For years, PJM’s power supply has stayed comfortably ahead of demand. That era is ending. This month, that transition shows up in three places: utility forecasts, forward prices, and the latest wholesale cost data.

Utilities across PJM requested approximately 14.5 GW of additional demand for the 2027 forecast year alone, with long-term projections ranging from roughly 78 GW to more than 120 GW by the mid-2040s.

Dominion remains at the center of the conversation, but significant growth is now spreading across Ohio, Illinois, Pennsylvania, and other PJM states. Utilities that had little or no data center exposure only a few years ago are now forecasting GWs of future load.

What stood out most was not the sheer size of the forecasts, but how much effort utilities are putting into proving those forecasts are real.

After several years of concerns that load projections were getting ahead of actual development activity, utilities have considerably tightened their methods. Many are now limiting forecast adjustments to projects backed by signed service agreements, transmission commitments, or take-or-pay contracts, which commit customers to pay for a minimum share of their contracted demand whether or not they use it.

That discipline matters because only firm commitments ultimately flow into PJM’s resource adequacy calculations and planning assumptions. As a result, the conversation is shifting away from speculative MWs and toward contracted MWs.

The challenge for PJM is twofold: If forecasts overstate growth, customers may pay for infrastructure that isn’t needed. If they understate growth, reliability risks increase, and future supply shortages become more likely.

While stakeholder conversations focus heavily on forecasts and market reforms, the forward market is focused on something else: What those changes are likely to mean for future power prices.

Over the last 3 years, PJM forward energy prices have steadily moved higher as market participants have incorporated stronger demand growth, tighter reserve margins, generator retirements, transmission investment requirements, and slower-than-expected resource additions. As Fig. 1-2 shows, the 2027 around-the-clock power price at PJM West Hub has risen from about $48/MWh in fall 2023 to a 3-year high of $76.18/MWh as of September 29.

What’s notable is not simply the move higher, but the persistence of the trend. Unlike short-term price spikes driven by weather or fuel volatility, today’s forward curve reflects a growing belief that PJM is entering a structurally tighter market. Demand growth is accelerating while the process of adding generation, transmission, storage, and supporting infrastructure remains slow and capital intensive.

The market is effectively signaling that higher prices will likely be required to attract the investment needed to maintain reliability.

That doesn’t mean prices will move higher every year. Commodity markets rarely follow a straight line. But it does suggest that the long-term pricing baseline for PJM may be shifting upward as the region transitions from an era of excess capacity to one increasingly defined by resource adequacy concerns.

The September update from PJM’s Independent Market Monitor reinforces the notion that this is more than a temporary market cycle.

Through the first 8 months of 2026 compared to the first 8 months of 2025:

• Total PJM wholesale electricity costs increased 42.5% year over year.
• Energy market costs increased 45% year over year.
• Capacity-related costs increased 101.8% year over year.
• Data center-driven load growth contributed approximately $10.10/MWh to wholesale market costs, representing roughly 9% of total wholesale costs.

Individually, these numbers are noteworthy. Collectively, they point toward a market undergoing structural change.

PJM is simultaneously managing accelerating demand growth, aging infrastructure, generation retirements, transmission expansion needs, and the challenge of integrating new resources quickly enough to maintain reliability. The implication is straightforward: Many of the factors supporting higher forward prices today appear likely to remain in place for years rather than months.

The natural gas market has recently shown renewed signs of strength, though it ultimately took a significant supply disruption to generate meaningful price volatility. Prior to the force majeure event on the Mountaineer Xpress pipeline, which temporarily removed approximately 1.8 Bcf/d of takeaway capacity from the Appalachian Basin, NYMEX futures had been trading within a relatively predictable range of $2.75 to $3/MMBtu. Following the outage, the October 2026 contract rallied sharply, reaching a high of $3.31/MMBtu before finally settling at $3/MMBtu.

Cash market fundamentals remain constructive, particularly across the South and Southeast, where next-day pricing continues to be well supported by warmer-than-normal temperatures. Storage inventories in the South-Central region also remain materially below year-ago levels, providing additional support to regional pricing and reinforcing concerns around winter preparedness.

As of late September, total working gas in storage stands at 3.415 Tcf, 138 Bcf below last year’s levels but 79 Bcf above the 5-year average. Looking ahead, due to the extended warmth, analysts have lowered their end-of-season storage projections from 3.92 Tcf a month ago to 3.88 Tcf, a level still widely viewed as comfortable and sufficient to meet typical winter demand.

The power sector's natural gas demand has been one of the more notable developments this summer. While temperatures, as measured by power-weighted CDDs, ranked among the highest observed in the past 76 years, natural gas-fired generation did not reach the record peaks seen in recent summers. Total gas burn from June through September 2026 came in at approximately 5.53 Tcf, compared to 5.47 Tcf during the same period in 2024. The apparent disconnect between record warmth and relatively flat gas demand highlights the ongoing evolution of the power grid.

A key driver of this trend has been the continued growth of battery storage and renewable generation. Expanded battery deployment has helped smooth peak demand by storing power when it’s plentiful and releasing it during the highest-demand periods, while growing solar and wind output continues to displace natural gas generation within the power stack. As a result, even periods of exceptional heat did not translate into proportionately higher natural gas power burns. However, power demand is expected to grow at an accelerated rate which could keep natural gas generation at the forefront of price volatility, depending on the generation mix.