US natural gas market Report Interpretation

Overview

Goldman Sachs presents a multi-year US natural-gas balance outlook in which the timing of large supply, pipeline, LNG and power-demand projects drives alternating periods of softness and tightness. Its central conclusion is bearish for 2027, more constructive from 2029, and strongly supportive of higher prices in 2031-32 before productivity gains moderate the market later in the decade.

Core views

Goldman Sachs frames US natural gas as a market that has usually had to price low enough to compete with coal for power-generation share and prevent storage congestion. It argues that demand growth is now accelerating through LNG exports and power demand, but the timing of supply and demand additions is uneven because large pipelines and liquefaction projects start in discrete increments. This produces a projected “push and pull” in Henry Hub prices, generally within a $2.50-$5.00/mmBtu range: supply-heavy years pressure prices lower to clear storage, while demand-heavy years permit higher prices. The 2026 balance is described as comfortable rather than congested. Supply and demand growth are both expected to be just over 4 Bcf/d, while the summer balance is estimated to average 0.5 Bcf/d tighter than Goldman Sachs expected in March, mainly because stronger coal-to-gas switching increased power burns. The institution estimates end-October 2026 storage at 3,768 Bcf, below its prior 3,866 Bcf estimate, the 4,017 Bcf historical maximum, and the EIA's estimated 4,280 Bcf capacity. Yet prices have averaged only $2.91/mmBtu since April, below Goldman Sachs' prior $3.50 summer forecast. The report attributes the weakness to market concern over rapid production growth and LNG-export outages, including Freeport LNG maintenance beginning July 10 alongside newly commissioned Permian takeaway capacity. Hotter-than-average weather and the end of Freeport maintenance subsequently helped normalize Gulf storage and move cash and forward prices closer to $3/mmBtu. For the 2026-27 winter, Goldman Sachs sees a slightly loose balance: a storage draw of roughly 1,800 Bcf versus a 2,000 Bcf average would leave end-March storage just below 2,000 Bcf under current forwards and average weather. Unless a major cold event occurs, it believes the modest withdrawal rate limits Henry Hub upside above $3/mmBtu. It therefore cuts its 4Q26 and 1Q27 forecasts to $2.90/mmBtu and $2.95/mmBtu, respectively, from $3.50 for each period; the corresponding forwards were $3.25 and $3.45. The report notes that cold-weather price effects could be amplified by investor positioning that it describes as near the 10th percentile. The principal downgrade is for 2027. Goldman Sachs raises its expected Permian gas-production path by 2 Bcf/d, citing a higher 2026 base and a faster assumed ramp for forthcoming pipeline capacity of 250 mmcf/d per month versus 200 mmcf/d previously. This lifts estimated 2027 US supply growth to more than 2 Bcf/d above projected demand growth of 3.8 Bcf/d. The resulting oversupply is expected to drive end-October 2027 storage above 4,300 Bcf under current forwards, exceeding estimated capacity and approaching or surpassing the historical maximum range. Accordingly, the report cuts its 2027 NYMEX gas forecast to $2.80/mmBtu from $3.50, below the $3.30 forward price. It considers downside risks to that forecast still present even at the lower price, recommends that US gas producers hedge 2027 exposure including the 2027-28 winter, and does not yet recommend an outright short position because winter weather uncertainty remains significant. From 2028, Goldman Sachs expects the supply overhang to unwind as demand additions increasingly dominate. It forecasts roughly 10 Bcf/d of cumulative demand growth in 2028-29, compared with 9.2 Bcf/d in 2025-26, with nearly 8 Bcf/d of the 2028-29 increase driven by upcoming US LNG export projects. Production is expected to grow by less than 9 Bcf/d in those two years, creating sequential balance tightening. The institution lowers its 2028 and 2029 forecasts to $3.05/mmBtu and $3.80/mmBtu from $3.55 and $3.85, respectively, because the market must first recover from a deeper 2027 softening; nevertheless, it expects prices to reach the high $3s by 2029. Higher prices are expected to moderate demand growth, particularly summer power-generation demand. The report sees a more pronounced tightening from the 2030-31 winter as another wave of LNG export projects starts, while Haynesville dry-gas growth inventory approaches its limits. Even assuming Permian takeaway beyond currently scheduled projects, Goldman Sachs believes the balance will require prices above $4/mmBtu to incentivize incremental dry-gas supply from areas such as Western Haynesville, the Arkoma Basin, or Eagle Ford, where marginal costs are likely above the $3-$3.50/mmBtu forward range associated with Haynesville rig gains. It maintains a $4.50/mmBtu Henry Hub forecast for both 2031 and 2032, extends the expected duration of high prices into 2032, and identifies upside risk to those bullish forecasts. Once investment occurs, however, it expects supply productivity to rise and prices to moderate below $4/mmBtu by the mid-2030s, consistent with its observation that US production has generally exceeded expectations except during severe oversupply and price-collapse periods. The report emphasizes execution uncertainty around pipeline and liquefaction start dates, which could create regional price dislocations. Additional final investment decisions for Permian and Appalachia pipelines, liquefaction facilities, and data-center demand projects increase uncertainty further out the curve. Goldman Sachs also assumes no LNG-export cancellations in its forecast horizon but flags cancellation risk in the early 2030s, when recently financed export capacity is due online and could soften global LNG markets.

Analysis framework

Goldman Sachs builds a year-by-year US gas supply-demand balance under current forward prices, linking projected production, pipeline takeaway, LNG export capacity, power demand, storage outcomes and Henry Hub prices. It compares balances with storage limits and historical experience, then revises price forecasts where supply or demand changes alter the level required to avoid congestion or incentivize new production.

Methodology notes

• Industry AnalysisSupply-demand framework

  US natural-gas supply-demand balance analysis

  The report forecasts annual supply and demand growth, compares their timing, and uses the resulting storage balance to explain periods of price pressure or tightening.

• Industry AnalysisSubstitution-Effect Analysis

  Coal-to-gas switching in power generation

  The report treats lower gas prices as increasing gas generation's competitiveness against coal, supporting power-sector gas burns and helping manage storage.

• Industry AnalysisCost curve analysis

  Marginal-price incentive for new dry-gas production

  Goldman Sachs argues that prices above $4/mmBtu are needed in 2031-32 to justify higher-cost incremental dry-gas supply after Haynesville growth inventory becomes constrained.

Asset mapping & comparison

Structured mapping from thesis to named assets (strengths, weaknesses, peers, risks).

• US natural gas / Henry Hub

  The report forecasts a supply-led price decline in 2027 followed by demand-led tightening from 2029 and high prices in 2031-32.

  Strengths

  Accelerating LNG exports and power demand are expected to support demand growth.

  Weaknesses

  Near-term Permian supply growth and potential storage congestion pressure 2027 prices.

  Comparison

  Gas prices have historically fallen to compete with coal for power-generation share; higher prices from 2029 are expected to lift gas relative to coal more often.

  Risks

  Weather, infrastructure start-up timing, additional supply or demand project FIDs, and LNG-export cancellations could alter balances and prices.

Key data

• 2026 supply and demand growthJust over 4 Bcf/d eachGoldman Sachs expects a comfortable 2026 balance rather than storage congestion.
• End-October 2026 storage3,768 BcfVersus 3,866 Bcf previously, 4,017 Bcf historical maximum, and 4,280 Bcf estimated EIA capacity.
• 4Q26 / 1Q27 Henry Hub forecast$2.90 / $2.95 per mmBtuCut from $3.50 / $3.50 per mmBtu; forwards were $3.25 / $3.45.
• 2027 Permian production revision+2 Bcf/dDriven by a higher 2026 base and a 250 mmcf/d-per-month pipeline ramp assumption versus 200 mmcf/d previously.
• 2027 US gas demand growth3.8 Bcf/dSupply growth is estimated to exceed this by more than 2 Bcf/d.
• End-October 2027 storageMore than 4,300 BcfGoldman Sachs' estimate under current forwards, indicating congestion risk.
• 2027 NYMEX gas forecast$2.80/mmBtuLowered from $3.50/mmBtu and below $3.30/mmBtu forwards.
• 2028-29 cumulative demand growthAbout 10 Bcf/dNearly 8 Bcf/d is expected to come from upcoming LNG export projects.
• 2031 / 2032 Henry Hub forecast$4.50 / $4.50 per mmBtuSupported by expected tightness and the need to incentivize new dry-gas production.

Impact & implications

The report's projected sequence is a softer 2027 market as Permian supply outpaces demand, followed by LNG- and power-led tightening from 2029. It expects the most acute tightness in 2031-32 to require materially higher prices for new supply, while recognizing that later investment and productivity gains should eventually temper prices.

Risks

• Material weather deviations could change winter withdrawals and Henry Hub prices; cold shocks could have an amplified price effect given low investor positioning.
• Unexpected timing changes for major pipelines or liquefaction facilities could create regional pricing dislocations.
• Additional final investment decisions for supply pipelines, LNG liquefaction, or data-center demand projects increase longer-dated balance uncertainty.
• US LNG export cancellations, particularly in the early 2030s, could soften global LNG markets and weaken gas demand.

What to watch

• Permian production growth and the ramp rate of new takeaway capacity.
• End-of-season US storage levels, especially the projected end-October 2027 balance.
• Winter weather and the pace of storage withdrawals during 2026-27.
• Start-up timing and utilization of LNG export facilities, including Freeport and future liquefaction projects.
• The pace of LNG-export and power-demand growth in 2028-29.
• Haynesville inventory constraints, incremental dry-gas investment, and the timing of new supply response after 2030.