Electricity Supply and Demand

U.S. utilities and power plant developers added about 12 GW of new generation resources between January and April of this year, compared to 11 GW over the same period last year, according to the latest monthly infrastructure report from the Federal Energy Regulatory Commission. 

The vast majority of that generation — some 9.5 GW — was solar, trailed by wind with 2 GW and 500 MW of gas.

“High probability” additions by April 2028 include 90 GW of solar, 23 GW of wind and 19.5 GW of gas, according to the report. It also projected the likely addition of 631 MW of hydropower and 92 MW of geothermal steam. 

The report showed the continued dominance of solar in new generation capacity amid robust demand growth projections.

That could change, however, as the Republican tax cuts and spending bill take effect. The law signed by President Donald Trump on July 4 dramatically cut incentives for wind and solar, phasing out tax credits and imposing restrictions on the types of projects that qualify. Trump followed that with an executive order instructing the Treasury Department to take a narrow approach in its interpretation of the law regarding wind and solar. 

The country added 62.5 miles of transmission lines from January to April, 2025, including, most recently, Entergy Louisiana’s 1.8-mile, 500-kV Wise-Bayou Labutte transmission project. 

The report did not include a breakdown of transmission built over the same period last year. In total, grid operators added nearly 1,700 miles of transmission in 2024, about a third of it high voltage 500 kV. 

FERC’s report follows a separate analysis from the U.S. Energy Information Administration that estimated solar generation would rise by a third this summer.

“By summer 2026, we forecast solar generation will grow by another 19% to 147 BkWh, which means solar would surpass wind to become the leading source of renewables generation during the summer,” the EIA said. 

While the curtailment of clean energy tax credits is expected to slow solar deployment, alternatives like gas, which are favored by the Trump administration, face their own challenges, including high fuel prices and a years-long backlog for new gas turbines.

“With higher generation from renewables and increased fuel costs, we expect U.S. natural gas generation will fall by 4% in 2025 followed by an increase of 2% in 2026,” the EIA said. 

The FERC report projected 24 GW of coal retirements and 14 GW of gas retirements through 2028. 

Utility regulators across the U.S. face a paradox that demands resolution, panelists at the American Clean Power Association’s CleanPower 2025 conference said.

There were 726 policy actions on grid modernization in the U.S. in the first quarter of this year, many requiring significant new investments, per the Clean Energy Technology Center’s most recent Grid Modernization policy update. But customer electricity prices are up 4.5% nationally, almost twice the 2.4% national inflation rate, according to the June Bureau of Labor Statistics Consumer Price Index.

“Utility regulation has always been a complex balancing act and the lesson learned is the need to ensure investment value and utility accountability,” said Regulatory Assistance Project, or RAP, Principal, Research and Strategy, Mark LeBel. Regulators must choose “the most cost-effective investments from a realistic set of alternatives,” he added.

Almost 80% of $186.4 billion spent by U.S. investor-owned utilities in 2024 went to infrastructure, according to September 2024 data from the Edison Electric Institute. And more spending must follow: April’s 120 GW five-year load growth forecast was over five times higher than 2023’s five-year forecast of 23 GW, according to the recent GridStrategies update.

“Regulators can approach modernization investments like they are investors in a business,” said Commissioner Abigail Anthony of the Rhode Island Public Utility Commission. Utilities should present investment information “like a business owner seeking a loan” to eliminate regulators’ concern that approval “is a gamble with customer money,” she added.

Balancing the apparent opposites of spending to modernize and not spending to avoid rate increases is what utility oversight is about, many commissioners agreed. Emerging tools for business case regulation are new metrics, effective planning and well-paced spending that can identify needed investments that add value and make the utility accountable, some regulators added.

Can opposites balance?

Conscientious regulators need new approaches for the hard choice between legitimate modernization investments and the upward rate pressure they cause, state commissioners and analysts said.

Pressures on an out-of-date system are rising and significant investments, mostly paid by utility ratepayers, are needed, said Bryce Yonker, executive director of modernization advocate Grid Forward. As a result, though, if “affordability is the paramount target, it will be difficult to achieve.”

The Georgia Public Service Commission recently initiated a solution to balance costs for new large load customers that many state regulators are adopting, said Georgia Commissioner Tricia Pridemore.

“New rules require Georgia Power to contract for 15 years with new large load customers at a rate that covers 100% of utility costs,” she added.

Georgia Power procures the generation needed by the new large load, and the commission approves the contract in “a collaborative planning process,” Pridemore said. Costs not recovered through the contract go into the utility’s rate case, but recovery of those costs is not likely to be allowed “because negotiating the contract was the utility’s responsibility and not a ratepayer problem,” she added.

With Georgia Power and its regulators facing questions about the utility’s nation-leading profitability, Pridemore stressed the estimated $2.64 per month downward pressure on each residential customer’s rates attributed to the new rule.“Like every state commission,” Georgia regulators are “working to find the right amount of spending to ensure reliability without unnecessary costs,” she added.

New elements for broader balancing of affordability and modernization are emerging in many other states.

The theory of balancing

One emerging tool for effectively balancing spending and rate increases is new metrics.

“Ultimately, potential investments need to be prioritized,” said Newport Consulting Group Managing Partner Paul De Martini, who co-authored a January Lawrence Berkeley National Laboratory report on optimizing distribution system modernization investments.

The report describes metrics for “multi-objective prioritization” developed by DTE Electric in Michigan and Portland General Electric in Oregon. Planning “must address multiple objectives” and “they need to be prioritized,” even though “most distribution grid investments solve more than one objective,” it added.

The Michigan utility commission uses DTE’s global prioritization model, but it recognizes the model’s usefulness has practical limits, said Michigan Public Service Commission Chair Dan Scripps. “If it is clear the model has good inputs, we can have confidence the outputs are good.”

A regulator’s priority should be “modernizations that can create the most value,” LBNL’s report said. And the most valuable modernization investments are “an outcome of Integrated Distribution System Planning” with comprehensive analyses that often include two metrics, it added.

A “best fit, least cost” analysis can be applied to individual expenditures that only achieve their full value “when the interdependent components are all deployed,” LBNL said.

Benefit-cost analysis is best if benefits “are discrete and assignable, quantitatively measurable, and do not materially change” with usage, the report added.

Best practices in planning align investments “to achieve specific outcomes ... that clearly support established planning objectives,” LBNL concluded. The best metrics reflect both “the priority ranking of the objective” and “the contribution of the proposed solution to addressing each objective,” it added.

Commissioner Ann Rendahl of the Washington Utilities and Transportation Commission agreed the planning process is critical to effective decisions. “Significant requests for rate increases have become more common,” but with effective planning, regulators can resolve “the trade-off” between cost savings and “the most efficient reliable service,” she said.

Other recent research has also developed new metrics, De Martini noted. The Pacific Northwest National Laboratory has worked on planning strategies for aging infrastructure replacement, and the Clean Air Task Force has looked at risks of relying too much on levelized cost of energy data, he said.

“It also is important to begin the planning process by defining affordability,” De Martini cautioned. “Utilities assume a certain percentage increase in revenue requirement in relation to the inflation rate is affordable, but stakeholders, regulators and legislators will likely differ,” he added.

Despite the best metrics, regulators ultimately face hard judgment calls, many acknowledged.

Harder balancing decisions

Protecting customers with affordable rates may mean making imperfect choices, regulators and analysts said.

“There are always tradeoffs, and potential investments that are not made, but resources are limited,” RAP’s LeBel said. “The best and most expensive choice, like undergrounding lines, might not be the most judicious for utilities and regulators to make, but the regulator’s job is to take all the lessons learned and do better going forward.”

Worsening extreme weather events driven by the changing climate are making it challenging to do better, especially if a necessary decision is expensive, Electric Power Research Institute, or EPRI, Principal Technical Leader, Energy Systems and Climate Analysis, Andrea Staid acknowledged.

But “research shows how large the cost of inaction will be,” Staid said. Regulators need to remember that “utilities are already planning significant spending to meet customer demand, and investments to reduce climate risk and prepare climate resilience have benefits that massively outweigh the upfront costs,” she added.

Former Arkansas Public Service Commission Chair Ted Thomas, currently founder of Energize Strategies, agreed regulators need to restrain spending “to hold utilities accountable.” But “they must not eliminate innovative investments in technologies like advanced metering infrastructure, or AMI, that can lead to a higher quality system,” he added.

Finally, regulators need to carefully pace investments by understanding “what is necessary to have and what is nice to have,” Oregon Public Utility Commission Chair Letha Tawney said. Current planning allows regulators to “pace and prioritize based on what additional capabilities and what reliability impacts” utility proposals offer, she added.

“There is no perfect answer because stakeholders value different things,” but the planning process allows stakeholders to “fully analyze the proposed investments,” Tawney said. Then regulators “can decide how fast each investment can be made.”

Regulators are bringing new metrics, the potential for innovation and the challenge of pacing expenditures into real world modernization proceedings.

Real world balancing

In the real world, hard cold business facts matter, commissioners said.

A third-party audit of the DTE and Consumers Energy distribution systems by Liberty Consulting was invaluable, said Michigan Chair Scripps. The year-long audit produced multiple “specific recommendations for cost effective improvements,” and “we approved investment recovery mechanisms informed by the audit,” he added.

Another example of the growing emphasis on the business approach was the Massachusetts Department of Public Utilities June order authorizing spending for utility modernization plans. “Grid modernization and resiliency planning must ultimately become a part of each company’s standard business practices,” it said.

A landmark “business case proceeding” led to May’s Rhode Island Public Utility Commission authorization of Rhode Island Energy’s AMI deployment. The commission authorized recovery of utility capital expenditures — but with “conditions.”

The commission’s decision is frequently between “what the utility wants and what Rhode Island needs,” said RI PUC Commissioner Anthony, long an advocate of the business case approach. “The AMI proposal was approved because, despite a limited demonstration of need and value, there was a strong accountability,” she added.

“The first piece of the accountability framework was a hard budget cap on ratepayer costs of $154 million, which the company itself offered,” Anthony said. The company also committed to continue investing its own money, even beyond the cap, “until the advanced metering functions it promised are achieved,” she added.

In addition, the commission imposed penalties if the company does not meet “things core to its value case,” like improved outage notification and “moving customer data faster from the meter to the utility and back to the customer,” Anthony said.

“Modernization could create a more reliable and sustainable power system,” but “there is also the risk that customers are left to pay for a system that doesn't deliver,” Anthony said. “The stakes are too high for regulators to take bets on the outcome,” but on the AMI deployment a good business case convinced the Rhode Island commission, she added.

“Rates will inevitably be higher because of the need to spend for distribution system modernization,” Newport Consulting’s De Martini said. “The question is how much higher.”

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By POWER Engineers, member of WSP

To meet growing energy demands, we must embrace 765 kV as a critical solution. And this will require a paradigm shift. When it comes to extra high voltage transmission design, it’s time to throw out the old playbook. Traditional transmission line project timelines have long followed a linear path: start with conceptual planning, move through design phases and end with a completed, in-service system. This approach works well for standard voltage classes where established practices and design standards guide the process.

But when it comes to higher voltage classes—500 kV and especially 765 kV—that linear model starts to break down. Because all design elements are interconnected, it’s best to use a cyclical design approach where study results inform line designs and line design outcomes feed back into the studies.

When Complexity Demands a New Path

Each extra high-voltage project, particularly 765 kV, presents unique challenges based on location, constraints and stakeholder needs. Understanding how these projects differ from lower voltage systems allows teams to focus their efforts where it matters most, setting the foundation for successful execution.

Extra high-voltage transmission projects involve complex design considerations across electrical studies, hardware, structures, loading, constructability and procurement. To begin, electrical studies (particularly relating to safety and physiological effects) drive key design elements like conductor sizing, bundle geometry and structure height.

Hardware assemblies must be thoughtfully designed, including elements such as yoke plates, insulator arrangements and jumper designs. Performance and availability are influenced by choices on corona ring placement and adherence to insulator standards.

Structure design is shaped by height restrictions (such as Federal Aviation Administration height limits). Horizontal configurations and steel lattice towers are favored for their strength and efficiency. These structures must be engineered to withstand high loads and extreme weather events (especially when using multi-bundle conductors).

Managing external components of the project is critical. Early contractor involvement is vital for constructability, foundation feasibility and stringing logistics. Procurement is a long-lead process, particularly for lattice steel, and requires a robust strategy to manage vendor risks and testing needs. Overall, success depends on balancing technical requirements with practical execution and early stakeholder collaboration.

Designing Extra High-Voltage Lines in Loops

Although 765 kV design is relatively new in the U.S., global experience offers valuable insights. The design process is inherently iterative. It requires multiple passes through key design activities, from initial baselining to final design. Rather than viewing the process as linear, it’s more accurate to think of it as a spiral. Each loop revisits and refines elements like criteria, conductor selection, insulation and structures.

This cyclical approach highlights the need for flexibility in managing the project schedule. The critical path may shift over time, requiring effective communication among project leads and the project manager to adapt the execution plan accordingly.

Transmission designers should expect to redo several calculations as they zero in on the final solution. This mindset shift is critical for clients and utilities accustomed to fast, linear design processes. They need to allow for longer timelines and more flexible budgets to accommodate the iterative nature of extra high-voltage design.

The Role of Benchmarking

Benchmarking plays a crucial role in this new design paradigm. It serves as a “gut check” after the initial design iteration, helping teams determine whether they’re still on the right path. Growing experience with 765 kV lines provides a baseline of data from which to reference throughout iterations of the design process.

This benchmarking process helps identify whether the design is aligning with expected parameters—such as the number of conductors or structure dimensions—or if it’s veering into uncharted territory. That’s just another data point, because ultimately design considerations are unique to each project.

Scaling Up the Team

Another major shift in extra high-voltage projects is the size and scope of the project team. Lower-voltage projects can often be managed by just a few engineers with broad expertise. Higher-voltage work, however, demands a much larger, more specialized team.

This expanded team often includes lattice structure leads, foundation and geotechnical leads, real estate and permitting professionals and construction contractors—among many others—who each play a critical role in ensuring the project stays on track and meets evolving technical and regulatory requirements.

The Long-Term Payoff

Designing extra high-voltage transmission lines requires a fundamental shift from traditional, linear project models to a more dynamic, iterative approach. By adopting a cyclical design process, leveraging benchmarking data and prioritizing early collaboration across disciplines, project teams can deliver reliable, efficient solutions that meet the demands of modern power infrastructure.

If we’re serious about meeting future demand, 765 kV must be part of the equation. But achieving success hinges on embracing the complexity of interconnected design elements, engaging a broader and more specialized team, and allowing for flexibility in both schedule and scope. This philosophy echoes the adage: an ounce of prevention is worth a pound of cure. Investing in thoughtful, expert-driven design early on can prevent costly rework, delays and inefficiencies during construction and operation.

About the author

Luke Sudkamp is a project engineer at POWER Engineers, member of WSP, with expertise in transmission line design and standards development from 138 kV to 765 kV. He applies his engineering strengths to oversight, coordination and implementation of multiple transmission line design projects. He has a broad background in detailed transmission line structure design, including steel, wood, concrete poles and lattice towers.

Projections around U.S. data center growth and the electricity necessary to power AI are almost certainly overstated due to global constraints in semiconductor chip production, according to a new analysis completed by London Economics International for the Southern Environmental Law Center.

Demand forecasts have alarmed utilities that are rushing to add energy resources, despite concerns over impacts on power bills.

Projected data center demand from the U.S. power market would require 90% of global chip supply through 2030, according to London Economics. “Such a scenario is unrealistic," the report concluded.

The United States is rushing to add new generation and transmission to power a variety of sectors — including transportation, buildings and industry — but data centers are expected to require an outsized portion of the resources.

The U.S. Department of Energy recently published a report estimating an additional 100 GW of new peak capacity is needed by 2030, with half of it needed for data centers. Schneider Electric’s 2030 AI power demand scenarios range from about 16 GW to 65 GW. 

The uncertainty, and an “upward bias” in projections identified by London Economics, is putting ratepayers at risk, according to SELC.

“Such speculative infrastructure investment creates significant economic risks for ratepayers, who ultimately bear the financial burdens,” SELC Senior Attorney Megan Gibson said in a statement. “Regulators must urgently prioritize transparent, realistic, and evidence-based analyses to ensure infrastructure developments are truly necessary and beneficial, safeguarding communities and promoting sustainable growth in the Southeast and throughout the country.” 

The report appears to reinforce some analyst observations that many data center requests appear to be duplicative.

Astrid Atkinson, a former Google senior director of software engineering and now co-founder and CEO of grid optimization software provider Camus Energy, told Utility Dive earlier this year that utilities are seeing five to 10 times more interconnection requests than data centers that will actually be built.

London Economics said it developed an approach to examining the “reasonableness” of data center forecasts by comparing the projected electricity demand increases reported by U.S. grid operators and balancing authorities with the global implied need for semiconductor chips.

The analysis is “meant to be a sanity check on the scale of projected data center growth and by extension the forecast of the aggregated electricity demand growth,” the report said. “LEI found evidence that the high-level forecast is not credible.”

According to the report, AI chip manufacturing capacity has grown about 6.1% annually over the last decade. If that rate were to rise significantly, to 10.7%, it would mean the chip sector could supply an incremental 63 GW of data center-related demand globally through 2030. But U.S. grid operators say they anticipate data center demand growth of 57 GW over the next six years.

“For the forecasts to hold water, this would mean the US would require more than 90% of the world’s new supply of semiconductor chips from 2025 through 2030,” London Economics concluded. “Such a scenario is unrealistic ... The United States currently accounts for slightly less than 50% of global semiconductor chip demand, and other regions in the world are also projecting strong demand.”

Blackouts could increase by 100 times in 2030, relative to today’s averages, if the United States continues to shutter power plants and fails to add additional firm capacity amid rising demand, the U.S. Department of Energy said in a recent report.

The report includes a uniform methodology to identify regions at risk of power outages and guide federal reliability “interventions,” DOE said. The report was required by President Donald Trump’s April executive order which directed the agency to respond to an “energy emergency” he declared in January.

But clean energy advocates say the report appears to exaggerate the risks, and undercount the contributions of wind, solar and battery storage resources. “If the analysis is overly pessimistic about advanced energy technologies and the future of the grid, consumers will end up paying too much for resources we no longer need,” Caitlin Marquis, managing director at Advanced Energy United, said in an email.

DOE’s report assumes 104 GW of plant retirements by 2030, alongside the addition of 210 GW of new generation — but only 22 GW of the additions will be “firm, reliable, dispatchable generation.”

“Modeling shows annual outage hours could increase from single digits today to more than 800 hours per year. Such a surge would leave millions of households and businesses vulnerable,” the report said. “We must renew a focus on firm generation and continue to reverse radical green ideology in order to address this risk.”

Average Loss of Load Hours could jump from 8.1 annually to 817.7 under some scenarios, the report said. It estimated an additional 100 GW of new peak capacity is needed by 2030 — of which, 50 GW is attributable to data centers.

“Data centers can be built in 18 months, but it takes more than three times as long to add new generation required to service those data centers,” DOE said in a fact sheet accompanying the report.

Even assuming no retirements, DOE said its model found outage risks in several regions rise more than 30-fold, “proving the queue alone cannot close the dependable-capacity deficit.”

“This report affirms what we already know: The United States cannot afford to continue down the unstable and dangerous path of energy subtraction previous leaders pursued, forcing the closure of baseload power sources like coal and natural gas,” Energy Secretary Chris Wright said in a statement.

America’s Power, which represents the coal sector, praised the report.

The analysis “is further proof that the premature retirement of coal plants is putting the reliability of the U.S. electricity grid at risk,” America’s Power President and CEO Michelle Bloodworth said in a statement. “Baseload power sources like coal are being replaced by less reliable sources like wind and solar. These renewables are not capable of meeting the constant 24/7 electricity demands required for AI, data centers, and other advanced technologies.”

The report includes a methodology that DOE says it will use to identify which generation resources within a region are critical to system reliability. The methodology uses hourly datasets for load, generation and interregional transfer capabilities for the 23 U.S. electric subregions.

DOE said it developed its outage risk estimates by running simulations using 12 different years of historical weather, with every hour based on actual data for wind, solar, load and thermal availability.

Clean energy advocates say they have doubts about the agency’s methodology.

DOE’s study “appears to exaggerate the risk of blackouts and undervalue the contributions of entire resource classes, like wind, solar, and battery storage,” AEU’s Marquis said.

“We are working quickly to dig into the numbers to unpack how DOE reached its conclusions,” Marquis said. “But it’s troubling that the report was not subject to public input and scrutiny, especially since the Executive Order that mandated it calls for it to be used to identify power plants that should be retained for reliability.”

The methodology “is another attempt to push the false narrative that our country’s energy future depends upon decades-old coal- and gas-plants, rather than clean renewables,” Sierra Club Senior Attorney Greg Wannier said in an email.

The Federal Energy Regulatory Commission and the states “are already well equipped to meet any projected resource needs through the existing regulatory process, which ensures that electricity demand is reliably met at the least public cost,” Wannier said. “Any effort by DOE to override this process to forcibly keep coal plants online past their planned retirements  would be an extraordinary and unlawful overreach of its regulatory authority.”

In May, DOE issued an emergency order under section 202(c) of the Federal Power Act, directing Consumers Energy to delay, by about three months, shutting down a 1,560-MW, coal-fired power plant in Michigan. Earthjustice and other groups have asked the agency for rehearing, and said they may go to the courts to challenge the order.

“Determining the reserve margin and ‘critical’ resources are complex decisions with severe health and economic consequences that Congress rightly entrusted FERC to oversee using a robust public adjudication process,” said Christine Powell, deputy managing attorney for Earthjustice’s clean energy program. DOE’s methodology “attempts to usurp that process, and would impose billions of dollars and harmful pollutants on consumers without any corresponding benefits for anyone except for the coal industry.”

DOE’s analysis “doesn’t support President Trump’s strategy of using emergency declarations to stop power plants from carrying through with their plans to retire,” said Jennifer Danis, federal energy policy director at the Institute for Policy Integrity.  

“The Trump administration’s own study has found that no present emergency exists in the two regions where it already issued 202(c) orders,” Danis said. “Reforms may be needed to ensure better planning for future resource adequacy to power AI, but they should focus on improving existing markets and planning standards, as well as speeding up new resource interconnection, rather than forcing customers to pay to keep old, inefficient plants online.”

Keeping electricity affordable for consumers is a “formidable challenge” amid projections of declining generation capacity reserves and persistent uncertainty around the scale and pace of future load growth, ICF International Vice President of Energy Markets Maria Scheller said. 

Meanwhile, broad policy uncertainty and an increasingly shaky regulatory environment give utilities and capital markets pause about expensive new infrastructure investments that could become stranded assets, Scheller said in a webinar on ICF’s “Powering the Future: Addressing Surging U.S. Electricity Demand” report.

Policy conversations around import tariffs, federal energy tax credits and permitting reform are unfolding as the balance of electricity demand shifts from residential and business consumers to technology and industrial customers, which tend to require around-the-clock power, Scheller added.

The coming shift in U.S. electricity consumption represents less of a new paradigm than a return to the industrial-driven demand the country saw from the 1950s into the 1980s, after which deindustrialization and consumer-centric trends like the widespread adoption of air conditioning, electric resistance heating and personal computing shifted the balance toward the residential segment, Scheller said.

The shift is important because unlike residential loads, which show considerable seasonal and intraday variation, industrial loads are flatter, less weather-dependent and more sensitive to voltage fluctuations, Scheller said.

By 2035, ICF expects nearly 40% of total U.S. load will have a “flat, power-quality-sensitive profile,” and that overall load will grow faster than peak load, she said. In 2030, ICF projects more than 3% annual power consumption growth, compared with less than 2% annual peak load growth, according to a webinar slide.

That’s not to say residential demand won’t also grow in the next few years as consumers electrify home heating and buy more electric vehicles — only that data centers and other industrial demand will “dwarf” it, Scheller said.

The only significant regional exception to that expectation is California, where ICF says light- and heavy-duty transportation electrification will drive most load growth through 2040. 

Capacity reserves will quickly dwindle across most of the United States as a result of near-term load growth, regardless of the regional drivers, said Lalit Batra, ICF director of energy markets.

“We expect the capacity reserve across most regions to be absorbed in the next few years,” Batra said.

ICF sees nationwide capacity reserves — currently between 20% and 25% — below the 15% target reserve margin by 2030 and in negative territory by 2035, according to a webinar slide. Without a meaningful acceleration in new generation deployment, some combination of delayed power plant retirements, load flexibility or slower overall load growth will be needed to avoid shortages, Batra said.

Building new power plants fast enough to keep pace with load growth will be more difficult if Republicans in Congress effectively repeal the Inflation Reduction Act, according to ICF’s projections. If the final budget reconciliation bill preserves the rapid phaseout of clean energy tax credits in the version the U.S. House of Representatives passed in May, ICF projects the U.S. would deploy 280 GW fewer renewables and storage capacity and 43 GW more gas and nuclear through 2040, even as cost-competitiveness, supportive state policy and corporate power buyers’ preference for clean electricity supports robust regional markets for those technologies. 

Regardless of the policy scenario, ICF expects electricity prices to rise as much as 25% in some regions through 2030 due to necessary grid expansion, wildfire hardening and other infrastructure projects, along with gas price volatility, said Deb Harris, ICF vice president for climate change and sustainability. ICF expects U.S. gas prices to be 7% higher in 2035 and 17% higher in 2045 if the House budget becomes law relative to a status-quo scenario, according to a webinar slide.

Utilities and regulators already have the tools to mitigate some of these changes, Harris said. For example, demand response programs and flexible load interconnection could avoid about 30% of infrastructure investment costs that would otherwise be necessary, Harris said. Large loads are more open than some realize to ramping down load or investing in more efficient processes, such as liquid rather than air cooling of server racks, she added.

“These large load customers do offer a lot of opportunities” for efficiency and demand response, she said. “Energy is the number one [operating] cost they face.”

Permitting reforms like uniform siting standards, incentives for brownfield redevelopment and wider adoption of advanced GIS tools to locate “areas of minimal impact” for energy development could speed up new builds and keep prices in check, Harris added.

The catch, she said, is that while efforts to mitigate rising electricity prices may benefit customers and the politicians who represent them, project developers and their lenders and investors want to see durable price signals before committing to build new generation and transmission.

Amazon and Google are trying to remain nimble as their electricity demands increase steeply during a period of political uncertainty and technological evolution for the energy sector, division heads for the hyperscalers said during a panel at the American Council on Renewable Energy’s Finance Forum.

As Google attempts to meet a goal of operating on 100% carbon-free energy by 2030, the company is making investments in emerging generation sources like geothermal and small modular nuclear reactors in an attempt to accelerate them, said Will Conkling, Google’s head of data center energy, Americas.

“But even at Google, we can't wish things to be true, right? We have to deal with the reality of technology and commercialization curves,” Conkling said.

“It's going to take a mix of everything to really reach the capacity that we need as a nation,” said Jessica Johnson, director of offtake at CleanCapital. “Not just for data centers, but for the entire demand.”

The last five years have been tumultuous for the renewable energy industry, Johnson said, and recently the sector has seen added uncertainty resulting from President Trump’s tariffs as well as a House-passed budget bill that would slash most tax credits included in the Inflation Reduction Act.

As a result, she said many energy buyers that don’t have the resources of Amazon or Google have been “shying away” from renewables and wanting to see “what else is out there.” However, Johnson said, fast-deploying generation like solar and storage still has a place when weighed against resources that are slower to bring online, like nuclear.

Conkling said he doesn’t see the challenge of responding to demand growth from data centers as one that can be met by a one-size-fits-all solution. He said that when there is growth, “the system has always basically looked at … building new gas,” but “I think we have to be careful that we don't over-generalize the solution to the growth question.”

“It's tailored responses to tailored problems,” Conkling said. “When we start to say, ‘well, the grid needs energy, and the solution is X,’ we're papering over a lot of detail and a lot of nuance, that actually probably leads us to the suboptimal.”

For instance, while data center loads on their own are too large to be handled by distributed resources, the deployment of distributed resources across a grid can ease constraints and free up transmission capacity overall, he said. 

Conkling said Google’s strategy “is generally to be a grid-tied customer, we see that as being a great benefit to us, and also being very much front and center as being part of the solution for how the grids grow and how Google grows and how the economy grows.”

“We think electricity growth on the system is actually not a threat, it's an opportunity for us and for the country and for utilities and states,” he said. “Infrastructure growth has always been a huge driver of economic growth in this country, and electricity growth on the system has always been a very big indicator of GDP growth, economic growth, and quality of life.”

Craig Sundstrom, Amazon’s Americas head of energy and sustainability public policy, said customers are the ones driving the demand for Amazon’s cloud services — and, as a result, driving the company’s increasing electricity demand.

“But our customers also want [Amazon Web Services] to be clean, which is why nothing's changed in terms of our own commitment to hitting that longer-term target of net zero by 2040,” he said. 

Sundstrom said that Amazon sees its role in the energy system as that of a customer, not a project developer, but that the company is — like Google — working to advance new technologies like small modular reactors, “putting capital up for a technology that has still not yet been deployed.”

“I think we're seeing that it's going to take a mix [of generation],” Sundstrom said, and creative solutions to address growing demand.

One example, he said, was Amazon’s partnership with Entergy to service its $10 billion investment in two data center complexes in Mississippi.

“As a utility customer, we rely on them to make decisions around their generation portfolio,” Sundstrom said. “But there was also a lot of creativity baked into that particular transaction as well, where as a customer, we were also able to bring about 650 MW of utility-scale solar onto Entergy’s grid to support our investment there. And I think it's going to take those continued partnerships to ultimately make this happen.”

A coalition of consumer-oriented groups is asking the Federal Energy Regulatory Commission to lead an effort to improve electricity demand forecasts, which they say are riddled with “uncertainty and lack of transparency.”

The issue is critical because of “exponential” load growth that will accelerate in response to new demands from artificial intelligence, data centers and reshored advanced manufacturing facilities, the groups, led by the Electricity Customer Alliance, said in a May 30 letter to FERC.

In a May 20 report cited by the groups, ICF said it expects U.S. electricity demand to grow by 25% by the end of this decade and by 78% by 2050 — driving a need for about 80 GW of generation to be added to the grid each year by 2045, double the pace from the last five years.

As a result, the consulting firm forecasts that electric utility bills could increase by between 15% and 40% by 2030 compared to 2025, depending on the utility. Electricity rates could double for some utilities by 2050, ICF said.

The grid planning needed to meet potential load growth requires “more confidence in load growth forecasts, greater transparency and standardization in how forecasts are constructed, and clearer lines of communication among state and federal regulators, transmission operators, generators, load serving entities, and customers as forecasts are adjusted,” the groups said.

Groups signing the letter include the Electricity Consumers Resource Council, the Industrial Energy Consumers of America, the Coalition of MISO Transmission Customers, the National Association of State Utility Consumer Advocates and the PJM Industrial Customer Coalition.

“Artificially low forecasts lead to insufficient infrastructure investment and resulting high costs and potential reliability problems, while artificially high forecasts risk overinvestment, unnecessary rate increases for already burdened customers, and stranded costs,” the groups said.

Load forecasts are a key input into resource adequacy assessments and can affect wholesale energy prices and transmission rates and services, according to the groups.

FERC should launch an independent forum to examine load forecasting issues or place them at the top of the agenda for the FERC-National Association of Regulatory Utility Commissioners Collaborative, the groups said.

“Examining where current load forecasting practices may be incomplete or inaccurate, and identifying best practices to improve the certainty, transparency, and consistency of load forecasting practices across regions, are important steps to protecting customers from the reliability and stranded cost risks of inaccurate forecasts,” the groups said.

Grid operators around the country face rapidly changing and highly particular resource adequacy challenges that mean a one-sized approach to reliability is not feasible, they told the Federal Energy Regulatory Commission.

They were speaking at a two-day, commissioner-led conference to discuss issues related to resource adequacy constructs. The first panel featured the heads of regional transmission organizations and independent system operators, as well as the North American Electric Reliability Corp., which oversees them.

NERC has been conducting seasonal and longer-term resource adequacy assessments for decades, but for most of the reliability watchdog’s history “these were some of the dullest reports we ever created,” President and CEO Jim Robb told regulators. “They weren't particularly interesting because everything looked pretty good.”

But then in 2018, NERC’s long-term resource adequacy assessment showed a material expectation of unserved energy, Robb said. And in August of 2020, California experienced a significant load shed event.

“Since then, our analyses have shown a growing risk of unserved energy across the continent,” Robb said. “There are a number of interrelated factors that account for that degradation and risk.”

“Disorderly generator retirements” have led NERC’s list of resource adequacy concerns for several years, Robb said. And while several ISO and RTO areas appear to be resource adequate “through the narrow lens of capacity,” he noted that future energy shortfalls “are looming because the resource mix is not supported with the right levels of dispatchable generation with secure fuel to balance supply and demand fluctuations.”

Since 2020, the California ISO has added about 25 GW of new generation capacity, including approximately 7 GW last year. The new capacity includes over 12 GW of battery storage, CAISO President and CEO Elliot Mainzer said.

“We now have a diverse portfolio of solar, wind, natural gas, hydro electric, geothermal, nuclear and energy storage resources, as well as strong transmission connections with our neighbors and a strategic reserve of resources to address extreme grid conditions,” Mainzer said. “Going forward, the [California Public Utility Commission’s] emerging reliable and clean power procurement program will bring sustained planning and procurement coordination, helping to maintain the pace of resource development.”

“We've also worked with the CPUC to increase the planning reserve margin, and we are now working to operationalize the CPUC’s new 24 hour ‘slice-of-day’ program, designed to ensure that load-serving entities procure sufficient resources to meet demand across all hours of the day,” he added.

Just eight years ago, the Southwest Power Pool “enjoyed a high level of reliability,” SPP President and CEO Lanny Nickell told regulators. The region’s 12% reserve margin requirement at that time yielded a loss of load expectation of only once every 140 years, he said. “That's much more reliable than the 1-in-10 year standard that we are all now struggling to adhere to.”

“Since then, we've seen our peak demand increase. We've experienced a reduction in accredited capacity. We've become increasingly dependent on intermittent generation, and we've experienced extreme weather events. Our unmitigated loss of load risk is now 125 times higher than it was eight years ago,” Nickell said.

The New York ISO enjoyed a surplus of generation capacity for decades but has seen that shift, “driven primarily by public policy which prioritizes the introduction of clean resources above high emitting fossil resources,” President and CEO Richard Dewey said. ”We've seen that reserve margin shrink considerably over the last five years.”

“While we feel we have adequate resources today, we have some significant concerns in a number of areas,” Dewey said. More than 10% of New York’s generation fleet is more than 50 years old and much of that “is well beyond the design life of those facilities ... we're also seeing supply chain concerns while we reform our interconnection queues.”

Outgoing FERC Chairman Mark Christie highlighted the difficulties in ensuring reliability across the different market areas, offering a hypothetical question.

“All of you have different constructs for trying to make sure that a load-serving entity, utility ... has enough resources. And we all know they don’t,” he said. “Should FERC require the RTOs to establish mandatory reserve margins, mandatory resource acquisitions, for every one of the LSEs that operate in your RTO using a standardized accreditation methodology?”

“I understand the appeal of the concept, and I think it would work if the region hasn’t been restructured and unbundled” ISO New England President and CEO Gordon van Welie replied. So the idea might work better in SPP or the Midcontinent ISO, he said.

“We do have LSEs in New England, but the LSEs essentially are either pure marketers or marketers that own generation, but they don’t own the wires,” van Welie said. The electric distribution companies “are not subject to NERC standards or FERC regulation.”

“The construct you described is very much what we have today in SPP,” Nickell said, adding that load responsibile entities can face penalties for not meeting resource adequacy requirements. But despite the enforceable planning reserve margin, he said risks continue to grow as demand rises.

MISO is already utilizing a system similar to Christie’s hypothetical, said MISO Senior Vice President of Markets and Digital Strategy Todd Ramey.

“We do have specific planning reserve margin requirement obligations that are assigned through our tariff to our load-serving entities,” Ramey said. “Our annual capacity auction, one of its core functions is to serve as the final exam every year for LSEs to come and demonstrate their compliance with their obligations in a financially binding, market based process.”

Where MISO’s process may “fall short” of Christie’s hypothetical proposal is lack of an “absolute guarantee” that every LSE achieves 100% compliance through that process.

“Having the market based process with a sloping demand curve that's centered around the net cost of new entry suggests that there will be outcomes where your cleared capacity could be less than your regional horizontal requirement,” Ramey said.