Risks in a Changing U.S. Power Grid

The U.S. power system is undergoing a structural transformation. On the demand side, rapid growth in AI-driven data centers and acceleration of electrification across heating, transportation, and industry are reshaping load profiles and increasing pressure on resource adequacy. On the supply side, expansion of renewable generation and storage, alongside coal retirements, has introduced greater variability and uncertainty into resource availability, raising new reliability concerns.

These changes are reconfiguring grid risk structures and exposing the limitations of market designs developed for conventional resources. Five categories of risk are particularly salient.

Locational Congestion Risk. Locational congestion risk arises when transmission constraints prevent lower-cost generation from reaching load centers, producing price differentials across nodes. As renewables and storage expand, congestion becomes more frequent and less predictable, exposing limits in systems designed around dispatchable thermal resources.

One example is PJM Interconnection (PJM), particularly in Northern Virginia, where rapid data center expansion significantly increased electricity demand. Much of the generation serving the region remains located elsewhere in PJM’s territory and must flow across constrained transmission interfaces. During high-demand periods, these constraints converge and trigger price separation between generation-rich regions and load centers. In a locational marginal pricing framework, this divergence between hub and busbar prices creates meaningful congestion-related financial risk for market participants.

Temporal Price Risk. Temporal price risk refers to uncertainty in locational marginal prices over time. Short-term volatility reflects dispatch decisions and fuel price fluctuations, while longer-term trends are driven by structural shifts in generation, plant retirements, and evolving demand.

Energy storage assets are especially sensitive to temporal dynamics. Storage owners depend on inter-hour price spreads, with profitability determined by the magnitude and persistence of those spreads. Short-duration storage benefits from frequent, brief price spikes, while longer-duration storage captures value during sustained scarcity events.

As dispatch decisions are intertemporal, actions taken influence subsequent prices and system conditions. These feedback effects create strategic interactions and increase the importance of well-aligned market rules.

Volume Variability Risk. Volume variability risk reflects uncertainty in the quantity of electricity supplied or demanded over time. Load fluctuations, renewable output variability, and unexpected outages contribute to this risk. For weather-dependent resources, volume uncertainty is particularly pronounced, raising concerns about capacity adequacy and real-time balancing.

The 2021 Texas power crisis illustrates this exposure. On a cold February day, wind generation in West Texas fell roughly 50% below forecasts as record-low temperatures pushed demand near 70 gigawatts. At the center of this supply shortfall was ERCOT, the region’s independent system operator. With enormous power supply shortages, ERCOT was forced to implement rolling outages, contributing to around $80-$130 billion in losses.

Demand and Supply Tail Risk. Tail risks are low-probability, high-impact events that strain system limits and aren’t easily hedged through conventional financial instruments. Climate change, for example, increases supply-side tail risks by exposing infrastructure to more frequent extreme weather.

Severe climate events account for many U.S. power outages, with evidence of upward trends in such disruptions. Beyond climate effects, cyberattacks and technology-driven failures present additional systemic threats. On the demand side, concentrated growth from large data centers may amplify localized stress during extreme conditions.

Regulatory Design Risk. Regulatory design risk stems from changes to market rules governing dispatch, pricing, and compensation. When new mechanisms interact poorly with prevailing system conditions, they can distort incentives or undermine reliability. Unlike operational risks, regulatory design risk originates from policy choices.

The California energy crisis from 2000 to 2001 demonstrated the ways partial deregulation, retail price caps, and flawed wholesale design led to price volatility. Wholesale prices surged while utilities could not pass costs through to retail customers, resulting in financial distress and emergency intervention.

Collectively, these risks reflect a power system whose financial and operational dynamics are becoming more complex and interdependent. As variability increases across locations, time horizons, and regulatory regimes, market participants will require more sophisticated hedging instruments and strategic frameworks to manage evolving grid exposure.

Daniel Yang

MPP/MBA, Harvard and Wharton

Daniel Yang is a joint degree MPP/MBA candidate at Harvard and Wharton. He previously worked in renewable energy structured finance and management consulting. He holds an MSc in Energy Systems from Oxford and a BA in Economics from Stanford.