The trajectory of U.S. natural gas production is increasingly dictated not by dedicated gas-focused drilling, but by the relentless economics of crude oil. The latest EIA data, released on November 21, 2025, underscores this reality, showing a 6% increase in U.S.-associated natural gas production in 2024. This growth, which saw output climb to an average of 18.5 billion cubic feet per day (Bcf/d), is a direct mirror of the uptick in oil-directed activity, confirming that for major producing basins, the gas stream is now a powerful, though secondary, strategic output.
For oil and gas professionals navigating the volatile energy landscape, understanding the dynamics of associated gas is no longer a peripheral detail—it is central to midstream infrastructure planning, price forecasting, and the strategic positioning of upstream assets. The continued expansion of this ‘co-produced’ resource is fundamentally altering the supply stack for both pipeline-ready methane and the valuable suite of Natural Gas Plant Liquids (NGPLs) that accompany it.
The Permian’s Dual Mandate
The lion’s share of this production increase originates, unsurprisingly, from the Permian Basin, spanning western Texas and southeastern New Mexico. In 2024, the Permian produced 12.5 Bcf/d of associated gas, an 8% year-over-year increase. This surge was firmly anchored by a favorable crude oil price environment, with West Texas Intermediate (WTI) averaging approximately $77 per barrel (b). Such pricing incentivized oil-directed drilling, leading to a 377,000 barrel per day (b/d) increase in Permian crude oil production—and the concomitant rise in associated gas.
While the Permian is the volume leader, the proportional dependence on associated gas varies across the major crude oil plays. Basins like the Bakken, for instance, sourced the largest share of their total gas output—a remarkable 67%—from associated gas wells, producing 2.3 Bcf/d. The Eagle Ford contributed another 1.8 Bcf/d. Across the five key producing regions—the Permian, Bakken, Eagle Ford, Anadarko, and Niobrara—associated gas has consistently accounted for 37% of the total natural gas volumes in both 2023 and 2024. This trend underscores a critical operational reality: the volume of natural gas captured from these crude oil regions is overwhelmingly governed by decisions rooted in the global crude market, not local natural gas demand. Consequently, any significant market disruption to crude prices can trigger a corresponding, and often lagged, contraction in gas supply from these areas, creating inherent volatility for gas buyers and midstream operators alike.
Decoding the Difference: Associated Gas vs. Dry Gas
To truly grasp the logistical and economic implications of this surge, industry readers must draw a clear distinction between associated gas and non-associated, or “dry,” natural gas. While both ultimately yield marketable methane, their origins, compositions, and processing requirements are vastly different, driving distinct investment needs for gathering and treating infrastructure.
Associated Natural Gas, also known as wet gas, is defined by its symbiotic relationship with crude oil. It is natural gas produced from wells where the primary target, by volume or economic intent, is oil. The U.S. Energy Information Administration (EIA) generally classifies these as wells with a low Gas-to-Oil Ratio (GOR), typically $\text{less than or equal to } 6.0 \text{ thousand cubic feet of natural gas per barrel of oil produced } (\text{Mcf/b})$. This gas is referred to as ‘wet’ because its composition is rich in heavier hydrocarbon molecules beyond simple methane (CH4). This includes valuable NGPLs such as ethane, propane, butane, and natural gasoline.
The key operational challenge for associated gas lies in this composition. Before the gas can be transported via sales pipelines, these liquids must be separated. This requires extensive gas processing and fractionation facilities—cryogenic or absorption plants—that strip the NGPLs from the gas stream. This complexity demands significant capital investment in midstream assets, but it is also the source of tremendous value, with record ethane production in 2024 directly fueling the petrochemical, plastics, and fibers industries. For the operator, managing the logistics of gathering, treating, and moving both the residue gas and the diverse NGPL products adds layers of complexity that are absent in dry gas production.
In sharp contrast, Dry Gas, or non-associated natural gas, is the result of drilling operations specifically targeting gas reservoirs that contain minimal or no crude oil or condensate. These wells are characterized by a high GOR, typically $\text{greater than } 6.0 \text{ Mcf/b}$. The gas stream from these wells is predominantly methane—sometimes exceeding 95%—and contains few, if any, heavier NGPLs. Processing for dry gas is far less complex, usually limited to simple dehydration and compression before it enters the high-pressure transmission pipeline network.
The production of dry gas in dedicated fields, such as the Marcellus or Haynesville, responds directly to gas market signals. Associated gas production, however, remains a byproduct, tethered to the profitability of crude oil. As long as the market encourages oil-directed drilling, the flood of associated wet gas will continue to challenge and shape midstream logistics, ensuring that the necessary infrastructure to capture, process, and fractionate this resource remains a priority for the industry’s investment thesis. The future reliability of U.S. natural gas supply is now inextricably linked to the operational efficiency of oil wells.
