The battle to restore energy reliability in Europe has breathed new life into North American LNG export projects — and into the Haynesville Shale in Louisiana, the closest supply basin to many of the planned and proposed liquefaction facilities. Gas production in the region has climbed more than 4 Bcf/d — an impressive 39% — since 2019 and we expect it to grow nearly as much over the next three years. The big question on everyone’s mind, however, is whether there will be enough pipeline capacity to move that gas to where it’s needed on the coast. Pipeline capacity for southbound flows through the Bayou State is already showing signs of stress. Will recently completed and upcoming debottlenecking projects help stave off major supply and pricing disruptions? In today’s RBN blog, we provide our outlook on Haynesville production and the nature and timing of Gulf-bound pipeline projects.
The Cushing, OK, storage and trading hub plays critically important roles in both the physical and financial sides of the crude oil market. Located at a central point for receiving crude from a wide range of major production areas — Western Canada, the Bakken, the Rockies, SCOOP/STACK and the Permian among them — the hub also has numerous pipeline connections to Gulf Coast refineries and export docks, and to a large number of inland refineries. And, with Cushing’s 94 MMbbl of storage capacity and status as the delivery point for NYMEX futures contracts for West Texas Intermediate, the hub’s inventory levels and the WTI-at-Cushing price are closely watched market barometers. But like a lot of other U.S. energy infrastructure in the Shale Era, Cushing’s place in the energy world has been in flux. Most importantly, Permian production has been surging, the ban on U.S. oil exports is a fading memory, and the Gulf Coast — not Cushing — is where most U.S. crude production wants to go. Today, we discuss Cushing’s changing role and highlights from RBN’s new Drill Down Report on the U.S.’s most important crude hub.
Crude oil production has been increasing in virtually all of the shale and tight oil plays that send their output to the storage and distribution hub in Cushing, OK. A number of pipeline projects are being built and planned to accommodate that growth, and — despite the fact that two-thirds of Cushing’s existing storage capacity is currently unused — several million barrels of new tankage is being installed at the hub, again in anticipation of incremental needs in 2019, 2020 and beyond. So it should come as no surprise that midstream companies also are planning a good bit of new pipeline capacity out of Cushing, some to refinery customers in the Midwest and Midcontinent areas but some to refineries and export docks along the Gulf Coast. Today, we continue our series on the “Pipeline Crossroads of the World” with a review of rock-solid and potential plans to enable more crude to flow out of the central Oklahoma hub.
There’s been a lot of talk lately that the crude oil hub in Cushing, OK, is losing its luster — that it may not be as important as it once was. Folks point to the precipitous, months-long decline in crude inventories that started last fall, or to the fact that just about all of the planned oil pipelines out of the red-hot Permian are pointed toward Gulf Coast refineries and export docks, not central Oklahoma. Then you’ve got ICE and CME’s new WTI futures contracts, both deliverable in Houston — another challenge to Cushing. While Cushing’s role as the epicenter of crude storage and trading may be in flux, rumors of its demise have been greatly exaggerated, as evidenced by the long list of midstream projects under development to transport more crude to — and out of — the Oklahoma hub, and to add storage tanks there. Just yesterday (November 5), in fact, Magellan Midstream Partners and Navigator Energy Services announced plans for what would be the first new Cushing-to-Houston pipeline since 2014. Today, we continue our comprehensive review of the “Pipeline Crossroads of the World” with a look at the many capacity-expansion efforts now under way.
Natural gas flows and market dynamics are shifting at national benchmark Henry Hub. Supply receipts at Henry this year to date have doubled since the comparable period last year to nearly 450 MMcf/d, on average. That’s also a five-fold increase from the same period in 2016. In fact, current gas flows through the hub are the highest we’ve seen since 2009. The last time we saw this level of flows through the hub was when Gulf of Mexico offshore gas production volumes — much of which hit the U.S. pipeline system in southern Louisiana — were still topping 6.0 Bcf/d. That was also before the Marcellus/Utica Shale gas supply ballooned, effectively emptying out the pipeline capacity that used to flow gas north from the Gulf Coast. Now, many of those pipelines have reversed flows and the hub is showing signs of becoming a destination market for that Northeast gas and other supply targeting LNG export demand on the Gulf Coast. Today, we continue our short series looking at the changing physical flows at Henry Hub.
Three major crude oil pipeline projects now under development would add nearly 1.8 MMb/d of much-needed takeaway capacity out of the Western Canadian Sedimentary Basin (WCSB), a region hit hard by pipeline constraints and widening price differentials. But each of the three projects — Kinder Morgan’s Trans Mountain Expansion (TMX), Enbridge’s Line 3 Replacement Project and TransCanada’s Keystone XL — continues to face regulatory challenges and it remains unclear how many of the projects will advance to construction and how soon the first of them might come online. It’s also possible that one or more may go the way of Northern Gateway and Energy East, two major pipeline projects that went belly-up after years of planning. Today, we continue our blog series on Western Canadian crude oil with a look at Keystone XL and its prospects.
Several large-scale gas pipeline expansions targeting the New England and New York City markets have been sidelined in the past year, either due to insufficient financial backing or the challenges of regulatory rigmarole in the region. But in recent weeks, a couple of smaller-scale projects along existing rights-of-way have managed to cross the finish line, allowing incremental gas supplies to trickle into the region. The new pipeline capacity will provide natural gas utilities and power generators in the region with greater access to additional gas supplies from the nearby Marcellus Shale this winter. Today, we look at recent capacity additions and their potential impacts.
In another key milestone for Northeast pipeline takeaway capacity expansions, Energy Transfer Partners’ beleaguered Rover Pipeline project began partial service on its Phase 1A portion on gas day September 1. The 3.25-Bcf/d project, which is due for completion in early 2018, is expected to provide relief for constrained Northeast producers while exacerbating oversupply conditions and gas-on-gas competition in the Dawn, Ontario, storage and demand market area and surrounding region. Within days of initial start-up, flows on Rover ramped up to 700 MMcf/d, and both Ohio and overall Northeast production already have posted record highs since then as a result. Today, we take a look at the project, including initial flows and the expected timing of full completion.
