How Zero-Marginal-Cost Renewables Suppress Wholesale Electricity Prices and Drive Negative Bidding

In April 2024, the California Independent System Operator recorded negative wholesale electricity prices during a quarter of all daylight hours, marking a structural shift in how power is valued on the grid. The surge in sub-zero pricing—where generators effectively pay the market to take their electricity—was driven by an unprecedented volume of zero-marginal-cost solar generation flooding the system.

This dynamic is the direct result of the merit-order effect, the fundamental economic mechanism that dictates how deregulated wholesale electricity markets clear. As regional grids transition away from fossil fuels, understanding this pricing architecture is essential for comprehending why electricity prices behave the way they do.[2][6]

Wholesale electricity markets operate on a marginal pricing framework designed to minimize the total cost of supplying power to millions of homes and businesses. Grid operators require power plants to submit bids detailing the exact capacity they can provide and the minimum price they will accept to generate it.

These bids are primarily based on a facility's short-run marginal cost—the expense required to produce one additional megawatt-hour of electricity. For traditional thermal power plants, this marginal cost is largely dictated by the price of combustible fuel, routine maintenance, and any applicable emission allowance costs required by environmental regulations.[1][3]

To meet real-time electricity demand, the grid operator stacks these incoming bids from the lowest price to the highest price, forming a comprehensive supply curve known as the merit order. Dispatchers activate the absolute cheapest available generation first, moving progressively up the curve to bring more expensive units online until the total electricity demand for that specific time interval is satisfied.

The last, most expensive power plant required to balance the grid becomes the marginal unit, and its specific bid sets the universal clearing price for all generators dispatched in that interval, regardless of their individual underlying costs.[1]

Wind and solar facilities fundamentally alter the architecture of this supply curve because they operate without any combustible fuel costs. Once the initial capital expenditure of building a solar farm or erecting a wind turbine is sunk, the ongoing cost of generating an additional megawatt-hour of electricity is effectively $0.00.

Consequently, renewable generators are able to bid into the wholesale electricity market at or near zero dollars. This unique economic advantage places them at the very front of the merit order, guaranteeing that they are dispatched first whenever the sun is shining or the wind is blowing.[1][6]

When renewable energy output is exceptionally high, these zero-cost bids push the entire supply curve to the right. This physical displacement forces the most expensive thermal generation—such as aging gas peaker plants and coal-fired facilities—out of the active dispatch stack entirely. Because the final clearing price is set by the most expensive unit left running, removing these high-cost fossil fuel plants from the margin actively suppresses the overall wholesale price of electricity across the entire grid, a phenomenon formally defined by energy economists as the merit-order effect.[1]

For residential consumers and load-serving utility entities, the merit-order effect delivers substantial financial savings by insulating the broader electrical grid from volatile global commodity markets. During the midday hours when solar production reaches its absolute peak, the wholesale cost of power routinely drops to zero, drastically lowering the average cost of procurement. However, this exact same market mechanism creates a severe structural paradox for the renewable energy developers who are actively financing and building the infrastructure required for the ongoing energy transition.[3][6]

Because solar power plants located within a specific geographic region all generate electricity simultaneously under the exact same weather conditions, they flood the wholesale market at the exact moment prices collapse. "Negative prices in CAISO effectively drive down the average price of power during certain times of day, which has significant implications on the revenue for energy resources, particularly solar and storage," notes Divita Bhandari, a senior research scientist at REsurety.

This self-induced price suppression is known as cannibalization. In the California market, the solar capture rate—the actual revenue a solar plant earns compared to a hypothetical baseload plant running continuously—plummeted below 30 percent in 2024. A utility-scale solar resource now earns 70 percent less per megawatt-hour than a facility capable of generating power around the clock.[6]

The market dynamics intensify significantly when electricity supply vastly exceeds consumer demand, but inflexible thermal power plants cannot easily shut down to accommodate the surplus. Nuclear reactors and certain combined-cycle natural gas turbines incur severe physical wear, thermal stress, and massive financial costs if they are forced to cycle off and restart hours later. To avoid these punitive shutdown penalties, inflexible generators submit negative bids, explicitly signaling their willingness to pay the grid operator to keep their units online and generating power.[6]

Renewable energy generators also actively contribute to the frequency of negative pricing due to out-of-market financial incentives. Wind and solar facilities frequently receive federal production tax credits or state-level renewable energy certificates for every single megawatt-hour of electricity they successfully generate and deliver to the grid. Because these lucrative subsidies are tied directly to generation volume rather than wholesale market revenue, renewable operators can bid negative prices—up to the exact value of their tax credits—and still turn a net profit on the transaction.[6]

The unprecedented collision of inflexible thermal generation, heavily subsidized renewables, and physical transmission constraints drove the California Independent System Operator to record 1,180 hours of negative wholesale prices in 2024, representing roughly 13 percent of the entire year. This marked a staggering 122 percent increase from the 530 negative-price hours recorded in 2023, signaling to grid planners that the merit-order effect scales non-linearly as zero-marginal-cost generation completely saturates the regional power grid.[6]

Rather than representing a fundamental market failure, negative prices function as a highly precise economic signal, indicating that the power system desperately requires operational flexibility rather than additional midday generation capacity. The primary structural solution to the merit-order penalty is the rapid deployment of grid-scale battery energy storage. By charging their cells during negative-price midday hours and discharging that stored power during the high-priced evening peak, battery systems perform lucrative energy arbitrage, effectively flattening the duck curve and restoring financial value to curtailed solar generation.[2][6]

As regional power grids approach 100 percent renewable energy penetration, the traditional merit order faces systemic and existential questions. A wholesale market design predicated entirely on the marginal combustible fuel costs of thermal power plants inherently struggles to adequately compensate capital-intensive infrastructure that costs absolutely nothing to operate. Regulators and independent system operators are increasingly evaluating capacity markets, long-term power purchase agreements, and locational marginal pricing reforms to ensure long-term grid reliability as the merit-order effect permanently erodes traditional wholesale energy revenues.[1][3]