Ample natural gas storage heading into winter gives executives a reasonable moment to put a number on 2027 energy costs, though it does not tell them the cheapest contract is on the table today. The more useful exercise is deciding how much cost uncertainty the business can carry, then testing supplier offers against that limit.
The U.S. Energy Information Administration (EIA) forecasts 3,969 billion cubic feet of working gas in storage on October 31, the end of the injection season, which would sit 5% above the five-year average. That figure comes from the agency's September Short-Term Energy Outlook, completed September 3. It is still a projection, and the next update arrives October 6. For leaders running gas-intensive operations or holding gas-indexed electricity contracts, storage is one input among several. Plant location, load profile and contract terms can matter just as much when judging whether an offer buys certainty at a fair price.
EIA Forecasts Henry Hub at $3.59 in Late 2027 but a Lower Annual Average
The September outlook's price tables put Henry Hub spot gas at $3.13 per million British thermal units (MMBtu) in the fourth quarter of 2026 and $3.59 a year later. On a full-year basis the direction reverses, with the average slipping from $3.43 in 2026 to $3.28 in 2027. A budget memo that quotes only the winter comparison implies a uniformly tighter year the annual forecast does not support. One that quotes only the annual figures hides the firming the agency expects late next year.
EIA's outlook pairs those prices with strong supply growth. The agency's natural gas outlook expects U.S. production to rise by 4.5 billion cubic feet per day in 2026 and another 4.6 in 2027, with the Permian and Haynesville regions providing more than 70% of the increase. These are forecasts of spot prices. They are not offers a company can sign. A fixed-price contract folds in the supplier's cost of covering the delivery period plus its margin, and that premium can turn a fixed price into an expensive hedge if nobody compares it with the expected indexed cost.
Eastern Gas Storage Enters Winter Near Average While Western Regions Carry Surpluses
The national cushion is not spread evenly. EIA expects inventories in the East to start the withdrawal season roughly at their five-year average, held back by a lower starting point and limited regional production growth. Other regions look more comfortable. The Mountain region is projected at 21% above normal, the Pacific at 10%, the Midwest at 6% and South Central at 4%. A manufacturer in Pennsylvania and one in Colorado are reading the same national headline from very different positions.
Supplier comparisons should reflect that. Separating the commodity benchmark from regional basis, transportation, balancing charges and volume limits shows how much of the delivered cost an offer actually fixes. A company that locks only the Henry Hub component can still carry most of its local price movement.
Power budgets deserve a similar look at scope. Fixing gas-linked energy charges leaves capacity, transmission and demand charges untouched. EIA's table shows the average U.S. commercial electricity price edging up from 13.99 cents per kilowatt-hour in 2026 to 14.15 cents in 2027, even as the annual gas forecast falls. National averages blur local tariffs, but the split is a reminder that electricity cost now behaves like a strategic exposure with drivers well beyond fuel.
Budget Certainty Should Be Priced Against the Company's Own Exposure
The executive conversation starts with volume. Contracting against an optimistic production plan can leave a company paying for gas it no longer needs if output falls short, so a conservative consumption estimate is the safer base. One structure worth evaluating fixes a share of predictable demand and leaves a flexible portion on index. It gives up some benefit if prices fall in exchange for certainty on a defined slice of usage, and it only works with clear rules for swing volumes and extra purchases. Those rules also settle who inside the company owns the contract exposure once the deal is signed.
A simple illustration helps frame the stakes. For a hypothetical business with 1 million MMBtu of unhedged annual consumption, a $0.50 move in commodity cost shifts spending by $500,000 before regional and contract effects. Leadership can weigh that swing against operating margin and available cash. An offer's value depends on how it fits that exposure, and much less on whether management thinks it has spotted the bottom of the market. Holding out for a better moment carries its own cost, since waiting for a contract to expire is itself a market bet.
Several questions will stay open after October 6. EIA's storage forecast assumes normal conditions through the end of injection season, and a cold early winter in the East would test a region that starts with no surplus. Supplier offers may also move once the updated outlook lands. The questions leadership controls are internal ones. How much budget variance is acceptable, and what premium is certainty worth? Answering them before offers arrive lets procurement act quickly, including on a decision to keep some volume indexed.
