Gas storage levels in the U.S. over the past year or so jolted market sentiment in different directions. Last year at this time, natural gas stocks hit all-time highs following an unusually mild winter. Natural gas prices plunged below $2 per million Btu (MMBtu), and as a result production actually declined after a decade-long surge in supply.
The U.S. shale gas revolution still persists, with the Marcellus play thriving, drillers using more efficient techniques, and exports possibly rising over the long term.
Now, however, the U.S. natural gas market looks dramatically different than it did in early 2016. Production has stopped declining, storage levels have burned off some of their excess, and demand continues to rise. Henry Hub prices are up more than 50 percent in 12 months and have stabilized just above $3/MMBtu, strong enough to incentivize an increase in drilling and production in the months and years ahead. The U.S. shale gas revolution still persists, with the Marcellus play thriving, drillers using more efficient techniques, and exports possibly rising over the long term.
New pipelines and drilling techniques make gas drillers more flexible
The most prolific shale gas formation the U.S. is the Marcellus Shale, which stretches across Pennsylvania, Ohio and West Virginia. Marcellus producers have been held back by a shortage of pipelines, a bottleneck that has forced steep discounts for gas from the region—but the situation is changing. A recent buildout of natural gas pipelines in the U.S. northeast and mid-Atlantic has been a boon to gas drillers. For example, Spectra Energy’s Alongquin Incremental Market project, which came into service in Q4 2016, added new pipeline capacity to the northeast for the first time since 2010. The nearly $1 billion project expanded the market for Marcellus and Utica shale natural gas into New England.
A recent buildout of natural gas pipelines in the U.S. northeast and mid-Atlantic has been a boon to gas drillers.
The additional pipeline capacity granted upstream producers flexibility, allowing them to send gas to a variety of markets. More pipeline capacity is expected to arrive this year and next, opening up even more new markets for the Marcellus and Utica Shales. A handful of pipeline projects nearing completion will increase midstream capacity from those two shale formations from 23 billion cubic feet per day (bcf/d) to 35 bcf/d, according to Reuters, or a more than 50 percent increase. That will allow a higher amount of Appalachian gas to reach the Northeast, the Mid-Atlantic, the U.S. Gulf Coast, and even Eastern Canada.
Shale gas revolution part two
Besides more flexibility from increase pipe capacity, the shale industry is deploying new innovations pioneered over the past few years. As Bloomberg recently reported, gas drillers have improved their ability at “choking” wells, or throttling back output in order to stretch out production over time. Prior to the use of this technique, shale gas wells would exhibit an initial burst of output, followed by a precipitous decline. But the use of computer-controlled technology can expand or restrict gas flows easier, allowing drillers in the Marcellus and Utica Shales to “swing from dropping overall production in that area … to bringing it all back online” in just a few weeks’ time, said Het Shah, an analyst at Bloomberg New Energy Finance.
Gas producers are now increasingly able to respond nimbly to market signals.
New pipelines and improved drilling techniques have led to the emergence of a close temporal link between natural gas prices and movements in production. According to Bloomberg New Energy Finance, production from gas drillers in the Northeast have recently correlated with prices on a three-day lag. For example, prices dropped toward the end of the third quarter in 2016, and drillers cut back on production on short notice. Within a few weeks prices climbed again, and so did output. In the past, drillers had no near-term ability to respond to prices–they would simply drill a well and sell what they could. Now, they are increasingly able to respond nimbly to market signals. Ultimately, this greater optionality and responsiveness could dampen overall volatility.
Drilling techniques continue to improve, cutting the cost of production, meaning companies can still be profitable if prices hang around $3/MMBtu. According to a 2016 EIA report, the cost per foot of depth drilled has declined by more than 30 percent since 2012 in the Marcellus, and the completion cost per lateral foot has fallen by even more. Some of those savings might prove to be temporary as service companies start to hike their prices as drilling activity picks up. But structural improvements in efficiency over the past half-decade mean that drillers can produce more with less. The rig count in the Marcellus has rebounded over the past six months, and production is back on an upward trajectory.
Gas exports set to surge?
In 2016, Cheniere Energy brought its Sabine Pass liquefied natural gas (LNG) export terminal online, inaugurating a new era in which the U.S. is set to play an important role is a major gas exporter. LNG exports have started off with a trickle, as most cargoes went to the Caribbean and Latin America. Although some cargoes have been sent to Portugal, Italy, and Turkey, only about 17 percent of the total LNG volume that have left U.S. shores up until now have been shipped to Europe. Fewer than U.S. 30 cargoes have arrived in Asian ports, where the bulk of LNG demand is located, with Japan as the world’s largest LNG importer. Many LNG export terminals around the world have been constructed on the basis of strong Asian demand and high prices. More recently, however, prices have tanked because of too much supply and slow demand growth. The Platts Japan Korea Marker (JKM)—a benchmark price for LNG delivery in Asia—dropped below $5/MMBtu for May delivery, down from the $20/MMBtu highs seen just three years ago.
The short-term glut has not dimmed the hopes of LNG suppliers, who expect their export facilities to offer paybacks for decades to come.
The market downturn will shelve a large number of proposed LNG export terminals. The near-term might be a rough one for exporters that have not booked their volumes under long-term contracts. But the short-term glut has not dimmed the hopes of LNG suppliers, who expect their export facilities to offer paybacks for decades to come. “The industry needs extra supply by the middle of 2022, 2023,” Elizabeth Spomer, president of the proposed Jordan Cove export facility in Oregon, told CNBC in early April.
Low prices could keep a lid on the volume of U.S. LNG that makes its way to Asia. However, U.S. LNG has already upended decades of trading norms. LNG has traditionally been bought and sold through long-term contracts with prices linked to the price of crude oil. Now, though, buyers are demanding more flexible prices, the ability to resell cargoes, and shorter time horizons on their contracts. Top importers in Japan and China are putting together a “buyers’ club,” seeking to exact concessions from producers. The end result will be a more liquid spot market with flexible prices. In other words, the LNG market will increasingly resemble the market for crude oil.
Ultimately, American LNG should be able to overcome poor global market conditions. “North America’s energy advantage extends from a unique combination of resources, the most advanced technologies being applied to those resources and the availability of capital,” Enbridge CEO Albert Monaco said at the CERAWeek Conference in March. “By 2035, it’s quite likely we are going to see the U.S. making up the largest market share of the LNG market,” surpassing Qatar and Australia. The emergence of the U.S. as the top LNG exporter will be made possible because of its vast supplies of cheap shale gas.