Over the past month, natural gas price increases have been concentrated in the prompt month portion of the curve, while longer-term winter pricing has remained stable or declined slightly. For example:

• The July 2026 contract rose by 27 cents from $3 on May 7 to $3.27 on May 29.
• The January 2027 contract fell by 7 cents, moving from $4.60 to $4.53.

Despite recent gains in near-term pricing, forward prices for calendar year 2027 continue to present an opportunity for consumers to lock in longer-term supply.

Figure 1-3 shows historical pricing (dating back to 2022) for a typical winter-weighted customer. Near the end of the COVID-era demand downturn, prices fell to a low of $3.18 before rebounding about 9 months later to a peak of $5.17.

General purchasing guidelines indicate:

• When prices drop below the 25th percentile, consumers should consider locking in a portion of their natural gas needs.
• As prices approach the 10th percentile — meaning prices have historically been higher 90% of the time and lower only 10% of the time — consumers should consider actively securing a portion of their natural gas needs.

While prices could still move lower — due to factors including weather variability and broader global uncertainties — pricing in the lower decile has historically provided a useful signal for customers evaluating incremental hedging of their natural gas exposure.

U.S. natural gas storage inventories started the injection season with stocks of 1.828 trillion cubic feet (Tcf), which is right in line with the 5-year seasonal balance of 1.815 Tcf. As of late May, total U.S. storage balances now stand at 2.578 Tcf — which is 138 billion cubic feet (Bcf) above the 5-year average due mostly to mild temperatures in March and April.

Broader energy market volatility has been more pronounced for crude oil and refined products, driven by ongoing uncertainty around ceasefire negotiations in the Middle East.

As a result, higher oil prices have encouraged U.S. producers to increase oil-directed drilling activity at home, adding 20 rigs in the last 2 months. (In contrast, natural gas-directed rig counts have declined modestly, with two fewer rigs.) Because natural gas is produced as a byproduct of oil extraction, this increased drilling is expected to boost the associated gas supply.

There are notable updates for liquefied natural gas (LNG) as well:

• Feedgas deliveries have declined by as much as 3 Bcf per day (Bcf/d) at certain points throughout the spring maintenance season.

• This reduction in LNG demand has put downward pressure on prices along the Gulf Coast.

• Global LNG demand still remains strong, as disruptions in the Strait of Hormuz have effectively curtailed exports from Qatar— one of the world’s largest LNG suppliers behind the U.S. and Australia.

• As a result, we’re seeing elevated global pricing: July LNG delivery prices are currently averaging $16.64 in Europe and $18.81 in Asia.

Most people expect hot, humid weather in July or August — not in the middle of spring. However, in mid-May, much of the eastern U.S. experienced unusually high temperatures, putting significant strain on the electric grid.

On Monday, May 18, and Tuesday, May 19, PJM operated in a heightened state of alert as electricity demand was driven to levels more typical of August. By the end of May 19, the grid operator had:

• Activated demand response programs in multiple service territories

• Obtained emergency authority from the U.S. Department of Energy to direct backup generation at data centers

• Issued Maximum Generation Alerts asking power plant owners to keep every available unit running

Typically, spring and fall are when the power industry performs maintenance, as mild weather means lower electricity demand, making it safer to take generation plants and transmission lines offline to complete maintenance work. This approach works well unless the weather unexpectedly drives demand higher — which is exactly what happened last month when temps reached the 90s across much of the PJM footprint while more than 40,000 megawatts (MW) of generation and transmission capacity were offline for planned maintenance.

Peak demand reached approximately 134,000 MW on May 18 and approximately 136,000 MW on May 19 against a backdrop of over 40,000 MW offline for maintenance. For comparison, PJM’s peak last summer was just over 160,000 MW. While these May peak levels were not extreme by themselves, against extensive maintenance outages, it left system operators with little margin for error.

When supply tightens and demand rises, PJM has a set of escalating tools it can deploy. The most visible to customers is demand response — a program in which businesses and large energy users agree, in advance, to reduce their electricity consumption during critical periods in exchange for payment.

On both May 18 and May 19, PJM activated Pre-Emergency Demand Response across several service areas. On May 18, that activation covered Baltimore Gas and Electric Company (BGE), Dominion Virginia (DOM), and Potomac Electric Power Company (PEPCO) territories in the Mid-Atlantic, targeting localized transmission constraints. The following day, the activations expanded to include AEP Ohio customers in the Columbus area, where a separate transmission constraint had emerged.

The AEP Ohio Columbus constraint is not new. The AEP-Marion subzone — which includes parts of central Ohio — has a known transmission limitation and has seen isolated demand response events before, most notably in June 2022. The activation on May 19 is a reminder that localized grid constraints can affect customers even when the broader regional grid is managing adequately.

One of the more unusual aspects of this event was the involvement of the U.S. Department of Energy. On the evening of May 18, the DOE issued an emergency order under Section 202(c) of the Federal Power Act, authorizing PJM to direct the operation of customer-owned backup generation at data centers and other large facilities if needed — specifically to protect residential customers from outages.

The order was effective through May 20. PJM indicated it did not expect to call on those resources, but having the authority in place gave operators one additional tool to manage the tight conditions. A similar order had been issued in January 2026 during Winter Storm Fern — PJM navigated that event without needing to invoke it.

In PJM, real-time electricity prices spiked during the afternoon and evening hours of both May 18 and 19, reflecting the tight supply-demand balance. The most pronounced price increases were in the Mid-Atlantic — particularly Maryland and Virginia — where localized transmission constraints caused prices in those zones to diverge sharply from the broader regional average.

For any customers on real-time or index-based pricing contracts, the afternoon hours on May 18 and 19 would have been notably expensive. For those on fixed-price contracts, the event underscores why price certainty has value.

It would be a mistake to treat May 18-19 as an anomaly and move on. PJM’s own summer outlook for 2026 flags that the grid will face increasing pressure as electricity demand grows — driven significantly by data center expansion, electrification of transportation and heating, and broader economic activity — while the generation fleet navigates an ongoing transition.

PJM is prepared to serve loads in excess of 160,000 MW during the peak summer months. But the May event illustrated that preparation and margin are not the same thing. When scheduled maintenance coincides with unexpected demand, the system tightens quickly, and the tools PJM relies on (demand response, emergency generation orders, export curtailments) get deployed in sequence.

That is a pattern we expect to see more frequently in the years ahead, not less.