Infrastructure – Matterhorn Express Pipeline has started flowing gas into pipelines near Katy, marking start-up of activity from the new 2.5 Bcf/d pipeline. Waha prices jumped this week as new egress opened from the Permian Basin.
Matterhorn began moving gas Tuesday (October 1) on new interconnects with the Transcontinental (Transco) and Texas Eastern Transmission (TETCO) systems in southeastern Texas. Matterhorn delivered 180 MMcf/d at Transco’s Clarks Branch receipt point in Wharton County, and 137 MMcf/d at TETCO’s Hillboldt Road interconnect in Austin County, according to nominations on pipeline bulletin boards. Natural Gas Pipeline of America (NGPL) has also added a Matterhorn receipt point near Katy but is not yet flowing gas.
Led by WhiteWater Midstream, the new 42-inch pipeline runs ~580 miles from the Waha hub to Katy, outside Houston. Waha prices jumped 34c on Tuesday to $0.45/MMBtu, and increased to $0.62 Wednesday on the bullish news. Permian gas prices have frequently traded negative since August as egress pipelines filled and Kinder Morgan (KMI) conducted extended maintenance work on the El Paso system.
East Daley expects oil and gas supply growth to pick up in the Permian following the start of Matterhorn. Permian gas production is on pace to grow 1.6 Bcf/d in 2024 (exit-to-exit), and oil production grows 150 Mb/d to 6.25 MMb/d by YE24, according to our latest supply forecasts in Energy Data Studio (see figure). Major Permian producers like Chevron (CVX), ExxonMobil (XOM), Matador Resources (MTDR) and Vital also have projected production growth into 4Q24.
Flows – Haynesville operators are sitting on ~1.2 Bcf/d of unused production from choked or delayed wells, according to our analysis of the ArkLaTex Basin production model. The latent supply gives us confidence in a more bullish 2025 outlook for G&P assets in the basin.
We estimate the 1.2 Bcf/d of spare production capacity based on a trend we’ve observed in the monthly basin forecast in our Production Scenario Tools, whereby gas delivery has consistently underperformed our model for East Texas and Louisiana.
Since January 2023, Haynesville producers have cut rig counts roughly in half, from a peak of 91 rigs in March ‘23 to a low of 41 in July ‘24. Today rigs sit at 44. Yet even with these steep cuts, Haynesville production has fallen much more sharply than rig counts alone would indicate in our basin model. This wedge of ‘unseen’ gas supply includes wells that operators have choked back, delayed turned-in-line wells (TILs), plus a growing DUC inventory as operators slow completion work.
We’ve observed this same trend in the Northeast, where Marcellus and Utica producers curtailed supply in the spring. In a recent interview with Hart, EQT CEO Toby Rice said the producer plans to restart wells in October and November when demand picks up.
In the Haynesville and Northeast, this ‘ready’ production can come online more quickly than rig-driven supply and will help producers rapidly respond to higher prices. Haynesville producers are particularly well-positioned to meet expected LNG demand growth this winter and through spring 2025 from the start-up of Plaquemines LNG and the Corpus Christi Phase 3 expansion.
G&P assets in the Haynesville have seen a weaker performance in 2024 given low prices and underwhelming supply. In the monthly Macro Supply & Demand Forecast, we forecast prices will rise above $3/MMBtu this winter, spurring a resurgence of ArkLaTex production. This outlook for improved performance is also reflected in East Daley’s Financial Blueprints for Haynesville G&P asset owners (see figure for EBITDA from ArkLaTex G&P assets, courtesy of Energy Data Studio)
As shown in the figure, East Daley forecasts higher earnings in 1Q and 2Q25 for many Haynesville G&P systems, including owners Energy Transfer (ET), Williams (WMB), and DT Midstream (DTM). Assuming new LNG projects start as planned, the latent Haynesville capacity gives us confidence that supply can respond rapidly and benefit these companies.
Storage – Traders and analysts expect the Energy Information Administration (EIA) to report a 56 Bcf injection into working gas for the week ending September 27. The past two weekly surveys have been in this range, reported at 58 and 55 Bcf, respectively. Inventories would effectively end September at 3,548, in line with East Daley’s expectation in the monthly Macro Supply & Demand Forecast.
Lingering hot weather is keeping generation demand strong in many regions and cutting into the injection pace. A 56 Bcf injection would decrease the surplus to the 5-year average by 42 Bcf to 177 Bcf, the first time the surplus has been under 200 Bcf since the week ending January 26, 2024. The surplus to last year would fall by 31 Bcf to just 128 Bcf.
Markets have responded to the falling surplus. The prompt-month November contract has increased 16% in two weeks, rising from $2.50/MMBtu on September 19 to trade at $2.90 on Tuesday. Henry cash prices have also increased to ~$2.65 from an average of $2.26 for the week ending September 20. We forecast Henry Hub cash prices to average $2.88/MMBtu in November.
Rigs – The US rig count decreased by 2 for the September 21 week, standing at 568. Basins losing rigs include the ArkLaTex (-2), Bakken (-1), Eagle Ford (-1) and Marcellus NE-PA (-1). The Anadarko (+2), Marcellus+Utica (+2) and Permian (+1) saw rig additions.
On the midstream side, Targa Resources (TRGP) is down 6 rigs total on its Permian and Eagle Ford systems. Several Exxon rigs on TRGP’s West Texas appear to be moving, and the Permian count should recover next week. Energy Transfer (ET) is up 5 rigs with additions on its Permian, Eagle Ford and ArkLaTex systems.  
East Daley’s weekly Midstream Activity Tracker monitors rig activity by basin and by gathering and processing (G&P) system to better understand midstream impacts. We allocate rigs and monitor flows through 150+ public and privately owned G&P systems in every North American basin. Reach out for more information on the Midstream Activity Tracker.
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