Some 3.2 Bcf/d of new LNG export capacity will be coming online along Texas’s Gulf Coast over the next two and a half years, and 8 Bcf/d of new natural gas pipeline capacity is under development to transport vast quantities of gas through Texas to the Mexican border. But while gas-export opportunities abound, Texas gas production is down, mostly due to a big fall-off in Eagle Ford output, so exporters will need to pull gas from as far away as the Marcellus/Utica to meet their fast-growing requirements. That will flip Texas from a net producing region to a net demand region once when you factor in exports that will flow through the state. This profound shift will put extraordinary pressure on Texas’s unusually complex network of interstate and intrastate pipeline systems, which will need to be reworked and expanded to deal with the new gas-flow patterns. It also will have a significant effect on regional gas pricing––putting a premium on Texas prices. These issues and more are addressed in RBN’s latest Drill Down Report, highlights of which we discuss in today’s blog.
One thing that U.S. natural gas producers have to be thankful for this week––and likely for many years into the future ––are the prospects for growing foreign demand for U.S. gas supplies. The potential for piping additional billions of cubic feet a day of Texas, Marcellus/Utica and other gas to Mexico and shipping increasing volumes of super-cooled gas as LNG to South America, Europe, and Asia is good news for gas producers, who need new demand sources to gobble up their product… well, enough Thanksgiving and turkey references––you get the idea.
The third part of RBN’s series of Drill Down reports on how fast-rising natural gas exports are transforming U.S. energy markets focuses on two things: 1) the existing and planned infrastructure needed to move several billion cubic feet of gas a day south/southwest through “Miles and Miles of Texas” to coastal LNG export terminals and to the U.S.-Mexico border; and 2) the changing market dynamics that are quickly morphing Texas from a major gas supplier to the rest of the U.S. to a state that needs gas from outside its borders to meet its needs plus the demands of export markets. These new dynamics have the potential to change everything, including the relationships between the prices paid for natural gas in Texas and elsewhere in the U.S.
The geographic focus of Part 3 of the “Miles and Miles of Texas” series is the state’s Gulf Coast Industrial Corridor, a 50-mile wide swath of coastline running 450 miles from the Rio Grande in the south to the Sabine River at the Louisiana state line. If this strip of coastal land were a separate state, it would be the largest natural gas consuming state in the nation, with 6 Bcf/d of demand––slightly more than California. And that does not include another 3.3 Bcf/d of gas exports to Mexico that flows through the industrial corridor. By the summer of 2019, 3.2 Bcf/d of all-new LNG export capacity along the Texas coast will be online and six new pipeline projects with the capacity to deliver another 8 Bcf/d to Mexico will be ready to roll. Even if, as we expect, only about 6 Bcf/d of that new export capacity gets used, gas flows to and through the Gulf Coast Industrial Corridor will rise to an astronomical 15 Bcf/d, which is equivalent to about 25% of total U.S. summer-season demand.
You might wonder, where is the gas going to come from? How is it going to find its way down the Texas coast to LNG export terminals and the Agua Dulce gas hub (near Corpus Christi), which has emerged as a key starting-off point for new gas pipelines to Mexico? And with the up-ending of traditional gas flows in Texas, what’s going to happen to Texas natural gas prices?
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