Natural Gas Futures Price Forecast: $2.84 as 108.7 Bcf/d Production Overwhelms Demand

Natural Gas Price Forecast: Futures Trapped at $2.84 After 62% Collapse From February's $7.50 Peak — EIA Withdrawal Misses, 108.7 Bcf/d Production, and a Wall of LNG Supply Point to $2.50 Before Summer

Natural gas futures (NG=F) are going nowhere fast. The April contract traded at $2.84/MMBtu on Friday inside a painfully tight $2.818-$2.894 range, up a barely perceptible 0.39% on the day and down roughly 62% from the February blowoff spike near $7.50 that accompanied Winter Storm Fern. The EIA storage report delivered a withdrawal of 52 billion cubic feet — less than the market expected — and the initial reaction was a drop to $2.83. Then weather models called for another round of cold air entering the Lower 48 next week, and price clawed back to $2.84. That one-penny bounce is the entire bull case right now: cold weather forecasts propping up a market that would otherwise be in freefall toward $2.50.

The technical picture is unambiguously bearish. Price sits below the 20-day EMA at $3.23, the 50-day EMA at $3.59, the 100-day EMA at $3.69, and the 200-day EMA at $3.62. All four averages are stacked above price and sloping lower. The RSI at 39 hovers below the 50 midline with no bullish divergence. The sequence of lower highs and lower lows from the February spike through current price is textbook distribution. Natural gas futures need to reclaim $3.23 — the 20-day EMA, which is 14% above current price — just to generate the first sign that the selling wave has exhausted itself. Until that happens, every cold snap rally is a selling opportunity, not a buying signal.

The February Blowoff and Unwind — From $7.50 to $2.84 in Three Weeks

Winter Storm Fern produced one of the most violent price spikes in natural gas history. The Dawn hub in Ontario surged to approximately $62/MMBtu in late January as the polar vortex slammed demand higher and froze production across the Appalachian Basin. Henry Hub followed with a spike toward $7.50 on the front-month contract. New England delivery points saw even more extreme prints — the Algonquin Citygate spiked above $120/MMBtu before collapsing back to single digits.

The unwind was equally brutal. Price failed to sustain levels above $4.50, broke through $3.80 support, and cratered below $3.00 in less than two weeks. The Dawn daily price is closing February below $3.00 after that historic $62 print just four weeks ago. The pattern is textbook: weather-driven demand shock, leveraged speculative surge, evaporation of the catalyst (temperatures normalized), cascading liquidation, and a return to fundamentally-driven price levels. The $7.50 peak will not be revisited until next winter — and possibly not even then, given the supply outlook.

EIA Storage Report — 52 Bcf Withdrawal Misses Expectations, Inventories Run 7.5% Above Year-Ago Levels

The Energy Information Administration's Thursday report showed a net withdrawal of 52 billion cubic feet for the week, below market consensus. Stockpiles are currently running approximately 7.5% above year-ago levels at the same point in the heating season. That surplus matters enormously for the forward curve. With winter demand winding down over the next 3-4 weeks, every weekly report that fails to draw down inventories faster than expected adds to the storage overhang that will weigh on prices through spring and summer.

The injection season typically begins in late March or early April. Once withdrawals flip to injections, the market needs enough demand — either domestic consumption or LNG exports — to absorb ongoing production without building stockpiles to record levels. With inventories already 7.5% above last year's pace and production running at 108.7 Bcf/d across the Lower 48 states in February, the math is straightforward: unless summer demand significantly exceeds expectations or production declines materially, storage will be at or near capacity by October, capping any meaningful price recovery.

108.7 Bcf/d Production — The Supply Wall Natural Gas Futures Cannot Climb

U.S. natural gas production in the Lower 48 averaged approximately 108.7 Bcf/d through February. That number is expected to increase further in March and beyond as seasonal maintenance concludes, new production lines come online, and new facilities begin operations. The Permian Basin continues to produce enormous volumes of associated gas as a byproduct of oil drilling, and pipeline takeaway constraints in West Texas have pushed Waha hub basis to deeply negative levels — below negative $5/MMBtu in some forward months, meaning Permian producers are effectively paying to get gas off their hands.

The production trajectory is the core bearish argument. Even if cold weather generates a short-term demand spike, the supply side responds within days as any curtailed production comes back online. And the structural ramp in production capacity — new liquefaction trains, expanded gathering systems, pipeline expansions — ensures that supply growth outpaces demand growth through at least mid-2026. Kinetik Holdings, a major Permian midstream operator, expects seasonal congestion to persist in 2026 despite nearly 5 Bcf/d of new takeaway capacity coming online, with guidance assuming roughly 100 MMcf/d of price-related shut-ins during peak maintenance periods. When a midstream company guides for shut-ins as part of its base case, the market has a production problem that price cannot solve at $2.84.

Forward Curve Collapse — Permian and Northeast Basis Prices Plunge Heading Into Spring

Forward natural gas prices across both the Permian Basin and the Northeast fell sharply over the past week as bearish forecasts and the approaching shoulder season pressured contracts out through next winter. The West Texas forward basis curves for El Paso Permian, Transwestern, and Waha show deep negative basis near -$5/MMBtu in the near months, narrowing only gradually toward -$1/MMBtu by 2028. Northeast basis prices, while still relatively elevated compared to the rest of the country, have also declined as forecasts call for a warm March and the extreme volatility of January-February fades from the market.

The biggest movers on Friday tell the story: El Paso-Waha Pool basis at $0.15, El Paso-Keystone & Waha Pools at $0.13, El Paso Permian at $0.12. On the bearish side, Algonquin Citygate basis dropped $1.915, PNGTS fell $2.285, and PNGTS Non-Border also declined $2.285. The Northeast premiums that were astronomical during Winter Storm Fern have evaporated. Without extreme cold, there's no structural reason for Northeast delivered prices to sustain significant premiums over Henry Hub — pipeline capacity additions and LNG export diversification have gradually reduced the seasonal chokepoints that historically drove winter spikes in New England.

LNG Export Demand — Cheniere's $2.3 Billion Quarter Can't Save Domestic Prices

The long-term LNG demand narrative remains constructive. Cheniere doubled its quarterly profit to $2.3 billion and expanded its share buyback program beyond $10 billion, targeting record exports of 51-52 million tonnes per annum this year. Venture Global signed a 20-year agreement for 1.5 million tonnes per annum with Hanwha Aerospace, bringing its contracted portfolio above 46 mtpa. Shell is progressing LNG Canada Phase 2 and indicated the project is reducing AECO price exposure. New liquefaction capacity is being built across the Gulf Coast.

But the export story cuts both ways. While LNG terminals provide incremental demand for U.S. natural gas, the forward guidance from major exporters also points to softer global LNG pricing from 2026 onward as additional U.S. supply enters the market. New liquefaction trains and rising cargo volumes are expected to ease global tightness — a dynamic that reduces the incentive for international buyers to pay premium prices for U.S. cargoes and could eventually slow feedgas demand growth. Right now, domestic prices already reflect robust export flows. The incremental benefit of another 1-2 Bcf/d in LNG feedgas demand over the next 12-18 months is insufficient to absorb the production growth that's coming from the Permian, Haynesville, and Appalachian basins simultaneously.

April Contract Dynamics — Why You're Trading Dead Money Until Summer

The April futures contract that's currently the front month represents delivery during one of the lowest-demand periods of the year. The transition from heating season to the shoulder months of April-May typically marks the annual low in natural gas prices. Demand falls off as neither heating nor cooling loads are significant, and production continues at full capacity, building storage rapidly. This seasonal pattern is one of the most reliable in commodity markets, and it's working against any bullish thesis right now.

The broader pattern from 2025 confirms the dynamic: gas futures remained low through much of last year until cold weather finally forced demand higher late in the year. Even then, inventories were so oversupplied that prices never sustained rallies for more than a few weeks. The same structural problem applies in 2026 — possibly worse, given that production is higher year-over-year and new liquefaction capacity takes time to ramp. By mid-2026, production facilities will be operating at peak output with minimal demand pull, creating the conditions for a potentially deep summer bear market in domestic gas.

Technical Structure — Every Moving Average Points Lower, RSI Shows Room to Drop

The daily chart is a clean bearish alignment with no ambiguity. All four major EMAs — 20-day at $3.23, 50-day at $3.59, 100-day at $3.69, and 200-day at $3.62 — are stacked above price and declining. The gap between the current $2.84 price and the nearest EMA ($3.23) is $0.39, or 13.7%. That gap quantifies how far natural gas is from even beginning to challenge the bearish structure. The 50-day and 200-day EMAs are clustered in the $3.59-$3.69 zone, forming a dense overhead resistance band that would require a 27-30% rally to reach.

RSI at 39 is below the 50 neutral line but not yet at extreme oversold levels (typically 20-25 for natural gas, which runs more volatile than most assets). There's room for RSI to decline further before a mechanical oversold bounce triggers. No bullish divergence is present — price and momentum are declining in tandem, which is the hallmark of a healthy (from the bears' perspective) downtrend.

Key Natural Gas Price Levels

Resistance: $2.894 (Friday high) → $3.00 (psychological) → $3.23 (20-day EMA — first meaningful test of bearish structure) → $3.59 (50-day EMA) → $3.60-$3.69 (200-day and 100-day EMA cluster — the zone that must break for any sustained recovery) → $4.50 (February failure point) → $7.50 (blowoff peak — irrelevant for months).

Support: $2.818 (Friday low) → $2.80 (consolidation floor and widely-watched psychological level) → $2.75 (identified as key structural support) → $2.60 → $2.50 (significant late-2025 base — the line in the sand for the broader downtrend) → $2.30-$2.20 (prior buyer zone from historical support).

Permian Basin Pipeline Constraints — Structural Negative Basis Isn't Going Away

The Permian Basin's pipeline situation deserves its own analysis because it represents a structural drag on national prices that won't resolve quickly. Nearly 5 Bcf/d of new takeaway capacity is coming online, but Permian gas production is growing alongside it — meaning the bottleneck shifts rather than disappears. Waha prices at deeply negative basis levels (-$5/MMBtu in forward months) signal that producers are trapped: they can't stop producing associated gas without shutting in oil wells, and they can't move the gas fast enough to clear the local oversupply.

The implications for Henry Hub are indirect but real. Every molecule of Permian gas that reaches the Gulf Coast adds to domestic supply and competes with Haynesville and Appalachian gas for the same LNG feedgas, industrial, and power generation demand. As pipeline capacity expands, more Permian gas reaches the national market, creating incremental supply pressure that shows up as lower Henry Hub prices. Energy Transfer's launch of natural gas deliveries to Oracle's data center represents the kind of new demand source — AI-driven power consumption — that could eventually absorb some of this surplus, but the scale is insufficient to make a dent at the macro level in 2026.

The Verdict — Natural Gas Is a Sell on Rallies Above $3.00, Targeting $2.50 by Late Spring

Natural gas at $2.84 is dead money with a bearish tilt. The structural picture is as clean as it gets in commodities: production at 108.7 Bcf/d and rising, inventories 7.5% above year-ago levels, the injection season about to begin, all major EMAs declining above price, RSI at 39 with room to fall further, forward curves in steep contango across both the Permian and the Northeast, and LNG export growth insufficient to absorb the domestic supply wave. The only bullish catalyst is weather — and weather is temporary by definition. Every cold snap rally since the February blowoff has failed at lower highs. The pattern is selling strength, not buying dips.

Sell natural gas futures on any rally toward $3.00-$3.23 (psychological resistance through the 20-day EMA). The primary target is $2.50 — the late-2025 structural base — with timing between late April and June as the shoulder season eliminates heating demand and production peaks. A breakdown below $2.50 would expose the $2.30-$2.20 zone where buyers previously stepped in. The stop for short positions sits above $3.25 on a closing basis, which would indicate the 20-day EMA has been reclaimed and the bearish structure is breaking.

The only scenario that flips the bias is a sustained reclaim of the $3.60 zone — where the 50-day, 100-day, and 200-day EMAs converge — accompanied by a fundamental shift in either production (significant decline) or demand (extreme weather or massive new LNG/industrial offtake). Neither is likely before autumn. Until then, natural gas is a short on strength, and the $2.80 consolidation floor will eventually give way to the $2.50 target. The trade is patient, the setup is clean, and the seasonal calendar is the most reliable tailwind a short seller can ask for.

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