U.S. Energy Markets Update: Power Prices, Gas Supply & Weather Risks

Executive Summary

Grid Pressures Push PJM Prices Higher as Summer Risks Build

Day-ahead index prices in Baltimore Gas and Electric (BGE) and Potomac Electric Power Company (PEPCO) climbed 30% in the first half of 2026 compared with just a year earlier, or 75% including Winter Storm Fern days. Worsening congestion has raised the cost of delivering power into these constrained zones.

Forward markets have recently repriced to match these structural pressures. BGE's and PEPCO's forward premiums over the PJM West hub have widened ~50% over the past 12 months, to $14–15/MWh across the 2027–2030 curve.

Outer year strips across PJM currently carry no term premium, even as data center growth, retiring local supply, and transmission bottlenecks point to worse congestion ahead. By contrast, ERCOT's North Hub 2030 forward already trades at a 16% premium over 2027, pricing comparable load growth into the curve.

U.S. gas fundamentals might provide some fuel price relief. The U.S. Energy Information Administration (EIA) and BloombergNEF forecast inventory levels 5–6% above the five-year average by the end of October. But that buffer still depends on how the summer plays out:

• U.S. liquefied natural gas (LNG) exports averaged ~2 million metric tons per month more in March–June 2026 than a year earlier. Sustained high global gas prices could keep LNG throughput elevated during the summer.
• If LNG feedgas demand grows further and a hot summer lifts power burn above current projections, gas injection levels could fall short and tighten regional balances ahead of the winter season.

Weather events could compound the structural risks:

• A 'super' El Niño is forming in the equatorial Pacific, raising the odds of overlapping weather events across the U.S. West and Central regions this summer.
• California's snowpack sits ~80% below its five-year average, the lowest in over a decade, limiting the multi-day flexibility that hydropower provides during prolonged summer heatwaves.
• El Niño also lowers storm counts in the Atlantic, but unusually warm Gulf waters can fuel more intense hurricanes, threatening gas production at the peak of injection season in August and September.

Figure 1: Daily Forward Curve 2030 Premium Over 2027, PJM West vs ERCOT North

Deep Dive into Power, Gas and Weather Trends

Power Market Update: Forward Curves Trend Near Rising PJM Congestion

Market Analysis PJM's grid tightening is more visible under normal conditions, not only during extreme weather events. In BGE and PEPCO, day-ahead congestion in index prices has tripled in 1H 2026 compared with the same period last year. Forward curves have repriced near today's level of congestion, but BGE's and PEPCO's basis over PJM West still holds flat across 2027–2030, even as data center growth and retiring local supply point to worse congestion ahead. By contrast, ERCOT forwards price that pressure into the curve, with North Hub 2030 trading ~16% above 2027. With the outer years in PJM still priced at today's congestion, buyers in constrained zones remain exposed to further basis expansion.

Around-the-clock forward prices at the PJM West Hub are up 20% year-to-date across the 2027–2030 curve, reaching ~$65/MWh as of early July and holding near that level across the period. Forward curves reflect market expectations of a tighter supply-demand balance keeping PJM prices higher for longer, driven by:

• Firm supply shortfalls: PJM is not expected to add enough firm supply to match the region's data center growth and meet its rising reliability requirements through 2030.
• Data center demand growth: new large loads, mostly data centers, are absorbing more of PJM's existing cheap supply and reducing the power that flows into constrained areas.
• Grid bottlenecks: too little transmission capacity exists to move excess generation out of western PJM and carry enough power into import-dependent load pockets such as BGE and PEPCO, further limiting available supply.

PJM's reliability pressures become especially apparent during grid stress. The recent heatwave pushed peak demand to ~163 GW on July 2, above PJM's ~156 GW normal-weather forecast for 2026. Real-time prices in constrained zones around Baltimore, Washington D.C. and Virginia reached $2,500–3,000/MWh.

But day-ahead power prices are also rising under 'normal' conditions and shoulder seasons, not just during stress events or summer peaks. Worsening congestion is the driver. Constraints have pushed BGE's and PEPCO's forward premium over PJM West ~50% wider over the past year, to $14–15/MWh. This is roughly equivalent to the congestion levels that these areas realized in the first half of 2026. Day-ahead congestion in BGE and PEPCO tripled during the first half of 2026 compared with 2025, averaging ~$14/MWh higher than in PJM West. These figures exclude both Winter Storm Fern in January and the recent July heatwave.

Figure 2: Average Day-Ahead Congestion Costs from January to June by PJM Zone, 2024 to 2026

PJM's Zonal Constraints Set to Tighten as Regional Demand Outruns Supply

Cheap power during high-demand hours is becoming harder to import into the broader Washinton D.C. and Maryland areas that BGE and PEPCO serve. Transmission constraints limit flows, while data center demand in neighboring Dominion and across PJM absorbs more of the available supply and strains aging grid infrastructure. BGE's and PEPCO's exposure to regional data center growth and lack of local firm supply will likely keep constraints from easing:

Lack of local firm supply prolongs the area's reliance on imports and expensive oil peakers. BGE's demand peaks at about 6.2 GW against only 1.5 GW of low-cost supply, 1.3 GW of it from two coal units set to retire in 2029. PJM has filed with federal regulators to extend them to 2031. When imports fall short, BGE must call on oil-fired peakers at marginal costs of $186–305/MWh, driving congestion up. PEPCO's demand peaks at nearly 6 GW and has barely any local firm supply.

Nearby grid infrastructure struggles to serve both Dominion's data center demand and adjacent zones at peak hours. Rising demand in neighboring Dominion has increased the utility's imports during high-demand hours, limiting the power that can flow into BGE and PEPCO through the heavily constrained west-to-east and north-to-south corridors that supply the area.

Regional data center growth is outpacing both planned grid upgrades and new firm supply. A new shared transmission hub should let more western power flow into Maryland and Virginia, but Dominion's demand is growing faster than its supply. PJM expects the utility to peak at 31 GW by 2030, up from 25 GW this year, against less than 1 GW of new firm supply. To cover the gap at peak hours, Dominion must import more, offsetting much of the relief for the broader Washington D.C. and Maryland areas from any grid upgrades.

The market has repriced PJM's near-term grid pressures and the level of BGE's and PEPCO's congestion, but not the worsening trajectory of either. PJM's forwards are not pricing in a term premium, either at the West Hub or in the zonal basis over the hub, even as the pressures behind that congestion are set to intensify. PJM's flat curve could partly reflect thin trading in the outer delivery years, especially in a single zone's basis. But PJM West's own liquid curve is also flat, while ERCOT's liquid North Hub, which faces a comparable wave of data center load growth, prices a 16% premium for 2030 over 2027.

Figure 3: BGE Forward Basis over PJM West by Delivery Year, vs 1H 2026 Day-Ahead Congestion

Gas Market Update: LNG Demand, Power Burn Threaten Inventory Build

Market Analysis Global gas prices remain high as Middle East LNG supply struggles to recover and safe passage through the Strait of Hormuz remains uncertain. U.S. LNG facilities will likely continue to maximize near-term throughput to capture high margins over the summer. The U.S. is still set to enter the next winter season with above-average gas storage. However, expected injection levels could be at risk if U.S. LNG feedgas demand grows further and cooling demand lifts summer power burn above current projections.

U.S. LNG exports averaged nearly 2 million metric tons per month more in March–June 2026 than in the same period of 2025, as facilities maximized throughput to capture high margins. Global gas prices remain high and could face further upward pressure over the coming months as China and Europe ramp up imports again. Sustained high prices would further encourage U.S. LNG operators to maximize throughput over the summer.

More domestic gas supply flowing to LNG export terminals just as summer heat lifts power burn can put pressure on U.S. gas prices and storage injection levels. The EIA expects LNG exports to reach 17.2 billion cubic feet per day (Bcf/d) in 2026, up from 15 Bcf/d in 2025. Both the EIA and BloombergNEF currently forecast U.S. gas inventory levels to trend 5–6% higher than the five-year average by the end of October 2026.

If injections run below the current EIA forecast, some U.S. hubs could see sharper price spikes and volatility ahead of winter 2026/27. However, El Niño winters also tend to run milder across the northern U.S. regions, which could offset price effects from lower-than-expected storage levels.

Figure 4: U.S. Natural Gas Inventories, 2026 EIA Forecasts vs Historical Levels

Weather Update: A Developing El Niño and a Drying West

Market Analysis The U.S. West faces a combination of warmer temperatures, droughts, and low hydro levels this 2026 summer season. Weather trends could lift gas-fired generation and limit the critical multi-day flexibility that hydropower provides during prolonged heatwaves. El Niño lowers the number of storms, but unusually warm Gulf waters can fuel more intense hurricanes. These could disrupt gas production in August and September, at the peak of injection season. For buyers locking winter gas and power in late summer/early fall, this raises the risk of hedging straight into a storm-driven price swing.

A 'super' El Niño is forming in the equatorial Pacific just as the U.S. faces persistent heat this summer. The Pacific is transitioning this year from a La Niña cool phase to an El Niño warm phase. Forecasters expect this year's El Niño to reach 'super' strength, defined as a sea-surface anomaly above +2°C, by August. The recent U.S. heatwave was not a direct result of El Niño patterns. Instead, it stemmed from stalled high-pressure systems (heat domes), with a global long-term warming trend amplifying the temperature peaks.

El Niño increases the risk of multiple weather events overlapping in some U.S. regions, such as wildfires, prolonged heatwaves, low wind speeds, and drought. CAISO, SPP, MISO, and the Northwest will likely be more exposed to heat-driven demand spikes over the summer, according to BloombergNEF forecasts.

The U.S. West entered the summer season dry. California's snowpack sits ~80% below its five-year average, the lowest in over a decade. Over the prior two years, snow levels tracked near the five-year average. The Pacific Northwest's snowpack also sits at just over half of normal:

• Hydropower supplies about 12% of California's electricity and more than half of the Northwest's. A weak hydro year can shift load onto gas-fired generation and tighten regional balances.
• Dry soils also raise wildfire and public safety power shut-off (PSPS) risks across the West and the Plains. As of late June, California and the U.S. West were already on high wildfire alert.

Figure 5: California Snowpack Water Equivalent, Deviation from Previous 5-Year Average by Water Year