The Missing Money Problem: How Capacity Markets Compensate Power Plants for Standby Reliability

The transition to intermittent renewable energy and the surge in data center load have fundamentally altered how wholesale electricity markets value standby power, forcing grid operators across the United States to pay generators billions of dollars annually simply to exist. In the PJM Interconnection, which serves 65 million people from New Jersey to Illinois, the cost of this standby reliability has skyrocketed. For the 2026/2027 delivery year, the grid operator will pay power plants a record $329.17 per megawatt-day just to remain available for dispatch, a nearly 1,100 percent increase from the prices seen two years prior.[3]

This massive capital outlay is the direct result of a structural flaw in deregulated electricity grids known to economists as the "missing money problem." When wholesale electricity markets were designed in the late 1990s, the theory was that power plants would recover their fixed construction and maintenance costs by selling electricity during periods of high demand, when prices naturally spike. However, to protect consumers from extreme volatility, regulators imposed price caps on these spot markets.[1]

By artificially suppressing the price of electricity during scarcity events, those caps prevent generators—particularly natural gas "peaker" plants that only run a few hundred hours a year—from earning enough revenue to survive. As Cambridge University Press research outlines, "The missing money problem is a theory contending that features specific to electricity markets distort incentives for investment in generation capacity, impairing reliability." The money they need to remain economically viable is "missing" from the energy market. Without an alternative revenue stream, these critical backup plants retire, and developers refuse to build new ones.[1]

The problem is compounded by the zero-marginal-cost nature of renewable energy. When wind and solar farms generate electricity, they bid into the wholesale market at or near zero, driving down the average spot price of energy across the board. This "merit order effect" further erodes the energy-market revenues of traditional thermal plants, making them even more dependent on scarcity pricing just as regulators act to cap it.[1][4]

To solve this, grid operators like PJM created forward capacity markets. In these markets, the product being bought and sold is not electricity itself, but the promise to deliver it if called upon three years in the future. PJM determines how much total power the grid will need during the hottest hour of the summer, adds a reserve margin for safety, and holds an auction to procure that exact amount of capacity.[4]

The financial scale of this mechanism is vast. For the 2026/2027 delivery year, PJM procured 146,244 megawatts of unforced capacity. At the clearing price of $329.17 per megawatt-day, Factlen calculates that the total cost of this capacity market will reach approximately $17.57 billion for the year. That cost is passed directly to utility customers as a reliability charge on their monthly bills, regardless of whether those specific power plants are ever actually turned on.[3][4]

The alternative to this system is the "energy-only" market, most prominently utilized by the Electric Reliability Council of Texas (ERCOT). ERCOT does not pay generators for capacity. Instead, it allows wholesale electricity prices to rise as high as $5,000 per megawatt-hour during grid emergencies. The promise of capturing those massive, fleeting windfalls is meant to be the sole financial incentive for developers to build and maintain power plants in the state.[2][4]

Energy-only markets theoretically avoid the missing money problem by refusing to cap prices below the true value of scarcity. However, they introduce immense political and operational volatility. When a winter storm or summer heatwave pushes the grid to the brink, the resulting price spikes transfer billions of dollars from consumers to generators in a matter of days, triggering intense political backlash and subsequent regulatory intervention.[1][2]

Both models are currently under severe stress from the dual pressures of retiring fossil fuel plants and surging demand from artificial intelligence data centers. In PJM, even the maximum allowable capacity price of $329.17 failed to attract enough supply to meet the grid's target, resulting in a 6.6-gigawatt shortfall. As analysts at Amperon note, "Power plants take longer to build than data centers—and markets have been ill equipped to handle that fundamental mismatch."[3]

Meanwhile, the energy-only model faces its own reliability anxieties. ERCOT's May 2025 Capacity, Demand and Reserves report projects that the state's summer reserve margin will drop to 17.2 percent in 2026 and could fall to 9.0 percent by 2027 under certain load-growth scenarios. Because ERCOT relies entirely on the threat of scarcity to incentivize building, the grid must perpetually operate near the edge of a shortfall to function as designed.[2]

The missing money problem represents a fundamental debate over who bears the risk of keeping the lights on. Capacity markets force ratepayers to buy an expensive insurance policy upfront, guaranteeing that steel is in the ground but risking billions in over-procurement. Energy-only markets save consumers that upfront premium, but expose them to extreme price shocks and a higher physical risk of grid failure when the margins run thin.[1][4]

As load growth accelerates for the first time in two decades, the tension between these two frameworks is dictating the pace of the energy transition. Regulators are increasingly intervening in both models—adjusting price caps, tweaking load forecasts, and altering how intermittent wind and solar are credited for reliability. Until a market design emerges that can adequately value both clean energy and dispatchable backup power, the cost of grid insurance will continue to rise.[1][3]