US LNG's Next Wave: Capacity, Contracts and the Gas Balance

Executive Summary

The US is roughly halfway through the largest build-out of liquefied natural gas (LNG) export infrastructure in its history. After the 2016–2022 "first wave" that lifted the country from a net importer to the world's largest LNG exporter, a "second wave" — anchored by Plaquemines, Corpus Christi Stage 3, Golden Pass, Rio Grande and Port Arthur — is now ramping. EIA's June 2026 outlook puts US LNG exports at an average of 17.0 Bcf/d in 2026, up 1.9 Bcf/d (about 13%) from the 2025 record of roughly 15.1 Bcf/d, with a further rise toward 18.5 Bcf/d in 2027 [1][2]. Peak nameplate capacity has already reached about 18.3 Bcf/d [2].

The decision-relevant number is incremental feedgas demand. EIA expects LNG feedgas to grow 9% (1.3 Bcf/d) in 2026 and 11% (1.7 Bcf/d) in 2027 — the single largest source of incremental US gas demand over the forecast horizon [3]. Feedgas hit an all-time high near 19.7 Bcf/d in March 2026 [4]. On a fully-utilized basis, our terminal ledger (below) sees US export capacity climbing from ~18 Bcf/d today toward 24–25 Bcf/d by 2028 as the second-wave trains complete (The Gas Gauge estimate, built up from EIA/FERC train data [1][2][5][6]).

That pull lands on a domestic market that no longer has a structural surplus to absorb it. EIA expects Henry Hub to average about $3.34/MMBtu in 2H 2026 before rising in 2027, as demand growth outpaces supply and draws down storage [7]. our central scenario carries that logic forward: once the second wave is fully on feedgas (2028–2030), Henry Hub averages $4.00–4.75/MMBtu in 2027 dollars — structurally higher and more volatile than the $2–3 norm of 2015–2020 (The Gas Gauge estimate).

The paradox of this report: US capacity arrives into a globally oversupplied market. Qatar is simultaneously lifting North Field capacity from ~77 Mtpa toward ~142 Mtpa by ~2030 [8][9], and the IEA expects a liquefaction surplus on the order of 15% of global capacity by 2030 under its central scenario [10]. The result is bifurcation: tight, price-supported US domestic balances coexisting with a soft, buyer's-market international price. US gas is now globally coupled — domestic price and basis are increasingly set at the dock, not the wellhead.

Bottom line: The second wave lifts US LNG export capacity from ~18 Bcf/d to ~24–25 Bcf/d by 2028 (The Gas Gauge estimate), adding 5–7 Bcf/d of feedgas — the largest single new source of US gas demand. our central case puts Henry Hub at $4.00–4.75/MMBtu (2027$), structurally higher and more volatile, even as a parallel Qatari surge pushes the global market into oversupply through 2026–2028.

Context and Scope

Two of our coverage domains intersect in this report: LNG export capacity, contracts and global flows, and prices, storage and balances (Henry Hub, TTF, JKM, basis). A third — demand: industrial, heating, LNG feedgas, and data-center load — frames the competition for incremental molecules.

The question is narrow and quantitative: how much US liquefaction capacity actually arrives by 2030, who has contracted it, and what does the resulting feedgas pull do to the domestic gas balance and Henry Hub — given a simultaneous global supply surge led by Qatar?

Scope. The system boundary is US Gulf Coast and East Coast liquefaction plus the feedgas pipelines that serve it. The report covers: (1) a terminal-by-terminal capacity ledger in Bcf/d by year; (2) the offtake/contract landscape; (3) feedgas demand and domestic price impact; (4) the global balance versus Qatar and global demand to 2030; (5) three scenarios for export capacity and Henry Hub with sensitivity; and (6) the public-equity read. Out of scope: detailed methane/permitting litigation mechanics (touched only as risk), downstream regas economics in importing markets, and shipping/charter rates.

A vocabulary note used throughout. Nameplate (peak) capacity is the engineered maximum; baseload capacity is the sustainable annual average, typically 10–15% below nameplate; utilization is actual feedgas versus nameplate. Mid-decade US terminals routinely run above nameplate in cool months and below in summer maintenance, so "capacity" and "exports" diverge. Unless stated, capacity figures are nameplate and flows are EIA feedgas/export averages.

The Second-Wave Capacity Ledger

From first wave to second wave

The first wave (Sabine Pass, Corpus Christi Stage 1–2, Cameron, Freeport, Cove Point, Elba, Calcasieu Pass) took the US to roughly 14–15 Bcf/d of operating capacity by 2024. The second wave is dominated by four sponsors — Venture Global, Cheniere, Sempra and NextDecade [11] — plus the ExxonMobil/QatarEnergy Golden Pass joint venture. By April 2026, Golden Pass Train 1 had produced its first LNG (first production reported March 30, 2026; first cargo from Train 1 reported April 22, 2026), making it the ninth operational US export terminal and lifting capacity to its highest-ever level [2][4].

Terminal-by-terminal ledger

The table below assembles nameplate capacity and the ramp by terminal. Figures are drawn from EIA capacity tracking and company/FERC disclosures; the "online" column reflects first-cargo or expected start dates as of mid-2026.

Reading the ledger: the near-term additions that move 2026–2027 balances are Plaquemines' ramp to full output, Corpus Christi Stage 3's trains 5–7 (+0.6 Bcf/d), and Golden Pass trains 1–2 (+1.4 Bcf/d) [1][3]. The next leg (2027–2028+) is Rio Grande trains 1–2 (+1.4 Bcf/d), Port Arthur Phase 1 (+1.6 Bcf/d) and Golden Pass train 3 (+0.7 Bcf/d) [1].

The Take: EIA's headline export forecast (17.0 Bcf/d in 2026) understates the capacity story because exports are flow-limited by ramp schedules and summer maintenance, not by installed metal. Summing the post-FID trains in the ledger, US nameplate capacity reaches ~24–25 Bcf/d by 2028 (The Gas Gauge estimate) — a 6–7 Bcf/d step over today's ~18 Bcf/d [2]. The gap between nameplate and realized flow (the "ramp wedge") is where the domestic price tension lives: capacity exists to pull far more gas than 2026 flows imply, so the binding constraint shifts to feedgas availability and price, not liquefaction.

Plaquemines: the swing factor and the brownfield option

Plaquemines is the most consequential single asset of the wave. Venture Global expects ~27 Mtpa of production with 35 Mtpa of authorized peak capacity (~1,873 Bcf/yr, ≈5.1 Bcf/d peak) [6]. In 2025 the company filed a FERC application for a brownfield expansion that would lift the complex's total peak production above 58 Mtpa — adding 24 modular trains and roughly $18 billion of incremental investment [5][6]. our analysis treats the expansion as optionality, not base case, until it clears FERC and reaches FID.

The Contract and Offtake Landscape

Capacity without offtake is a stranded asset; the second wave is unusually well-contracted, but the counterparties have shifted.

The four lead sponsors have built long-term sale-and-purchase agreement (SPA) books spanning Europe, Asia and portfolio players. Venture Global alone reports total contracted capacity of about 43.5 Mtpa across its three Louisiana projects (Calcasieu Pass, Plaquemines, CP2), with CP2 Phase 1 SPAs signed across Europe, Asia and the rest of the world [11][14]. Cheniere remains the pure-play anchor with a large contracted book and a substantial portfolio (uncontracted/spot) volume that captures international-domestic spreads directly [15].

Three structural features matter:

• Free-on-board (FOB), Henry-Hub-indexed pricing. Most US SPAs price liquefaction as a fixed fee (typically ~$2–3/MMBtu) plus ~115% of Henry Hub for the gas, FOB. This passes commodity risk to the buyer and tethers global cargoes to the US benchmark — the mechanism by which US export growth couples Henry Hub to TTF/JKM.
• Portfolio buyers, not just end users. A growing share of offtake sits with portfolio players and majors who optimize destination, blurring the old "European vs Asian" split [11][14].
• The 2024 DOE pause and its reversal. On January 26, 2024, DOE paused pending decisions on exports to non-FTA countries pending an updated economic/environmental/security study [11]. That pause was subsequently lifted and approvals resumed in 2025–2026 (e.g., incremental authorizations for Plaquemines and Elba in early 2026 [3]), but it injected a permitting-risk premium that still shadows un-FID'd projects.

The Take: The contract book is the second wave's ballast. Because the lead trains are sold on fixed-fee, HH-indexed FOB terms, sponsor cash flows are far more insulated from a global price collapse than the headlines about "LNG glut" imply — the buyers wear the spread risk. The corollary for the domestic market is less comforting: contracted feedgas will be pulled even in a soft global market, because the liquefaction fee is owed regardless. That is precisely why a global oversupply does not translate into feedgas relief at home (our view).

Feedgas Demand and the Domestic Price Impact

Feedgas is where LNG meets the domestic balance. EIA's accounting is unambiguous: LNG feedgas is the largest single source of incremental US gas demand, growing 1.3 Bcf/d (9%) in 2026 and 1.7 Bcf/d (11%) in 2027 [3]. Deliveries peaked near 19.7 Bcf/d in March 2026 and averaged ~16.6 Bcf/d in the week ending June 10, 2026 [4].

The supply side has so far kept pace — US dry production has repeatedly set records — but the margin is thinner than in the first wave. EIA's June 2026 STEO shows demand growth outrunning supply growth in 2027, drawing down storage and lifting prices [7]. The mechanism: each ~1 Bcf/d of sustained new feedgas is roughly 1.3–1.5% of total US dry gas demand, and at the margin must be met by either incremental Appalachian/Permian/Haynesville production (which requires a higher price signal to accelerate) or storage draws.

Note the price range for 2027: EIA's June 2026 STEO carries ~$3.46/MMBtu for 2027, while its January 2026 STEO had carried a sharper rebound toward ~$4.60/MMBtu [7][16] — the spread reflects how sensitive the back-year is to storage and weather assumptions. our analysis reads the truth as somewhere between: structurally higher than the recent past, but bounded by the elasticity of US shale supply.

The Global Balance: US Capacity Into a Qatari Surge

The US is not building in isolation. Between 2025 and 2030, roughly 345 bcm/yr of new global liquefaction (from projects already FID'd/under construction as of 2025) is set to arrive — the largest wave of additions ever, with annual additions rising from ~35 bcm/yr in 2025 to a peak near ~95 bcm/yr in 2028 [10][17]. IEEFA estimates ~57 Mtpa of new capacity starting in 2026 alone — the most ever in a single year [17].

Qatar is the other pillar. QatarEnergy is lifting North Field nameplate capacity from ~77 Mtpa (2023) toward ~110 Mtpa (North Field East, ~2025–2026) and ~142 Mtpa by around 2030 (North Field West), though NFW first exports have slipped toward end-2031 [8][9][18]. That would move Qatar from ~17–19% of global LNG supply today toward ~20–24% by late decade [8]. Crucially, a large share of new Qatari volume remains uncontracted, giving Doha latitude to defend market share on price [8].

The demand side is the soft spot. IEA's central (STEPS) scenario sees demand reaching ~460–490 Mtpa by 2030 but a liquefaction surplus equivalent to ~15% of global capacity — a structural glut, concentrated in 2026–2028 before new Asian demand (regas, distribution) is fully built out [10]. The swing buyer is price-elastic Asian and European demand: cheap LNG pulls coal-to-gas switching and discretionary buying; expensive LNG destroys it.

The Take: The global glut and the US domestic tightness are not contradictory — they are two ends of the same fixed-fee contract. Internationally, marginal cargoes will clear at a soft TTF/JKM as Qatari and US volumes compete, compressing the variable margin on uncontracted (portfolio/spot) volumes. Domestically, contracted feedgas is pulled regardless, so Henry Hub stays supported. The investable distinction is therefore between toll-takers (paid the fixed liquefaction fee — insulated) and spread-takers (exposed to the international-domestic arb — squeezed in a glut). Most US listed midstream sits closer to the toll-taker end; the spread risk concentrates in portfolio marketers and the equity of merchant exporters.

Scenarios: Export Capacity and Henry Hub to 2030

Three scenarios bracket the range. All are The Gas Gauge estimates built on the cited capacity ledger and EIA balance data; assumptions follow.

All three are The Gas Gauge estimates (basis below). The central case aligns capacity with the post-FID ledger [1][2][12] and the price with EIA's directional call that demand outpaces supply in 2027+ [7], extended to a fully-ramped wave.

Sensitivity

The Henry Hub answer is moved by four levers, in rough order of impact (one-way, The Gas Gauge estimate):

The asymmetry: US shale's ability to add 2+ Bcf/d at a modest price signal is what keeps even the High case from running away. The binding question for 2028–2030 is whether Appalachian takeaway and Permian associated-gas growth can stay ahead of a 5–7 Bcf/d feedgas step without a sustained $5+ price.

Feasibility, Scale-Up, and Risk

The near-term wave (through 2027) is largely de-risked — the trains are built or under construction with offtake in hand. The risk concentrates in the next leg (un-FID'd and brownfield capacity) and in the demand assumptions underpinning the global balance.

Risk Register

Readiness grade (our view): the 2026–2027 additions are high-confidence; the 2028+ leg is medium-confidence, gated on FID, permitting and global price; the Plaquemines brownfield and a true >25 Bcf/d build-out are optionality, not base case.

Market and Equity Implications

This report's thesis — structurally higher, more volatile Henry Hub at home; a soft, oversupplied international market; and the toll-taker/spread-taker distinction — cuts cleanly across the listed names. Exposure reads are directional, tied to the thesis, and are not investment advice. Tickers are NYSE-listed.

The Take: The cleanest expression of this report's thesis is long the toll, cautious on the spread. The fee-based feedgas midstream (KMI, WMB, and the transport side of ET/TRGP) captures the volume growth of the second wave with minimal commodity beta — they get paid whether the global market is tight or glutted. The merchant-margin exposure (LNG's portfolio book; any spread-taker) is where a 2026–2028 international oversupply bites. And the under-appreciated beneficiary is the upstream gas producer (EQT): the domestic price floor is being reset upward by an export pull that, unlike the global price, is contractually committed. If the report is right that Henry Hub re-bases to $4+ (2027$), the producer with the lowest-cost, longest-lived inventory captures the most durable margin.

Outlook and Strategic Implications

The second wave changes the nature of the US gas market more than its size. The US becomes the marginal global supplier whose domestic benchmark is now transmitted worldwide through fixed-fee, HH-indexed cargoes. That coupling cuts both ways: Henry Hub re-bases higher and more volatile, while the international price softens under the weight of simultaneous US and Qatari additions. The winners are the toll-takers and the lowest-cost producers; the squeezed are the spread-takers and high-cost, un-FID'd projects chasing a glutted international market.

What to watch: (1) FID and FERC milestones on Rio Grande trains beyond train 2, Port Arthur Phase 1 schedule, CP2, and the Plaquemines brownfield — these decide whether the wave tops out near 24–25 or pushes toward 28 Bcf/d. (2) Feedgas vs the 19.7 Bcf/d March-2026 high [4] — sustained new records confirm the central case. (3) The Henry Hub 2027 strip relative to EIA's $3.46–4.60/MMBtu range [7][16] — a back-year that holds above ~$4 validates the re-basing thesis. (4) Asian regas additions and the TTF–JKM spread — the demand signal that determines whether the 2026–2028 global glut is shallow or deep [10].

Disclosures & Disclaimer

This report is general commentary published for information purposes only. It is not investment advice, a recommendation, or a solicitation to buy or sell any security. The Gas Gauge is a research publication, not a registered investment adviser or broker-dealer. Views are the publication's own analytical opinions, are subject to change, and may prove wrong. Readers should do their own research and consult a licensed financial professional before acting. The publication and/or its principals may hold positions in securities mentioned. © Terawatt Intelligence Briefings.

Methodology and Assumptions

The capacity ledger is assembled bottom-up from EIA capacity tracking and "Today in Energy" terminal data, cross-checked against company and FERC/DOE disclosures; flows and the balance use EIA's June 2026 Short-Term Energy Outlook as the primary basis. Where a figure is a our construction rather than a cited datum, it is labelled "The Gas Gauge estimate."

Key derived numbers and their inputs:

• ~24–25 Bcf/d 2028 nameplate capacity (The Gas Gauge estimate): sum of operating capacity (~18 Bcf/d, EIA [2]) plus post-FID second-wave trains in the ledger — Golden Pass remaining trains, Rio Grande trains 1–2 (+1.4), Port Arthur Phase 1 (+1.6), Corpus Christi Stage 3 completion, plus Plaquemines full ramp [1][2][12]. Excludes un-FID'd brownfield optionality.
• Henry Hub scenarios (The Gas Gauge estimate, 2027$): anchored to EIA's directional finding that demand outpaces supply in 2027 and draws storage [7], extended to a fully-ramped feedgas wave; bounded above by US shale supply elasticity and below by the global glut's spillover into domestic netbacks. The low/central/high spread maps to the four sensitivity levers (supply elasticity, utilization, weather/storage, power demand).
• Global supplier shares (The Gas Gauge estimate): US ~185–195 Mtpa-equivalent by 2030 from the ledger; Qatar ~142 Mtpa from QatarEnergy guidance [9]; both against IEA global demand (~460–490 Mtpa, STEPS) [10].

What would change the conclusion: a re-pause or judicial block on non-FTA approvals (slips the 2028+ leg); a materially deeper or shallower Asian demand recovery (sets the depth of the glut); or a step-change in US shale productivity (caps or unleashes the Henry Hub response). Data vintage: EIA figures are June 2026 STEO and 2026 "Today in Energy" releases; Qatar/global figures are 2024–2026 QatarEnergy/IEA/IEEFA. Prices are nominal unless marked 2027$.

References

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2. U.S. Energy Information Administration. "North America's LNG export capacity could more than double by 2029." Today in Energy, 2026. https://www.eia.gov/todayinenergy/detail.php?id=66384
3. U.S. Energy Information Administration. "Domestic and international demand drive natural gas production growth." Today in Energy, 2026. https://www.eia.gov/todayinenergy/detail.php?id=67425
4. American Gas Association. "Natural Gas Market Indicators – June 11, 2026." 2026. https://www.aga.org/research-policy/resource-library/natural-gas-market-indicators-june-11-2026/
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10. International Energy Agency. "Coming surge in LNG production is set to reshape global gas markets." IEA News, 2025. https://www.iea.org/news/coming-surge-in-lng-production-is-set-to-reshape-global-gas-markets
11. U.S. Department of Energy / Morgan Downey. "US LNG Exports — Oil 101" (second-wave sponsors; 2024 DOE non-FTA pause). https://oil101.morgandowney.com/chapters/us-lng
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13. U.S. Energy Information Administration. "North America's LNG export capacity is on track to more than double by 2028." Today in Energy, 2025. https://www.eia.gov/todayinenergy/detail.php?id=64128
14. Venture Global, Inc. "CP2 Phase 1 press release." Form 8-K, FY2025. https://www.sec.gov/Archives/edgar/data/0002007855/000200785525000036/cp2phasei-pressrelease.htm
15. Cheniere Corpus Christi Holdings, LLC. "Form 10-Q." FY2026. https://www.sec.gov/Archives/edgar/data/0001693317/000169331726000005/cch-20260331.htm
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17. Institute for Energy Economics and Financial Analysis (IEEFA). "Global LNG Outlook 2024–2028." 2024. https://ieefa.org/resources/global-lng-outlook-2024-2028
18. Enerdata. "Qatar unveils North Field West project to raise LNG production by 85% by 2030." 2024. https://www.enerdata.net/publications/daily-energy-news/qatar-raise-lng-production-2030.html
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