Listen to the article 9 min This audio is auto-generated. Please let us know if you have feedback. The Indiana Utility Regulatory Commission recently approved AES Indiana’s plan to serve a Google data center in a contested case that highlights the complex challenges regulators and utilities face in allocating system costs for large computational loads. According to the Oct. 7 order, AES will acquire or build new generation, storage and grid infrastructure for a 390-MW data center planned for Monrovia, a town Southwest of Indianapolis, at an estimated project cost of about $737 million.  The new generation, storage and transmission assets included in the Monrovia Project will go into the utility’s rate base.  AES says its electric service agreement with Google is designed to ensure the revenues will be sufficient to “reimburse at least 100%” of the project’s incremental direct costs. But the contract itself is heavily redacted, and an estimated $74 million in network upgrades has been explicitly allocated to all customers as a reliability need, prompting criticism from consumer advocates that the arrangement is shifting costs onto other ratepayers. What are ‘reasonably allocable’ costs?  Indiana state law requires large load customers to reimburse at least 80% of project costs “reasonably allocable” to them.  Claire Wayner, a senior associate at the clean energy nonprofit RMI, said in an interview that while local projects are fairly easy to trace back to a specific data center, broader regional system upgrades raise more complex questions about who benefits and how costs are allocated across jurisdictions. “Maybe they’re upgrading a part of the grid that they were going to have to upgrade anyway because it’s aging infrastructure,” Wayner said. “If that’s the case, they should have to demonstrate that, and then maybe cross socialization makes sense.” But, she continued, “If that upgrade was

Robert Plumb is an executive vice-president at CAC, part of The Baldwin Group. Robert co-founded the Energy Practice of CAC Specialty in July 2016 with Josh Kirklin. Prior to joining CAC, Robert began his career as an oil and gas underwriter, working for both Travelers and the boutique energy wholesaler & MGA outfit, J.H. Blades & Co. Through these positions, he has drafted insurance policies and written thousands of General Liability, Umbrella, Well Control, Builders Risk, Loss of Production Income, Pollution, Property, Workers Compensation, and auto policies. In his underwriting career he was responsible for an aggregate portfolio of more than $500 million in gross written premium on behalf of various carriers including domestic and international markets, specifically Lloyd’s of London securities. Robert brings unique market perspective on how carriers analyze energy risks, and he specializes in property and casualty lines for on energy accounts worldwide. Robert has a bachelor’s degree in Corporate Communications and a Minor in Business Foundation from the University of Texas at Austin.  

Vaalco Energy Inc., Houston, has been granted government approval to begin the second exploration phase at Block CI-705, offshore Côte d’Ivoire. News comes following encouraging results following completion of the first exploration phase work commitments, which included the evaluation and interpretation of existing seismic and well data, the company said in a release Nov. 9. Work on the second exploration phase includes additional seismic reprocessing, relinquishing 25% of the exploration block to the government, and commitment to drill an exploration well by yearend-2028. In March 2025, Vaalco farmed into and became operator of the exploration license with a 70% working interest. The block lies in the Ivoirien basin about 70 km to the west of Vaalco’s CI-40 Block, which hold Baobab and Kossipo oil fields. “We see encouraging prospectivity on the block in the play types proven throughout the Ivoirien Basin including both structural and stratigraphic traps in the Upper Cretaceous and Albian sections,” said George Maxwell, Vaalco’s chief executive officer. “Recent nearby discoveries are on trend with CI-705 and provide additional validation of our play concepts and our view of the block’s prospectivity,” he continued.

Vietnam Refining and Petrochemical Corp. (BSR) has entered talks with a consortium of FutureTec Co. and Zhejiang Hanghua Technology Co. Ltd. (Hanghua) to discuss and explore development opportunities along the refining and petrochemical value chain. At a Nov. 5 meeting between the parties, officials from the companies weighed potential collaborations on the deep processing of petroleum products, the development of value-added products, and research into related industrial infrastructure projects, BSR said in a release Nov. 6. While specific projects discussed at the meeting were not revealed, BSR said the event has laid the groundwork for further in-depth talks on potential areas of collaboration that would contributing to expanding the petrochemical refining value chain, improving resource utilization efficiency, and moving operations towards sustainable development. The proposed collaboration discussion comes amid shared interests of BSR and the FutureTec-Hanghua consortium in developing green, clean, and environmentally friendly products, as well as researching and developing new higher-value products, BSR said. With its experience in operating and managing refineries, BSR offers a favorable platform for expanding cooperation efforts with partners such as FutureTec and Hanghua that bring specialized capabilities in technology, research, and product development, added Nguyen Viet Thang, BSR’s general director. Potential collaborations with external partners come alongside BSR’s upgrading and expansion project now underway at the operator’s the 6.5-million tonne/year (tpy) refinery in the Dung Quat Economic Zone of Binh Tri Commune in Binh Son District, Quang Ngai Province, Vietnam. During the Nov. 5 meeting with the FutureTec-Hanghua consortium, BSR said its near-term plans for the refinery—which is currently operating at about 121% capacity—include further improving operational efficiency; optimizing technological processes; diversifying crude oil and product sourcing; as well as developing additional cleaner, sustainable fuels, petrochemicals, and high-value products. The operator said it will also continue focusing on efforts further efficient energy use,

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