The Northeast, rapidly moving from natural gas importer to nationwide supplier, has become a hub of activity for pipeline operators as they rapidly reconfigure, expand and build systems to transport the region's excess capacity elsewhere.
The natural gas world, as the United States long knew it, basically has been turned upside down because of the plump Appalachian Basin. BNP Paribas analyst Teri Viswanath, who directs the firm's natural gas strategy, discussed the overhaul at the Genscape Inc. Oil & Gas Symposium in Houston earlier this month and offered NGI's Shale Daily more insight on the sidelines of the conference.
"How we transport and store gas is radically being reinvented," she said. "It is having a profound impact on reliability and the cost of supply."
Because of abundant gas in the Appalachian Basin, an estimated 48 projects are on the drawing board in the Northeast alone that would add 33 Bcf/d in takeaway capacity at a cost of $20 billion, she noted. Close to 15 projects are scheduled to ramp up between 2015 and 2016.
Storage projects, however, are not on anyone's radar. They've "flatlined," Viswanath said. "There is no storage...no new development occurring." What's taken its place are drilled but uncompleted wells (DUC), with the Appalachian Basin a de facto storage warehouse for DUCs that stand ready to tie to sales when needed.
For both pipeline flows and storage, "the overarching theme is the massive transformation," she said.
In 2008, an Energy Information Administration map showed 11 major transportation paths that moved gas across the United States, mostly from the traditional southwestern/Gulf Coast basins. Pipes at that time, Viswanath said, were delivering an estimated 10.2 Bcf/d to the Northeast and 7-8 Bcf/d to the Midwest. Gulf Coast pipes also carried gas to points west, while Canada supplies were moved into the Northeast via the Midwest, as well as to West Coast markets.
It was "supply basin parity," Viswanath said. The parity party now is over. "Not all shale basins are alike, and they differ in productivity and in the connectivity of those basins. "But "the story is that we have a lot of resource base" and in some parts of the country, it's now "very cheap."
That cheap gas is the result of Appalachia, which since 2008 has seen an 85% increase in supply, mostly from the Marcellus Shale. And over the next five to 10 years, "that's not going to change."
BNP is forecasting that the Marcellus will account for half of all U.S. shale supply over the next five to 10 years. With so much growth, pipeline flows have to be significantly altered. Pipeline flows have changed dramatically in the past few years. In 2013, ANR Pipeline, Texas Eastern, Transcontinental Gas Pipeline Line, Iroquois, Rockies Express Pipeline and Tennessee Gas Pipeline together accounted for 60% of the gas flows to the Northeast, according to Viswanath. But the capacity was 21-84% below 2008 levels.
The Northeast corridor quickly is becoming self-reliant when it comes to gas. Even with growing gas demand across the region, it now produces more than it consumes. Meanwhile, along the Gulf Coast, "the picture is reversed" as demand is set to expand through industrial/petrochemical facilities and liquefied natural gas (LNG) exports.
Reversing some of the major pipeline systems now directed to the Northeast corridor could add almost 9 Bcf/d of takeaway capacity, Viswanath said. Greenfields/expansions could add another 20 Bcf/d. By 2020, up to 11 Bcf/d of new incremental gas is predicted to flow out of the Appalachian market, with most of the gas destined for the southern Atlantic region. But that's a few years from now.
Until at least 2017, constraints are going to "linger" in the Northeast, suggesting that 2016 could be "another year of production cycling for Marcellus gas-on-gas competition," the analyst said.
Most at risk for the expanded supply competition is the Midcontinent, which could continue until enough LNG exports ramp up. Another danger are Gulf Coast prices, which could begin to weaken in 2017 as more midstream capacity becomes available. The Gulf Coast region is expected to be increasingly valuable to "smooth rising seasonality," Viswanath said.
"The amazing thing is, we haven't cycled production since the '90s...We used to always cycle production back in the summertime. Now with 'active' storage, that was unnecessary until this year. This year is the first time we have actually seen real cycling in our production as a means of balancing the marketplace..."
Close to 100 Bcf/d of new pipe may be in the works, but "deliverability has only increased by about 10 Bcf/d." LNG exports would change that dynamic. If the United States becomes, as expected, a major LNG player, "most of the world doesn't have adequate storage space," which would enable the Gulf Coast region to become another de facto storage area.
Pipeline operators also see an avenue in more greenfield systems and expansions into Mexico. The country today is "an 8 Bcf/d market but it would like to be a 16 Bcf/d market," Viswanath said. "We see all of the pipeline capacity but we don't see the requisite combined cycles...The industrials in Mexico are used to the fact that supplies are interrupted all of the time. There’s no secure source of supply and all the pipe is not spec pipe." But it's a big advantage for the U.S. systems because Mexico's gas imports "may be as large as the LNG market."