The Net Cost of New Entry and Value of Lost Load That Anchor Capacity Markets

Before a single megawatt of electricity is traded in a capacity auction, the financial fate of the power grid is decided in a regulatory spreadsheet. Grid operators must mathematically define two abstract concepts: the exact dollar cost of a blackout, and the minimum revenue required to keep a new power plant alive. These two administrative figures—the Value of Lost Load (VOLL) and the Net Cost of New Entry (CONE)—form the anchor points of the demand curve that dictates billions of dollars in annual energy investments. Because electricity cannot be easily stored at a continental scale, regulators cannot rely on natural consumer demand to ensure enough power plants are built. Instead, they engineer a synthetic market, and VOLL and Net CONE are the parameters that control it.[6]

The system exists to solve the "missing money" problem. In wholesale energy markets, power plants are paid for the electricity they generate by the hour. However, a grid requires backup generators that might only run for 50 hours a year during extreme weather or peak demand. The hourly energy market does not provide enough revenue to cover the fixed costs of building and maintaining these standby plants. To prevent them from retiring, grid operators like PJM Interconnection and the Midcontinent Independent System Operator (MISO) run forward capacity markets. These auctions pay generators a fixed annual fee simply to exist and guarantee their availability years in the future.[3][4]

To run this auction, the grid operator must construct an administrative demand curve, which requires establishing a baseline cost. This is the gross Cost of New Entry (CONE). CONE represents the annualized capital and fixed operating expenses of building a brand-new, highly efficient power plant—traditionally a natural gas combustion turbine. According to the Brattle Group's 2026/2027 analysis for PJM, the gross CONE for a reference gas peaker sits near $160,000 per megawatt-year. This figure acts as the starting line, representing the raw financial hurdle a developer must clear to bring new steel into the ground.[2][3]

But a new plant will not survive on capacity payments alone; it will also sell power into the daily energy and ancillary services markets. Net CONE subtracts those projected market revenues from the gross CONE. If a plant costs $160,000 per megawatt-year to finance, but is expected to earn $45,000 selling electricity, the Net CONE is $115,000. This resulting figure is the exact revenue gap that the capacity market is designed to fill. If the capacity auction clears below Net CONE, the market is signaling that the grid has enough power and no new plants are needed. If it clears at or above Net CONE, it triggers new construction.[2]

While Net CONE defines the cost of supply, the Value of Lost Load (VOLL) defines the absolute ceiling of demand. VOLL is an economic estimate of the damage inflicted on society by a megawatt-hour of involuntary power interruption. It attempts to quantify the unquantifiable: spoiled inventory in commercial freezers, halted assembly lines, and the societal danger of darkened hospitals. Because consumers cannot bid in real-time to avoid a blackout, regulators must set this price administratively.[1]

Calculating VOLL is notoriously difficult and highly subjective. The Federal Energy Regulatory Commission (FERC) and regional operators frequently debate its magnitude. In the United States, implied VOLL figures often range between $5,000 and $9,000 per megawatt-hour, acting as a scarcity pricing cap during emergencies. In contrast, the European Union Agency for the Cooperation of Energy Regulators (ACER) has overseen methodologies that place VOLL significantly higher, with some European nations setting the parameter above €20,000 per megawatt-hour to reflect a lower political tolerance for supply interruptions.[1][4]

These two metrics do not exist in isolation; they are mathematically bound together by the reliability standard, universally defined as a Loss of Load Expectation (LOLE) of 0.1 days per year—or one blackout day every ten years. Grid operators plot Net CONE against the target reserve margin needed to meet that 1-in-10 standard. The curve then slopes upward, capping out at a maximum price derived from VOLL. If the grid is short on power, the auction price rides the curve up toward VOLL. If the grid is oversupplied, the price slides down the curve, eventually hitting zero.[1][4]

The tension lies in the fact that these administrative choices have massive financial consequences. A slight adjustment to the Net CONE reference technology—such as switching the baseline from a gas turbine to a four-hour lithium-ion battery—can shift the entire demand curve, altering the clearing price for every generator on the system. Similarly, an artificially high VOLL steepens the curve, forcing ratepayers to procure excess capacity as an expensive insurance policy against political fallout.[3][6]

Critics argue that these administrative demand curves structurally over-procure capacity. As noted in a report for FERC, U.S. regional transmission organizations and their regulators have not yet demonstrated substantial interest in considering a purely value-based approach to estimating demand curves. By setting Net CONE based on expensive fossil-fuel assets and maintaining rigid reliability standards, capacity markets routinely retain uneconomic generation that would otherwise retire. In regions like PJM, this has historically resulted in reserve margins hovering near 28%, well above the 15% target required to maintain the 1-in-10 standard, costing consumers billions in excess payments.[4][6]

As the grid transitions toward zero-marginal-cost renewable energy, the mechanics of Net CONE and VOLL are facing unprecedented stress. Clean energy advocates argue that anchoring Net CONE to the cost of a new natural gas peaker ignores the reality of the modern grid, pushing for battery storage to become the baseline reference technology. However, grid-scale batteries carry their own unique risk profiles and capital costs. As Canary Media reports on the recurring incidents at Vistra's facility in California, "Another plume of smoke rose from Vistra’s Moss Landing battery plant Friday morning, a year and a half after a catastrophic fire wrecked the grid storage facility in Northern California." These physical risks highlight the operational uncertainties that regulators must now price into their capacity models. Ultimately, regulators are forced to decide whether the capacity market should remain anchored to traditional fossil-fuel economics, or if the formulas must be rewritten to reflect a grid where flexibility matters more than sheer megawatt volume.[5]