The conference’s opening session framed today’s energy landscape as a rapid shift from a decarbonization-first mindset toward a dual priority of decarbonization and energy security, accelerated by Russia’s invasion of Ukraine, with natural gas positioned to serve both goals as global energy demand continues to rise. The module connected growing global gas demand to a major buildout of LNG liquefaction capacity on the U.S. Gulf Coast. Then, using recent North American demand, supply and pricing history, we showed how regional production characteristics (dry gas vs. associated gas) and pipeline capacity or lack thereof are reflected in local price basis differentials versus Henry Hub.
North American natural gas demand has gone through three distinct phases since the start of the Shale Era, each defined by how new supply found markets. Early demand growth (2007-13) came from gas displacing Canadian supply, competing with coal in power, and ending a brief period of U.S. LNG imports. The next phase (2013-19) broadened as LNG exports surged, industrial projects added demand, coal retirements “locked in” gas in the power stack, and pipeline exports to Mexico expanded. The most recent phase (2019-25) was still fast-growing but dominated by LNG, with rising questions about gas’ environmental role, grid reliability, pipeline constraints in some regions, and, in 2025, a pullback in power-sector gas demand as higher prices allowed coal to regain share. Looking ahead, U.S. power load growth — in part from data centers — could drive incremental gas demand, but outcomes will vary by region depending on renewable buildout, coal’s role as a reliability buffer, pipeline capacity, and the mix/efficiency of gas generation technologies.
LNG has become the largest source of U.S. natural gas demand growth, with feedgas demand concentrated in Texas and Louisiana and rising further as other terminals start up. This module connects LNG destination flexibility and contracting structures to shifting global price signals and shipping constraints, then assesses full-cycle and marginal economics for U.S. LNG into Europe and Asia. Even with concerns about global LNG oversupply later in the decade, development momentum remains strong, and growing LNG feedgas demand is already tightening U.S. gas balances and increasing strain on Gulf Coast pipeline infrastructure and pricing.
The fireside chat between RBN President and CEO David Braziel and energy policy expert Tala Goudarzi focused on LNG export policy, global demand dynamics and grid reliability. Goudarzi drew on her experience across industry and government — including time leading parts of the U.S. Department of Energy’s fossil energy portfolio — to argue that policy choices have consequences and that energy policy shouldn’t be overpoliticized, particularly when it comes to permitting, investment and energy security.
When it comes to the rapidly growing — and heavily hyped — story of U.S. data center power demand, the biggest challenge is separating real projects from press releases, aligning inconsistent units of measurement (gas vs. power), and understanding whether power will come from behind-the-meter gas generation or from the grid. Using a series of unit conversions and top-down scenarios for 2026-30, the module concluded that even aggressive data-center growth is unlikely to materially change the overall U.S. natural gas balance over the next five years — especially compared with LNG exports — though local impacts could be significant.
Dan Brouillette, former Secretary of Energy during the first Trump administration, argued in his keynote address that natural gas has shifted from a regional commodity to strategic infrastructure as U.S. LNG exports and global interdependence expand. Brouillette emphasized that the core challenge is no longer resource availability or demand, but execution — infrastructure buildout, permitting certainty, and integration into global markets and power grids. In a closing Q&A, Brouillette discussed the need to rebalance energy policy beyond a single environmental lens, warned that revoking permits after issuance creates damaging uncertainty for capital, and predicted that despite AI-driven efficiency, total energy use will still increase.
RBN’s North American gas supply outlook is examined in the context of rising demand from LNG exports and new data centers. The module clarifies how production is measured, what “shrinkage” is and why it varies by basin, and why gas- and oil-directed drilling both matter for future gas supply. The session emphasized that meeting LNG-driven demand in the 2030s will require contributions from both associated gas (driven by crude and liquids economics) and dry gas basins (more price-sensitive), plus sufficient infrastructure and drilling inventory.
U.S. associated gas supply could evolve in many ways based on a set of case studies using Novi’s machine-learning rock-quality tiers and operator drill-out modeling. The module contrasted recent oil and gas production responses across the Permian and other basins, noting that Permian gas growth has been more resilient than oil growth during recent price weakness. Across modeled scenarios, there is a clear path to significant new U.S. Gulf Coast associated gas by 2035 — even with oil in a rangebound price environment.
The biggest U.S. gas-market questions ultimately hinge on remaining drilling inventory and how that translates into production at different gas prices. Using well-by-well spatial inventory work from Novi Labs, the module compared the five-year outlook for the two major dry-gas basins: the Haynesville and Appalachia. The core message was that Haynesville growth is being overestimated because declines are set to steepen and well productivity has deteriorated, meaning that sustained growth likely requires unprecedented activity and higher prices. By contrast, Appalachia may be underestimated, as spare and incremental takeaway improvements plus in-basin demand growth could support stronger production growth, with certain operators positioned to gain share.
The session’s first panel discussion brought together perspectives on where U.S. natural gas supply growth is most likely to come from over the next five years and what could constrain it. Panelists emphasized that meeting that demand will depend as much on infrastructure and price signals as on resource availability. The discussion also covered inventory runway by basin, gas quality constraints (notably nitrogen for LNG), hedging philosophies, and the role of continuous operational and analytical improvements (including AI) in driving efficiency gains.
The U.S. and Canadian natural gas supply-demand outlook emphasized the tight linkage between the two markets via cross-border pipelines and the recent ramp-up of Canada’s first LNG export project. The outlook projects strong growth in demand plus net exports through 2030 — driven primarily by LNG feedgas and power generation — requiring substantial upstream and midstream buildout near the Gulf Coast. The module also tackled the topic of storage and noted that, despite rising demand and exports, U.S. working gas storage capacity has not grown since 2015, increasing the importance and value of storage (especially salt caverns) due to market volatility (“extrinsic” value) and seasonal price spreads (“intrinsic” value).
Recent major natural gas pipeline developments across North America are focused on five regions: Western Canada, the Marcellus/Utica, the Southeast, the Permian, and the Haynesville. The current buildout can be seen as a shift from early Shale Era “supply push” takeaway projects toward demand-corridor expansions driven by LNG exports, rising power demand and reliability needs. Across the regions, new long-haul takeaway and “last-mile” connectors are being built to link supply basins to Gulf Coast and Canadian LNG terminals and to fast-growing power markets, although not all announced projects are expected to be constructed. In this module, Mr. Copeland takes us through a detailed pipe-by-pipe explanation of each of the major development regions.
The second panel discussion brought together perspectives from an independent storage developer (Caliche), a federal regulator (FERC) and a major integrated pipeline operator (Kinder Morgan) to discuss how transportation and storage must expand to meet rising demand from LNG exports, industrial growth and data centers. Panelists emphasized that the U.S. has ample natural gas supply, but infrastructure — pipelines, storage and flexible services — must be built and financed to connect supply to new demand centers. The discussion highlighted the need for better gas-electric coordination, the role of storage in balancing variable loads, and the commercial and permitting realities that shape what gets built and when.
The closing module synthesized the main themes of GasCon 2026 — rising U.S. power demand, rapid LNG growth, and the need for major supply and midstream expansion — then focused on how those forces and their timing reshape flows, infrastructure needs and pricing across the Texas-Louisiana Gulf Coast. A central takeaway was differing outlook for Texas and Louisiana: Texas supply growth (especially Permian/Eagle Ford associated gas) is positioned to cover much of Texas LNG expansion, while Louisiana LNG growth outpaces in-state production, implying increased reliance on inbound gas and new pipeline capacity. The module concluded with basis and Henry Hub price observations, emphasizing heightened volatility risk amid tight balances, all against a backdrop of geopolitical uncertainty.
