deepening our

Nainish Gupta is director of REC portfolio and regulatory compliance at POWWR, an energy software company. After years of shifts towards widespread renewable energy adoption, presidential executive orders are pausing federal investments in new wind and solar projects, slowing the development of clean energy supply chains and manufacturing. The leasing of federal lands for renewables has also been rolled back, limiting the expansion of large-scale projects. In the first quarter of 2025, clean energy manufacturers canceled, closed or downsized nearly $8 billion in projects. Tariffs are also making solar panel installations more expensive, since about 75% of panels come from China. At the same time, the policy changes benefit the expansion of fossil fuels: they lift restrictions on oil, gas and mineral production in Alaska and expand drilling in places like the Alaska National Wildlife Reserve. These moves open areas for development and revive the natural gas industry, which could pose a risk to wildlife and natural habitats. Simplifying the approval process for natural gas pipelines could also speed up construction, but it might overlook environmental assessments. Retail energy suppliers are already feeling the effects of increased price volatility and rising compliance costs. To navigate this new reality, suppliers need to focus on three smart strategies: Buy renewable energy certificates (RECs) now, leverage data and predictive analytics to make more informed decisions, and grow market share. Getting ahead of REC price increases With fewer renewable projects on the horizon, the supply of RECs is tightening. Yet, state renewable portfolio standards are not going anywhere, and will continue to require retail suppliers to acquire a certain percentage of RECs based on the region and their portfolio size. That supply imbalance, paired with an increased demand, guarantees that prices will go up. The best way for suppliers to mitigate risk is to

Load growth, plant retirements could drive 100x increase in blackouts by 2030: DOE | Utility Dive Skip to main content An article from Dive Brief The U.S. Department of Energy on Monday published a methodology for assessing grid reliability, but clean energy advocates say it likely exaggerates the risks of blackouts. Published July 8, 2025 Power outage hours could increase from single digits today “to more than 800 hours per year,” the U.S. Department of Energy said in a report published July 7, 2025. Marizza via Getty Images Dive Brief: Blackouts could increase by 100 times in 2030, relative to today’s averages, if the United States continues to shutter power plants and fails to add additional firm capacity amid rising demand, the U.S. Department of Energy said in a Monday report. The report includes a uniform methodology to identify regions at risk of power outages and guide federal reliability “interventions,” DOE said. The report was required by President Donald Trump’s April executive order which directed the agency to respond to an “energy emergency” he declared in January. But clean energy advocates say the report appears to exaggerate the risks, and undercount the contributions of wind, solar and battery storage resources. “If the analysis is overly pessimistic about advanced energy technologies and the future of the grid, consumers will end up paying too much for resources we no longer need,” Caitlin Marquis, managing director at Advanced Energy United, said in an email. Dive Insight: DOE’s report assumes 104 GW of plant retirements by 2030, alongside the addition of 210 GW of new generation — but only 22 GW of the additions will be “firm, reliable, dispatchable generation.” “Modeling shows annual outage hours could increase from single digits today to more than 800 hours per year. Such a surge would leave millions of households and

The PJM Interconnection’s market monitor on Monday urged federal regulators to set conditions on a pending $12 billion deal between NRG Energy and LS Power citing concern over potential market abuses. Under the planned transaction, NRG would buy from LS Power 18 natural gas-fired power plants, totaling about 13 GW across nine states, some of which fall in PJM’s territory. NRG would also acquire CPower, a commercial and industrial virtual power plant platform that has about 6 GW of capacity and operates in all deregulated markets in the U.S., according to a news release announcing the deal.  Setting conditions on the deal would help prevent NRG from exerting market power, Monitoring Analytics, PJM’s independent market monitor, said in a filing at the Federal Energy Regulatory Commission. The companies expect to close the deal early next year, subject to FERC and other approvals. Without the conditions, Monitoring Analytics said it would oppose the transaction because it would increase NRG’s ability to affect electricity and capacity prices. Under the pending deal, NRG’s capacity in PJM would jump from about 2.1 GW to 9.5 GW. The transaction would also add to NRG’s emergency and pre-emergency demand response capability. Even with the increased capacity, NRG and LS Power contend that NRG would be unable to exert market power, according to their June 12 application at FERC. However, the transaction would increase NRG’s market power in some parts of PJM, according to Monitoring Analytics. Also, under PJM’s market conditions, capacity prices are likely to continue being “very high,” the market monitor said.  “The market conditions and structural market power increase the potential impact of market power on customers under the current market structure,” it said. The market monitor said it is concerned that NRG would be able to affect capacity prices using its increased ownership in emergency and