Rising Wholesale Power Prices: What Energy Buyers, Developers, and Lenders Need to Know About PPA Risk in 2026

After nearly two decades of flat electricity demand, the U.S. power market has entered a new era of rising prices, growing volatility, and structural change. Wholesale electricity prices surged across the country in 2025, with year-on-year increases of 62% in New York, 60% in New England, and 45% in PJM, driven by higher natural gas prices, tightening capacity markets, and deepening grid constraints. [1] Retail prices rose more modestly—about 2.3% nationally—but the widening gap between wholesale volatility and retail pass-through is creating significant financial exposure for market participants on both sides of power purchase agreements.

These price movements are not cyclical blips. They reflect a fundamental shift in the supply-demand balance. U.S. electricity demand is rising at the fastest pace in a generation, fueled by data center buildouts, manufacturing reshoring, and electrification of transportation and buildings. [2] The country commissioned 54 GW of new utility-scale generation and storage in 2025—the most in over two decades—and invested a record $115 billion in grid expansion and reinforcement. [3] [4] Yet even that record-setting buildout has not been enough to ease pricing pressure in congested regions, particularly in the Northeast and Mid-Atlantic, where natural gas dependence amplifies weather-driven volatility.

The January 2026 winter storm underscored this vulnerability. Frigid temperatures and restricted natural gas supplies triggered widespread power plant outages across the Eastern U.S., sending prices spiking and raising fresh concerns about resource adequacy during peak demand periods. [5] These events are not hypothetical risks—they are the operating environment in which PPAs, capacity market positions, and project finance assumptions must perform.

The PPA Market Is Repricing Risk

For renewable energy developers and corporate offtakers, the most consequential trend is the repricing of risk in the PPA market. S&P Global reports that spreads between buyer and seller price expectations have widened significantly in key markets, as both sides reassess the economics of long-term contracting in a higher-price, higher-volatility environment. [6] Solar capture rates—the ratio of a project’s average realized revenue to the market clearing price—are deteriorating as more solar capacity compresses midday prices, exposing projects to growing periods of zero or negative pricing.

This dynamic is driving several important structural shifts in PPA terms. Contract durations are trending shorter, reflecting buyer reluctance to lock in long-term price commitments amid uncertainty about future wholesale price trajectories. Downside protections, including floor prices and shape guarantees, are becoming more common as developers seek to de-risk revenue streams. [7] And battery energy storage is increasingly being integrated into PPA structures—both co-located and standalone—as a mechanism to shift generation into higher-value hours and mitigate capture rate risk. Standalone and co-located BESS deals are rising rapidly, with particularly strong growth in Texas, California, and the PJM footprint. [8]

Capacity Markets Under Pressure

The capacity market overlay adds another layer of complexity. PJM’s capacity market—the largest in the country—has been a flashpoint for litigation and regulatory action, as stakeholders contest whether current market designs adequately compensate the resources needed to ensure reliability in a rapidly changing resource mix. The D.C. Circuit recently found that FERC erred in declining to consider Section 206 relief in the 2024/25 PJM capacity auction re-run case, a decision that could have significant implications for future auction design and pricing. [9]

At the state level, regulators are grappling with the affordability implications of wholesale price increases. The combined share of electricity and natural gas costs as a percentage of total household expenditure rose to 1.62% in 2025, a departure from the recent trend of declining energy cost burdens. [10] Several state commissions are placing greater emphasis on how utility programs align with affordability goals and grid reliability, and are scrutinizing whether rate designs adequately protect consumers from wholesale price pass-through. [11] Massachusetts provides a compelling case study: Governor Healey’s March 2026 executive order establishing the “10X10X10 Plan”—targeting 10 GW of new energy resources over 10 years with $10 billion in projected customer savings—was driven explicitly by ISO New England’s projection that electricity consumption could rise nearly 15% by 2035. [12]

What This Means for Market Participants

For corporate energy buyers, the current environment demands a more sophisticated approach to energy procurement. Companies that have relied on standard virtual PPAs may find that basis risk—the divergence between the contract settlement point and the buyer’s actual load zone—has become a material financial exposure. Physical PPAs and behind-the-meter generation options warrant fresh evaluation, particularly for companies with concentrated load in high-price regions. The strategic case for energy risk management has never been stronger—energy should appear alongside cybersecurity, supply chain, and regulatory risk in enterprise risk management frameworks. [13]

For renewable developers, the key challenge is structuring projects and offtake agreements that can attract financing in a market where merchant tail risk is increasing and capture rates are compressing. Lenders and tax equity investors are asking harder questions about revenue assumptions and hedge coverage, and project finance underwriting is tightening in response to wholesale price volatility. [14] Developers who can pair generation with storage, offer shaped products, and demonstrate grid-positive attributes will be best positioned to compete for offtake and financing.

The throughline connecting these developments is straightforward: the repricing of wholesale power is simultaneously reshaping PPA economics, pressuring capacity market design, and tightening project finance underwriting—and these forces are reinforcing one another. [14] [15] Higher wholesale prices widen the gap between contracted and market revenues, which intensifies capture rate risk in PPAs, which in turn makes lenders demand more conservative debt sizing and hedge coverage, which raises the cost of capital for new projects at precisely the moment when record new capacity is needed to meet surging demand. [14] [7] [3] The market participants who navigate this cycle successfully will be those who treat PPA structuring, capacity market positioning, and financing strategy not as separate workstreams but as an integrated discipline—and who act on that recognition now rather than after the next price spike forces their hand.

References

1. 2026 Top Six Trends – Business Council for Sustainable Energy
2. Energized for 2026 | Federal Energy Regulatory Commission
3. 2026 Top Six Trends – Business Council for Sustainable Energy
4. 2026 Top Six Trends – Business Council for Sustainable Energy
5. Power plant outages surge in Eastern US amid restricted gas supplies and frigid weather | Reuters
6. Horizons Top Trends 2026 | S&P Global
7. Horizons Top Trends 2026 | S&P Global
8. Horizons Top Trends 2026 | S&P Global
9. D.C. Circuit Finds FERC Erred in Declining to Consider …
10. 2026 Top Six Trends – Business Council for Sustainable Energy
11. Regulatory Trends Shaping Utility Customer Programs in 2026 – ICF
12. Executive Order to Secure Massachusetts’ Energy Future | Mass.gov
13. The New Energy Trade War: Why Every CEO Must Rethink Their Power Strategy Now | Foley & Lardner LLP
14. 2026 Top Six Trends – Business Council for Sustainable Energy
15. 2026 Top Six Trends – Business Council for Sustainable Energy