Last month, Google announced a deal with Voltus for a virtual power plant (VPP) of up to 1,070 MW in PJM, roughly the output of a large nuclear reactor. Rather than build a plant, Voltus will offer homes and businesses financial incentives to trim usage when the grid is strained, through smart thermostats, batteries and flexible equipment. The deal represents an inflection point for the power and utilities sector, where “speed to power” innovations are defining the moment. It also underscores the importance of the equipment that will decide how far such programs go: the electric meter. Capacity you find instead of build NEMA’s 2026 Grid Reliability Study projects U.S. economy-wide electricity demand as much as 55% by 2050, with data center consumption alone growing 300% over the next decade. New generation and transmission can’t keep pace, as permitting, capital needs and equipment and skilled labor backlogs protracting project delivery timelines. As a result, operators are looking for capacity in the system they already have. On the transmission side, grid-enhancing technologies show what’s possible: PJM modeling finds they could unlock between six and seven GW of usable capacity. At the grid edge, the opportunity may be larger. Demand response contributed 33.3 GW of enrolled wholesale capacity in 2024, about 6.5% of peak demand in organized markets and could reach 20% of U.S. peak by 2030. Behind-the-meter resources, which include microgrids and aggregations of customer-sited resources (i.e., VPPs), are scaling too. What these grid-edge resources share is a need for measurement. A demand response event or VPP dispatch only has value if someone can prove the load dropped and pay the customer who dropped it. That job falls to the electric meter. Barriers to scale Despite the momentum, only 6.5% of U.S. electricity customers are enrolled in retail demand response programs.

Next week, much of the industry will gather in Las Vegas for RE+ to talk about what gets built next. It’s an important conversation, but I’d encourage asset owners to bring a second question with them: what more can we get from what’s already been built? This question matters more than ever as electricity demand climbs and customers feel it on their monthly bill. EIA expects consumption to grow another 3.1% in 2027, driven largely by data centers and other commercial loads, while residential customers will pay nearly 5% more for power this year. The industry is working hard to add capacity, but getting it built takes time. According to Lawrence Berkeley National Laboratory and GridTracker, the median project built in 2025 spent more than five years moving from interconnection request to commercial operation and only 13% of the capacity that requested interconnection between 2000 and 2020 had come online by the end of 2025. New generation is essential, but the fleet already operating is an opportunity we can’t afford to pass up. With nearly 52 gigawatts (GW) of utility-scale battery storage operating in the U.S. as of mid-2026, the installed base is too large to overlook and performance across it varies widely. When a battery energy storage system (BESS) falls short, the instinct is often to blame the battery and reach for augmentation or replacement, but in many cases the bottleneck is the controls, software and integration around it. Operating assets are under more pressure Higher prices should raise the value of delivering power when and where the grid needs it, yet revenues for many operating assets are moving in the other direction. In ERCOT, the average battery earned 84% less in 2025 than at its 2023 peak, as more storage competed for the same services. With incentive economics

Nuclear growth plans are accelerating as data centers, large-load customers, uprates, restarts, extended operations and new generation projects reshape the industry’s outlook. But the challenge of capacity expansion extends far beyond megawatts. Every utility must also expand the capacity of its workforce.  The workforce challenge is not simply about hiring more people. Recruiting is critical, but so are retention strategies, qualification timelines, knowledge transfer processes and the availability of experienced employees and contractors. Utilities must continue operating existing plants safely and reliably while extending asset life, modernizing infrastructure, preparing for growth and developing the next generation of workers. In many cases, the same people are asked to do all of it.  An experienced engineer supporting an uprate may also be needed for aging management reviews. The supervisor helping qualify new employees may also be responsible for outage preparation. The skilled craft resources needed for capital projects are often the same resources supporting ongoing plant reliability and maintenance activities. To execute an ambitious growth plan, your workforce needs support and clear expectations as it navigates the demands of the present and the future.  That reality makes employee engagement and retention critical operational necessities.  Keeping today’s fleet running while preparing for tomorrow’s expansion  Across the industry, organizations are managing a growing list of demands. Employees are operating plants, supporting outages, resolving equipment issues, onboarding new hires, transferring knowledge, implementing modernization efforts and preparing for future growth. Subsequent license renewal and long-term operations programs add further demands through inspections, evaluations, documentation and equipment replacement activities.  At the same time, many organizations continue to face shortages in experienced operators, engineers, technicians and other critical roles. Long qualification timelines and retirements only increase the pressure.  Growth introduces another challenge that is less visible but equally important: cognitive load. Experienced employees must continually sort through competing

Data centers and AI infrastructure are intensifying the strain on existing power grids across the U.S. Large-load facilities are built quickly, only to face years-long waits for grid interconnection and new generation capacity, such as gas turbines. Behind-the-meter (BTM) power is becoming an effective solution to bridge the gap between what the grid can provide and what data centers need to operate smoothly. Utilities and large-scale customers alike are embracing BTM power: 80 percent of utilities view BTM power generation as permanent infrastructure and expect it to serve a significant share of large-load demand by 2030, according to Bloom Energy’s 2026 Utilities Insights Report. Nearly two-thirds of data center developers cite onsite power as their primary response when grid timelines slip. “BTM addresses a major issue, which is avoiding increases in grid retail prices,” says Nik Nunes, Chief Executive Officer at Industrial Development Funding (IDF), a top investment partner of Bloom Energy. “For that reason, several governors have come out in support of it.” Key considerations for successful BTM power generation BTM power isn’t always a simple fix. It involves complications related to regulatory requirements, power storage and permitting. Yet, when used in tandem with local utilities in front of meter power resources, it can provide an effective bridge for bringing large-scale customers online faster, helping them bypass lengthy wait times for a grid connection. BTM can also be affordable over the long term relative to other power sources. To launch a successful BTM power effort, data center developers must address growing public concerns about noise, water usage and emissions. In many jurisdictions, permitting has become a challenge, and BTM power projects are often delayed. To simplify air permitting, it’s helpful for BTM solutions to produce few or no combustion-related emissions. Bloom Energy fuel cells run on natural gas today

WASHINGTON—The U.S. Department of Energy (DOE) renewed two emergency orders to support continued improvements to Puerto Rico’s electric grid as the island faces rising energy demand and energy reliability challenges. Building on previous actions in 2025 and 2026, the emergency orders authorize the Puerto Rico Electric Power Authority (PREPA) to dispatch generation units essential for maintaining critical generation capacity, while continuing vegetation management to reduce outages, strengthen long-term grid reliability, and minimize the risk of blackouts.  “The Department of Energy remains committed to modernizing Puerto Rico’s electric grid to provide American families and businesses with more affordable, reliable, and secure energy,” said U.S. Secretary of Energy Chris Wright. “These orders ensure critical work moves forward, pressing reliability challenges are addressed, and the island’s electric grid is equipped to meet growing energy demands. Thanks to President Trump, these efforts are driving meaningful and long-term improvements to Puerto Rico’s energy infrastructure.”  The emergency orders will help secure Puerto Rico’s electricity supply and ensure uninterrupted power service in the face of unforeseen conditions. The orders also address vegetation management issues near power lines. Falling tree limbs and brush can damage transmission lines, cause widespread outages, and potentially cause wildfires.  “I thank President Trump and Secretary Wright for once again demonstrating their commitment to strengthening Puerto Rico’s electric system,” Puerto Rico Governor Jenniffer González-Colón. “The Department of Energy’s Section 202(c) orders have provided essential flexibilities to increase generation capacity, strengthen grid stability, and advance critical maintenance activities. More work remains to be done, and these emergency authorities will be vital as we continue our joint efforts to deliver the reliable and affordable electric service that Puerto Rico’s families and businesses deserve.” The renewed orders are in effect beginning on November 8, 2026, through February 5, 2027. DOE will continue working closely with Governor González-Colón and local authorities to ensure Puerto Rico’s 3.2 million Americans have access to a reliable and secure electric grid. 

Vista Energy SAB de CV has let a 2-year drilling contract to Archer for work in the Vaca Muerta shale play in Argentina. Under the agreement, Archer will deploy its AC drilling rig DLS-156 to support Vista’s development program in the region. The total contract value is estimated at $35-40 million over the full contract term, including the optional extension year. Vista has an inventory of about 1,470 ready-to-drill locations in Vaca Muerta, and 486 net wells already drilled at the end of third quarter 2026. In July, Vista applied to include its Bandurria Norte shale oil development in Argentina’s Large Investment Incentive Regime (RIGI). Bandurria Norte spans 26,500 acres in Vaca Muerta’s oil window and currently has no producing wells. Vista plans to drill and complete 332 horizontal wells and build dedicated infrastructure, including a 40,000-b/d oil treatment plant, a gas compression plant, gathering systems, pipelines, and associated infrastructure. The project would be Vista’s first large-scale development outside its core Bajada del Palo hub, where existing roads, processing capacity, and gathering networks support lower-cost drilling.