By Apollo Kokkinopoulos, CEO Market data checked August 24, 2026. This outlook covers November 2026 through March 2027. It is refreshed after each monthly EIA Short-Term Energy Outlook through October 2026, and will be reframed as a historical review after March 2027.
EIA's August Short-Term Energy Outlook puts Henry Hub at $3.14/MMBtu in the fourth quarter of 2026 and $3.62/MMBtu in the first quarter of 2027 — cut by roughly 40 to 45 cents from the July edition on record production and the highest pre-winter inventories since 2016. That is a base case that looks adequately supplied rather than tight. Neither figure is the rate on a Texas gas bill. Henry Hub is a Louisiana wholesale benchmark; what a business actually pays depends on its pricing hub, local basis, upstream transport and fuel, LDC tariff, load shape, and the risk language buried in the contract.
So the honest answer to "should we lock before winter?" is conditional, and the conditions are specific to your account. Below is the evidence, the parts of it that can break, and the facts that decide whether you fix, layer, or float.
EIA forecasts Henry Hub at $3.14/MMBtu in 4Q 2026 and $3.62/MMBtu in 1Q 2027. Texas businesses with heavy winter use or tight budgets should compare fixed-price coverage for actual requirements within stated tolerances or a defined block; flexible loads may retain some indexed volume. Decide from delivered quotes, not Henry Hub alone.
Winter 2026–27 Natural Gas Outlook: Five Numbers to Know
| Number | Reading | What it actually is |
|---|---|---|
| EIA Henry Hub forecast, 4Q 2026 | $3.14/MMBtu | Model forecast completed August 6, 2026, down from $3.57 in the July edition. A quarterly average covering October–December, so one of its three months sits outside this winter. |
| EIA Henry Hub forecast, 1Q 2027 | $3.62/MMBtu | Model forecast for January–March 2027, down from $3.83 in July — the back three months of this winter, and the colder half. |
| Forecast end-October 2026 storage | 3,985 Bcf, about 5% above the five-year average | A forecast of the cushion the market carries into winter, not an observation. EIA calls it a record, and it is 19 Bcf above the July forecast. |
| NYMEX Nov.–Mar. futures curve, five trading days ending August 6, 2026 | $3.480 simple monthly average; January 2027 highest at $4.100 | The five-day settlement average EIA itself publishes alongside the forecast. A dated market benchmark, not a forecast and not a delivered price. |
| Texas commercial deliveries in the five 2025 winter months | 55.3% of the calendar year | A seasonality calculation from EIA history — January–March plus November–December 2025, not one contiguous winter, and not your load. |
Sources: EIA August 2026 Short-Term Energy Outlook, Table 2 (forecast completed August 6, 2026); EIA STEO Figure 22 workbook for the futures curve; EIA Texas commercial deliveries. Checked August 24, 2026.
One label to get right before going further: winter 2026–27 crosses two calendar years, so the relevant quarterly pair is 4Q26 plus 1Q27. EIA's 4Q 2027 figure of $3.63/MMBtu belongs to the following winter, 2027–28, and has nothing to do with the season you are buying now. Quarterly averages are also blunt instruments in both directions — 4Q26 drags in a mild October, and any three-month average can hide a single brutal week.
Statewide, more than half of Texas commercial gas volume lands in five winter months. Your own share may be radically different — a greenhouse and an office building in the same ZIP code are not the same buyer. Calculate it from your meter history before you decide anything else.
Should Texas Businesses Lock Natural Gas Rates Now?
Work the decision in this order. Skipping to the last question is how businesses end up comparing two offers that were never comparable.
- Eligibility and timing. Which LDC and rate schedule serve the meter? What does the current contract say about end date, notice deadline, and auto-renewal? Third-party transportation service can require available capacity and pressure, an approved shipper or qualified supplier, credit or security, telemetry, a minimum service term, and utility approval — and it has its own conditions for returning to bundled sales service.
- Winter load share. What percentage of your annual usage actually falls November through March? Split it into firm baseline and weather-sensitive swing; those two need different treatment.
- Existing coverage. Is any winter volume already fixed, capped, or otherwise protected under an agreement you have not re-read recently?
- Budget tolerance. What would one extreme monthly settlement do to cash flow or operating margin? Not the annual average — the single worst month.
- Comparable quote quality. On the same pricing index or hub, LDC receipt point, end-use meters, load, start date, and term, how does each offer treat basis, transport, fuel, fixed-price scope, swing, imbalance, pass-throughs, and termination?
Only then does a structure follow from the facts:
| Buyer situation | Structure to investigate | Reason |
|---|---|---|
| Winter-heavy load, tight operating budget, little existing coverage | Fixed-price actual-requirements product within stated tolerances, or a larger fixed block with indexed swing | Reduces price volatility on covered volume. Verify every tolerance, exclusion, and out-of-band settlement before assuming the product absorbs shape risk. |
| Predictable baseload plus variable winter swing | Fixed block plus indexed swing, purchased in one or more layers | Protects the known baseline while leaving genuinely uncertain volume flexible, and avoids concentrating the whole decision on a single trade date. |
| Strong budget flexibility, limited winter sensitivity, or existing protection | Indexed pricing, or a smaller protected share | Retains downside participation while accepting event risk you have the balance sheet to absorb. |
| Multi-site portfolio | Site-specific fixed and index combinations, potentially purchased in layers | Different LDCs, pricing points, and load shapes are not one account and should not be priced as one. |
| West Texas or Waha-linked account | Explicit basis review before choosing a structure | A Henry Hub hedge can leave material local basis exposure untouched. |
| Small bundled utility-sales customer | Verify transportation eligibility first | A marketer switch may not be available or economic under the applicable tariff. CenterPoint's Houston T-93 schedule, for example, works from an estimated 10 MMBtu/day requirement; other Texas tariffs set different conditions. |
Notice what is missing: an arbitrary 50/50 or 70/30 split. There is no defensible universal hedge ratio, because the ratio is an output of your load and budget, not an input. The defensible target is to protect the amount of winter spend the company cannot afford to leave exposed — and to know exactly what the protection covers.
Not sure whether your meters are even eligible for third-party supply? That is the first question our commercial natural gas brokerage in Texas answers, before any pricing conversation starts.
What Henry Hub Does — and Does Not — Tell a Texas Business
| Measure | What it is | What it is not |
|---|---|---|
| EIA forecast | A government model-based expectation, revised monthly | A hedge price, a supplier quote, or a guarantee |
| NYMEX futures curve | A dated wholesale benchmark for future delivery at Henry Hub | A prediction certain to be realized, or an all-in Texas rate |
| Delivered business quote | A customer-, hub-, term-, volume-, and contract-specific offer | A statewide average, or a number you can compare across different start dates and terms |
Two compact structures explain most of the gap between a benchmark and a bill:
Bundled utility-sales bill = utility customer, demand, and distribution charges + a PGA/GCA/COG cost-of-gas mechanism that may already include commodity, storage, and upstream transport + applicable riders and taxes.
Transportation economics = supplier charge using a local index or benchmark-plus-basis, with upstream transport and fuel either included or separately stated + LDC customer, contract-demand, and distribution charges + applicable shrinkage, metering, riders, and taxes.
Components may be bundled rather than itemized, which is why two quotes can look different and price identically. A few distinctions worth holding onto:
- Basis is a differential, not a fee. It is the spread between the contract's benchmark and its local market pricing or contractual delivery point — not your end-use meter. If a quote already uses a local index, the location value is embedded; do not let anyone add basis to it a second time.
- Three different points get confused constantly: the pricing index or hub, the marketer's LDC receipt point, and the business's end-use meter. Waha, Houston Ship Channel, Katy, NGPL TXOK, and LDC citygates can all diverge from Henry Hub, and no two contracts necessarily use the same one.
- "Fixed" needs a scope every time it is used. A fixed unit price may cover commodity only, commodity plus stated basis, actual requirements within specified tolerances, or a defined block. It normally does not fix total spend, because usage, demand charges, riders, taxes, and out-of-band volumes still move.
- "Actual requirements" has no universal risk allocation. Verify the swing band, minimum or take-or-pay quantity, excess and shortfall pricing, nominations, daily and operational-flow-order exclusions, and imbalance pass-throughs before believing a product absorbs volume or shape risk.
- Gas choice is not ERCOT choice. Texas electricity deregulation does not carry over to gas. Transportation eligibility is tariff- and account-specific, and the Railroad Commission's own explanation separates cost of service from cost of gas for exactly this reason.
For the full cost stack — how Henry Hub, basis, and LDC delivery charges stack into a delivered rate — we keep the evergreen mechanics in one place rather than rebuilding them here.
One credibility check on all forecasts, including this one. In January 2026, EIA's first look at 2027 put the annual Henry Hub average just under $4.60/MMBtu. By August, that same annual forecast was $3.31/MMBtu — roughly 28% lower in seven months, and it fell again between the July and August editions. That is not a criticism of EIA; it is the nature of a monthly model. It is also the reason a procurement decision should be stress-tested against a range rather than anchored to one point forecast.
Why the Base Case Looks Adequately Supplied
Four things support the moderate view heading into November:
- Storage. EIA forecasts record end-October inventories of 3,985 Bcf, about 5% above the five-year average — the highest level heading into a winter since 2016. Lower 48 stocks stood at 3,169 Bcf the week ending August 14, 6.2% above the five-year average and 0.9% below the same week last year.
- Production. EIA expects record U.S. dry gas production of 113.0 Bcf/d in 4Q26 and 114.1 Bcf/d in 1Q27, led by the Permian. That is the main counterweight to rising LNG exports of 18.0 and 18.7 Bcf/d over the same quarters.
- Texas takeaway capacity. EIA counts 29.7 Bcf/d of planned 2026–27 U.S. pipeline additions originating in Texas, including Blackcomb (2.5 Bcf/d toward Agua Dulce, targeted 3Q26), Hugh Brinson (first phase targeted 4Q26, second 1Q27), and Rio Bravo (second half of 2026).
- The current curve. The five-day curve ending August 6 averaged $3.480 across November–March, effectively on top of EIA's own monthly path for the same months ($3.484) — though January still carried a pronounced premium. Forecast and market agreeing is not a forecast of calm; it means neither one is currently pricing a winter problem.
For context on how fast this moves: EIA's five-trading-day curve ending July 1 averaged about $3.79/MMBtu across November–March, with January and February above $4. The comparable curve five weeks later, ending August 6, averaged $3.480 — about 31 cents lower on a like-for-like basis, with only January still above $4. That demonstrates curves change, not that the market will keep falling.
The defensible statement is that the base case looks adequately supplied. It is not that gas will be cheap, and it is certainly not that there is no reason to lock.
Four Risks That Can Still Make Winter Expensive
1. A short, severe freeze
January 2026 is the relevant precedent, not 2021. Winter Storm Fern produced a record 360 Bcf weekly storage withdrawal and widespread freeze-offs, and EIA's daily series shows Henry Hub spot at $30.72/MMBtu on January 23 and $25.01 on January 26. Inventories fell 5.6% below the five-year average in the following weeks, then recovered enough to begin the injection season about 3% above it. A quarterly average of $3.62 cannot describe that week — which is the entire argument for sizing protection to your worst month rather than your expected year.
2. LNG commissioning and utilization
EIA expects Gulf Coast export demand to keep climbing as Corpus Christi Stage 3, Golden Pass, and other projects ramp. Commissioning dates move in both directions: faster starts or high utilization would tend to tighten the domestic balance, while delays or outages would tend to loosen it. EIA has demonstrated that relationship in a prior sensitivity study — useful as inference support, not as the August 2026 base forecast.
3. Power burn and late-summer injections
EIA forecasts record U.S. gas use by electric generators in 2027, so heating demand is not the only claim on the same molecules. Nearer term, a hot late summer raises gas-fired power burn and can slow the pace of storage additions before November — which is why the end-October storage number is a forecast worth rechecking, not a fact already banked.
4. Texas basis and pipeline dislocation
A customer priced at Waha, Houston Ship Channel, NGPL TXOK, Katy, or an LDC citygate can experience a completely different winter from Henry Hub. FERC's 2026 Summer Assessment showed summer Waha futures averaging negative $1.26/MMBtu as of April 10 on takeaway constraints, with new capacity expected to improve Waha pricing toward year-end. Read that carefully in both directions: more takeaway can relieve Permian egress congestion and improve deliverability, and it can also narrow Waha's discount, raising the value of West Texas gas relative to Henry Hub. It can equally pull more Permian supply toward Gulf Coast power and LNG demand. Whether that helps or hurts your account depends on your pricing index, receipt point, end-use location, and basis clause — and a negative Waha print has never meant anyone receives free gas.
A fifth item belongs on the list even though it is not a market risk: operational terms. A business can be fully hedged on commodity and still face expensive swing, imbalance, critical-period, or daily-index exposure. And a fixed price is not firm delivery — LDC and upstream curtailment rules, including the Railroad Commission's curtailment plan, operate independently of what you paid.
Four Scenarios for Winter 2026–27
| Scenario | What would have to happen | Likely market effect | Procurement implication |
|---|---|---|---|
| Comfortable base case | Storage tracks near EIA's path, production grows, pipeline projects broadly on time | Winter curve stays orderly with a January–February premium | Compare fixed vs. indexed pricing and actual-requirements vs. block volume; cover budget-critical risk |
| Mild / downside-price case | Low heating demand, strong production, slower LNG ramp | Inventories finish above baseline; index may outperform fixed | Retained index exposure benefits, subject to the contract's own terms |
| Cold / upside-price case | Freeze, production losses, large withdrawals, high LNG and power demand | Henry Hub and/or regional basis jump; daily exposure becomes costly fast | Fixed pricing may reduce commodity exposure on covered volume — confirm whether basis, shape, swing, daily-index, and imbalance risk remain |
| Texas basis case | Takeaway capacity starts on time or slips; local constraints shift | Waha, Houston Ship Channel, or citygate pricing diverges from Henry Hub | Your hub and basis language decide the outcome, not the national headline |
No probabilities and no price targets are attached to these, deliberately. Nobody publishing a winter outlook in August knows which one arrives, and a made-up percentage would only make the page feel more precise than the evidence is.
Weather deserves the same discipline. NOAA's August 13 discussion has El Niño strengthening, with a greater than 90% chance of a very strong event through fall and winter 2026–27 and a 69% chance that October–December exceeds every event back to 1950 (+2.5°C or more on the three-month RONI). That is still not permission to call a mild Texas winter: NOAA's August 20 seasonal outlook puts equal chances on temperature across south-central CONUS for December–February, with only modest above-normal precipitation odds, and even a historic ENSO event does not guarantee the typical regional result. A seasonal outlook is a probability of a broad three-month anomaly. Operational risk is a specific Arctic outbreak lasting several days. The first does not eliminate the second.
Ask for Comparable Offers, Not Just a Headline Price
Request every offer on the same date, for the same pricing index or hub, LDC receipt point, end-use meters, forecast load, start date, and term. Then keep three decisions separate that suppliers routinely blend together: pricing (fixed, indexed, or capped), volume (actual requirements within stated tolerances, or a defined block), and timing (one transaction, or layered purchases).
- The exact index or hub, settlement timing, and the fallback if that index stops publishing.
- Basis treatment, and whether upstream transport and fuel are embedded or separately stated.
- What the fixed price covers: commodity, basis, actual requirements within stated tolerances, or only a block.
- Swing, overage and underrun, nomination obligations, imbalance, daily and OFO treatment, and corrected-meter true-ups.
- Pass-through language, auto-renewal, supplier mark-to-market termination, remaining LDC transportation charges, and return-to-sales conditions.
One nuance worth knowing before a supplier explains it their way: utility tariffs generally settle imbalances with the shipper or qualified supplier, and the retail supply agreement determines whether and how those costs reach your business. A cash-out is a settlement mechanism, not automatically a penalty. Term length matters too — Texas Gas Service transportation is generally unavailable for less than 12 months and CenterPoint uses a one-year initial term, so a tidy five-month winter supply offer may not line up with the utility agreement underneath it. The complete Texas commercial gas procurement process covers the extended legal and operational checklist.
What to Watch Between Now and Winter
| Signal | Source | What matters |
|---|---|---|
| Weekly Lower 48 and South Central storage | EIA | Path versus the five-year average and versus EIA's end-October forecast |
| Nov.–Mar. strip and the Jan./Feb. premium | CME / NYMEX | The current wholesale curve, not one day of noise |
| Dry gas production | EIA STEO and monthly data | Whether supply keeps pace with the base case |
| LNG commissioning and utilization | EIA and project updates | Timing versus forecast |
| NOAA seasonal and short-range outlooks | NOAA CPC / NWS | Probabilities first; event forecasts only closer to delivery |
| Blackcomb, Hugh Brinson, and Rio Bravo in-service dates | EIA, project announcements, FERC filings | Effect on takeaway, deliverability, and basis |
| Same-day supplier quote spreads | Your own procurement process | Delivered economics and risk allocation — the only numbers you can actually transact |
What is deliberately not on that list is a "lock before November" rule. Seasonal expectations are already priced into the curve, which is why the January premium is visible from August. On most accounts the terms of a supplier's offer matter more than the calendar month it was signed in.
Frequently Asked Questions
What is EIA's natural gas forecast for winter 2026–27?
EIA's August 2026 Short-Term Energy Outlook forecasts Henry Hub averaging $3.14/MMBtu in 4Q 2026 and $3.62/MMBtu in 1Q 2027, roughly 40 to 45 cents below the July edition. Those are quarterly averages, so 4Q26 also includes October — outside a November–March winter. The forecast was completed August 6, 2026 and is revised monthly.
Should Texas businesses lock natural gas rates now?
It depends on four facts: your November–March share of annual usage, how much winter volume is already protected, what one extreme monthly settlement would do to your budget, and what the delivered quotes actually cover. Winter-heavy loads with little coverage and thin tolerance have the strongest case. Flexible budgets with limited winter exposure can reasonably keep some volume indexed.
Does a $3.14 Henry Hub forecast mean my rate will be $3.14?
No. Henry Hub is a Louisiana wholesale benchmark. A transportation customer pays commodity plus basis, upstream transport and fuel, LDC customer, contract-demand and distribution charges, shrinkage, riders, and taxes. A bundled sales customer pays utility charges plus a cost-of-gas mechanism instead. For historical context on delivered Texas pricing, see what Texas businesses currently pay per Mcf.
Does a fixed gas rate fix my entire bill?
Usually not. A fixed unit price can cover commodity only, commodity plus stated basis, actual requirements within tolerances, or only a defined block. Usage, demand and distribution charges, riders, taxes, and volume outside the contracted band can still move. Ask in writing what the fixed price covers and how out-of-band volume settles.
Can every Texas business choose a natural gas supplier?
No — gas choice is not ERCOT electricity choice. Third-party transportation service is tariff- and account-specific, and eligibility can turn on the utility, rate schedule, meter and load size, available capacity and pressure, an approved shipper or qualified supplier, credit or security, telemetry, minimum service term, and utility approval. Confirm return-to-sales conditions before switching.
The Bottom Line
EIA's August base case combines record end-of-October storage with record production, and the futures curve now sits on top of that forecast rather than below it. None of it protects a budget from a freeze, a local basis move, or an out-of-band charge — the January 2026 storm is only nineteen months old, and it produced $30/MMBtu daily prints inside a quarter that averaged nothing like it.
So decide how much winter spend you cannot leave floating, then compare pricing method, volume treatment, and purchase timing on identical account assumptions. That is a procurement decision you can document and defend. A market prediction is not.
Get Your Winter Gas Position Reviewed
Send a recent bill, 12–24 months of monthly usage (24–36 is better for a weather-normalized review), your LDC and rate class, your contract end date and notice deadline, and any planned operational changes. We will come back with a delivered-structure comparison on identical assumptions — not a headline rate.
Request A Gas Contract ReviewSources
- EIA, August 2026 Short-Term Energy Outlook (PDF). Table 2 quarterly Henry Hub prices and Table 5a production, LNG export, and inventory forecasts; forecast completed August 6, 2026, released August 11, 2026.
- EIA, Short-Term Energy Outlook — Natural Gas. Storage, production, power-burn, and annual forecast narrative.
- EIA, Weekly Natural Gas Storage Report. Lower 48 stocks for the week ending August 14, 2026, released August 20.
- EIA, Texas natural gas deliveries to commercial consumers. 2025 monthly volumes used for the 55.3% seasonality calculation.
- EIA, Winter Storm Fern analysis and EIA daily Henry Hub spot price series. The 360 Bcf withdrawal and January 2026 daily prices.
- EIA, planned 2026–27 natural gas pipeline additions. Blackcomb, Hugh Brinson, and Rio Bravo capacity and target dates.
- FERC, 2026 Summer Energy Market and Reliability Assessment (PDF). Summer Waha futures averaging negative $1.26/MMBtu as of April 10, 2026.
- NOAA CPC, ENSO diagnostic discussion (August 13, 2026; next update September 10) and the long-lead seasonal outlook discussion (August 20, 2026). El Niño probabilities and the south-central temperature caveat.
- EIA, STEO Figure 22 workbook (August 2026 edition). NYMEX Henry Hub monthly settlements averaged over the five trading days ending August 6, 2026, sourced by EIA from Bloomberg L.P. and LSEG. The workbook URL is republished each month, so these values are retained here as a dated capture.
- EIA, natural gas price series definitions. Coverage and scope caveats for state-level delivered price averages.
Forecasts are dated scenarios, not guarantees, and futures settlements are wholesale benchmarks rather than delivered offers. Nothing here is an Elite Energy Consultants rate, a quote, or individualized financial advice. Market data verified at the publisher on August 24, 2026.
