Bank of America has adjusted its balance-year Henry Hub price outlook downward by about $0.2 per million British thermal units, arriving at a revised forecast of $3.4 per mmbtu. The bank attributed the reduction to unusually mild temperatures that extended from winter into April, a pattern that supported inventory replenishment and exerted downward pressure on prices.
Despite the cut, the bank notes its forecast still sits above the current forward curve, a consequence of recently tight physical balances in the market. On inventories, the bank now projects end-of-summer gas stocks will rise to roughly 3.83 trillion cubic feet, a level it expects to be above the five-year average.
Regionally, the bank flagged several demand-side risks that could exert upward pressure on pricing. In the western United States, the report points to bullish demand risks tied to an early peak in snow water equivalent and a concurrent snow drought that has left reservoirs unusually low. The bank expects these hydrological conditions to reduce hydrogeneration this summer, increasing reliance on gas-fired power plants to meet electricity demand.
Bank of America highlighted the potential for stronger gas demand in locations such as Southern California, where competition for Canadian imports could intensify. The bank noted that if Costa Azul LNG begins operations this summer and adds incremental demand in California, western markets could face tighter supplies. At the same time, rising feedgas requirements for LNG Canada were cited as another upward force that could lift AECO prices.
In the East and Midwest, the bank observed growing power sector demand as a driver of tighter balances. Increasing electric loads associated with data centers may necessitate the use of less efficient gas-fired generation to balance supply, putting upward pressure on power prices in PJM and MISO. Bank of America warned that storage deficits in the East and Midwest could be challenging to refill in the face of this expanding power demand.
The bank called out the Midwest, including hubs such as Chicago, as potentially vulnerable this summer. It said stronger demand in the West from LNG and diminished hydro availability could restrict Canadian gas flows into the Midwest, while robust power demand in PJM could keep more gas supplied to the East.
On production and logistics, Bank of America said the Permian Basin has effectively exhausted natural gas pipeline takeaway capacity, a situation that has resulted in record low prices at the Waha hub. With gas-to-oil ratios climbing and higher oil prices potentially incentivizing additional associated gas output, the bank expects Waha to remain distressed through the summer as stranded gas is likely to fill the recently expanded GCX capacity immediately.
Meaningful transport relief, the bank added, is not anticipated until late in the year or into early 2027, when larger pipeline projects such as Blackcomb and Hugh Brinson are slated to begin service. Looking further ahead, the bank suggested the Permian should be well positioned to supply planned LNG export facilities in Texas, including Golden Pass, Rio Grande, and Port Arthur.
- Inventory outlook: End-of-summer storage seen at about 3.83 trillion cubic feet, above the five-year average.
- Price forecast: Henry Hub forecast trimmed to $3.4 per mmbtu but remains above the forward curve due to tight recent balances.
- Regional risks: Western hydropower losses, rising power demand in the East and Midwest, and Permian takeaway constraints.
Bank of America emphasized that while milder weather has temporarily eased price pressure through inventory rebuilds, structural and regional constraints - including hydrological shortfalls in the West, increasing power-sector loads in the East and Midwest, and persistent Permian pipeline limits - pose tangible risks to supply balances through the remainder of the summer.