Noreva’s new U.S. gas forecasting service expects a more volatile market featuring higher regional price spikes, including potential $10/MMBtu levels in constrained areas.

Noreva (formerly Karbone Research), an AI-powered energy market intelligence platform, recently expanded its offerings with enhanced U.S. natural gas forecasting tools. These include merchant curves, scenario modeling, fundamentals analysis, basis and logistics analytics, and capacity pricing forecasts that integrate real transactional data, supply-demand balances, policy factors, and proprietary models. The service aims to provide clearer visibility into near-term and long-term (up to 25-year) price paths amid shifting market dynamics.

This outlook aligns with broader structural changes in U.S. natural gas markets: surging demand from LNG exports and power generation for AI/data centers, while supply growth faces constraints from producer discipline, maturing acreage productivity, and infrastructure bottlenecks. The result is a market that can appear well-supplied on average yet prone to sharp regional dislocations and price spikes during weather extremes, maintenance, or peak demand periods.

LNG Exports Drive Structural Demand Growth

U.S. natural gas demand is rising significantly through LNG exports as the country solidifies its position as the world’s largest exporter. Current operational export capacity exceeds 18–20 Bcf/d, with feedgas demand recently averaging around 17–19 Bcf/d (subject to maintenance seasonality).

EIA projections show U.S. LNG gross exports averaging about 17.4 Bcf/d in 2026 and 18.6 Bcf/d in 2027, up from roughly 15 Bcf/d levels in prior periods. Longer-term forecasts point to capacity more than doubling toward 30+ Bcf/d by the early 2030s (and potentially higher with additional FIDs), capturing over one-third of global LNG supply in some scenarios. This growth stems from strong international demand in Europe and Asia, geopolitical diversification needs, and U.S. cost advantages.

Export volumes can still face temporary limits from plant maintenance, weather, or global price arbitrage, but the long-term trajectory is firmly upward. U.S. production is expected to support this: EIA forecasts record marketed natural gas output averaging around 122.5 Bcf/d in 2026 (up from prior records near 118.5 Bcf/d), driven by the Permian (associated gas) and Haynesville.

Upcoming Trains and Key Companies

A wave of new liquefaction trains and projects is coming online or under construction, adding substantial capacity through the late 2020s. Near-term additions (2026–2027) include further ramp-up at Venture Global’s Plaquemines LNG, Cheniere’s Corpus Christi Stage 3 (Trains advancing toward full completion), and ExxonMobil/QatarEnergy’s Golden Pass (Train 1 operational with subsequent trains following).

Medium-term projects under construction or advancing include Venture Global’s CP2 LNG (Phases), Sempra’s Port Arthur LNG Phase 1, NextDecade’s Rio Grande LNG (Trains 1–5 and beyond), Woodside’s Louisiana LNG, Commonwealth LNG, and others such as Delfin FLNG. These could collectively add well over 10–15 Bcf/d of nameplate capacity in the coming years when fully ramped, with more potential from expansions and pending FIDs (e.g., further Cheniere Sabine Pass stages).

Key companies span the chain:

• LNG developers/operators: Cheniere Energy (Sabine Pass, Corpus Christi), Venture Global (Calcasieu Pass, Plaquemines, CP2), Sempra Infrastructure (Cameron, Port Arthur), NextDecade (Rio Grande), ExxonMobil/QatarEnergy (Golden Pass), and others.
• Producers: Firms with strong positions in Haynesville, Marcellus/Appalachia, and Permian associated gas (e.g., Expand Energy, EQT, and larger integrated players).
• Midstream: Pipeline and gathering operators critical for takeaway to Gulf Coast terminals and power markets.

How much can the U.S. ultimately export?

Authorized volumes far exceed current builds (DOE long-term authorizations total tens of Bcf/d), but practical limits depend on feedgas availability, pipeline capacity, capital discipline, offtake contracts, and regulatory/permitting timelines. North American capacity (including limited Canadian/Mexican contributions) is on track for major growth if projects proceed as planned.

Implications for AI Power Consumption and New Demand

AI and data-center growth represent a major new domestic demand driver layered on top of LNG. Natural gas already accounts for roughly 40%+ of U.S. power generation. Data-center electricity use is projected to rise sharply—potentially reaching hundreds of TWh by the late 2020s—and much of the incremental reliable/dispatchable power will come from gas-fired generation (grid-connected or behind-the-meter).

Analyst estimates for incremental gas demand from data centers/AI range from several Bcf/d by 2030 (e.g., ~6 Bcf/d in some forecasts) to higher figures of 10+ Bcf/d or more in aggressive scenarios by the mid-2030s. Wood Mackenzie sees power-sector gas demand alone potentially requiring an extra ~17 Bcf/d by the mid-2030s (nearly 50% growth from mid-2020s levels) as load surges and gas complements intermittent renewables.

This dual demand (LNG exports + power/AI) tightens balances, increases competition for molecules in key regions (Gulf Coast, Texas, Southeast, Northeast), and heightens the risk of regional price spikes when weather, freezes, or infrastructure constraints hit. It also supports more pipeline, storage, and generation infrastructure buildout.

What Analysts Say About Natural Gas Prices

Short-term views remain moderate amid strong production and storage, but structural bullishness is growing for the medium-to-long term, with elevated volatility.EIA Short-Term Energy Outlook figures have recently pointed to Henry Hub averages in the mid-$3/MMBtu range for 2026–2027 (with quarterly variations and recent adjustments for production and storage).

Wood Mackenzie forecasts a sustained rise, with Henry Hub approaching ~$5/MMBtu (real) by 2035 as demand growth outpaces low-cost supply and productivity gains slow.

Other analyses (Rystad, ICF, etc.) note that sustained prices above ~$4/MMBtu (and higher for peak growth) may be needed to incentivize sufficient new drilling in secondary acreage, particularly in the Haynesville. Forward curves have often lagged these views, remaining relatively flat in the near years before steeper rises farther out. Volatility is expected to increase, with regional basis spikes (Northeast, constrained Gulf or California points, etc.) capable of reaching extreme levels during stress events—consistent with Noreva’s $10 regional spike expectations and historical precedents during cold snaps or freezes.

Overall, averages may rise modestly at first while the frequency and magnitude of spikes increase due to tighter seasonal balances and infrastructure limits.

What Investors Should Watch Across the Nat Gas and Utility Value Chain

Investors should focus on companies positioned for volume growth, fee-based cash flows, and exposure to the dual LNG + AI/power demand story, while monitoring risks from price volatility, capital costs, regulation, and execution.

Upstream producers: Prioritize those with low-cost inventory in growth basins (Haynesville for LNG-proximate dry gas, Appalachia, Permian associated gas). Look for capital discipline, hedging, free cash flow, and ability to ramp when prices support it. Exposure to higher realized prices and volume growth is key.

Midstream/pipelines and storage: Favor operators with Gulf Coast takeaway, connections to LNG terminals, and expanding capacity to data-center load centers (Texas, Southeast, etc.). Fee-based models with long-term contracts provide resilience; backlog growth for power-related laterals and expansions is a positive signal (examples include major pipeline players serving both LNG and power markets).

LNG pure-plays and integrated exporters: Cheniere and peers benefit from contracted capacity, expansion upside, and global arbitrage. Watch utilization rates, offtake strength, and project delivery timelines.
Utilities and power generators: Those with significant gas-fired fleets or new build plans stand to gain from higher utilization and capacity payments driven by AI load, though they face fuel-cost pass-through dynamics, regulatory scrutiny on rates, and the need for reliable supply. Look for companies investing in generation near data centers or securing firm gas transportation.

Broader considerations: Balance sheets and leverage; dividend sustainability; ESG/regulatory exposure; weather and storage dynamics; global LNG pricing (JKM/TTF influence on U.S. netbacks); and potential policy shifts supporting domestic energy and AI infrastructure. Diversification across the chain or via midstream-focused vehicles can help manage commodity volatility.

Higher average prices and spikes support upstream and LNG margins but can pressure industrial users and utility fuel costs (with potential rate impacts). Infrastructure owners often capture more stable upside from throughput growth.

In summary, Noreva’s forecasting service highlights a market shifting from prolonged low-volatility surplus toward one defined by stronger demand fundamentals, rising price floors over time, and more frequent regional spikes. LNG export expansion and AI-driven power needs are the primary catalysts. For Energy News Beat readers and investors, monitoring project ramp schedules, basin-level supply responses, and infrastructure bottlenecks will be essential as these trends unfold.