UNG ETF At $12.25: Can Natural Gas, LNG Expansion And AI Power Demand Ignite A Rebound In 2026?

Natural Gas And NYSEARCA:UNG At A Structural Turning Point

NYSEARCA:UNG Price, Range And Liquidity Snapshot

United States Natural Gas Fund LP (NYSEARCA:UNG) closed at $12.25 on December 31, down 6.67% on the day from a previous close of $13.12, after trading in a volatile intraday band between $12.18 and $13.67. Over the last year, UNG has moved in a wide $11.48–$24.33 range and currently sits much closer to the yearly floor than to the peak, with a market cap of roughly $1.68 billion and average daily volume around 3.78 million shares. At $12.25, the ETF trades roughly 28% below its recent high near $17.00, and almost 50% below the 52-week top at $24.33, despite a natural gas futures curve that has shifted into a structurally higher zone versus early 2024.

Henry Hub Futures Trend And The Repricing Of U.S. Gas

NYMEX Henry Hub natural gas has already executed a full regime shift. After collapsing to roughly $1.60/MMBtu in February 2024, front-month futures have printed a sequence of higher lows and higher highs, reaching about $5.496/MMBtu in December 2025, the strongest level since December 2022. A correction pulled prices back to just above $4.00/MMBtu in late December, but the market is still well above the August 2025 low at $2.738/MMBtu, which remains the first critical support. Consensus projections now cluster around an average of roughly $3.60/MMBtu for 2025 and $4.20/MMBtu for 2026, materially above the sub-$3 environment that dominated 2023 and early 2024. In that context, UNG at $12.25 is being priced as if the recent move back to ~$4.00 has already exhausted the upside, even though the underlying fundamental drivers are clearly different from the earlier glut phase.

UNG ETF Performance Versus NYMEX Gas And Roll Mechanics

Over the latest winter leg, February 2026 NYMEX natural gas futures rallied approximately 34.5%, from about $3.734/MMBtu on October 17 to $5.022/MMBtu in early December, while the nearby continuous contract briefly approached $5.50/MMBtu. Across the same window, UNG gained roughly 47.2%, moving from around $11.55 to about $17.00 per share as it rolled exposure into stronger near-dated contracts. That outperformance is exactly how a front-month futures ETF behaves in backwardation spikes: the roll works in favor of holders when the front contract is tighter than back months. The tradeoff is structural drag over longer horizons. UNG charges a 1.24% management fee and carries roll costs whenever the curve is in contango, which is why quantitative factor screens now flag it as a “Strong Sell” with a score near 1.06 on expenses, momentum, and risk metrics, even while discretionary commodity analysts treat it as a buy-the-dip vehicle for leveraged exposure to Henry Hub strength.

Shale Gas Supply: Permian “Gas Burp” Versus Plateau Everywhere Else

Headline EIA 914 data shows U.S. dry gas production near 109 bcf/d as of August 2025, up roughly 6 bcf/d year-on-year, but that aggregate number hides a structural turning point. Shale gas now accounts for over 80% of total output and nearly all recent growth is concentrated in a single basin. In December 2023, total shale dry gas was about 85.93 bcf/d. By August 2025 it was roughly 87.39 bcf/d, up 1.5 bcf/d, but every major gas-focused play except the Permian has flattened or rolled over. Marcellus slipped from 27.76 bcf/d to 27.42 bcf/d (-0.34 bcf/d), Haynesville from 13.34 to 12.85 bcf/d (-0.48 bcf/d), Utica from 6.69 to 6.42 bcf/d (-0.28 bcf/d), and mature basins like Barnett, Fayetteville, Eagle Ford and others all show incremental declines in the 0.1–0.4 bcf/d range. Aggregating all shales ex-Permian, production has slipped from roughly 68.13 to 66.56 bcf/d, a drop of about 1.57 bcf/d. The only true growth engine left is Permian associated gas, which has climbed from around 17.8 bcf/d to approximately 20.83 bcf/d, adding about 3.07 bcf/d over the same period. That rise is a byproduct of well physics: a typical Permian well starts life with roughly 75% oil on an energy-equivalent basis and gradually shifts toward about 45% oil as the reservoir depressurizes and gas increasingly dominates the stream. Cumulatively, this “gas burp” has masked the exhaustion in pure-gas basins, but it is finite. Permian crude oil production is already negative year-on-year, down roughly 160 kb/d across shale oil and around 100 kb/d in the Permian itself. Modeling of mixed-medium reservoirs suggests associated gas can grow perhaps another 1 bcf/d over the next 12–18 months before tracking oil lower. Once that inflection hits, total U.S. shale gas is far more likely to flatten and then decline than to resume the old 4–5 bcf/d per year growth trend the market got used to between 2008–2019.

Inventory Dynamics: From Surplus To Tightening Risk For U.S. Gas

Storage confirms that the easy-oversupply phase is fading. After the 2025 injection season, U.S. working gas in storage peaked near 3.960 tcf, slightly below the 3.972 tcf peak of 2024 but still high by historical standards. A cooler-than-forecast summer in 2025—roughly 3% cooler than normal—kept power demand subdued and allowed inventories to build from slightly below the ten-year average at the start of injection to around 150 bcf above that benchmark by season’s end, roughly a 4% surplus. As of the week ending December 19, 2025, storage had dropped to about 3.413 tcf, which is 3.6% under the prior year and 0.70% below the five-year average for mid-December. Historically, withdrawals between November 1 and April 1 average roughly 1.9 tcf (about 12.6 bcf/d). If this winter merely mirrors last year—which was still about 1% milder than normal—but overlays higher LNG exports and incremental power-sector demand, draws could reach around 2.3 tcf, tightening relative storage by approximately 400 bcf and leaving inventories around the 1.1 tcf area by spring 2026. Against projected dry gas supply of roughly 108 bcf/d, net exports around 17 bcf/d (up from 13 bcf/d last winter), and consumption near 106.5 bcf/d, the system has very little slack. Any meaningful cold spell, LNG outage, or pipeline issue can shift balances by several bcf per day, which is exactly the setup that produces repeated price spikes above $5/MMBtu and fuels outsized upside moves in UNG.

Global LNG Expansion, Convergence And The International Price Anchor

The global LNG build-out is no longer a story on paper; the commissioning wave is now running straight into a plateauing U.S. supply profile. From 2026–2028, the world will see the largest LNG liquefaction expansion in history. Qatar’s North Field East (NFE) adds around 4.3 bcf/d, while U.S. projects and brownfield expansions elsewhere bring the global pool up by an incremental double-digit bcf/d. For the U.S. alone, export plants ramping over 2025–2026 add roughly 55 bcm of capacity, equivalent to more than 5 bcf/d of extra demand versus today. Earlier delays in three major projects—together representing about 6 bcf/d—pushed the “convergence” trade out by a couple of years and allowed Henry Hub to languish below $3/MMBtu longer than expected. With those volumes finally coming online into a system where non-Permian shales are already shrinking, convergence toward international pricing in the $10–$12/MMBtu zone is far more plausible than a return to sub-$2/MMBtu gas. In the medium term, the LNG market will likely swing into surplus around 2027–2028, forcing TTF and JKM down toward the short-run marginal cost of U.S. LNG—roughly $6+/MMBtu assuming Henry Hub at $4.50/MMBtu—but even that scenario still implies a structurally higher Henry Hub band than the one embedded in UNG at $12.25 today.

Europe’s Gas Balances, Russian Phase-Out And The LNG Pull On U.S. Supply

Europe’s gas situation amplifies the pull on U.S. molecules. The EU entered the 2025–26 winter without hitting the old 90% storage target by November 1, after the Commission relaxed rules to a 75–90% range between October and December. Storage peaked close to 83% in mid-October and then slid to around 75% by early December, below both the five-year average and last year’s 85% level at the same date, leaving the region more vulnerable despite looser regulatory pressure. At the same time, speculative money has built an extreme short in TTF futures: investment funds flipped from a net long of roughly 292 TWh in February to a net short around 50 TWh by late November, with gross shorts at a record 491 TWh, more than 100 TWh above the prior peak. This positioning is built on a medium-term bearish thesis: that the LNG expansion plus weak Asian demand and relaxed EU storage rules will crush prices and keep TTF anchored near U.S. LNG short-run marginal cost. The risk is obvious. A colder-than-normal 2025–26 winter or a serious supply disruption would force a violent short squeeze, drive TTF sharply higher, and drag more U.S. LNG across the Atlantic, tightening Henry Hub well ahead of current forecasts and delivering powerful upside to UNG holders. Policy decisions further lock in LNG’s role. The EU’s 19th sanction package bans new short-term Russian LNG contracts from April 25, 2026 and requires long-term Russian LNG to cease by January 1, 2027. A separate gas package bans short-term Russian pipeline flows from June 17, 2026 and mandates an end to long-term pipeline supplies by September 30, 2027, with only a small extension window to November 1 if storage is critically low. Russian LNG currently accounts for about 13% of EU LNG imports—roughly 17 bcm across the first eleven months of 2025—while TurkStream pipeline flows contribute around 15 bcm per year, of which a little over 10 bcm is under long-term contracts. These volumes must be replaced. Given that the U.S. and Russia are the two largest gas producers and that Russian molecules will be constrained by policy, U.S. LNG is the natural backfill. That substitution is structurally bullish for U.S. gas and by extension for NYSEARCA:UNG, even if European benchmarks eventually grind lower in the surplus years.