AI Boom Reshapes Power Landscape as Data Centers Drive Historic Demand Growth

The power industry was once considered slow-moving and perhaps even boring. That is no longer the case as technology has expanded and power demand projections skyrocket. New reports released by analysts at Enverus and Deloitte are examined to provide insight on what’s likely to evolve in the power industry over the coming year and beyond.

The artificial intelligence (AI) revolution is dramatically transforming power demand forecasts, with data center expansion emerging as the dominant force shaping energy markets in 2025. This seismic shift in energy demand comes at a pivotal moment for the U.S. power sector, as it grapples with competing priorities around reliability, environmental impact, and cost. The new Trump administration’s energy priorities and policies should not be overlooked either, and innovative advances in technologies under development could be game-changing for the industry. Despite all the uncertainties, industry analysts offer valuable insights into likely developments.

AI Data Centers Drive Load Growth

Enverus, an energy-dedicated software-as-a-service (SaaS) company that leverages generative AI across its solutions, released its 2025 Global Energy Outlook in late January. Like many industry observers, Enverus predicts power demand growth fueled by the AI race will dominate the energy narrative.

“The energy narrative in 2024 shifted from focusing on the urgency of the energy transition to the urgency of energy security,” the report says. “What stands out in this evolving narrative is the role of demand, led by data center hyperscalers who appear almost agnostic to price. For this group, the energy trilemma prioritizes reliability as No. 1, environmental concerns as No. 2, cost as No. 3. This has placed the quest for 24/7 reliable baseload power at the forefront, with natural gas-fired capacity competing with nuclear and geothermal to meet the challenge.”

Enverus forecasts U.S. load to increase 1.2% in 2025 compared to 2024, and 38% by 2050. It says accelerated AI adoption, and several energy transition and electrification themes, foster expansion. “Two of these levers—data centers and residential solar—impact the future in complex ways,” the report says. “Installed residential solar will rise from 45 GW to 56 GW in 2025 and 557 GW by 2050, vastly contributing to intraday volatility in load and offsetting load growth from all non-data center demand drivers. Data centers are the largest driver of load growth, with the highest requirement for reliability and most risk to the upside.”

Experts at Deloitte agree that data centers represent the proverbial “elephant in the room.” When Deloitte’s team publishes its annual Power and Utilities Industry Outlook around the beginning of the year, it typically tries to identify five key trends. However, this year, Thomas L. Keefe, vice chair and U.S. Power, Utilities & Renewables sector leader with Deloitte, suggested there was really one key trend and four others that support it. “Clearly, data centers is the biggie,” he told POWER.

“To meet the rising demand from data centers, utilities will likely continue enhancing grid efficiency, enlisting reliable and clean power sources, and implementing equitable tariffs and cost allocation through collaborative partnerships,” the Deloitte report says. Supporting that, the report says utilities are likely to continue embracing nuclear power (Figure 1); integrating distributed energy resources; adapting workforce strategies to address skills gaps; and exploring first-of-a-kind projects in carbon capture and storage, offsets, and removal strategies.

1. Talen Energy’s Susquehanna nuclear power plant, located near Berwick, Pennsylvania, has a power purchase agreement to supply power for at least 10 years to a data center campus Amazon Web Services (AWS) purchased near the site from a subsidiary of Talen. Courtesy: Talen Energy

Of course, the biggest challenge surrounding the data center boom is supplying the potentially explosive load growth. “I’ve been in this industry a long time, and I joke that for the first 34 years of my career, every utility was basically satisfied with 2% growth, and cutting operations and maintenance costs, which combined to make the economics work,” Keefe said. “Now, some utilities are talking 100% growth in the next five years. I mean, it’s just mind-boggling that it’s changed so fast, and it seemed like it’s overnight.”

Tax Incentive Changes Could Put Projects at Risk

Meanwhile, the inauguration of a second Trump administration has raised concern over the potential rollback of renewable energy incentives. Enverus says tax credits are foundational to the economics of the U.S. renewable energy sector.

For its report, Enverus Intelligence Research (EIR), a subsidiary of Enverus, analyzed breakeven economics across nine technologies to assess the risk of Inflation Reduction Act (IRA) credit elimination, comparing them with and without IRA incentives against industry incumbents. Of the credits analyzed, EIR suggested the 45Q tax credit for blue hydrogen and enhanced oil recovery (EOR) projects, as well as the production tax credit (PTC) and investment tax credit (ITC) for solar and onshore wind, are least at risk for elimination.

“Across the Lower 48 [the continental U.S.], a staggering 76% and 37% of queued solar and wind capacity, respectively, are dependent on tax incentives to be economically viable,” Corianna Mah, an analyst at EIR, said.

Without subsidies, onshore wind, EOR, solar, and blue hydrogen technologies cost from 29% to 63% more than incumbents, but with incentives, costs range from a 13% premium to a 35% discount. “The tax credits enable them to compete with industry today, with the hope that further buildout will reduce costs and increase their unsubsidized competitiveness,” the report says. Mah added, “On average, we see that solar projects have a higher reliance on tax credits because of higher average LCOEs [levelized cost of energy] and lower average capacity factors than wind.”

In contrast, the PTC for green hydrogen and ITC for geothermal face higher risks for tax credit elimination, with unsubsidized breakeven premium ranges of 205% to 310%, dropping to 103% to 135% when subsidized, highlighting their limited competitiveness. Landfill and manure renewable natural gas projects outcompete the voluntary market without credits, potentially making credits unnecessary for these technologies.

“In our analysis, we find the most competitive projects are those with before-tax levelized cost of energy that are already below the average power price and are viable without the boost from RECs [renewable energy certificates] and tax credits. Projects with an after-tax levelized cost of energy below the average power price and average REC price are only viable because of the existence of tax credits,” Mah said.

Marlene Motyka, Deloitte’s U.S. Renewable Energy leader and a principal in Deloitte Transactions and Business Analytics LLP, felt the coming year would be a good one for renewables. “Renewables are generally expected to retain momentum in 2025,” she told POWER. “They’re really in a race with other clean generation options to fill this growing resource gap, but they offer technology maturity, lower cost, higher modularity, and so I think those are all very good things and very positive things,” she said.

While Motyka acknowledged hearing discussion around terminating the IRA, she didn’t think a full repeal is likely. “There’s a possibility that certain provisions of IRA could be modified or repealed, but I think many areas of the country are seeing the positive impact of broader economic goals and benefits from IRA, and the expectation is that it’s unlikely that it will be completely repealed,” Motyka said. She specifically cited nuclear and carbon capture and storage as areas that may be less impacted than others.

Potentially Disruptive Developments

Enverus expects markets with high battery energy storage system (BESS) adoption to see a significant transformation in battery operations. Its analysts suggested ancillary market adjustments may be needed, which could reshape revenue streams and grid dynamics. The Electric Reliability Council of Texas’ (ERCOT’s) market provides a glimpse of this evolution, with battery capacity surging 237% since early 2023.

“While battery revenues traditionally depended on ancillary services and energy arbitrage, growing storage saturation is changing the landscape,” the Enverus report says. “As capacity outpaces ancillary market eligibility, operators will shift toward arbitrage-driven models, competing with dispatchable capacity such as natural gas-fired generation. Negative pricing hours will further enhance batteries’ competitiveness, allowing them to outbid natural gas plants and lowering bid prices.”

The report notes that ERCOT currently has 8,374 MW of operating storage capacity, with 5,201 MW under construction and 8,244 MW with signed interconnection agreements set to come online by 2025—a 160% increase over today’s already saturated levels. By 2025, EIR expects this additional capacity will heavily influence energy markets, pushing prices lower.

Enverus also sees positive prospects for advanced nuclear reactors and direct air capture (DAC) carbon capture projects. While its analysts recognize that nuclear projects will require significant regulatory reforms to streamline integration into the energy grid and address operational barriers, Enverus believes the ADVANCE Act of 2024 has boosted momentum for advanced nuclear technologies, especially small modular reactors.

Concerning DAC, the report says momentum stems from the commissioning in 2024 of Climeworks’ Mammoth project in Iceland (Figure 2). While it was the world’s largest DAC facility at 36,000 tons of CO₂ per year (tpa) when it opened, it will be dwarfed by 1PointFive’s 500,000 tpa Stratos facility when it comes online in Ector County, Texas, this year.

2. Climeworks began operations of its direct air capture and storage plant, Mammoth, in Iceland last year. The plant is designed for a nameplate capture capacity of up to 36,000 tons of CO₂ per year by filtering CO₂ from the air and storing it permanently underground. Courtesy: Climeworks

Yet, DAC faces growing challenges associated with its energy-intensive nature, as highlighted by the withdrawal of Project Bison in Wyoming. Additionally, the future of the U.S. Department of Energy’s Regional DAC Hubs program and any future funding for DAC is uncertain under the new administration. Meanwhile, high capital costs and energy demands remain significant hurdles as DAC approaches the peak of inflated expectations, Enverus said.

Deloitte’s Keefe noted that carbon capture technology is not new or unproven, it’s just not cost-effective at the present time. However, if incentives are offered and investments are made in the technology, the costs will likely come down. Keefe reflected on solar and wind cost curves and how they’ve declined over the past 20 years. “Pick your source,” he proposed. “Whether it’s geothermal or hydrogen or carbon capture, I’m hopeful that we can get there, and smart people continue to find ways to make it more cost-effective.”

—Aaron Larson is POWER’s executive editor.