The Northeast region has traditionally been a demand market for gas produced in the SE/Gulf, Midcontinent, and Canada. But, this changed when the Marcellus and Utica formations were discovered and then developed.
Over the past 10 years, natural gas production in the Marcellus and Utica basins has risen sharply — from about 2 Bcf/d in 2008 to more than 26 Bcf/d as of February 2018 — and now represents about 33 percent of total U.S. dry gas production. While other basins also experienced growth during the same time period, the rates were much lower: Eagle Ford at 3.3 Bcf/d, Permian at 3.2 Bcf/d, and Anadarko at just 1.2 Bcf/d. The graph below shows historical dry gas production by region since 2010 and forecast through 2018.
This massive growth has created a lot of challenges to producers in the Northeast, the most significant being bottlenecked pipeline takeaway capacity. This became a real challenge in 2013, when production levels reached capacity limits.
Because of this, as shown below, pricing dropped in the region: trading at a premium (basis higher than Henry Hub) plummeted to trading at a discount (below Henry Hub), with basis as low as $2/MMBtu below Henry Hub.
Pipeline infrastructure operators have responded to this new dynamic by changing flow direction in existing pipelines and expanding capacity through looping and compression as well as by installing new (greenfield) pipeline capacity. But so far, capacity additions haven’t kept up with production growth, and price basis has remained depressed. In fact, from 2013 through 2017, producers have filled up all capacity additions as soon as they became available.
However, there’s good news ahead. As shown in the chart above, Drillinginfo expects pipeline capacity constraints to end in 2018, when key takeaway projects will come online and add over 5.0 Bcf/d of additional Northeast takeaway capacity. Energy Transfer Rover Phase 2, Transco’s Atlantic Sunrise, Nexus Gas Transmission, and Columbia’s Gulf Xpress projects will, in effect, debottleneck the region during the third quarter. Regional gas basis is therefore expected to trade within variable transport costs of about $0.20–$0.30 per MMBtu below Henry Hub.
Once the capacity constraint is lifted, production economics — the difference between market prices and breakeven prices — will start to dictate growth in the Northeast going forward. Based on Drillinginfo’s pricing expectations of Henry trading somewhere between $2.65 and $2.75 MMBtu over the next five years, by 2021, production will reach almost 30 Bcf/d, an increase of more than 5.0 Bcf/d from current levels.
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