The PJM capacity auction has been critical to energy budgets in the eastern U.S. for years, but current market shifts have created significant uncertainty. Find out what’s making this capacity pricing so hard to predict and how it affects your energy strategy. 

What Is the PJM Capacity Market? 

The PJM capacity market is a planning mechanism designed to ensure sufficient electricity-generation capacity to meet future demand within the PJM Interconnection region (Pennsylvania–New Jersey–Maryland). Operating as a competitive auction system held ahead of the delivery year, it allows utilities to secure the capacity necessary to serve their customers.  

Power producers bid to provide electricity during peak demand periods, establishing a “clearing price” paid to all successful sellers. These costs are ultimately incorporated into the electricity rates paid by consumers. 

The Importance of the PJM Capacity Market 

PJM capacity prices are a vital financial mechanism that ensures the power grid remains stable across a large swath of the eastern United States. The PJM Interconnection covers all or part of 13 states and Washington, D.C. The PJM capacity price is key to securing enough electricity supply to meet future peak demand.  

Unlike the daily energy market, which pays for the actual electricity consumed, the capacity market pays generators simply to be on standby and available to perform in the future. Historically, PJM capacity costs provided three years of advance visibility, but over the last few years, it’s been delayed. 

Capacity markets provide a critical revenue stream for power plants that might otherwise be unprofitable but are essential for preventing blackouts during extreme heatwaves or winter storms. By setting long-term price signals, capacity prices incentivize investors to build new power plants, maintain existing infrastructure, and integrate emerging technologies such as battery storage and demand response. 

As a reliability pricing model, this market fundamentally shapes corporate energy strategies, as capacity charges often account for a significant portion of a commercial or industrial organization’s electricity costs. PJM calculates these costs based on a company’s peak load contribution (PLC), which measures usage during the grid’s five highest electricity demand hours of the year. Consequently, businesses are increasingly adopting “peak shaving” strategies to reduce their PLC and lower their long-term capacity obligations. 

These methods involve using real-time monitoring and automation to shift energy-intensive operations away from these critical hours. Deploying on-site resources, such as renewable energy generation and battery storage, is another method to reduce their reliance on the grid during peaks. And by participating in a demand management program, not only can businesses avoid higher prices, but they may also be able to generate additional revenue. However, this requires deep knowledge of the PJM market prices and a cohesive, detailed energy strategy.  

Why PJM Capacity Costs Are Uncertain in the Current Cycle 

The current cycle is uniquely volatile due to a set of underlying technical and regulatory shifts. These have amplified the uncertainty by changing the very rules and calculations PJM uses to define “reliability.” There are also infrastructure and energy-use changes that affect grid reliability.  

Taken together, these factors include: 

Retiring Power Plants 

Several power plants in the PJM region are set to retire in the near-term future, creating a supply gap that complicates market calculations. This trend is particularly challenging as regional demand is forecasted to increase significantly, driven by data center expansion and electrification. 

Demand From Data Centers 

Much of this increase in demand results from the growing importance of data storage and AI. A data center is often a massive consumer of energy, so large loads that stem from the presence of these centers — and the prospect of more builds to come — exerts significant upward pressure on capacity costs. 

There’s an ongoing legal battle regarding data centers that sit “behind the meter.” These are centers that are physically connected to a power plant, like a nuclear facility, rather than to the general grid. The Federal Energy Regulatory Commission (FERC) and PJM are debating whether these data centers should pay the same transmission and capacity fees as everyone else. 

Delays in Capacity Auction Schedules 

As of January 2026, PJM has not yet caught up to its traditional three-year-forward schedule for capacity auctions, but it’s currently operating on a condensed “catch-up” calendar. PJM is expected to officially return to the normal three-year-forward cycle in May 2027, when it conducts the auction for the 2030–2031 delivery year. 

PJM is currently running auctions roughly every six months rather than annually to close the gap created by previous regulatory delays and market rule changes. This compressed timeline is intended to provide long-term price signals as quickly as possible, though it gives developers less time between auctions to advance new generation projects. 

Changes in Market Rules and Pricing Collars 

To combat the extreme price spikes seen in 2024, PJM and FERC implemented a temporary price cap and floor system. This system sets both a maximum and a minimum price for its capacity auctions, providing short-term cost certainty for consumers and revenue stability for generators. 

The Interconnection Queue Backlog 

There’s also a massive bottleneck in the interconnection queue, which is the physical process of getting new plants approved to plug into the grid. There are currently more megawatts of renewable projects waiting in the queue than there are total megawatts powering the entire PJM region today. This means companies can’t rely on new supply to lower costs because it takes years to clear the queue, meaning the supply crunch is effectively locked in for the near future. 

Fixed-Price vs. Pass-Through Contract Structures 

In today’s volatile market, choosing between fixed-price and pass-through contracts — specifically for capacity — is a critical decision for energy budgeting. While capacity is the most common variable, other components, like transmission, can also be structured as pass-throughs. 

Fixed-price contracts provide budget certainty by locking in all components. However, since a supplier must commit to a price before an organization’s future PLC is known, they include a risk premium. This covers the “volume risk” — the uncertainty of how much capacity the customer will be obligated to pay for based on their peak demand. 

Pass-through contracts pass PJM capacity charges directly to the customer at the actual auction rate and the customer’s actual PLC. This eliminates the supplier’s risk premium and rewards active peak shaving, but requires the customer to absorb the risk of auction volatility and usage patterns. 

Fixed-price contracts offer simplicity, while pass-throughs offer potential savings for large users who can manage consumption.  

Risk Premiums: How and Why They’re Added to Contract Rates 

A risk premium is an additional fee built into fixed-rate contracts to compensate the energy supplier for assuming market uncertainty. When an organization signs a fixed-rate deal, the supplier essentially provides an insurance policy against price spikes related to both kWh (energy volume) and kW (capacity/demand) usage. 

This premium is the cost of peace of mind and budget security. Suppliers add these margins because they assume several types of risk — such as fluctuations in a customer’s PLC — that could result in significant financial loss if the market or the organization’s usage patterns shift unexpectedly. 

Procurement Challenges for End-Users Amid Capacity Uncertainty 

As if all of this weren’t complex enough, end-users face additional energy procurement challenges amid all this uncertainty. These include: 

• Slow interconnection queues: Massive backlogs and study timelines that stretch for years prevent new, cheaper generation from entering the market. This supply-side freeze means that even when prices spike, new competitors cannot arrive quickly enough to lower them, potentially leaving end-users trapped with high rates from existing, often aging, resources. 

• Flawed capacity market design: Potentially inflated load forecasts and administrative price parameters, combined with shifting rules on how much credit renewable sources receive, can lead to multibillion-dollar cost jumps for consumers without a corresponding increase in actual grid reliability. 

• Interdependence with the natural gas market: As natural gas has become the largest fuel supply in the PJM region, electricity prices are increasingly tethered to gas price volatility and supply chain risks. Geopolitical events and pipeline constraints now have a direct impact on electric bills. 

• Price signal mismatch: Because building new power generation takes longer than the PJM auction visibility period, the market struggles to function as intended. High prices are failing to attract new supply in time to help current end-users manage their budgets. The next PJM Capacity auction for the 2028–2029 delivery year is scheduled for June 2026, which is still a very tight window for new projects to respond to that specific price signal. 

• Transmission Cost Surges: While capacity prices have captured headlines, transmission costs are also rising as utilities spend record amounts to replace aging equipment; over 70% of the U.S. transmission infrastructure is now past its mid-life expectancy. These costs are ultimately passed through to end-user bills. 

All these challenges and complexities underscore the value of having in-depth and up-to-date energy market intelligence.  

How Might Upcoming PJM Auctions and Regulatory Shifts Affect Pricing for 2028–29? 

As of January 2026, the term dominating the PJM capacity market remains “uncertainty.” While we can reliably predict that energy demand will continue to surge due to data centers and AI infrastructure, the timing and volume of new supply reaching the grid remains difficult to forecast. 

The upcoming 2028–2029 Base Residual Auction (BRA), scheduled for June 2026, will be a critical turning point. It will reveal whether the high price signals from previous auctions have successfully accelerated supply or if the market will remain constrained by interconnection backlogs and regulatory shifts 

The best way to sail these choppy waters is with a reliable navigator by your side. When it comes to energy procurement, there’s no better navigation system than EnerConnex, with our detailed market intelligence and deep experience in finding and negotiating energy contracts. Explore our services to learn more.