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Frank Willey is an assistant director and Stephen Greene is a nonresident senior fellow in the Atlantic Council’s Global Energy Center.
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 are indicative of 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 in the past have plagued the vertically integrated model. Rather than discarding competitive markets altogether, along with the decades of improvements they have brought, states, FERC and regional transmission organizations should drive greater use of long-term power purchase agreements between generators and off-takers, including load-serving entities, or LSEs, that serve retail customers. These long-term agreements support the more durable, long-term investment signals encouraging the sustained buildout of infrastructure that RTO-managed spot and capacity markets cannot reliably provide.
As PJM's recent white paper lays out, these long-term agreements could be bilateral agreements between independent power producers and LSEs, driven by hedging requirements imposed by regulators, or 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 at which 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 1992 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 include attractive default-provider provisions that substantially reduce the incentives for competition. In 2024, residential customers’ subscription rates to competitive suppliers hovered around 25% in those states, excluding Texas, according to EIA data.
Utility commissions pushed to make default service options very attractive, in part to show that restructuring would deliver lower prices quickly, oftentimes mandating rate reductions of 10% to 20% as the program was implemented. Many states also encouraged default providers to lean heavily on the spot market rather than locking in longer-term supply. Rather than making electricity markets and the underlying system more efficient, many academic papers have argued that 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 has not been 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 fault in market implementation has been exposed, and price spikes have been the result.
‘Market’ means more than just RTO exchanges
Introducing competition into electricity markets was never intended to yield total reliance on central RTO-administered spot markets. In fact, 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 some 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 over-investing in capital assets to drive revenue growth. Restructuring has delivered on both of these goals and brought substantial benefits to consumers over the past two decades. Neither goal required abandoning contracts nor exposing consumers to volatile spot markets.
Managing demand growth requires providing 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, because the higher investment needs to be recovered over the life of the project, while, under the current market structure, the 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 that would result 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 drives 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. If anything, the use of long-term contracts is 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 simply restoring the contracting layer that was abandoned in the move to a retail structure reliant on primarily short-term contracts. That restoration doesn't 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 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 do 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.