Energy Transfer’s Hugh Brinson Pipeline has begun moving intrastate natural gas months ahead of the project’s full operational date, according to a new tariff filing with the Federal Energy Regulatory Commission.
Hugh Brinson Pipeline said intrastate flows began June 13, 2026, the same date its initial Section 311 tariff and Statement of Operating Conditions became effective. However, the filing also indicates that the entire system is not scheduled to be fully operational until March 1, 2027.
That distinction suggests Energy Transfer is placing Hugh Brinson into service in phases, providing incremental Permian gas takeaway before all of the project’s mainline, compression, lateral and interconnect facilities are complete.
The Hugh Brinson system will ultimately include roughly 400 miles of 42-inch pipeline running from the Waha area in West Texas to Maypearl, south of the Dallas–Fort Worth Metroplex. The project also includes a 42-mile, 36-inch lateral connecting the mainline to processing facilities in Martin and Midland counties and nine interconnects.
The route is designed to move Permian and Midland Basin gas east from Waha and provide access to East Texas, the Katy Hub and Gulf Coast demand markets, including LNG export facilities, power plants, storage assets and industrial customers.
Tariff Points to $0.465/MMBtu Maximum Rate
Hugh Brinson is seeking approval for a maximum firm transportation rate consisting of:
- A $0.415/MMBtu daily demand charge
- A $0.05/MMBtu commodity charge
- Fuel retention of up to 1.81%
Those are ceiling rates rather than necessarily the actual rates paid by contracted customers. The tariff allows Hugh Brinson to negotiate rates between zero and the maximum, with the specific economics, capacity commitments, receipt points, delivery points and contract terms documented in individual shipper agreements.
Seven Shippers Commit 1.48 Bcf/d
The filing also provides the first look at the project’s commercial support. Hugh Brinson has firm transportation agreements with seven large customers. During the first year of full operations, those contracts subscribe up to 1.48 million MMBtu/d of transportation capacity, or approximately 1.48 Bcf/d depending on the heating value of the gas.
The identities of the shippers and their individual contract terms remain confidential. Hugh Brinson said the agreements were negotiated separately and reflect each customer’s specific needs. It appears Matador Resources (MTDR) has contracted 0.5 Bcf/d on the pipeline based on recent disclosures. Using Market Data in Energy Data Studio, EDA will update other known shippers and contractual information once the data is available
One of the seven contracts does not begin until April 2029, meaning the full 1.48 Bcf/d of contracted capacity may not be effective when the entire pipeline enters service in March 2027. The start of intrastate flows on June 13 provides another incremental outlet for Permian gas at a time when Waha has remained constrained despite recent pipeline expansions.
However, the filing does not disclose how much gas Hugh Brinson is currently moving or which portions of the system are operational. The June service date therefore should not be interpreted as the full 1.48 Bcf/d of contracted capacity becoming available immediately.
Instead, the filing points to a gradual ramp:
- Intrastate service began June 13, 2026.
- The entire system is scheduled to be operational March 1, 2027.
- At least one shipper contract does not begin until April 2029.
The near-term impact on Waha will depend on how quickly Energy Transfer completes the remaining facilities and how much contracted capacity shippers use during the phased startup. Once fully operational, Hugh Brinson should improve the Permian’s access to Central and East Texas and provide additional optionality into Gulf Coast demand markets. But the tariff filing suggests the project’s full impact on regional gas balances will build over several quarters rather than arrive all at once. – Rob Wilson, CFA Tickers: ET, MTDR, Waha
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Reading the Signals: Staying Ahead of Gas, Crude & NGL Markets Through Year-End
Volatility is defining today’s energy markets, and East Daley’s July webinar will help you make sense of what’s next.
Prices are the signal producers can’t ignore. Natural gas prices remain under pressure while crude oil markets continue to react to geopolitical tensions in the Middle East. When realized prices compress, producers respond: deferring completions, high-grading acreage, and re-underwriting economics in real time. The question isn’t whether producers are adapting, it’s how fast, and where the next pressure point emerges.
Infrastructure is the other half of the equation. In the NGL market, rising Waha gas prices, driven by new pipeline capacity, are eroding the cost advantage that’s long favored ethane rejection. In the Permian, the math is even more binding: how much longer can oil and associated gas production keep growing as crude takeaway capacity tightens? Infrastructure doesn’t just move barrels. It sets the ceiling on what producers can economically bring to market.
And none of this happens in isolation. Gas, crude, and NGLs are structurally linked through associated production, processing economics, and shared basin infrastructure. A shift in one commodity’s price or takeaway capacity ripples through the others, which means forecasting any single molecule in a vacuum gets you the wrong answer.
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