Utility leaders are managing a hard reality. Load is growing faster than the grid was built to handle, increasing the likelihood of costly upgrades and rate pressure. AI-driven data center development is making headlines as a major source of load growth. These projects are large, fast-moving and highly visible, drawing public attention and political scrutiny. Utilities and commissions are now facing the question: “How do we add capacity quickly, without overbuilding the grid and pushing costs into rates?” One of the most promising answers is leveraging distributed load flexibility. With distribution-level orchestration, this flexibility can enable utilities to serve growing loads on existing distribution infrastructure, supporting affordability for all customers. Bottom-up load growth requires bottom-up solutions Distributed load flexibility refers to the growing share of new electricity demand that is spatially distributed across the grid and can be shifted temporally. The flexibility opportunity now includes electric vehicles, batteries, heat pumps, smart water heaters and connected building systems. These grid-edge devices are distributed across homes, workplaces and commercial zones. Adoption of these resources is accelerating and many already respond to price signals and automation. Managed EV charging is a common example. A vehicle may be plugged in overnight but only needs a few hours of charging. When charging is scheduled to avoid bottlenecks, that flexibility becomes a real capacity tool for the utility. However, many programs, price signals and planning tools were designed for bulk system needs. Time-of-use rates and demand response reduce system peaks by telling every device to do the same thing: shift away from the bulk system peak. The “just shift it off-peak” solution misses a significant risk. Flexibility without orchestration simply moves the problem rather than solving it. EV charging can synchronize around the same low-cost hours. Batteries can do the same if they charge in identical

For decades, municipalities and utility companies have buried water mains, gas lines, fiber optic conduits, power cables and other vital infrastructure under streets and sidewalks. Burying these systems improves safety, reliability and aesthetics, but it also creates a long-term problem: once installed, many of these utilities become practically invisible. The ground protects and hides them, but over time the memory of where they run becomes foggy. Records age, streets are widened or rerouted and even highly accurate GPS coordinates can drift or lose relevance as the surface infrastructure changes. The result? What was once a known network of pipes and cables becomes a metaphorical “lost treasure.” When crews dig — for maintenance, upgrades or new construction — that invisibility can turn into a disaster. Minor incidents are common: broken lines that cause service disruptions and headaches. But sometimes the consequences are far worse: ruptured gas mains, flooding from damaged water or sewer lines, or severed fiber cables; all capable of causing serious safety hazards, costly repairs and major public inconvenience. The limitations of “traditional” locating Historically, locating buried plant often relied on conductive materials (metal pipes, conduits or tracer wires). These can be detected with standard locating equipment. But since the 1970s, many new installations, especially gas, water and fiber optic conduits, have been built using nonconductive materials such as PVC or HDPE. When utilities are nonconductive, conventional electromagnetic locators often fail. In blind trials (McMahon, 2000) using standard survey methods, as much as half of all subsurface utilities were missed. [AC1] Additionally, PHMSA (Pipeline Hazardous Materials Safety Administration) has reported (PHMSA, 2025) an average cost of $594,218,469 over the past three years for gas utility pipeline incidents with an average of 11 deaths and 30 injuries. More expensive and specialized methods exist such as ground penetrating radar (GPR), but these have

At one level, the challenge of meeting load growth from data centers is straightforward. After all, the task is fundamentally about quickly delivering a substantial amount of electrons to data centers to power cloud computing and artificial intelligence applications (AI).  The sheer scale of the demand for electricity is enormous, especially for a utility industry that spent decades forecasting flat or even declining load growth. For example, the U.S. Energy Information Administration’s (EIA) most recent short-term energy outlook (STEO) report forecast commercial electricity consumption to grow 3% in 2025 and 5% in 2026, a revision up from the annual increase of 2% EIA had previously projected.  “The revisions are most notable in the commercial sector, where data centers are an expanding source of demand,” the EIA wrote. A report last year by the Lawrence Berkeley National Laboratory (LBNL) reached similar conclusions, finding that the percentage of the nation’s electricity consumed by data centers could rise from 4.4% in 2023 to as much as 12% in 2028. Complexity beyond scale Utilities obviously want to serve data centers. However, the question for both utilities and data center developers is whether extremely large and reliable amounts of electricity can be provided within the required timeframe — speedy access to power is a key strategic imperative for data centers. But the reality is that very little about meeting the enormous electricity demand from data centers is straightforward. For example, besides their sheer size, data centers have unique load characteristics, whether they’re being used to train new models or for inference, when trained AI models produce answers to questions users ask. Additionally, some data center loads are extremely variable and rapidly changing, with power demands fluctuating quickly as compute workloads shift.  This rapidly changing variability can put mechanical stress on a behind-the-meter or grid-connected but

A statement posted on OPEC’s website last week announced that the OPEC Secretariat had received updated compensation plans from Iraq, the United Arab Emirates (UAE), Kazakhstan, and Oman. A table accompanying this statement showed that these compensation plans amount to a total of 267,000 barrels per day in December 2025, 415,000 barrels per day in January 2026, 708,000 barrels per day in February, 710,000 barrels per day in March, 810,000 barrels per day in April, 831,000 barrels per day in May, and 829,000 barrels per day in June. According to the table, Iraq’s compensation plans amount to 120,000 barrels per day in both December 2025 and January 2026, 115,000 barrels per day in both February and March, 101,000 barrels per day in April, and 100,000 barrels per day in both May and June. Kazakhstan’s compensation plans come in at 131,000 barrels per day in December, 279,000 barrels per day in January, 569,000 barrels per day in both February and March, 650,000 barrels per day in April, and 669,000 barrels per day in both May and June, the table showed. The UAE’s compensation plans amount to 10,000 barrels per day in both December and January, 20,000 barrels per day in both February and April, 54,000 barrels per day in both March and May, and 55,000 barrels per day in June, according to the table, which showed that Oman’s compensation plans come in at 6,000 barrels per day in both December and January, 4,000 barrels per day in February, 6,000 barrels per day in March, 5,000 barrels per day in April, 8,000 barrels in May, and 5,000 barrels per day in June. “As agreed during the virtual meeting held by the eight countries with additional voluntary adjustments, including Saudi Arabia, Russia, Iraq, the United Arab Emirates, Kuwait, Kazakhstan, Algeria, and Oman on

Iberdrola SA said it has fully energized a 1,600-kilometer (994.19 miles) transmission line between the north of Minas Gerais state and São Paulo. With six substations and 3,250 towers, the Alto Paranaíba project is the biggest transmission project undertaken by Iberdrola, through its local subsidiary Neoenergia, in Brazil and one of the country’s biggest, the Spanish power and gas utility said in a press release. The project cost BRL 4.2 billion ($782.21 million), Iberdrola said. Alto Paranaíba was completed 15 months ahead of the schedule set by Brazil’s National Electric Energy Agency, according to Iberdrola. On November 24, 2025, Iberdrola launched a takeover bid for Neoenergia after which its stake would rise from 83.8 percent to 100 percent. This follows Iberdrola’s acquisition of a 30.29 percent stake in Neoenergia held by Banco do Brasil’s pension fund, PREVI. Iberdrola announced the completion of the transaction with PREVI October 31, 2025. “Iberdrola offers the same price paid in the recent acquisition of Caixa de Previdência dos Funcionários do Banco do Brasil (PREVI) stake corresponding to 30.29 percent of the capital – 32.5 Brazilian reais per share – updated by the official Brazilian interest rate, called SELIC”, Iberdrola said announcing the takeover bid. “A total disbursement (before its update according to the evolution of the SELIC rate and assuming that Neoenergia does not pay any intermediate dividend) of around EUR 1.03 billion is expected. “The transaction will simplify Neoenergia’s structure, providing its operations and financing with greater flexibility and reducing costs arising from maintaining the trading of shares on the market. “With this transaction, Iberdrola reaffirms its commitment to Brazil and to a growth model based on electricity grids, which account for 90 percent of Neoenergia’s business”. According to the November statement, Neoenergia had nearly 40 million electricity customers served through five distribution units in the states of Bahia, Brasilia, Mato Grosso

TotalEnergies SE and its partners in Block 9 have signed an agreement with the Lebanese government to enter the adjacent Block 8 around the Israeli-Lebanese maritime border. “Although the drilling of the Qana well on Block 9 did not give positive results, we remain committed to pursue our exploration activities in Lebanon”, TotalEnergies chair and chief executive Patrick Pouyanné said in a statement on the company’s website. France’s TotalEnergies is to own 35 percent in Block 8 as operator. Italy’s state-backed Eni SpA would get 35 percent. QatarEnergy would hold 30 percent. “The consortium’s initial work program on Block 8 consists of the acquisition of a 1,200 km2 [463.32 square miles] 3D seismic survey, in order to further assess the area’s exploration potential”, TotalEnergies said. Block 8 sits about 70 kilometers (43.5 miles) off the southern coast of Lebanon in waters about 1,700-2,100 meters (6,889.76 feet) deep, according to a separate statement by QatarEnergy. About three years ago TotalEnergies contracted Transocean Ltd to start drilling in Block 9, as announced by the block operator May 2, 2023. TotalEnergies launched exploration after Lebanon and Israel agreed to delineate their maritime border, around which Block 9 lies. Under the treaty brokered by the United States and signed by the Mediterranean neighbors October 2022, Israel agreed not to develop hydrocarbon deposits in Block 9 in exchange for remuneration by developers. The treaty stated no Israeli or Lebanese corporation shall hold exploration and exploitation rights in Block 9. “The parties understand that there is a hydrocarbon prospect of currently unknown commercial viability that exists at least partially in the area the parties understand to be Lebanon’s Block 9, and at least partially in the area the parties understand to be Israel’s Block 72”, read the agreement, as shared by the websites of the Israeli parliament