Out of Sync: The Infrastructure Misalignment Undermining the U.S. Grid

U.S. power infrastructure—the intricate physical fabric that laces together generation, transmission, and distribution—is under intensifying strain. Outdated and overextended, it must now absorb relentless growth from electrification and data centers or risk escalating reliability threats, surging costs, and a weakened global competitive edge. POWER examines the dysfunction and what it will actually take to future-proof the grid financially, physically, and institutionally.

In May, as the North American Electric Reliability Corporation (NERC) unveiled its latest summer reliability outlook, officials underscored a key point: The grid is stretched. “We’ve done a lot as a cross-sector industry—gas and electric—to make sure we’re operating efficiently, reliably, cost-effectively, and affordably,” John Moura, NERC’s director of reliability assessment and performance analysis, told POWER. “Those paradigms have made the reserve margins get to a point where we have enough to serve demand and a little reserve to cover some contingencies. But as demand grows, we’ve got to build infrastructure. We really don’t see a lot of ways around it.”

The infrastructure “gap” has been a longstanding concern. Historically, grid buildout has been a reactive, incremental—even “lumpy”—process, advancing in fits and starts atop shaky scaffolding, vulnerable to shifting policy winds and uneven investment. For decades, the bulk power system was treated as a fixed structure, patched, retrofitted, and reinforced only as needed to support a largely stable load. Many utilities, driven by cost-recovery mechanisms that favored maintenance over modernization, found little incentive to extend transmission lines across jurisdictional divides in the absence of strong federal siting authority. And, given policy shifts with every changing administration and oversight still fragmented among state regulators, regional transmission operators, and federal agencies, the physical system is growing increasingly—and critically—misaligned (see sidebar “Engineering Organization Gives U.S. Energy Infrastructure a D+”).

Adding new pressure to the aging foundation is a fast-approaching new class of high-density load from data centers, artificial intelligence (AI) clusters, electrified industry and manufacturing, and synthetic fuel production. Utilities and grid planners are scrambling to adapt. American Electric Power (AEP) in May, for example, reported more than 180 GW of load in its queue, five times its system peak, and is already investing in 20 GW of new capacity to serve rising demand.

Regional transmission organizations (RTOs) and independent system operators (ISOs) have also sharply revised their forecasts (Figure 1). PJM Interconnection now projects a 47% rise in summer peak load by 2039; the Midcontinent Independent System Operator (MISO) expects electric load to surge 60% over the next two decades; and the Electric Reliability Council of Texas (ERCOT) forecasts its summer peak demand will climb 69%—from 85.8 GW in 2025 to 144.5 GW by 2031. ERCOT also projects total energy consumption to more than double over the same period, driven by large flexible loads like data centers, hydrogen production, cryptomining, and industrial electrification, alongside a rapid expansion in electric vehicle charging, which alone is expected to increase more than fivefold by 2031. RTO and ISO leaders all report efforts to accelerate unprecedented transmission buildouts, upgrade market structures, and launch interconnection and planning reforms to better align infrastructure with explosive demand growth.

Demand forecasts, however, remain a wildcard (Figure 2). At the Enverus Evolve conference in Houston this May, experts warned that the scope and scale of digital infrastructure, particularly AI-enabled data centers, are already outpacing traditional planning models. “We’re in a very different, complicated growth phase that’s hard to sort out,” said Mark Mills, executive director of the National Center for Energy Analytics.

He pointed to the sheer energy intensity of AI inference. If compared in terms of British thermal unit equivalence, “an Nvidia cluster, 1-GW-scale data center, every day, uses as much LNG [liquefied natural gas] as every single launch on a SpaceX Starship. It’s going to be more than one cluster, and it’s going to be running more than one day,” he said. Mills also noted that deep-pocketed tech companies may follow behind-the-meter models, predicting the model could become dominant over the next five to six years, given that the value of getting a data center operational quickly now outweighs the traditional cost considerations.

Echoing the scale of uncertainty, Ryan Luther, director of energy transition research at Enverus, described the sector’s expansion as “a capital treadmill.” He noted: “If you’re going to build a new gigawatt data center, that’s about $37 billion of [capital expenditure] upfront, and the chips are $27 billion of that. The chips last five years, and then they need to be replaced.” While utilities may not have that type of leverage, tech companies have large cash reserves, Mills noted, and may be uniquely positioned to sustain the investment cycle.

In its latest Report Card for America’s Infrastructure, released in March 2025, the American Society of Civil Engineers (ASCE)—the nation’s oldest engineering organization, founded in 1852—gave U.S. energy infrastructure a dismal D+, citing infrastructure aging, investment shortfalls, and a widening mismatch between grid capability and modern demands. The mark represents a downgrade from the C– rating the sector received in 2021, its last quadrennial report, which reflected early momentum around grid modernization. Still, the current D+ rating generally echoes previous grades over the past decade. According to the 2025 report, the U.S. energy system comprises more than 600,000 miles of transmission lines, 5.5 million miles of distribution lines, 180 million poles, and 79,000 substations, as well as 60 million distribution transformers, and extensive natural gas and petroleum pipelines. All of these serve a fleet of 12,500 utility-scale power plants. But that infrastructure is aging: 70% of transmission lines and transformers are more than 25 years old, 60% of circuit breakers exceed 30 years, and half of the nation’s gas pipelines date back to the 1950s and 1960s. Worn and weathered—and in many cases operating well past their intended lifespans—components of the energy infrastructure are slipping into obsolescence, increasingly unable to accommodate the modern power system’s demands: two-way power flows, fast-ramping inverter-based resources, and a gauntlet of extreme weather, cybersecurity threats, and precision-driven load events. Despite recent federal investment, ASCE warns that spending has not kept pace with need, and that inflation and supply constraints have eroded the purchasing power of public dollars. Distribution transformer lead times, for example, now average 120 weeks, up from 50 just three years ago, and prices have surged 60% to 80% The implications are increasingly visible, ASCE notes. While weather-related events have accounted for 80% of major grid outages since 2000, much of the system still lacks basic hardening. Aging transformers, deteriorating substations, and overloaded distribution lines have become liabilities as utilities battle against outages, wildfires, and storm-related damage. On the gas pipeline side, between 2013 and 2022, the U.S. reported more than 1,100 significant incidents, resulting in more than $4 billion in damage, 470 injuries, and 90 deaths. Without sustained investment and coordination, ASCE warns, the energy system risks becoming a structural bottleneck to economic growth, public safety, and national resilience. To reverse the decline, ASCE calls for a comprehensive modernization strategy that focuses on expanding capacity, deploying advanced technologies, and accelerating project timelines. Its top recommendations include increasing sustained investment; streamlining permitting and siting processes for both transmission lines and natural gas pipelines; creating cost-recovery mechanisms that support innovation and a more flexible grid; and improving coordination among federal agencies, state regulators, and utility operators. ASCE also highlights an urgent need to strengthen the energy workforce, warning that deployment timelines will falter without enough skilled labor to implement system upgrades at scale.

Transmission Expansion Bottlenecks and Reform Attempts

Over 2024, the federal government supercharged the effort to modernize the grid and build out new infrastructure, aided by billions of dollars in funding from the Infrastructure Investment and Jobs Act (IIJA) and the Inflation Reduction Act (IRA). Through programs like the Grid Resilience and Innovation Partnerships (GRIP) and the Transmission Facilitation Program, the Department of Energy (DOE) began directing capital toward shovel-ready transmission lines and grid-enhancing technologies, and initiated the first National Interest Electric Transmission Corridor (NIETC) designations in over a decade—a measure that could unlock backstop siting authority and catalyze interregional projects long stalled by permitting delays. DOE also finalized its Coordinated Interagency Transmission Authorizations and Permits (CITAP) program in April 2024, establishing itself as the lead agency for environmental reviews and setting a binding two-year timeline for major onshore transmission projects.

Despite record federal investment, however, progress has remained incremental. As the Federal Energy Regulatory Commission (FERC) reported in March, the power system added just 5,578 circuit miles of transmission in 2024, primarily consisting of 138-kV upgrades aimed at addressing local reliability needs. Only 22% of those projects reached 230 kV or higher—the threshold typically required for regional power transfers or large-scale clean energy integration. For context, the DOE’s 2023 National Transmission Needs Study projects the U.S. will need 54,500 GW-miles of new transmission by 2035—a 64% expansion—under moderate load and high clean energy growth scenarios (Figure 3).

According to a May 2025 working paper from think tank Resources for the Future (RFF), transmission delays remain mired by long-standing barriers. “Linear infrastructures such as transmission lines face siting and permitting challenges in multiple jurisdictions, adding to the timelines for moving from identification of a recognized need for a transmission expansion to having one that is operational,” it noted. Over the past few years, “the average development timeline has grown to 10 years for new transmission lines. For new generation capacity, it now takes five years from interconnection request to commercial operation, up from two years in 2008,” RFF noted (Figure 4).

The delays directly exacerbate grid stress and congestion, and that has had real implications for overall grid reliability and costs, the think tank warned. Under RFF’s central assumptions, transmission delays alone raise total congestion by 14%, with measurable ripple effects: electricity and gas costs rise by $22 billion, or 3% of economy-wide retail energy spending—“more than four times the capital cost savings” from deferring projects. In regions such as PJM, delays have already manifested in record capacity market spikes, underscoring what RFF calls “a key indicator of system reliability.”

To address persistent planning and cost-sharing hurdles, FERC in May 2024 issued Order No. 1920—its most consequential transmission rule in more than a decade. The rule requires long-term (20-year) regional transmission planning horizons, updated every five years, and gives states a formal role in scenario development, project selection, and cost allocation. Transmission providers must propose at least one ex ante cost allocation method per selected project, but a dedicated six-month window gives states time to negotiate alternatives. Follow-on orders in November 2024 and April 2025 further strengthened state engagement and clarified compliance milestones. While filings are underway, and FERC officials say the rule is structured to break longstanding logjams, implementation will take time—and friction remains around balancing regional priorities with multistate coordination.

At the state level, several legislatures—including Oregon, Washington, and Montana—moved in 2025 to create dedicated transmission authorities to streamline permitting and financing, following earlier models in Colorado and New Mexico. Regional task forces in Nevada, the Carolinas, and parts of the Midwest are working to harmonize siting rules and planning assumptions.

On the project front, large-scale transmission investments also appear to be advancing, despite supply chain constraints (see sidebar “Transmission Supply Chains Are Stretched to the Limit”). Construction is underway on the 732-mile, 3,000-MW TransWest Express high-voltage direct current (HVDC) line, the first major interregional project in the West in decades, which will deliver Wyoming wind to Nevada and California. In the eastern U.S., PJM approved a $6.7 billion regional plan in February 2025—its largest to date—encompassing a new 765-kV backbone to alleviate congestion associated with data centers and electrification. Texas followed suit in April with its first 765-kV line under the Permian Basin Reliability Plan, a major undertaking that marked ERCOT’s shift toward extra-high-voltage infrastructure. Other major HVDC projects moving forward include SunZia (3,000 MW, New Mexico to Arizona), Grain Belt Express (4,000 MW, Kansas to Indiana), SOO Green (2,100 MW, Iowa to Illinois via rail corridors), and New England Clean Energy Connect (1,200 MW, Quebec to Maine). Meanwhile, MISO’s $10.3 billion Tranche 1 buildout continues, with Tranche 2 planning active in 2025, and SPP has approved $1.6 billion in new regional lines to support wind integration and resilience.

According to the International Energy Agency’s (IEA’s) March-released Building the Future Transmission Grid report, investment in global transmission infrastructure surged 10% in 2023, growing to $140 billion. Yet, it will need to “more than double” by the 2030s in scenarios that meet national and global climate goals. The report notes that while many advanced economies have introduced policies to accelerate transmission investment, the market is also serving a surge of energy demand from data centers for electrical components. That is setting up a cut-throat competition for cables, materials, and critical electrical components—and, in effect, putting extraordinary pressure on supply chains. “Manufacturers are experiencing skyrocketing demand, leading to higher prices, longer procurement lead times, and record-breaking order backlogs,” the report says. Transformer and high-voltage direct current (HVDC) cable manufacturing—already concentrated among a handful of suppliers—is struggling to keep up. Manufacturers report procurement timelines of two to three years for alternating current (AC) cables, and up to five years for large HVDC submarine cables. Transformer delivery timelines have nearly doubled since 2021, now reaching four years in some cases. Power transformer prices, the IEA notes, have climbed as high as 2.6 times their pre-pandemic levels in real terms. A core challenge is that high-voltage transformers are customized for each project, requiring large drying ovens, advanced insulation processing, and grid-specific load and site design. Cable manufacturing is equally constrained, given that only 10 companies account for half the global market. Installation capacity is even tighter: only about 60 vessels worldwide can lay submarine cable, and many are already booked through 2030. Supply chain constraints have been exacerbated by disruptions in global logistics, while tight markets for raw materials, and skills shortages for manufacturing and installation, have added complexity to the landscape. Meanwhile, prices have surged across nearly every transmission component category. IEA data show cable prices have nearly doubled over the past five years, even accounting for a brief plateau in 2022. Transformer prices have risen more steeply—up to 160% in real terms—driven by material shortages, energy costs, and extreme backlog competition. Grain-oriented electrical steel (GOES), which accounts for more than 20% of a transformer’s cost, has doubled in price since 2021. Copper, which makes up roughly 60% of underground cable weight, and aluminum, used for overhead lines, have also spiked (Figure 5). High-power semiconductors used in HVDC converter valves and circuit breakers also remain in short supply. As a bright spot, the report suggests manufacturers are responding. Hitachi Energy recently announced investments of $1.5 billion to expand transformer capacity across six countries, including the U.S. Siemens Energy last year set out to build its first U.S. transformer plant—a $150 million investment. Cable makers Prysmian, Nexans, NKT, and LS Cable have all announced major expansions, citing long-term contracts as key enablers. Still, most new capacity isn’t slated to come online until 2026 or later. Delays are already affecting projects. Belgium’s Princess Elisabeth Island transmission hub, for example, has tripled in cost, from $2.3 billion to $7.3 billion, while Poland’s Harmony Link has slipped from 2025 to 2028 due to equipment constraints. The IEA warns that the global scramble for transmission hardware has fundamentally altered the nature of procurement. “Buyers, who once had the option to choose between multiple suppliers based on price and quality, are now competing for limited production slots. In many cases, there is only one supplier available, and companies often need to negotiate years in advance to secure their needs,” the report notes. Framework agreements—once limited to smaller equipment—are now standard for major components, often running up to five years and combining fixed and variable pricing indexed to inflation and raw material costs. In Europe, for example, transmission operators like TenneT and RTE have secured multi-billion-dollar cable contracts stretching through 2028. In the U.S., developers are increasingly forced to lock in transformer and cable capacity before final project approvals. To mitigate risks, the IEA outlined a coordinated response. It suggested grid planners and policymakers enhance visibility into long-term demand through transparent project pipelines and credible investment plans, while strengthening dialogue among governments, grid operators, regulators, developers, and manufacturers to improve demand forecasting. Regulatory frameworks should encourage proactive grid investment and streamline permitting without compromising environmental safeguards. At the procurement level, utilities and developers are urged to adopt long-term, standardized contracts that offer price and volume certainty. Maximizing the efficiency of existing assets through digital technologies—such as dynamic line ratings and power flow controls—can help ease immediate pressure. At the same time, the agency calls for deliberate efforts to diversify supply chains, reduce overreliance on top-tier suppliers, and expand regional manufacturing capacity. Finally, the global workforce must scale in parallel, with modernized training programs that align skills development with every stage of transmission project delivery—from design and engineering to factory work and field installation.

Distribution Grid: Modernizing the Last Mile

In response to mounting reliability concerns and the demands of a changing energy landscape, utilities invested a record $50.9 billion in distribution infrastructure in 2023, a sharp increase over prior years. For 2024, the most recent data indicate that total capital investment in the U.S. power sector reached an all-time high of approximately $179 billion, with about 42% of that—roughly $75 billion—allocated to transmission and distribution systems combined. A key driver has been the urgency to accommodate rising distributed energy resources (DERs)—rooftop solar, batteries, and electric vehicles—as well as nontraditional large loads emerging behind utility meters, such as AI clusters, cryptominers, and industrial fleets. Many of these loads connect directly to distribution feeders, bypassing ISO interconnection queues.

Federal support has been pivotal. The DOE directed about $14 billion in grants and formula funding—much of it from the IIJA—toward grid modernization, with $2.2 billion specifically earmarked for projects that harden distribution lines and boost DER integration. Projects funded through these programs supported reconductoring, automation, and targeted capacity upgrades in vulnerable and high-growth load areas.

According to the NC (North Carolina) Clean Energy Technology Center, all 50 states, plus the District of Columbia and Puerto Rico, took some form of policy or deployment action on distribution modernization in 2024—resulting in 822 recorded actions. Among key priorities last year were the establishment of distribution system planning (DSP) rules, cost-sharing frameworks for interconnection-related upgrades, and state-led evaluations of virtual power plants (VPPs). Ten of the most active states—led by New York, Massachusetts, Michigan, and New Jersey—approved major utility grid plans, adopted multi-gigawatt energy storage targets, and launched new demand-side management (DSP) dockets aimed at proactive, locationally aware investment.

Utilities, meanwhile, report modernizing operations through increased deployment of advanced distribution management systems (ADMS), DER management systems (DERMS), and feeder-level controls. So far, pilots in states including Minnesota and California are already testing advanced time-varying rates and critical peak pricing as tools to improve load management and unlock DER flexibility (see sidebar “The Technology Promise for Transmission, Distribution, and Pipelines”).

However, here too, persistent challenges remain. Experts note that many utilities lack full hosting capacity data, real-time system visibility, or the workforce needed to design and integrate modern distribution technologies at scale. For now, as the NC Clean Energy Technology Center notes, many states are examining performance-based regulation tools and launching integrated distribution system planning frameworks. These developments, combined with the tapering of near-term federal grant funding, suggest that future progress will increasingly depend on how effectively utilities and regulators adapt their planning, rate design, and digital infrastructure to manage a more distributed, two-way power system.

In both grid and pipeline sectors, the past few years have been characterized by a rapid adoption of technologies that promise to make infrastructure smarter, safer, and more efficient—delivering more energy, faster, with fewer emissions and lower costs. Transmission & Distribution. Utilities are rapidly scaling deployment of advanced conductors such as ACCC (Aluminum Conductor Composite Core) to double line capacity, reduce thermal losses, and avoid costly rebuilds. As of 2025, more than 1,350 global projects have integrated these high-performance conductors, many retrofitted onto existing towers to bypass siting constraints. U.S. utilities are using them to accelerate capacity additions and harden corridors against rising load and extreme weather. Grid-enhancing technologies (GETs), including dynamic line ratings (DLR), topology optimization software, and modular power flow controllers, are also gaining traction. These tools promise to unlock up to 30% more capacity on existing lines using real-time telemetry and analytics, offering a near-term solution to congestion, renewable curtailment, and delays in large-scale buildouts. Regulatory bodies are responding. So far, the National Association of Regulatory Utility Commissioners (NARUC), along with multiple state legislatures, has called for continued funding, valuation frameworks, and integrated resource plan integration for transmission-enhancing technologies. California, Virginia, Minnesota, and New Mexico now require utilities to evaluate GETs in transmission planning. Planners are also taking note: the California Independent System Operator’s (CAISO’s) 2024–2025 transmission plan, for example, prioritizes advanced conductors as a lower-cost pathway to meet reliability and interconnection targets. Industry is also adapting. This year, Ameren Illinois reached a regulatory settlement to integrate GETs and storage into its planning process, combining digital and physical assets to manage constraints. And in New York, National Grid is using utility-owned batteries as “storage-as-transmission” to mitigate congestion and improve renewable integration. Still, challenges remain. Standardization, integration with ISO markets, limited sensor coverage, and persistent equipment lead times all temper full-scale deployment. Pipelines. Parallel innovation is transforming the gas pipeline sector. Internet of Things (IoT)-enabled smart pipeline networks are rapidly becoming the industry standard, leveraging sensor arrays and artificial intelligence for predictive maintenance and real-time leak detection—capabilities that can reduce maintenance costs by up to 30%. Modular and prefabricated pipeline sections, currently expanding at an annual rate of 8% to 10%, accelerate deployment and mitigate quality risks, particularly for remote projects. Security and monitoring technologies are also advancing rapidly. Operators such as Enbridge and Chevron are implementing advanced supervisory control and data acquisition (SCADA) systems, blockchain-secured data protocols, and real-time anomaly detection tools to comply with new federal safety and cybersecurity requirements. Enhanced in-line inspection (ILI) and non-destructive evaluation (NDE) techniques are increasingly being codified in industry training and standards programs as of 2025.

Keeping Dispatchable Power Online—and Fueled

While investments in transmission and distribution remain critical, experts are also increasingly flagging an urgent need to reinforce the infrastructure underpinning dispatchable generation—a near-term reliability pillar that, in many regions, may prove indispensable. “There are states where you can’t build certain types of generation,” NERC’s Moura explained to POWER. “There are areas where you have a lot of generation. Transmission is an obvious solution as one option,” he said, “but there are local solutions as well.” Natural gas is among the most readily available, “but you can’t really even think about building natural gas without thinking about the gas pipeline infrastructure,” he added. “So whether that means storage, more pipeline, and other options—even oil backup—I think that is a critical component. All that infrastructure, we see, needs to be increased as we progress forward.”

In 2024, natural gas supplied 43% of U.S. electricity generation (Figure 5), drawn from a gas-fired fleet of about 567 GW. That dominance is only slated to grow. Rystad Energy in January suggested U.S. utilities are planning 17.5 GW of new gas-fired capacity—marking the highest level of project activity since 2017. Newer industry projections hover around 46 GW of additions over the next five years, while a recent POWER analysis of utility earnings statements suggests the actual buildout may be higher still.

But as demand for natural gas surges, the physical system that supports it will be strained. “According to EIA [the U.S. Energy Information Administration], in 2024, U.S. natural gas consumption averaged a record 90.3 billion cubic feet per day (Bcf/d) and set new winter and summer monthly records in January and July,” Amy Andryszak, president and CEO of the Interstate Natural Gas Association of America (INGAA), said in testimony before a House subcommittee in April. Last year, the U.S. added a record 17.8 Bcf/d of new pipeline capacity, including the Mountain Valley Pipeline and the Matterhorn Express. However, federal data shows that most of those additions supported LNG exports or upstream congestion relief—not power markets. According to the EIA, only 0.9 Bcf/d of that total came from interstate pipelines—down from 65% of additions in 2017—while 5.2 Bcf/d was intrastate, nearly all concentrated in Texas and Louisiana to serve Gulf Coast LNG demand.

Gas consumption will be even higher in 2025 and 2026, Andryszak noted. “A Goldman Sachs analysis shows an additional 47 GW of electric generation capacity will be required to support data center power demand growth by 2030, and it estimates 60% will come from gas and 40% will be derived from renewables. That equates to an additional 3.3 Bcf/d of natural gas pipeline capacity to meet the demand growth from data centers by 2030.” Meanwhile, “Calculations by S&P Global suggest additional gas demand could be as high as 6 Bcf/d by 2030,” she said. “It is self-evident that we will not meet this scale of growing demand for natural gas without adding new pipeline and storage capacity, and the status quo regulatory regime that discourages investment in infrastructure will not get us there.”

Even where pipeline expansion is technically feasible, projects often face delays due to permitting, environmental review, land acquisition, and local opposition—issues that are compounded by rising material costs and increasing project management complexity. The sector is also grappling with its own supply chain challenges, driven by global competition for critical components, transportation bottlenecks, labor shortages, and ongoing disruptions in the availability of specialized equipment and materials. Additionally, regulatory uncertainty, evolving climate policies, and financing risks can further complicate and delay project development.

Storage Shortfalls and Systemic Gaps Threaten Gas Reliability

Gas-fired generation projects face their own set of challenges. As POWER recently reported, surging demand for gas-fired generation is straining the turbine supply chain, driving up prices and extending lead times for new combustion turbines to as much as four to five years. All three major original equipment manufacturers have reported record turbine order backlogs, prompting a return to reservation fees and production slot agreements to secure manufacturing capacity. Developers now often must commit funding well before siting or interconnection is finalized adding to project financial and operational risks.

But the natural gas sector is also grappling with serious natural gas storage constraints. The American Gas Association (AGA) underscored in an April 2025 report, the power sector already leans heavily on gas storage: On peak days, natural gas storage withdrawals support more than 21,000 GWh of electricity, equivalent to 144 times the output of all U.S. battery and pumped hydro storage combined. And, while storage is rarely included in capacity accreditation or state-level energy planning, dozens of new gas-fired power plants under development across the U.S. are sited in high-demand areas with little or no adjacent storage infrastructure. Compounding this is that seasonal patterns are also shifting. Electric-sector gas consumption now peaks in summer, compressing refill windows even more and straining traditional planning assumptions.

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On peak days, natural gas storage withdrawals support more than 21,000 GWh of electricity, equivalent to 144 times the output of all U.S. battery and pumped hydro storage combined.

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The key concern is that underground storage capacity has grown at just 0.1% per year since 2014—far slower than increases in gas production, pipeline expansions, or demand from gas-fired generation. Over the past five years, underground storage utilization in the East, Midwest, and Mountain states has approached or exceeded 90% heading into the winter heating season. At the same time, daily Henry Hub price volatility has surged, averaging 71% between 2020 and 2024 compared to 43% in the preceding five-year period, pointing to storage’s diminished traditional role as a physical and financial buffer against market shocks and extreme weather demand.

According to AGA, “Despite the proven value of natural gas storage facilities to the energy system, several structural and regulatory challenges continue to limit the system’s overall effectiveness.” Chief among these are lengthy, uncertain permitting processes, which could stretch several years from concept to operation, along with land-use opposition and overlapping federal and state reviews that discourage early-stage investment. In many cases, developers face unclear cost recovery pathways, especially in deregulated power markets, where storage receives little or no compensation for providing backup capacity or fast-ramping flexibility. And, even in regulated regions, rate cases may not fully reflect the resilience and system-wide benefits storage provides. At the same time, many older storage facilities suffer from limited withdrawal capability, reducing their usefulness for fast power-sector ramping. These factors create a disconnect between the operational importance of storage and its perceived market value—a mismatch that, AGA warns, could leave the power system vulnerable as demand rises and clean energy integration deepens.

AGA President and CEO Karen Harbert warned, “America’s natural gas system requires expanded storage capacity that is flexible and responsive to help enable our system to reliably meet increasing demand from power generation, data centers, and a reshoring of American manufacturing.” Without targeted policy action, the AGA said, the U.S. risks “service interruptions during extreme weather, price shocks for consumers, and impacts on grid reliability”—especially as renewable integration further amplifies the need for fast-ramping, on-demand fuel reserves.

Finally, experts point to another persistent systemic blind spot: Because natural gas and electric planning remain largely siloed, the risk of fuel supply disruptions during periods of peak power demand is increased. A joint review by FERC, NERC, and regional entities of January 2025 arctic events, which comprised Winter Storms Blair, Cora, Demi, and Enzo, underscored the need for better coordination, citing misaligned scheduling, limited real-time transparency, and inadequate data sharing—especially in intrastate gas systems—as persistent barriers that hinder generators’ ability to secure timely fuel deliveries. The report calls for more formalized cross-sector planning, shared risk modeling, fuel availability surveys, and scheduling reforms.

NERC has consistently highlighted the growing operational risk (Figure 6) posed by the rising reliance on gas-fired generation, especially in regions where pipeline constraints, wellhead freeze-offs, and electricity-dependent gas infrastructure can challenge deliverability during extreme weather. It warned that planning coordination between gas and electric systems remains insufficient, and that both systems would benefit from regulatory reforms, improved communication protocols, and aligned market schedules during extreme weather. The designated reliability organization, notably, has expressed strong support for new efforts, such as the Gas Electric Reliability for America (GERA) task force, while also calling for deeper coordination across policy, market, and infrastructure domains to ensure winter readiness and system-wide resilience.

Persistent Uncertainties

The behemoth task of modernizing and expanding the interconnected power system ultimately hinges on two things: investment and people. Despite unprecedented federal support through the IIJA and IRA, the U.S. still lacks a coherent financing model for long-term grid infrastructure. Transmission, dispatchable generation, and fuel supply all rely on state-level rate cases—a process increasingly mismatched with the speed of electrification and market volatility. As Deloitte noted in its 2025 industry outlook, delays in cost recovery are already inflating electricity prices, and some utilities are piloting large-load tariffs to shift grid upgrade costs onto data centers and industrial users. The bigger question is looming: Who pays for the grid of the future—and will regulators adapt in time?

The urgency is mounting, driven by intensifying global competition and shifting energy geopolitics. In China, permitting and investment decisions flow through centralized five-year plans, allowing ultra-high-voltage lines to be built in just a year and a half—compared to eight or more in the U.S. and Europe, where permitting remains a core obstacle. The European Union mandates coordinated cross-border planning and ties grid operator returns to performance. By contrast, even the most ambitious U.S. reforms are still years away from impacting the industry, and face legal headwinds and constant political churn.

“We have this very big mountain to climb in terms of investment because we need to push more electrons to the grid,” Anthony Allard, executive vice president and managing director of Hitachi Energy in the U.S., told POWER in March. “The grid, on top of that, needs to be reliable and resilient.” What’s missing, he added, is a 20- to 30-year vision that gives the private sector confidence to act. “Once this planning is available, then the private sector can come in and say, ‘Let’s find ways with the right type of project and the right type of capital to be able to execute on that,’ ” Allard said.

The next big bottleneck will be finding skilled labor. According to the International Energy Agency, the global power sector will need 1.5 million more workers by 2030 just to meet current transmission and distribution targets—a gap that threatens to stall both grid projects and domestic equipment manufacturing. “We need to invest a lot in people. We need the workforce to grow, and that’s a real concern for the entire industry,” Allard noted. n

—Sonal Patel is a POWER senior editor (@sonalcpatel, @POWERmagazine).