Five-minute auctions set wholesale electricity prices that manufacturers pay across regional grids

Wholesale electricity prices across the largest U.S. grid jumped nearly 76 percent in the first quarter of 2026 compared to the same period a year earlier, reaching $136.53 per megawatt-hour. The surge reflects a collision between exploding demand for power from artificial intelligence data centers and grid constraints that prevent new generation from reaching market quickly enough.

PJM Interconnection, which serves 13 states and the District of Columbia and 67 million people, and MISO operate the two largest competitive wholesale electricity markets in North America. Both use real-time auctions conducted every five minutes to set the prices manufacturers, utilities and data centers pay for power.

Real-time pricing based on grid location

Both PJM and MISO use locational marginal pricing (LMP), a system that updates every five minutes to reflect the cost of delivering electricity to a specific point on the grid. LMP comprises three components: the marginal cost of generating electricity, the cost of transmission losses as power flows across wires, and the cost of congestion—the expense incurred when too much demand presses against the transmission system's physical limits.

In each five-minute interval, both operators run a security-constrained economic dispatch: they solve for the least-expensive combination of power plants to meet demand while respecting the grid's physical transmission limits. The price at each location reflects the cost of serving the next unit of demand at that spot. A manufacturing plant in western Pennsylvania will face a different wholesale price than one in northern Virginia, depending on local generation costs and congestion.

PJM also operates a day-ahead market, where participants can lock in prices a day in advance for the following 24 hours. Real-time prices discover any gap between what was expected and what actually occurs—a critical safety valve when demand spikes or a large power plant trips offline unexpectedly.

Capacity auctions and regional reliability

Beyond energy prices, PJM holds annual capacity auctions to ensure the region has enough power plants (or other resources like batteries or demand reduction) standing ready to meet peak demand three years in the future. These capacity prices have become the dominant driver of electricity costs in recent years.

The 2025-2026 and 2026-2027 auctions together imposed a $13 billion cost increase on the grid's customers.

Capacity prices have become the dominant driver of electricity costs because the challenge is not supplying electricity on an average day, but ensuring enough resources exist to meet peak demand on the hottest summer afternoons or coldest winter evenings. Data centers, which run 24 hours a day and consume power continuously, contribute to the total peak load that PJM must plan for—unlike factories that can shift production schedules or residential users who reduce consumption during peak hours.

Congestion costs add to regional price premiums

The grid's transmission system—the high-voltage lines that carry electricity across long distances—has a maximum capacity. When demand in a region exceeds the transmission system's ability to import power from elsewhere, prices spike in that region. These regional price premiums are called congestion costs.

PJM's transmission constraint costs alone reached $6 billion in the first half of 2026. Before 2021, annual congestion costs had never topped $8 billion.

Northern Virginia—home to the largest concentration of data centers in the world—has emerged as one of the most congested parts of the grid. As demand centers shift toward the Mid-Atlantic, existing transmission lines that were built decades ago to serve other patterns of electricity consumption are frequently operating at or above their thermal limits. During the first half of 2026, PJM's high-voltage 500-kilovolt transmission lines hit or exceeded operating limits in 8,920 five-minute intervals, up from 1,865 in the same period a year earlier.

Manufacturing-heavy regions face different price pressures

MISO and PJM differ in their regional composition. MISO covers the agricultural and manufacturing heartland—Wisconsin, Illinois, Indiana, Kentucky, Louisiana and other states—while PJM stretches from the industrial Midwest through Pennsylvania and into the Mid-Atlantic. Both serve industrial users, but their regions face different supply-demand balances.

A manufacturer choosing between locations must account not only for electricity prices but also for the direction of those prices over time. PJM's rapid data center growth is pushing long-term capacity prices higher. MISO faces different pressures, including the retirement of coal plants and wind resource variability. Both regions have seen increased price volatility as the grid's mix of generation sources shifts toward renewables.

Market participants forward-looking enough to purchase multi-year power purchase agreements (PPAs) can lock in prices years in advance to avoid price swings. Those buying on the spot market face whatever the five-minute auction delivers. Large industrial users typically negotiate annual or multi-year contracts; smaller businesses often buy more electricity exposure on the spot market.

Real-time price signals drive the market

The five-minute auction system is designed to send real-time price signals that incentivize efficient behavior. When congestion emerges, local prices spike; this signals new power plants or demand reduction to locate in congested areas. When renewable generation floods the grid on a windy day, wind-dependent regions see negative prices or very low prices, signaling producers to reduce dispatch and consumers to increase consumption.

PJM's market monitor reported that real-time load-weighted average prices increased $21.19 per megawatt-hour, or 68.3 percent, in the first three months of 2025 compared to the prior year. Fuel costs accounted for nearly 75 percent of this increase, according to Joseph Bowring, PJM's independent market monitor. Energy uplift charges—the cost of operating the grid outside the competitive market to maintain reliability—surged to $462.6 million in Q1 2025 from $77.3 million in Q1 2024, a 498 percent increase.

These uplift charges represent electricity purchased outside the normal auction to manage real-time emergencies. Their growth signals that the five-minute market is becoming more strained as demand outpaces the rate at which new generation and transmission can be built and connected to the grid.

Related coverage: How utilities balance rising electricity demand against grid constraints; Why Vertiv Paid Up to $2.6 Billion to Buy Its Way Into the Power Queue; Why Connecting a Power Project to the Grid Takes Years.