The Department of Energy warns that blackouts could increase by 100% in 2030 if the U.S. continues to shutter reliable power sources and fails to add additional firm capacity. WASHINGTON— The U.S. Department of Energy (DOE) today released its Report on Evaluating U.S. Grid Reliability and Security. The report fulfills Section 3(b) of President Trump’s Executive Order, Strengthening The Reliability And Security Of The United States Electric Grid, by delivering a uniform methodology to identify at-risk regions and guide Federal reliability interventions.  The analysis reveals that existing generation retirements and delays in adding new firm capacity, driven by the radical green agenda of past administrations, will lead to a surge in power outages and a growing mismatch between electricity demand and supply, particularly from artificial intelligence (AI)-driven data center growth, threatening America’s energy security. “This report affirms what we already know: The United States cannot afford to continue down the unstable and dangerous path of energy subtraction previous leaders pursued, forcing the closure of baseload power sources like coal and natural gas,” Secretary Wright said. “In the coming years, America’s reindustrialization and the AI race will require a significantly larger supply of around-the-clock, reliable, and uninterrupted power. President Trump’s administration is committed to advancing a strategy of energy addition, and supporting all forms of energy that are affordable, reliable, and secure. If we are going to keep the lights on, win the AI race, and keep electricity prices from skyrocketing, the United States must unleash American energy.” Highlights of the Report: The status quo is unsustainable. DOE’s analysis shows that, if current retirement schedules and incremental additions remain unchanged, most regions will face unacceptable reliability risks within five years and the Nation’s electrical power grid will be unable to meet expected demand for AI, data centers, manufacturing and industrialization while

OPEC+ will increase oil production even more rapidly than expected next month, as the group led by Saudi Arabia seeks to capitalize on strong summer demand in its move to reclaim market share. Eight key alliance members agreed to raise supply by 548,000 barrels a day at a video conference on Saturday, putting the group on pace to unwind its most recent layer of output cuts one year earlier than originally outlined. The countries had announced increases of 411,000 barrels for each of May, June and July – already three times faster than scheduled – and traders had expected the same amount for August. The latest increase amplifies a dramatic strategy pivot by the Organization of the Petroleum Exporting Countries and its partners that has weighed on oil prices this year. Since April, the group has shifted from years of output restraint to reopening the taps, surprising crude traders and raising questions about its long-term strategy. Saturday’s decision was based on “a steady global economic outlook and current healthy market fundamentals, as reflected in the low oil inventories,” OPEC’s Vienna-based secretariat said in a statement. The cartel will consider adding another roughly 548,000 barrels a day in September at the next meeting on Aug. 3, according to delegates who asked not to be identified, which would complete the revival of 2.2 million barrels a day of supply shuttered in 2023. After that, the group has another 1.66 million-barrel tier of idle output to potentially consider. OPEC+ is pushing barrels into a market that is widely expected to be oversupplied later in the year. Brent oil futures have retreated 8.5 percent in 2025 as crude production rises both across the alliance and globally, while the threat to economic growth from President Trump’s trade war has cast a shadow on future demand.  Still, oil fundamentals look more

Mexico’s state-owned oil company is throwing Cuba a much-needed lifeline as the Caribbean island struggles to keep its power grid operational amid its worst economic crisis since the collapse of the Soviet Union.  Petroleos Mexicanos sold 3.1 billion pesos ($166 million) of crude and fuel to the communist-run nation in the first quarter of this year through its subsidiary Gasolinas Bienestar, according to a company filing.  The volume of exports — 19,600 barrels a day of oil and 2,000 barrels a day of petroleum products — marks a slight increase from the combined 19,900 barrels a day Pemex shipped to Cuba in the second half of 2023. Cuba has been reeling ever since its lynchpin tourism industry was crushed by the combination of tighter US sanctions during President Donald Trump’s first term and then the Covid-19 pandemic. Rolling blackouts are constant and the national power grid has collapsed multiple times over the past year. The dire conditions have prompted a mass exodus that has shrunk the island’s population by almost one-quarter over the past four years. Mexico’s energy shipments, first reported Sunday by newspaper El Universal, are part of what President Claudia Sheinbaum’s government describes as humanitarian support for Cuba. The island has been subjected to broad US sanctions for more than six decades. The latest sales represent 3.3% of Pemex’s total exports of crude oil and 1.9% of its petroleum product exports, according to the June 23 filing to the US Securities and Exchange Commission. The Mexican company said it has “procedures in place to ensure such sales are carried out in compliance with applicable law.” WHAT DO YOU THINK? Generated by readers, the comments included herein do not reflect the views and opinions of Rigzone. All comments are subject to editorial review. Off-topic, inappropriate or insulting comments will be removed.

Activity in the oil and gas sector contracted slightly in the second quarter of 2025, according to oil and gas executives responding to the Dallas Fed Energy Survey. That’s what the Federal Reserve Bank of Dallas stated last week on a Dallas Fed Energy Survey page on its website, adding that the business activity index turned negative, “declining from 3.8 in the first quarter 2025 to -8.1 in the second”. The Dallas Fed highlighted on its site that this index is the survey’s broadest measure of the conditions energy firms face in the Eleventh District. “The company outlook index was little changed at -6.4, suggesting slight pessimism among firms,” the Dallas Fed noted on its site. “Meanwhile, the outlook uncertainty index increased four points to 47.1, indicating elevated uncertainty,” it added. The Dallas Fed went on to state on its site that “oil and gas production decreased slightly in the second quarter, according to executives at exploration and production firms”. “The oil production index fell from 5.6 in the first quarter to -8.9 in the second quarter. Meanwhile, the natural gas production index also turned negative, declining from 4.8 to -4.5,” it said. Among oilfield services firms, the input cost index increased from 30.9 to 40.0, the Dallas Fed highlighted on its site, noting that this suggests input costs for oilfield services firms rose at a slightly faster pace than in the prior quarter. “Among E&P firms, the finding and development costs index decreased slightly from 17.1 to 11.4,” the Dallas Fed said on its site. “Also, the lease operating expenses index declined from 38.7 to 28.1. This suggests costs for E&P firms rose at a slower pace relative to the prior quarter,” it added. “Oilfield services firms reported modest deterioration in nearly all indicators. The equipment utilization index for

Buru Energy Ltd. said Monday it had received government approval for a two-year extension of time for the Rafael gas project in Australia’s Canning Basin to apply for a production license. Western Australia’s Mines, Petroleum and Exploration Department gave the project until July 2027 to seek a production license. “This approval for an extension of time in which to apply for a Production License for Rafael will allow important work to be completed, including the maturation of technical and commercial work with our development partner, Clean Energy Fuels Australia (CEFA)”, Buru chief executive Thomas Nador said in a regulatory filing. The Rafael gas and condensate field is in Exploration Permit 428, about 150 kilometers (93.21 miles) east of Broome and around 85 kilometers south of Derby in the Shire of Derby-West Kimberley. According to Buru, Rafael is the only confirmed source of conventional gas and liquids onshore Western Australia north of the North West Shelf Project. First drilled in 2021 and confirmed as a discovery the same year, Rafael has been assessed to hold contingent and unrisked gross recoverable volumes of 85-523 Bscf of gas and 1.8-10.6 MMstb of condensate, according to Buru. Buru eyes a 20-year production life. It expects the project to supply trucked liquefied natural gas and liquids to Pilbara and the Northern Territory. Buru plans to drill two wells, including the 2021 discovery, according to a project update published by the company April 9, 2025. It expects to reach an FID (final investment decision) 2027 and start production 2028, according to the April update. Earlier on April 2 it announced a deal with CEFA to co-develop Rafael. CEFA would own the downstream components of the project. “The SDA [strategic development agreement] provides a clear pathway to building a valuable long-term gas and condensate business in the

Dive Brief: The North Carolina Utilities Commission will hold a technical conference on October 14 to address “the rising prevalence of large electric load additions in the region,” it said last month. The commission’s order cited “growing reliability concerns related to large electric load integration,” pointing to North American Electric Reliability Corporation analyses of more than two dozen recent voltage-sensitive load loss events related to data centers and cryptocurrency mines in the Mid-Atlantic and Texas.  The move came less than a month after Duke Energy updated its periodic large electric load forecast to 5.9 GW by 2035, an increase of nearly 2 GW from 12 months earlier, and after Amazon announced it would invest an estimated $10 billion in North Carolina data centers. Dive Insight: In its technical conference order, the commission asked Duke and Dominion to weigh in on whether new tariffs should be developed for some or all customers above a certain demand threshold; whether those tariffs should address customer self-generation, sensitivity to grid disturbances and other reliability issues; cost allocation and potential “stranded cost issues” for new large loads; and possible modifications to North Carolina’s interconnection procedures needed to accommodate large loads. The commission also asked the utilities to provide updates on ongoing negotiations with data centers and other large load customers, including plans for backup generation, co-location with generating facilities and “measures that will need to be implemented to ensure grid reliability and fair cost to customers” for such co-located facilities. Tyler Norris, a Duke University Ph.D student and former renewables development executive who published a widely cited paper on large-load flexibility earlier this year, said North Carolina lacks the transparency needed for the public to gauge the potential impact of proposed large loads on utility rates, the environment and the state’s progress toward its legislative