ENMG Analysis
Permian gas pipeline access is becoming increasingly important to the economics of producing oil in West Texas. Permian Resources’ third-quarter results offer a useful example: Some wells curtailed when regional natural gas prices turned negative returned to production after additional firm transportation agreements took effect.
The Midland-based company reported average third-quarter natural gas production of 787.1 million cubic feet per day, a 42% increase from the second quarter. Natural gas liquids production increased 37% to 118,312 barrels per day, while crude oil production rose 5% to 208,029 barrels per day.
Permian Resources said natural gas and liquids volumes benefited from putting high gas-to-oil-ratio wells back online after curtailing them during the second quarter because of negative regional gas prices. A high gas-to-oil ratio means a well produces comparatively more natural gas for each barrel of crude oil.
Those figures come from the company’s third-quarter earnings release. They do not show how much of the production increase came specifically from restarted wells. Acquisitions, well activity, operating performance, and other changes could also affect quarter-to-quarter volumes.
Why Can Waha Gas Prices Turn Negative?
The Permian Basin produces substantial volumes of associated natural gas alongside crude oil. Because the wells are often developed primarily for their oil, regional gas production can continue growing even when gas prices are weak.
The Waha natural gas hub in West Texas reflects the balance between Permian supply, local demand, and the pipeline capacity available to move gas out of the basin. The U.S. Energy Information Administration says Permian production has at times grown faster than takeaway capacity, causing Waha prices to trade below other hubs and occasionally fall below zero. U.S. Energy Information Administration (EIA)
A negative price means a seller may effectively have to pay another party to accept the gas. That does not automatically force every producer to shut down. A company may continue operating if oil and natural gas liquids revenue supports the overall economics and if it has a lawful, operational outlet for the gas.
However, wells that produce comparatively large amounts of gas can become less attractive when the local gas price is deeply negative. Curtailing those wells can preserve value until prices improve or another transportation route becomes available.
That appears to be part of what happened at Permian Resources. The company said it curtailed high gas-to-oil-ratio wells during the second quarter and returned them to production during the third quarter. The disclosure supports a connection between regional gas conditions and operating decisions, but it does not establish a universal price at which the company will curtail or restart a well.
What Firm Transportation Changes
Permian Resources also reported that additional firm transportation agreements took effect during the quarter, increasing the amount of its gas priced in Gulf Coast and Dallas-Fort Worth markets.
Firm transportation generally gives a shipper contractual rights to pipeline capacity with a higher service priority than interruptible transportation. The shipper typically pays applicable reservation and transportation charges under its contract and the pipeline’s tariff. The commercial value depends on the capacity reserved, the route, the fees, the difference between regional prices, and how consistently the shipper uses the service.
Firm service does not guarantee that gas will flow at the maximum contracted quantity every day. Physical deliveries depend on nominations, available supply, downstream demand, pipeline pressure, compression, maintenance, and operating conditions. ENMG recently examined this distinction in its coverage of two Texas gas pipeline expansions entering service.
Moving the pricing point away from Waha can reduce exposure to West Texas price weakness. It does not eliminate transportation costs, nor does it guarantee that another market will always offer a favorable price.
Permian Resources reported a third-quarter realized natural gas price of 74 cents per thousand cubic feet. That was the company’s realized price across its sales portfolio, not the quarterly spot price at Waha. Realized prices can reflect the locations where gas is sold and the commercial arrangements used to market it.
The company has not publicly disclosed in the earnings release how much firm capacity began service during the quarter, the specific pipelines involved, the associated transportation costs, or the physical destination of every volume.
Pricing Gas Elsewhere Is Not The Same As Exporting It
Permian Resources said more gas was priced in Gulf Coast and Dallas-Fort Worth markets. That statement should not be interpreted as proof that all those volumes physically traveled to those locations.
Natural gas contracts can use a regional hub as a pricing reference even when the physical delivery path is more complicated. Confirming where the gas went would require information about pipeline nominations, receipt and delivery points, contracts, and measured flows.
The Gulf Coast also contains power plants, refineries, petrochemical facilities, industrial customers, storage sites, local distribution systems, pipeline interconnections, and LNG terminals. Pricing gas in a Gulf Coast market does not establish that it became LNG feed gas or was exported.
ENMG’s analysis of U.S. LNG export growth explains why Permian supply is important to Gulf Coast export infrastructure. That broader relationship does not identify the final customer for Permian Resources’ third-quarter production.
The same caution applies to North Texas. Dallas-Fort Worth is a major population and commercial center with electricity-generation, industrial, and utility demand. A DFW pricing reference does not prove that every associated molecule was consumed within the metropolitan area.
More Texas Pipeline Capacity Is Coming
EIA expects Texas to account for more than 66% of planned U.S. natural gas pipeline-capacity additions originating in a state during 2026 and 2027. Its May outlook identified 29.7 billion cubic feet per day of planned capacity originating in Texas, including projects intended to relieve Permian constraints and move gas toward Gulf Coast, power-sector, industrial, residential, and export markets. U.S. Energy Information Administration (EIA)
Those numbers describe planned capacity across multiple projects. They should not be treated as current throughput or as transportation available to Permian Resources today. Some projects remain under construction, projected service dates can change, and a producer needs contractual access to benefit from a particular route.
New pipelines can also create additional market choices without guaranteeing uniformly higher prices. The effect depends on how quickly Permian production grows, the capacity contracted by producers and marketers, demand at the destination, pipeline utilization, and the timing of other infrastructure.
Storage can provide another form of flexibility. ENMG’s coverage of the Texas gas storage expansion targeting Gulf Coast deliverability explains why having enough gas over a month differs from being able to deliver it at the correct location on a particular day.
Pipeline transportation and storage solve related but different problems. Transportation connects supply with another market. Storage helps manage timing differences between supply and consumption. Neither substitutes for the other.
What The Results Mean For Texas
For Texas producers, access to more markets can reduce dependence on a single constrained hub. That can be especially valuable for companies producing associated gas from oil-focused wells because the gas must be handled even when crude oil is the primary economic product.
For pipeline companies, the results illustrate why producers may be willing to pay for firm service. Reserved capacity can protect access to downstream markets during periods when regional infrastructure is congested.
For Gulf Coast and North Texas buyers, additional supply routes can broaden purchasing options. That does not guarantee lower prices. Customer costs also reflect pipeline tariffs, storage, weather, local demand, contract terms, and infrastructure investment.
The third-quarter results likewise provide no basis for predicting lower household gas bills or diesel prices. Diesel is a refined petroleum product whose price depends on crude costs, refinery operations, product inventories, transportation, and global distillate markets. A producer moving more Permian natural gas to another pricing point does not establish a measurable diesel-price effect.
What To Watch Next
The next reporting step is to determine how much operational flexibility Permian Resources actually gained.
The company should clarify:
- How much firm transportation capacity entered service during the third quarter.
- Which pipelines and delivery points support the new agreements.
- How much gas is priced in Gulf Coast and Dallas-Fort Worth markets.
- How much of the production rebound came from restarted wells.
- What transportation costs and contractual commitments accompany that access.
- Whether the restarted wells remain online during the next period of negative Waha prices.
The third-quarter numbers show that previously curtailed wells returned to production as the company expanded its access to other pricing markets. They do not yet quantify how much the transportation agreements contributed to that decision.
The more revealing test will come when West Texas prices weaken again. If the wells remain online, and if Permian Resources can demonstrate that its transportation portfolio protected their economics, that would provide stronger evidence of what pipeline access is worth than one quarter of higher production alone.
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