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.
So far, relatively mild weather this winter has insulated New England natural gas consumers from pipeline capacity-related price spikes that occurred during cold snaps in previous winters. And even if another polar vortex were to happen, it’s likely the regional electric grid operator’s Winter Reliability Program to shift gas-fired generators from pipeline gas to stockpiled oil or LNG would keep the lights on. But New England’s day of reckoning is coming. The region is becoming ever-more dependent on gas-fired power, most gas pipeline projects into New England are stalled or scrapped, and New York’s recently announced plan to close two Indian Point nuclear units will only make matters worse. Today we discuss the still-widening gap between Northeast pipeline capacity and gas demand.
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.
The build-out of incremental natural gas takeaway capacity out of the Marcellus/Utica region has come in fits and starts, with new pipelines—as opposed to the reversal or expansion of existing pipes—proving to be the most troublesome. Energy Transfer Partners and Traverse Midstream Holdings’ long-planned 3.25-Bcf/d Rover Pipeline to southern Michigan is a case in point. The latest challenge for the $4.2 billion project is getting final federal approval in time to allow tree clearing along the pipeline’s 711-mile route to be completed before federally protected bats start roosting in early April. If that timeline’s not met, Rover’s planned completion later in 2017 may be delayed a full year, enabling Western Canadian gas producers to sell more gas to Ontario and the Upper Midwest. Today we assess what’s at stake for ETP, Traverse, and producer-shippers in the Marcellus/Utica and Western Canada.
There’s good reason to believe that the international LNG market has turned a corner, with demand and LNG prices on the rise and with a number of new LNG-import projects being planned. That would be good news for U.S. natural gas producers, who know that rising LNG exports will boost gas demand and support attractive gas prices. It also would help to validate the wisdom of building all that liquefaction/LNG export capacity now nearing completion. Today we look at recent developments in worldwide LNG demand and pricing and how they may signal the need for more LNG-producing capacity in the first half of the 2020s.
Of the six interstate pipelines that account for most of the natural gas crossing the Texas/Louisiana state line, two have net flows that are westbound into Texas––something that would have been unthinkable just a few years ago. By the end of this decade—and maybe far sooner—Texas will be receiving more gas from Louisiana than vice versa, mostly due to planned pipeline reversals aimed at moving more Marcellus/Utica gas to Texas export markets. Today we continue our look at changing Texas gas flows, this time with a focus on the half-dozen most important pipelines at the Texas/Louisiana border.
Takeaway capacity out of the Marcellus/Utica shale producing region is about to get another significant boost. Tallgrass Energy’s Rockies Express Pipeline (REX) expects to bring the first 200 MMcf/d of its 800-MMcf/d Zone 3 Capacity Enhancement project (Z3CE) in service any day now, and ramp up to the full 800 MMcf/d by end of the year. Moreover, the pipeline operator has hinted that it may be able to eke out incremental Zone 3 operating capacity over and above the new design capacity in the near future. The Z3CE expansion will mark the third time in as many years that REX will increase westbound takeaway capacity out of the Marcellus/Utica region. With each capacity boost, Northeast production volumes have risen to the occasion and the capacity has filled up. Today we examine this latest expansion and what it will mean for U.S. gas production.