One of the major target markets for Appalachian natural gas is the U.S. Southeast. More than 32 GW of gas-fired power generation units are planned to be added in the South-Atlantic states by 2020 and LNG exports from the Southeast are increasing. Of the 15.5 Bcf/d of takeaway capacity planned for Appalachia, close to 5 Bcf/d is targeting this growing demand. Despite the need, these pipeline projects designed to increase southbound flows from the Marcellus Shale have faced regulatory delays and setbacks. Today, we provide an update on capacity additions moving gas south along the Atlantic Coast.
Since 2013, nearly 3.0 Bcf/d of natural gas pipeline capacity has been added from Appalachia to the heavily populated, hard-to-reach demand centers along the East Coast. And another nearly 3.0 Bcf/d is in the works. The need for gas supply reliability in the heavily populated East, along with producers’ need to move their gas to market, is driving these expansions. But concentrated population centers, along with the geography, geology and regulatory environment of the area, all also make it tough and expensive for upgrading, expanding and developing the gas transportation system. Many of the proposed projects have been delayed or canceled as a result. Today, we provide an update on eastbound pipeline expansions from Appalachia.
For years now, limited natural gas pipeline takeaway capacity has constrained gas production growth in the Marcellus/Utica natural gas shale plays in the Northeast. To fix that, a slew of pipeline projects were planned to relieve the constraints as regional supply began outstripping demand starting in 2014. Now, the region is on the verge of being unconstrained for the first time since the Shale Revolution hit Appalachia. Many of those projects have come online since then, and another 19 expansions totaling 15.5 Bcf/d are planned for completion by late 2019. If all goes as expected, this next round of projects should turn the Northeast market on its head again, as the capacity additions should start to outpace production growth. The problem, though, is that several projects have faced significant challenges in recent months, resulting in either cancellation or major delays. At the same time, Marcellus/Utica production growth has slowed dramatically in the past 18 months or so. In today’s blog, “In a Northeast Minute…Everything Can Change — An Update of Marcellus/Utica Takeaway Projects,” Sheetal Nasta begins a series looking at the status of regional takeaway capacity expansions.
Natural gas production growth in the U.S. Northeast—the primary driver of U.S. production growth in recent years—has slowed dramatically in the past few months, up no more than 1 Bcf/d year-on-year, compared with growth in increments of 3 and 4 Bcf/d in previous years. Despite the slowdown, the regional balance continues to lengthen, with supply growth outpacing demand. Yet, regional gas prices, specifically at key supply hubs, which previously were struggling under the weight of oversupply coupled with limited access to growing demand markets, are strengthening. Is this the beginning of the end of takeaway constraints and distressed supply pricing in the region? Or will constraints reemerge this summer? Today, we provide an update of Northeast gas supply/demand balance.
As a group, the nine natural gas-focused exploration and production companies that were analyzed in our Piranha! market study are forecasting a 62% increase in capital spending in 2017 compared with 2016, a significantly higher percentage gain than their oil-focused and diversified counterparts. The driver of accelerated investment is the expected completion of natural gas infrastructure that will boost takeaway capacity from the Marcellus and Utica shales, the operational focus of eight of the nine gas-weighted E&Ps. Expanded access to Canadian, Midwestern, Gulf Coast and export markets should significantly boost realizations and margin. Production growth by the nine E&Ps, which slowed to 4% in 2016 after a 19% rise in 2015, is expected to accelerate to 10% in 2017 and to rise rapidly in 2018 and beyond. Today we continue our analysis of U.S. E&P capital spending and production trends by taking a deep dive into the investment strategies of the natural gas-weighted peer group.
Rising natural gas exports from South Texas and increasing production of “associated” gas in the Permian Basin are driving the development of several new gas pipelines from West Texas to the Agua Dulce gas hub and nearby Corpus Christi. The age-old questions apply: How much new pipeline capacity will be needed, and how soon? The construction of these new pipelines also raises the question of how a potential flood of new gas supply from the Permian to the South Texas coast might affect plans by others to flow gas down the coast from Houston. Today we continue our look at proposed gas pipelines from the Permian to Agua Dulce and Corpus Christi with a review of two more projects and their potential impact.
Anticipating renewed growth in natural gas and natural gas liquids production in the Marcellus and Utica plays, midstream companies active in the region are planning new gas processing plants and fractionators, as well as new NGL takeaway capacity and in-region NGL storage. And Shell Chemicals has made a Final Investment Decision to build a $6 billion, ethane-consuming steam cracker in western Pennsylvania by the early 2020s. In today’s blog, “Unleashed in the (North)East—New Gas Processing and Fractionation Capacity in Marcellus/Utica,” Housley Carr continues our series on on-going efforts by midstreamers and others to keep pace with NGL growth in the epicenter of U.S. gas and NGL production.
Natural gas production in the Marcellus and Utica plays is projected to rise by 30% or more by 2022 under all of RBN’s forecast scenarios, and production of Northeast natural gas liquids is expected to increase even more quickly. Midstream companies are responding to this next phase of gas/NGL growth with plans for still more gas-processing plants, fractionators, NGL storage facilities, and NGL takeaway capacity––pipeline, rail, ship and barge. Also, Shell Chemicals continues to advance plans for an ethane-consuming steam cracker in Beaver County, PA, and another petrochemical company may soon decide to build a cracker in Ohio. Today we begin a new series on the latest push by midstreamers to keep pace with NGL growth in the epicenter of U.S. gas and NGL production.
South Texas—and its primary trading hub, Agua Dulce—is emerging as the fulcrum for U.S. natural gas producers and growing demand markets on the Texas Gulf Coast and across the border in Mexico. Between the Freeport and Corpus Christi LNG export projects and cross-border pipeline projects to Mexico, nearly 4.0 Bcf/d of export capacity is being developed in South Texas over the next few years. Meanwhile, U.S. producers as far north as the Marcellus/Utica are jockeying to capture this new demand. Large investments are being made to expand and reverse traditional pipeline flows across the Texas-Louisiana border to get gas all the way down to South Texas and the Texas-Mexico border. But will enough capacity be available when the demand shows up? Today, we break down the natural gas supply/demand picture in South Texas and what it will take to balance the market there as exports ramp up.
Evaluating midstream companies—their assets, their value, their prospects—is a complicated task. It’s not enough to rely on the public face that companies put forward; typically, they highlight their strengths and minimize their weaknesses. To gain a fuller understanding of midstreamers, you need to poke around, consider their individual assets, and assess the status and outlook of the various production areas they serve. Asset location matters for a lot of reasons, but mostly because midstream infrastructure serving a thriving basin—the Permian and Marcellus, for instance—will contribute a lot more to a company’s bottom line than assets serving an area in steep decline. Today we conclude a blog series that highlights key takeaways from East Daley Capital’s new, detailed assessment of more than 20 U.S. midstream companies.
As natural gas exports to Mexico continue to rise and as construction proceeds on liquefaction/LNG export terminals in Freeport and Corpus Christi, TX, the need to transport increasing volumes of gas down the Texas Gulf Coast becomes ever more urgent. And moving gas down the coast is no easy task; the Lone Star State’s convoluted mix of interstate and intrastate pipelines were designed primarily to flow gas up the coast from South Texas and Gulf Coast production areas to the greater Houston Ship Channel area—and from there on interstate pipes to Louisiana and beyond. Today we use RBN’s Fretboard Model to discuss whether existing and planned southbound pipeline capacity will be sufficient to meet export demand.
Earlier this month, Tallgrass Energy’s Rockies Express Pipeline (REX) achieved full in-service of its 800-MMcf/d Zone 3 Capacity Enhancement Project, boosting the line’s east-to-west takeaway capacity out of Ohio to 2.6 Bcf/d, up 45% from 1.8 Bcf/d previously. Flows since then provide early indications of how Marcellus/Utica producers and downstream markets are responding to this added ability to move gas west. In today’s blog, we continue our look at how the expansion has impacted flows, this time with a focus on the delivery side.
Tallgrass Energy’s Rockies Express Pipeline earlier this month (on January 6, 2017) brought into service the last 350 MMcf/d of its 800-MMcf/d Zone 3 Capacity Enhancement Project, boosting the line’s east-to-west takeaway capacity out of Ohio to 2.6 Bcf/d, up 45% from 1.8 Bcf/d previously. The new, fully-subscribed capacity, designed to serve Marcellus/Utica producers, filled up almost instantaneously. But unlike previous capacity additions, Northeast production did not increase. Instead the gas came from other pipelines. This development provides an early indication of what the new capacity will mean for producers, flows and prices. In today’s blog, we delve into pipeline flow data to understand the early impacts of the new takeaway capacity.
Northeast producers are about to get a new path to target LNG export demand at Cheniere Energy’s Sabine Pass LNG terminal. Cheniere in late December received federal approval to commission its new Sabine Pass lateral—the 2.1-Bcf/d East Meter Pipeline. Also in late December, Williams indicated in a regulatory filing that it anticipates a February 1, 2017 in-service date for its 1.2-Bcf/d Gulf Trace Expansion Project, which will reverse southern portions of the Transcontinental Gas Pipe Line to send Northeast supply south to the export facility via the East Meter pipe. Today we provide an update on current and upcoming pipelines supplying exports from Sabine Pass.
Crude oil and natural gas production growth stalled in 2015 and has declined this year in some of the big shale basins. But we may be seeing a turnaround. The latest EIA Drilling Productivity Report, released on December 12, 2016, included upward revisions to its recent shale production estimates and also projects an increase in its one-month outlook for the first time in 21 months (since its March 2015 report). Today we break down the latest DPR data.