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With 7 Bcf/d of LNG capacity coming, industry not sure where gas will come from

U.S. LNG export capacity is set to surge to more than 9 Bcf/d by the end of 2019. What is not clear is where all that natural gas might come from.

Observers generally agree that drillers will be able to meet what amounts to a 10% increase in U.S. gas demand. But which shale plays will benefit most appears to be a roll of the dice on which pipelines are permitted and built.

Cheniere Energy Inc., which operates the only operational LNG export terminal in the Lower 48, has served as a case study in just how far gas for export on the Gulf Coast could come from, announcing in February that it was preparing to receive supplies from Canada's Montney play. The U.S. LNG export pioneer already considers itself the largest physical gas consumer in the country, often pulling more than 2 Bcf/d on pipelines leading to its Sabine Pass facility in Louisiana.

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RBN Energy Managing Director Rick Smead said a significant portion of the gas shipped to liquefaction terminals will come from the Marcellus and Utica shale plays in the Appalachian Basin, even though four of the six LNG export projects are located along the U.S. Gulf Coast. That will largely depend on pipeline buildout linking the Northeast to the Gulf Coast, such as the 1.5 million-Dth/d Leach Xpress and connected Rayne Xpress, which are expected to come online before the end of the year. Pipelines including Spectra Energy Corp's Texas Eastern Transmission LP, which used to run from the Gulf Coast to the Northeast, are upgrading their systems to allow them to flow gas in the reverse direction.

Luke Jackson, senior energy analyst at S&P Global Platts Analytics, sees the Northeast adding 7 Bcf/d of gas from 2016 levels by 2022. "That is definitely short of the additional LNG demand," he said. Jackson thinks there is still significant risk to pipeline projects out of the Marcellus and Utica, making his forecast more conservative.

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But gas for the Gulf Coast LNG projects can be sourced closer to home. Oklahoma's SCOOP and STACK plays should see demand from the growing LNG export market, Smead said. Cheniere is already betting on sourcing gas from the sister plays, launching in May an application for its 1.44 Bcf/d Midship pipeline project that would help secure gas for its Sabine Pass and Corpus Christi LNG terminals.

Another wild card is associated gas from oil drilling in the Permian, Jackson said. "We've seen substantial gas growth out of the region so far this year," he said. "But, getting incremental gas to Gulf Coast markets is contingent upon new pipelines, which have been proposed, yet would likely not begin service until 2019 at the earliest."

The Texas basins will likely become bigger players for LNG export demand in what is often called the "next wave" of U.S. LNG export projects, which would enter service alongside new pipeline projects that will connect the Gulf to the Permian, said Cameron Chandler, who heads Chandler Energy Resources LLC, a Dallas-based consulting firm that specializes in sourcing U.S. gas for export. While a handful of those LNG projects, which would enter service in the early 2020s, have all major regulatory permits, they have yet to receive final investment decisions while buyers express an unwillingness to sign long-term contracts amid a global glut.

While the U.S. waits for pipelines to the Gulf Coast from the Northeast and West Texas, the industry will likely rely "pretty heavily" on Louisiana's Haynesville Shale to meet new demand for LNG exports, said Jackson. The Haynesville's contribution could grow if technological improvements reduce break-even costs, Smead pointed out, though LNG exports will compete in the Southeast with demand for gas for industrial use and power generation.

S&P Global Platts and S&P Global Market Intelligence are owned by S&P Global Inc.