The U.S. power sector is facing a critical supply-demand imbalance. As electricity demand projections accelerate—driven by everything from Artificial Intelligence (AI) data centers to onshoring of industrial capacity—the challenge of ensuring resource adequacy has moved from a technical concern to a systemic risk. Grid operators, regulators, and market participants are now being forced to grapple with a widening gap between new load growth and planned, dispatchable supply.
We see the evolving risk landscape as more than just a planning challenge. It is a test of policy coherence, technology readiness, and market design.
Demand Projections Are Outpacing Supply
Recent load forecasts point to significant demand growth through the end of the decade. Even after accounting for de-duplication among utilities (removing double- or triple-counting of load assumptions), the net picture remains significant enough to put pressure on reserve margins, with resource adequacy having become elevated to a government priority.
One key driver is hyperscale data centers with large and dynamic 24/7 loads. Time is of the essence for the developers and owners of these facilities which create additional requirements for voltage stability and overall grid reliability. In response, the current administration has prioritized resource adequacy with a renewed preference for fossil fuels, re-emphasizing natural gas as a necessary bridge fuel.
Deferred Retirements and Interconnection Friction
In this environment where demand is rising but new supply remains uncertain, grid operators and government agencies are increasingly deferring planned retirements of dispatchable assets. Coal and aging gas plants that were scheduled to shut down are being kept online longer as a reliability hedge.
Meanwhile, the interconnection queues—where developers seek approval to connect new generation to the grid—remain congested. Reforms by entities like FERC and regional transmission operators are beginning to reduce the backlog of planned projects; however, delays remain long and costly. Although most projects in the queues are renewables, the pace at which they can come online is throttled by transmission constraints including equipment supply chain delays, permitting delays, and project attrition.
Headwinds for Renewables
Renewables continue to dominate the pipeline of proposed projects, but looming federal policy changes threaten that trajectory. The “Big Beautiful Bill” signed into law July 4, 2025 is set to curtail tax credits for renewable energy projects completed after 2027, and combined with recent executive orders, this policy shift could significantly impact the project economics of wind and solar just as they are poised to scale up in response to demand growth.
In parallel, new capacity accreditation mechanisms (e.g. Marginal ELCC in PJM) designed to account for the true reliability value of a resource are reducing the contribution of intermittent sources like wind and solar toward capacity requirements. In essence, a megawatt of solar does not count the same as a megawatt of gas when it comes to resource adequacy.
Storage: Crucial but Constrained
Battery storage is frequently cited as the bridge to a renewable-dominant future. However, in practice, storage is hampered by several factors:
- Technology risk: Lithium-ion remains the only “bankable” chemistry, limiting innovation in long-duration storage.
- Duration limits: Most commercial-scale systems are designed for 4–6 hours of discharge, insufficient for multi-day lulls in wind or sun.
- Market design: In regions like PJM, price signals remain unsupportive of storage’s full capabilities, limiting its role in capacity markets.
- Tariffs: Proposed tariffs on several Asian countries, especially China, could have significant negative impacts on battery storage economics going forward.
Until these constraints are addressed, whether through new technologies, subsidies, or reforms, battery storage alone will not provide the firm reliability planners are seeking.
New Firm Capacity: Challenges and Tradeoffs
Even where there is appetite for new firm generation, actual new-build activity faces serious headwinds. Lead times for key equipment—including prime movers, turbines, and transmission components—can stretch into years. That leaves planners turning to a combination of preferred sources of incremental capacity:
- Uprating existing generation units
- Reactivating recently retired plants
- Demand response programs that reduce peak loads
- Baseload dispatch of mid-merit combined cycle gas plants
- Selective new-build of gas-fired units, where feasible
Of these, natural gas remains the preferred fuel source for dispatchable additions. Next-generation nuclear, while promising, is still sidelined from near-term capacity plans due to financing challenges, long development cycles, and regulatory complexity—a topic we will explore in a future Tangibl blog.
Distorted Price Signals in Organized Markets
One of the paradoxes of today’s energy market is that while reliability risks are rising, organized markets (like PJM, ISO-NE, and CAISO) often fail to send clear investment signals. Several factors contribute to this:
- Capacity price collars cap upside potential in auctions
- Energy price caps at peak reduce returns on firm resources
- Reactive power services that are essential for voltage stability are often uncompensated
This distortion hampers rational planning and discourages the very kinds of investments the system needs.
PJM Interconnection’s Board of Managers, realizing a forecast increase in 32 GW of peak load from 2024 to 2030, has “decided to implement the Critical Issue Fast Path (CIFP) accelerated stakeholder process mechanism to pursue stakeholder consensus that would inform a PJM Board decision on a potential FERC filing on this subject targeted for December 2025.”
Bilateral Markets Offer Relief—With Caveats
In contrast, bilateral markets—particularly those with state-led integrated resource planning (IRP)—have emerged as a more favorable environment for firm capacity additions. By allowing utilities to recover costs through ratepayer-backed plans, these markets have enabled some new builds to proceed.
But the model is not without risk. Plant Vogtle, the most prominent example, is nearing $33 billion in cost, underscoring the danger of overbuilding or encountering runaway capital costs under ratepayer guarantees.
The Political Optics of Affordability
Finally, affordability is becoming an increasingly contentious political issue, particularly in high-cost states like New Jersey. As customers begin to see higher bills driven by passthroughs for transmission upgrades and generation capacity, there is growing frustration with opaque pricing mechanisms and policy overlays.
This may spark a renewed appreciation for more transparent market structures that are less burdened by caps, collars, and carve-outs that skew incentives and tilt outcomes in favor of particular stakeholders.
Looking Ahead
The U.S. grid is entering a period of structural stress. The clean energy transition is momentarily challenged, and the path forward will require sober decisions about how to maintain firm reliability, control costs, and keep markets functional. Resource adequacy risk is no longer theoretical; it’s a defining challenge of this decade.
At Tangibl, we help infrastructure investors, developers, and policymakers navigate this complexity with real-time insight and practical analysis. As conditions evolve—from tax policy to technology readiness—we’ll continue to publish perspectives on the key shifts that matter.