A Utility Dive commentary argues that PJM's capacity price spikes reflect a market design problem, with the market having drifted too far toward dependence on spot prices, rather than proof that competition itself has failed.

Across the country, wholesale markets are signaling looming electricity shortages, and some observers have called for a return to the regulated, vertically integrated utility model. The PJM Interconnection's latest capacity market auction cleared at the Federal Energy Regulatory Commission's approved cap for the third consecutive time, more than eleven times the price four years ago, and fell short of PJM's reliability requirement. The results reflect the scope of the underinvestment crisis.

However, advocating for competitive markets to be abolished and replaced with vertically integrated models conflates concerns about aspects of competitive wholesale market implementation with a fundamental failure of the market-based framework itself.

Competitive markets have brought innovation and efficiency to the deployment of power generation and have removed the poor incentives that plagued the vertically integrated model in the past. Rather than discarding competitive markets altogether, along with the decades of improvements they have brought, states, FERC and regional transmission organizations (RTOs) should drive greater use of long-term power purchase agreements between generators and off-takers, including load-serving entities (LSEs) that serve retail customers. These long-term agreements support the durable, long-term investment signals needed to sustain the buildout of infrastructure, which RTO-managed spot and capacity markets cannot reliably provide.

As PJM's recent white paper lays out, these long-term agreements could take several forms: bilateral agreements between independent power producers (IPPs) and LSEs, driven by hedging requirements imposed by regulators, or agreements directly between IPPs and RTOs, funded through a reliability charge to participants.

## History of competitive wholesale electricity markets

Introducing competition into electricity markets was a policy goal pursued over several decades. A series of legislative actions and FERC orders enabled competitive wholesale power markets:

- **1978:** The Public Utility Regulatory Policies Act required utilities to buy electricity from qualifying independent generators at the price the utility would have paid to generate electricity or purchase it from another source.

- **1992:** The Energy Policy Act, among other reforms, expanded FERC's authority, on a case-by-case basis, to require utilities to provide access to transmission systems.

- **1996:** FERC Orders 888 and 889 built on the Energy Policy Act, requiring public utilities to provide open, non-discriminatory access to transmission and establishing standards of conduct and rules for information sharing.

- **1999:** FERC Order 2000 established the framework for the RTOs that now operate across much of the country, including PJM.

## Retail competition never materialized outside of Texas

In PJM, as in many restructured markets, retail competition never developed as robustly as regulators expected. Thirteen states and the District of Columbia offer residential electricity choice programs, but they include attractive default-provider provisions that substantially reduce the incentive to switch suppliers. In 2024, according to EIA data, residential customers' subscription rates to competitive suppliers hovered around 25% in those states, excluding Texas.

Utility commissions pushed to make default service options very attractive, in part to show that restructuring would deliver lower prices quickly. They often mandated rate reductions of 10% to 20% as the programs were implemented. Many states also encouraged default providers to lean heavily on the spot market rather than lock in longer-term supply. Rather than making electricity markets and the underlying system more efficient, many academic papers have argued, electricity market restructuring created a structural subsidy under which the cost of default retail supply is subsidized by regulated transmission and distribution service.

Until recently, the danger of relying heavily on the spot market was not evident, because low demand growth masked the importance of long-term contracts, including for capacity. Such "hedging" contracts would protect consumers from volatile wholesale prices and give generators predictable revenue streams, thereby facilitating more investment in additional generation capacity at lower cost, which helps moderate prices. As demand growth has accelerated, this weakness in market implementation has been exposed, and price spikes have followed.

## "Market" means more than just RTO exchanges

Introducing competition into electricity markets was never intended to produce total reliance on centrally administered RTO spot markets. The original designers of markets envisioned sophisticated LSEs procuring power from sophisticated generation operators, while RTO markets would simply handle transmission constraints and "imbalances" close to or in real time.

In most well-functioning commodity markets, such as agricultural commodities, steel or bulk chemicals, buyers and sellers rely on a mix of contracts and spot purchases to manage supply, demand and volatility. Long-term contracts provide stability for both consumers and producers, keeping supply and demand in rough balance, while participation in short-term or spot markets allows both sides to make shorter-term adjustments. Electricity market restructuring had two goals: to bring competition to electric generation and retail sales, and to reduce regulated utilities' structural bias toward overinvesting in capital assets to drive revenue growth. Restructuring has delivered on both goals and brought substantial benefits to consumers over the past two decades. Neither goal required abandoning contracts or exposing consumers to volatile spot markets.

Managing demand growth requires predictable and durable incentives for generation investment. There is no business case for a developer to build generation on the back of short-term price spikes when supply costs are high, as they are now. Higher investment must be recovered over the life of a project, but under the current market structure, prices available through the market are likely to return to lower, normal levels in just a few years.

An all-spot market is feasible in theory, but the extreme spot prices it would produce would be disruptive and unacceptable. Long-term contracts work better for both suppliers and customers. Even in Texas, where shortages can drive spot energy prices to high levels, the retail market structure leads retail providers to put contracts in place to hedge against short-term price spikes.

## Recommendations and conclusion

Encouraging long-term agreements in competitive wholesale power markets would support reliability while maintaining the original goals of restructuring. The use of long-term contracts is, if anything, consistent with how these markets were expected to work from the start: independent developers still compete to offer the best generation projects and still bear the risk of executing them. What changes is restoring the contracting layer that was abandoned in the move to a retail structure reliant primarily on short-term contracts. That restoration does not require reinventing wholesale markets, but rather using tools already available under the existing framework.

Prudent buyers would build a portfolio of overlapping agreements signed at different times, so that contracts signed during a shortage at higher prices are balanced by contracts signed when new capacity is cheaper to build. Spot markets still play a role, reconciling the gap between what was contracted and what is actually needed at delivery, but they should not be relied on to carry the entire market, any more than they are in other commodity markets.

PJM's capacity price spikes are a symptom of a market that drifted too far toward spot-price dependence, not an indication that competition itself does not work. Reorienting competitive wholesale markets requires rebuilding the long-term contracting layer, through hedging requirements driven by state regulators, RTO-brokered reliability charges, or both, rather than abolishing the competitive market structure and the benefits it has already demonstrated.

*Frank Willey is an assistant director and Stephen Greene is a nonresident senior fellow in the Atlantic Council's Global Energy Center.*