On August 17, a consortium led by WhiteWater Midstream reached a final investment decision on the Solitude Pipeline System out of the Permian Basin. This project will move 4.5 billion cubic feet per day of natural gas from West Texas to Katy. During that same week, Baker Hughes data indicated the number of domestic frac crews dropped by nine in a single week. The national active drilling rig count fell by five to 588. Exploration and production companies are committing billions of dollars to build pipeline infrastructure for the next decade. At the same time, they are halting current completion activity to avoid selling gas into a depressed spot market.
Operators in the Permian Basin produce large volumes of :associated gas from wells drilled primarily for crude oil. Because they cannot stop the gas from coming out of the ground along with the oil, they need a place to put it. Limited pipe capacity frequently traps this gas in West Texas. Waha gas for September delivery averages $1.590 per thousand cubic feet.
This low price is an improvement over the negative pricing events common in the basin. When local production exceeds the available pipe space, producers run out of options. State regulations limit the amount of gas a producer can flare into the atmosphere. If a producer cannot flare the gas and cannot pipe it out, they must shut in the oil well. To keep the oil flowing, operators will pay buyers to take the gas away. This leads to negative natural gas prices at the West Texas hubs. The financial risk of shut-in oil wells pushes operators to sign binding, decade-long transportation agreements on new infrastructure projects.
The Blackcomb Pipeline will enter service later this year and send 2.5 billion cubic feet per day to the Agua Dulce hub in South Texas. Kinder Morgan expanded its Gulf Coast Express pipeline by 0.57 billion cubic feet per day. That expansion increases the system’s total capacity to 2.6 billion cubic feet per day. Energy Transfer operates the Hugh Brinson Pipeline to move 2.2 billion cubic feet per day toward Northeast Texas. The planned Traverse Pipeline will provide another 2.4 billion cubic feet per day from Agua Dulce to Katy by 2027.
The second wave of infrastructure
The capacity of the projects scheduled for 2028 and beyond exceeds the near-term additions. The Eiger Express pipeline will move 3.7 billion cubic feet per day through a 48-inch diameter line to Katy. The Matterhorn joint venture owns 70 percent of the project. ONEOK and MPLX hold 15 percent each. Eiger Express will initiate service in mid-2028 with 2.5 billion cubic feet per day of capacity and add the remaining 1.2 billion cubic feet per day in mid-2029.
Energy Transfer is advancing the Desert Southwest Project as an expansion of its Transwestern Pipeline system. This expansion will increase westbound capacity out of the Permian from 3.2 billion cubic feet per day up to 5.5 billion cubic feet per day by the fourth quarter of 2029. The 516-mile pipeline stretches from West Texas to the Phoenix area.
When fully operational in 2030, the Solitude Pipeline System will consist of two parallel 48-inch pipelines. Each will transport 2.25 billion cubic feet per day. WhiteWater owns 50 percent of the system. Devon Energy holds 25 percent, MPLX holds 10 percent, and Diamondback Energy and Western Midstream Partners each hold 7.5 percent. The first pipe will flow gas in late 2029. The second follows a year later. The Arrow Model report released on August 13 projected that the Permian Basin would need about two billion cubic feet per day of new :takeaway capacity by 2033. Solitude offers more than double that projected capacity three years ahead of schedule. This new capacity scheduled for the next six years will alter the physical flow of the domestic gas market.
The destination for Texas production
Operators are financing this infrastructure because they anticipate demand from liquefaction terminals along the Texas Gulf Coast. Natural gas pipeline operators make their money by securing long-term commitments from producers. A producer signs a decade-long shipping contract only when they know a buyer waits at the end of the line.
Cheniere Energy took a final investment decision on Midscale Trains 8 and 9 at Corpus Christi in 2025. The company filed its federal application in February for Corpus Christi Stage 4, a proposed expansion that adds 3.2 billion cubic feet per day of capacity across four trains. Sempra is advancing Port Arthur LNG Phase 2, which will add Trains 3 and 4 in 2030 and 2031. When mineral owners hear that record Texas gas production is here, they should trace the gas to the coast. Production flows to Katy and Agua Dulce to feed the chilling units that load ships bound for foreign buyers.
Europe competes for the same molecules
The pricing dynamics in Europe influence the viability of the Texas infrastructure buildout. European buyers compete directly with Asian buyers for spot market cargoes of liquefied natural gas. This competition dictates how much buyers are willing to pay at the Texas terminal gates.
Goldman Sachs estimated that Dutch Title Transfer Facility prices must move above €100/MWh by December 2026 to incentivize buyers to fill regional storage for the winter. The bank maintains a base case of 50 euros per megawatt hour. The 100-euro threshold represents a 110 percent increase over this base case. Prices in late August sit near 66.85 euros, or $78 per megawatt hour. European storage facilities are 62 percent full, which is the lowest level for this time of year in 17 years. The continent relies on a steady flow of imported liquefied natural gas to replace the pipeline supply it previously imported from Russia.
The global market for natural gas operates on ocean freight. Ships loaded with liquefied gas do not have fixed destinations. Cargo owners direct the ships in transit toward the continent offering the highest price. If Asian buyers bid the spot price up, the ships sail toward the Pacific. If European energy providers need to fill their storage caverns before winter, they must outbid the Asian markets. The companies building the Solitude and Eiger Express pipelines expect this global bidding war to sustain demand for their transportation services throughout the 2030s. Demand in Europe creates a direct pull on the pipeline network in Texas.
Appalachian drilling stays in a holding pattern
Companies operating in the Marcellus and Utica basins face different economics compared to Texas operators. The Northeast produces dry gas. When gas prices drop, Appalachian operators cannot rely on crude oil revenue to subsidize their drilling costs. Their response is to stop spending money on well completions until the market recovers.
The rig count in the Marcellus and Utica region held at 35 for the third consecutive week in late August. Pennsylvania maintains 16 active rigs, Ohio has 10, and West Virginia has nine. The Haynesville shale in Louisiana and East Texas lost two active rigs. A parked rig means the operator is not currently drilling new holes.
The drop in national frac crews indicates operators are refusing to complete the wells they have already drilled. A frac crew pumps the sand and water required to stimulate the rock. Without this stimulation, the well does not produce gas. By dropping completion crews, companies keep their proven reserves trapped in the rock rather than selling the production at current low prices.
Operators secure locations without spending on crews
Stopping completion activity does not mean the companies are walking away from their acreage. Operators use this period to process paperwork and secure legal rights for future development.
The state regulatory agencies in Pennsylvania, Ohio, and West Virginia received 27 new drilling permits between August 10 and August 16. This volume increased sharply from the eight permits issued two weeks prior. Ohio issued 16 permits, West Virginia issued seven, and Pennsylvania issued four.
EOG Resources secured eight of the new permits, and Antero Resources acquired six. Ascent Resources obtained five, while Expand Energy claimed four. Jay-Bee Oil & Gas, LOLA Energy, Range Resources, and Seneca Resources received one permit each. An approved permit allows the operator to move a rig onto the pad when the economics improve.
Obtaining the permit requires the operator to survey the land, file unit declarations, and finalize the leasing arrangements. Landmen run title searches at the county courthouse to confirm mineral ownership. Attorneys draft the title opinions, and the regulatory team demonstrates to the state that the proposed wellbore meets all legal spacing requirements from existing producing wells. Companies spend this administrative capital today so they can act quickly when commodity prices rise. By finishing the engineering, legal, and regulatory work early, the operator only needs to contact a drilling contractor to begin operations.
What this means for your paperwork
Mineral owners should interpret these industry movements by reviewing their own documents. If you own interest in a Texas unit, this pipeline buildout will eventually appear as line items on your check stub. Operating companies pay a tariff to move their gas on the Blackcomb, Eiger Express, and Solitude systems. They often attempt to pass those transportation costs down to the royalty owner. Companies regularly deduct pipeline deficiency fees from your royalty before cutting the check.
If you negotiated a lease that prohibits post-production deductions, audit your statements to ensure compliance. The exact wording of your lease determines whether the operator can charge you for gathering and transportation expenses. A minor drafting error can erase your cost-free royalty and leave you paying a percentage of the costs for a new pipeline to Katy.
If you own minerals in Pennsylvania, Ohio, or West Virginia, the stagnant rig count means you should not expect sudden production spikes this fall. Your check will reflect the lower prices and the natural decline of your existing wells. The surge in state permitting activity indicates a need to monitor the regulatory maps. If an operator files a permit that includes your tract, they intend to drill eventually. You can track this activity on the state oil and gas department websites, which list the unit shapes and the approved surface locations. Because a permit is a matter of public record, you can see the total acreage allocated to the unit and calculate your exact decimal interest before the well is drilled. Understanding your decimal interest allows you to verify the division order when the operator mails it to you.
Interpreting the market indicators
The 4.5 billion cubic feet per day of capacity coming from the Solitude pipeline does not guarantee an increase in Permian gas prices in 2030. Pipeline infrastructure frequently runs below maximum capacity during its initial years of service. A pipe capable of moving billions of cubic feet sets a ceiling on constraints rather than establishing a floor on pricing.
The drop in the active rig count does not indicate a collapse of the domestic energy sector. Producing companies are operating with high discipline in 2026 and refusing to oversupply the spot market. Holding gas in the ground is a calculated financial decision rather than a sign of operational failure. When European demand pulls storage levels low enough and the Texas Gulf Coast liquefaction terminals require feed gas, the operators will deploy the frac crews to turn the wells in line. Operators will wait until the infrastructure is ready to consume the supply.
We can review your specific property to determine how these market shifts affect its value. Request a free mineral rights valuation and our team will walk you through the math on your acreage.
:associated-gas
Natural gas produced as a byproduct of drilling a well that primarily targets crude oil. The operator pumps the oil for revenue but must safely capture, transport, or flare the gas that comes up the pipe with it.
:takeaway-capacity
The maximum volume of oil or natural gas that pipelines can transport out of a specific producing region to a market hub. When local production exceeds this limit, prices in the region crash because the excess gas has nowhere to go.