EQT CEO Toby Rice: Data Centers Boost Gas Demand

Context

EQT CEO Toby Rice addressed energy prices, liquefied natural gas (LNG) markets, and the growing footprint of hyperscale data centers during an on-stage interview at CERAWeek in Houston on March 23, 2026 (Bloomberg, Mar 23, 2026). His remarks underscored a strategic pivot in conversations among gas producers: demand-side structural change driven by cloud infrastructure and AI workloads rather than purely cyclical commodity moves. Rice framed the debate around two measurable variables—the pace of LNG offtake growth and incremental power demand from data centers—which together could reshape regional flows and price dispersion across U.S. hubs. The remarks came as Henry Hub natural gas traded at approximately $3.60/MMBtu on Mar 23, 2026 (Bloomberg), a level that sits below preceding 12-month peaks but above multi-year lows, highlighting market sensitivity to incremental demand shifts.

Rice's commentary should be read against a backdrop of sustained U.S. production and expanding global liquefaction capacity. U.S. dry natural gas production averaged roughly 99.8 billion cubic feet per day (Bcf/d) in 2025, according to the U.S. Energy Information Administration (EIA, 2025). Global LNG export capacity has expanded materially in recent years; the International Energy Agency reported ~550 million tonnes per annum (mtpa) of nameplate export capacity by end-2025 (IEA, Dec 2025), amplifying the linkage between domestic gas markets and international weather and demand cycles. Those supply-side developments mean that even relatively modest additive demand—measured in low single-digit Bcf/d—can have outsized impacts on regional pricing and basis differentials.

For institutional investors following energy equities and infrastructure, Rice’s comments signal a need to re-evaluate capital allocation frameworks that previously treated power and industrial gas demand as marginal. Data centers are not only end-users of power but increasingly drivers of long-term load growth proximate to unconventional gas basins and pipeline corridors. That reorientation has implications for pipeline tolling, regional congestion risks, and the prioritization of brownfield versus greenfield investments. This article examines the data behind those shifts, estimates potential demand increments, and assesses the implications for LNG-linked markets and EQT’s strategy.

Data Deep Dive

Quantifying the potential incremental gas demand from data centers is challenging but essential. Independent estimates vary: a conservative scenario from an industry dataset projects data-center-related incremental power demand could translate to roughly 0.5–1.5 Bcf/d of additional gas-fired generation by 2030 in the continental U.S., while more aggressive scenarios tied to AI and hyperscale expansion envision 2–5 Bcf/d incremental demand (Rystad Energy, 2025; IEA analysis, 2025). The range reflects assumptions about cooling efficiency, on-site gas-fired generation versus grid-supplied electricity, and the geographic clustering of facilities near low-cost power pools. Rice emphasized at CERAWeek that data centers are ‘‘already changing load shapes’’ and that operators are making infrastructure decisions with a 10–20 year outlook, suggesting that near-term capital allocation decisions will lock in persistent regional demand.

On the LNG side, global demand recovery and project commissioning are shifting the marginal buyer and pricing dynamics. IEA data show global LNG trade grew by approximately 4% year-over-year in 2025, with new export trains in the U.S., Qatar, and Mozambique bringing incremental supply (IEA, 2025). At the same time, European and Asian seasonal dynamics continue to drive sharp short-term price volatility that propagates back to U.S. basis markets via header flows and maritime economics. The interplay means U.S. Henry Hub is increasingly subject to a two-tier influence: domestic supply/demand balance and the optionality of exports converting domestic gas to internationally priced LNG where arbitrage exists.

From a corporate perspective, EQT’s operating metrics matter. Public filings show EQT reduced well-level cash costs through 2024–25 and focused on high-return drilling programs, improving free cash flow per Mcf even as midstream bottlenecks constrained takeaway during certain months (EQT 2025 Form 10-K, 2025). Those operational improvements provide a cushion against price intermittency, but they do not fully immunize companies from structural shifts that increase basis volatility or require incremental midstream capex to serve new demand pockets. Investors should monitor realized pricing, basis spreads at major hubs such as Leidy, Dominion South, and Appalachia, and EQT’s disclosures on firm transportation commitments.

Sector Implications

The convergence of LNG expansion and data-center-driven electric demand creates differentiated winners and losers across the energy value chain. Pipelines and local distribution companies that can secure long-term, firm contracts with hyperscalers or with LNG liquefaction terminals will capture more predictable returns and reduced exposure to seasonal swings. Conversely, merchant pipelines that rely on short-term spreads may see return compression if baseload consumption shifts to on-site power or to regions beyond existing pipeline footprints. The asymmetry is already visible in regional basis moves: pipelines serving the U.S. Northeast experienced volatility in 2025 with monthly spreads swinging by as much as $1.20/MMBtu versus Henry Hub in extreme months (EIA monthly data, 2025).

For LNG exporters, the elasticity of seaborne demand will determine marginal incentives to draw on U.S. supply. If Asian demand for spot LNG holds above 60 mtpa in 2026—consistent with IEA and market broker projections—U.S. trains operating under long-term contracts will continue to underpin upstream activity, but spot-linked flows could compress domestic seasonal dislocations. In equity markets, companies with flexible portfolio exposures—those able to pivot between domestic powermarket sales and export contracts—may navigate the near-term uncertainty better than pure-play exporters or solely domestic-focused producers. Equity valuation multiples have already begun to reflect these nuances; gas producers with integrated midstream assets have traded at a premium to peers lacking firm takeaway capacity through parts of 2025 (Bloomberg analysis, year-end 2025).

Institutional investors should also consider non-price catalysts: permitting timelines, state-level power procurement policies, and corporate renewable PPAs (power purchase agreements) that influence whether data centers demand grid-supplied electricity (which may or may not be gas-fired) or opt for on-site gas generation as a reliability strategy. Policy shifts in technology hubs—such as expedited transmission approval or localized tax incentives—can materially change project economics and, by extension, marginal fuel choice. For asset-backed energy infrastructure, these regulatory and corporate procurement variables are as influential as commodity price forecasts.

Risk Assessment

Key downside risks to the thesis that data centers and LNG materially boost U.S. gas demand include technological substitution, policy intervention, and slower-than-expected AI growth. Advances in cooling, server efficiency, or a pivot toward more electrified solutions backed by renewables could reduce incremental gas-fired generation needs. Similarly, policy measures—like accelerated transmission build-out or incentives for utility-scale battery storage—could allow data centers to achieve reliability without on-site gas turbines, dampening direct gas demand. These risks are non-trivial: in 2024–25, several announced data center projects revised power procurement plans following changes in local interconnection timelines and tax incentives (company filings, 2024–25).

Operational and market risks to upstream operators persist as well. Midstream capacity constraints, pipeline outages, and unexpected maintenance can create short-lived price spikes and damage counterparty relationships. For LNG chains, shipping rates and geopolitical disruptions remain tail risks: a significant rerouting event or a consecutive cold winter in Europe could drive spot prices high and distract markets from long-term fundamentals. Commodity price risk management remains essential; producers with robust hedging programs and diversified outlets will better withstand episodic shocks.

Credit and capital allocation risk also loom. If producers commit to upstream growth to capture potential data-center demand pockets, they could face capital intensity and regulatory headwinds that compress returns. Conversely, underinvestment risks creating scarcity that could drive higher prices and narrower spreads for contracted midstream. Monitoring capital expenditure guidance, firm transportation commitments, and the maturity profile of offtake contracts across the sector is critical for assessing balance-sheet resilience.

Fazen Capital Perspective

Fazen Capital views Rice’s CERAWeek remarks as a clarifying signal rather than a market-moving surprise: the structural potential for data-center demand is real, but the path is lumpy and highly regional. Our contrarian insight is that the most actionable leverage for investors is not bet on headline LNG volumes or broad Henry Hub forecasts, but on localized infrastructure optionality—specifically, assets that can flex between serving LNG trains and nearby power markets for large users like hyperscalers. That means favoring pipeline and compressor investments where contracting terms, route optionality, and regulatory clarity align, rather than chasing upstream dry-gas exposure without takeaway.

We also anticipate a bifurcated pricing environment over the next 3–5 years: hubs proximate to data center corridors and export terminals will exhibit tighter fundamentals and potentially 10–20% higher realized prices versus national averages in high-demand scenarios; by contrast, peripheral basins with constrained takeaway will see more pronounced seasonality and basis discounts. Institutional investors should engage with midstream operators on contract granularity, and track capex-to-contracted-revenue ratios as predictive metrics of cashflow stability. For further reading on infrastructure dynamics and valuation frameworks, see our work on topic and analyses of power-market linkages at topic.

Outlook

Over the next 12–36 months, the interplay between LNG commissioning schedules and data-center siting decisions will be the main driver of regional price dispersion. If global LNG demand grows at approximately 3–5% annually in 2026–28 (IEA baseline), and if data centers contribute even 1–2 Bcf/d incremental domestic demand by 2028, the combined effect will tighten U.S. basin balances during seasonal peaks, compressing basis differentials in select hubs. That outcome would benefit assets with guaranteed throughput and penalize uncontracted, merchant exposures. Investors should stress-test portfolios against scenarios where data-center demand is front-loaded versus delayed by 24 months due to permitting or corporate procurement changes.

Medium-term catalysts to monitor include announced hyperscaler commitments to on-site generation versus PPA-backed grid supply, the timing of major U.S. LNG train start-ups, and state-level transmission reforms that change the economics of delivering renewables to data centers. Public company disclosures—EQT’s 2026 guidance and midstream partners’ subscription levels—will provide early read-throughs on whether demand projections are translating into firm contracts. Scenario-driven modeling that incorporates contract tenure, capacity payments, and downside utilization shocks will be essential for institutional allocation decisions.

FAQ

Q: Could data centers fully offset seasonal declines in gas demand? A: No single demand category is likely to fully offset established seasonal declines driven by heating demand, but data centers can materially reshape monthly load profiles by adding relatively steady, baseload-like consumption in localized areas. Historically, U.S. residential heating accounted for the largest seasonal swings; even if data centers add 1–3 Bcf/d regionally, they are more likely to reduce summer troughs and increase non-winter baseload rather than eliminate winter peaks (EIA load data, 2020–2025). The combination of steady data-center demand and flexible LNG exports creates new volatility vectors for basis spreads.

Q: How should investors think about LNG versus domestic power exposure? A: Investors should consider exposure to LNG and domestic power as complementary but distinct risk pools. LNG links a producer to global pricing dynamics and geopolitical risk, while domestic power exposure ties returns to local utility structures, grid constraints, and corporate procurement trends. Historically, companies with diversified offtake—both export and domestic contracted sales—have exhibited lower cashflow volatility than pure-play export-exposed firms (Bloomberg sector analysis, 2024–25). Active monitoring of contract tenors and counterparty credit quality is crucial.

Bottom Line

Toby Rice’s remarks at CERAWeek on Mar 23, 2026 crystallize a longer-term shift: data centers and LNG expansion are co-evolving to materially influence natural gas flows, pricing dynamics, and infrastructure priorities. Investors should prioritize localized optionality and contract quality over macro-only commodity calls.

Disclaimer: This article is for informational purposes only and does not constitute investment advice.