Alissa Jean Schafer is climate and energy director at Private Equity Stakeholder Project, a nonprofit watchdog group focused on the impacts of private firms on people and the planet. Over a year after announcing its plan to take over Minnesota Power, the Duluth-based utility serving more than 150,000 accounts and several large industrial users, Global Infrastructure Partners, wholly owned by BlackRock, is now waiting on one final step for the deal to close: approval from the Minnesota Public Utilities Commission. If the commission approves, this giant private equity firm would take over ALLETE, the parent company of Minnesota Power. What’s at stake for Minnesota Power ratepayers is their utility being beholden to the private equity business model, notorious for cost-cutting and raising prices for consumers to generate high profits in a short amount of time. If this deal is approved, BlackRock would be making decisions that affect the price people in Duluth pay to light and heat their homes. That risk is not unique to Minnesota. Across the country, private equity firms have been moving into essential public infrastructure — from hospitals to housing to water systems and now utilities — often with similar results: higher costs for consumers, reduced transparency, and decisions driven by short-term investor returns rather than long-term public needs. Minnesota is now on the front lines of this national trend, and what happens here will send a signal to other states about whether regulators are willing to put public interest ahead of Wall Street profit. Against that backdrop, the Minnesota Public Utilities Commission has the benefit of a lengthy review process before Minnesota Administrative Law Judge Megan J. McKenzie. The commission has pages of expert testimony, cross-examination, and deal details to review, including volumes of information labeled “highly confidential” and blocked from public view. Judge McKenzie has

Gas-fired generating capacity accounted for about three-quarters of the 26,575 MW that has applied to take part in the Midcontinent Independent System Operator’s fast-track interconnection review process, the grid operator said Tuesday. MISO received 47 applications for its Expedited Resource Addition Study, which aims to bring power supplies online quickly to meet near-term grid needs. The process allows planned resources that meet eligibility criteria to sidestep MISO’s standard interconnection queue reviews. ERAS projects must meet a clear resource adequacy or reliability need, be able to come online in three to six years and have support from a “relevant electric retail regulatory authority,” such as a state utility commission. Most applications were gas-fired projects, while storage projects accounted for about 15% of the proposed capacity and wind, solar and a nuclear project in Iowa made up about 4.5%, 4% and 2.5% of the capacity, respectively, according to MISO’s list of projects. MISO draws 26.6 GW in fast-track review proposals Gas-fired generation made up about three-quarters of the proposed capacity. “This broad mix underscores MISO’s evolving energy landscape and the urgent need to bring new resources online to address growing reliability challenges,” Aubrey Johnson, MISO’s vice president of system planning, said in a press release. “These projects are designed to meet localized and accelerating demand growth.” MISO will study ERAS projects on a first-come, first-served basis, with the first quarterly study beginning on Sept. 2. Under the ERAS process, MISO will study up to 10 projects per quarter, up to a maximum of 68 projects before the program ends on Aug. 31, 2027. Proposals from Louisiana include five gas-fired power plants totaling 6,170 MW and a 208-MW storage project, according to MISO. Potential projects in Indiana include three gas-fired projects totaling 4,100 MW and three storage projects totaling 1,470 MW. Proposals from Minnesota

The One Big Beautiful Bill Act accelerated the phase-out of key tax credits for solar and wind projects but battery energy storage “retains a relatively stronger position,” Stout, a global advisory firm, said Tuesday in a first half energy update. Battery storage projects will have tax credits available through 2033. However, they will still face headwinds including compliance with new Foreign Entities of Concern restrictions that pose “a significant challenge due to the sector’s heavy reliance on Chinese-dominated supply chains,” Stout noted. “While U.S. energy storage capacity is still expected to grow, the administrative burden of demonstrating compliance with FEOC rules and sourcing non-restricted components could slow development and raise costs, hindering the sector’s long-term expansion,” the firm said. The growth outlook for battery storage is evident in the most Short-Term Energy Outlook published by the U.S. Energy Information Administration on Aug. 7. The report estimates utility-scale domestic storage capacity will rise from about 29 GW at the end of Q1’25 to 65.7 GW at the end of 2026. That’s slightly higher than the 64.9 GW at the end of 2026 that EIA estimated in its June STEO, before the budget bill phasing out renewable tax credits was signed. U.S. developers are planning to bring a total of 64 GW of generating capacity online this year, with more than 18 GW coming from battery storage, EIA said in an Aug. 20 note. Retrieved from U.S. Energy Information Administration. “Battery storage, wind, and natural gas power plants account for virtually all of the remaining capacity additions for 2025,” EIA said in an Aug. 20 note. “If planned capacity additions for solar photovoltaic and battery storage capacities are realized, both technologies will add more capacity than in any previous year. For both technologies, this growth is largely attributable to changes occurring in Texas.”

In a statement posted on its website on Tuesday, GasBuddy, which describes itself as North America’s trusted fuel savings platform for more than 25 years, announced the release of its 2025 Labor Day U.S. gasoline price forecast. According to that statement, GasBuddy is predicting that “average gas prices on the last summer holiday weekend of 2025 will be $3.15 per gallon, 14 cents lower than in 2024, and the lowest price at the pump since Labor Day since 2020”. “While it will be the most affordable Labor Day weekend to fill up for most in the last five years, gas prices in nearly half of all states have risen in the last month due to localized refinery outages,” GasBuddy said in that statement. “However, motorists can expect more relief to arrive in the weeks ahead as much of the nation will see the transition back to cheaper winter gasoline in mid-September,” it added. “Gasoline demand will also soon begin to fall with the conclusion of the summer as motorists take fewer road trips and as temperatures start to cool off,” GasBuddy continued. In that statement, GasBuddy highlighted that the average Labor Day gas price came in at $3.29 per gallon in 2024, $3.77 per gallon in 2023, $3.79 per gallon in 2022, $3.16 per gallon in 2021, and $2.22 per gallon in 2020. “Labor Day marks the unofficial end of summer, and when it comes to gas prices, it’s been the cheapest summer to hit the road since the pandemic, a trend that will likely continue with the potential for the national average to fall below $3 per gallon this fall,” Patrick De Haan, Head of Petroleum Analysis at GasBuddy, said in the statement.   “We’ve seen a remarkably affordable summer to hit the road with incomes up and gas

Phoenix Energy One LLC has reported $18.7 million in net profit for the second quarter, up 122.65 percent from the same three-month period last year. “The increase was largely driven by higher income from operations of $20.1 million, primarily due to higher operated production volumes sold by the company, and higher gain on derivatives of $8.9 million, partially offset by higher interest expense, net of $19 million due to increased sales of our debt securities and increased interest under our term loan that was not payable in the prior-year period”, Irvine, California-based Phoenix Energy said in a statement online. Revenue rose 105.23 percent year-on-year to $163.83 million for the April-June quarter, while EBITDA increased 81.31 percent to $91.98 million. Product sales accounted for $97.26 million of revenue for 2Q 2025, compared to $27.31 million for 2Q 2024. Mineral and royalty revenue totaled $31.99 million, down from $51.6 million for 2Q 2024. Water services contributed $3.7 million in revenue, up from $904,000 for 2Q 2024. Phoenix Energy also recorded $30.8 million in revenue from the sale of purchased crude for 2Q 2025, according to a regulatory filing. Production averaged over 23,800 barrels of oil equivalent a day. Phoenix Energy said it had drilled 23.2 net production wells during the three months. It had 26.6 net development wells in progress at the end of the period. It contracted its third drilling rig, which will support Williston Basin operations. “The company hydraulically fractured its longest laterals to date in the Williston Basin of 3.75 miles and anticipates production from these wells in the third quarter”, Phoenix Energy said. Operating activities in 2Q 2025 generated $99.63 million in net cash, compared to $29.44 million for 2Q 2024. Cash and cash equivalents were $60.49 million at the end of 2Q 2025. Current assets amounted to $156.37

Enterprise Products Partners LP has sealed its purchase of a natural gas gathering affiliate of Occidental Petroleum Corp. operating in the Midland Basin for $580 million in cash. “The acquired assets include certain natural gas gathering systems in the Midland Basin, as well as approximately 200 miles of natural gas gathering pipelines that support Occidental’s production activities in the Midland Basin”, Houston, Texas-based Enterprise said in a statement online. “With access to more than 1,000 drillable locations, these systems will immediately expand Enterprise’s natural gas gathering footprint in the Midland Basin and provide long-term development visibility”. The sale, signed July and completed August, is part of Occidental’s divestment program aimed at keeping debt manageable following its acquisition of CrownRock LP in a $12.4 billion transaction completed last year. “Since July 2024, Occidental has repaid $7.5 billion of debt, including proceeds from non-core Delaware Basin transactions that closed in April and July, and expects to apply an additional $580 million to debt reduction upon closing of the Midland Basin gas gathering divestiture”, the Warren Buffett-backed producer said August 6 announcing the deal with Enterprise. “These transactions bring the total divestitures since the December 2023 announcement of the CrownRock acquisition to approximately $4 billion”, Occidental said. Occidental launched a $4.5-$6 billion asset sale program when it announced its merger with CrownRock December 2023. Occidental said in its annual report for 2024 it had achieved its near-term debt repayment goal of $4.5 billion in 4Q that year.  At the end of 2Q 2025 it owed $433 million in current maturities from long-term debt. Occidental accrued total current liabilities of $8.56 billion as of June, according to a regulatory filing. Meanwhile it had current assets of $8.98 billion including $2.33 billion in cash and cash equivalents. Occidental reported $396 million in adjusted net profit attributable to common shareholders for