With the rise of LNG feedgas demand in southern Louisiana, physical natural gas flows at Henry Hub have been climbing. As such, volumes moving through the U.S. benchmark pricing location are increasingly affected by swings in LNG feedgas deliveries, as well as in the gas supply flows into southern Louisiana that serve that demand. Those impacts have become particularly evident in recent months as nearby LNG export capacity utilization went from a trough this summer due to cargo cancellations, to being erratic during late summer and fall as hurricanes disrupted marine traffic and facility operations, and, in more recent days, to being at full bore at most facilities. In conjunction with brimming storage and pipeline maintenance in the area, this has meant more operational constraints and volatility in flows and pricing at the hub. Today, we continue our series on the changing dynamics in and around Henry Hub.
Daily Energy Blog
A few years ago, the most damning things skeptics could say about using LNG as a fuel for large ocean-going ships were that very few ships were fitted with LNG storage tanks and that there was little or no infrastructure in place at most ports to load the fuel. Well, they can’t say that anymore. About 170 large, LNG-powered vessels already are in operation around the world — including a French containership that just set a world record for carrying the most containers — and another 220 or so are on order. Just as important, the vast majority of key ports either have robust LNG bunkering operations in place or are in advanced stages of developing them. Today, we continue our series with a look at LNG’s growing acceptance and use as a ship fuel.
Within the next year, the Permian Highway and Whistler natural gas pipelines will add 4.0 Bcf/d of incremental capacity from the Permian Basin to the Gulf Coast, with gas supplies on those pipes primarily targeting LNG exports. But in the years since these pipeline projects were initially envisioned, market conditions have been radically transformed by consequences of the COVID era, on both the supply and demand sides of the equation. The outlook for supply growth is lower, while the dependability of LNG exports has been thrown into question following massive cargo cancellations this summer. In RBN’s special-edition multi-client market study, titled Some Beach, we break down the consequences of these developments into eight distinct steps that demonstrate how Texas gas markets are likely to evolve as flows and basis respond. Today’s blog summarizes those conclusions.
Since August, physical natural gas flows at Henry Hub have been at all-time highs for each respective month, and, in early October, they recorded the highest single-day flows that we’ve seen since December 2009. For decades, liquidity at the U.S. natural gas benchmark pricing location in southeastern Louisiana has been dominated by financial trades, with minimal physical exchange of gas, despite the hub boasting robust physical infrastructure and ample pipeline connectivity. That’s still the case, but physical movements of gas in the area have been on the rise due to LNG exports ramping up from the Sabine Pass and Cameron LNG facilities in southwestern Louisiana and a slew of Appalachia gas supply pipelines targeting that export demand. As more physical gas is moving through the hub, operational constraints are developing at key interconnects there. That, along with the ups and downs of LNG feedgas demand, is contributing to spot price volatility at the hub and, at times, a deeper divergence between Henry spot and futures prices. Today, we begin a short blog series on the changing gas flow dynamics in and around Henry.
2020 has been as anomalous as it can get for energy markets, but that’s especially the case for the LNG sector, which was battered by COVID-related demand destruction. U.S. export volumes, in particular, experienced wild swings this year, going from steady increases and close to 100% utilization over the past few years as new export capacity was added, to operating at barely 30% of capacity this past summer as national lockdowns decimated demand and led to historically low gas prices abroad. Contracted cargoes were canceled en masse for the first time since the U.S. began exporting in 2016, amounting to over 500 Bcf between June and September that was pushed back into the U.S. natural gas market and into storage. But these events only exaggerated what was already a growing risk; with each new train being commercialized, domestic markets are increasingly exposed to the demand swings and other fundamentals in the export markets it serves. Today, we look at how seasonal demand patterns in the U.S.’s primary destination markets could translate to increased volatility at home.
The natural-gas market disruptions hitting the Texas-Louisiana coast so far in 2020 — a pandemic, the collapse of the LNG export market, a rare hiccup in Permian gas production, and multiple hurricanes —threw a big wrench into market expectations. Everything had been moving along pretty smoothly since mid-2016, when the first of a series of new liquefaction trains came online at Sabine Pass LNG. As new LNG export capacity started up at Sabine Pass, Corpus Christi, Cameron, and Freeport, so did relatively steady, predictable growth in feedgas demand. Then came this crazy, unforgettable year. Still more liquefaction capacity started up, but LNG export volumes plummeted, mostly due to very weak export economics. Recently, LNG exports have been picking up and, whenever hurricanes stop pounding the Gulf Coast, the U.S. will likely finally experience the full impact of all 9.15 Bcf/d of export capacity operating at full strength, requiring nearly 10 Bcf/d of feedgas across the U.S, almost 9 Bcf/d of which is located in Texas and Louisiana. Gas flow patterns across Louisiana’s dense network of pipelines already are shifting in response to the incremental demand and are signaling increased supply competition along the Gulf Coast this winter. Today, we continue our series discussing the changing flow patterns along the U.S. Gulf Coast, this time providing an overview of the main drivers of those shifts to date, including LNG feedgas demand and Northeast inflows.
Natural gas production has been growing in Western Canada in recent years with an increasing share of that supply coming from core areas of activity within the Montney and Duvernay plays. This tighter focus has forced TC Energy to rework and expand its giant Nova Gas Transmission Limited pipeline system, a network that originally gathered gas supplies across a much larger geographic footprint. The problem is, it took far longer than expected for the latest round of NGTL expansions to win final approval from Canadian regulators. Today, we review the next phase of the pipeline’s system development, and what the regulatory delay might mean for Western Canada’s gas market.
Back in January, when the International Maritime Organization implemented more stringent limits on sulfur emissions for large, ocean-going vessels, the vast majority of shipowners and charterers complied with the new rule — commonly referred to as IMO 2020 — by switching to very low sulfur fuel oil or gasoil. A few others stuck with old, higher-sulfur bunker but installed scrubbers to remove sulfur from the engine exhaust. A third option — fueling ships with LNG — is now gaining traction, in part because it could help shipping companies deal with future IMO mandates on reducing greenhouse gas emissions. Orders for new-build LNG-powered vessels and LNG bunker ships are rolling in, and plans for port infrastructure to support LNG bunkering are being implemented. Today, we begin a series on the growing use of LNG in global shipping.
Over the past decade, floating LNG — for liquefying and shipping offshore natural gas supply — emerged as a promising technology that would enable development of smaller, more remote offshore gas fields around the world. But with a handful of projects now completed and in commercial operation, the challenges of financing, developing, and operating this relatively new technology are overshadowing its prospects. Of the more than 20 FLNG projects that have been proposed since 2007, only five have crossed the finish line and only two others have reached a favorable final investment decision (FID). Moreover, Shell’s Prelude FLNG offshore Northwest Australia — the largest of the existing FLNG facilities — has been dogged by issues since its commissioning in mid-2019, and the operator last week said the unit will not produce any more LNG cargoes this year, after being shut down since February for electrical problems. Today, we examine the headwinds facing FLNG projects.
By the middle of the decade, LNG Canada should be sending its first cargoes of Canadian-sourced LNG to Asian markets. More importantly, Canada for the first time will have an alternative export market for its natural gas supplies — for more than 50 years, piping gas south to the U.S. has been its only option. But getting gas from the Montney and Duvernay production areas to the British Columbia coast is no easy task. It requires the construction of an entirely new, 2.1-Bcf/d pipeline — expandable to 5 Bcf/d — much of it over very rugged terrain. Coastal GasLink, as the planned pipe is known, has also faced major regulatory hurdles. Today, we conclude a two-part series with a look at where the pipeline project stands today.
The Permian is set to send increasing volumes of natural gas to the Texas Gulf Coast next year, but it is unlikely to be the flood that was once expected. This year’s decline in oil prices has slashed budgets for West Texas producers and rig counts show no sign of a big rebound anytime soon. As a result, growth of oil and associated gas from the Permian will be tepid at best over the next few years, which is a major change from when oil prices hovered north of $50/bbl. Despite the moderation in gas volumes out of the basin, infrastructure changes in 2021 are likely to roil Permian gas markets and have important knock-on impacts for adjacent regions and end-users that depend on West Texas supply. With much less incremental gas from the Permian, there are likely to be significant shifts in gas flows, particularly across the Texas-Louisiana border, to help meet the big increases anticipated for LNG exports. Today, we continue a series that highlights findings from RBN’s new, Special Edition Multi-Client Market Study.
With the rise of U.S. LNG exports in recent years, southern Louisiana has become a focal point for natural gas demand, pulling in gas supply from near and far and all directions. That market was severely disrupted this summer as COVID-19 decimated global LNG demand and hammered the economics of U.S. LNG exports. Pipeline flows into southern Louisiana during those months went from record-breaking highs that pushed the limits of the area’s infrastructure capacity to levels consistent with 2018, when the Bayou State’s LNG export capacity was just 2.65 Bcf/d, compared with 4.9 Bcf/d now. More recently, an active hurricane season has also curtailed exports. But demand for U.S. LNG is rebounding, and as LNG feedgas heads back to its previous highs and beyond, a new flow dynamic is emerging along the Gulf Coast, driven by the 1.35 Bcf/d of new export capacity in Texas that came online this year. Flows between Louisiana and Texas are reversing as an increasing amount of gas is needed on the western side of the Sabine River to feed the Corpus Christi and Freeport LNG facilities. The incremental gas demand and flow reversal will create new challenges and constraints for the region’s pipeline infrastructure as steady exports resume. Flows into Louisiana will be higher than ever, but so will flows out of Louisiana heading west to serve additional LNG demand. Today, we begin a series discussing how LNG demand is changing gas flows along the U.S. Gulf Coast.
Global LNG demand has picked up, cancellations for U.S. cargoes have subsided, at least for now, and there’s upside to U.S. cargo activity once tropical storm-related disruptions are resolved. But positive netbacks year-round are no longer a foregone conclusion for U.S. offtakers. As global oversupply conditions persist, at least on a seasonal basis, and supply competition intensifies, the economic decision to lift U.S. cargoes will be much more nuanced than it was in previous years. What do the economics for cargoes this winter and beyond look like? Today, we put the LNG economics model to work to understand what’s in store for U.S. LNG in the coming months.
Permian natural gas production is now expected to grow at a subdued pace over the next five years, as lower oil prices and a focus on capital discipline have slashed rig counts. Few observers see the Permian situation changing anytime soon, especially as crude oil prices continue to hover around $40/bbl. That said, the Permian gas market will be anything but dull over the months and years ahead. More than 4 Bcf/d of new outbound pipeline capacity from the Permian to the Gulf Coast will be coming online next year, throwing natural gas flows from West Texas into flux and deeply impacting neighboring markets. While natural gas basis at the Permian’s primary Waha hub should improve dramatically, outflow to the Midcontinent will likely fall sharply and potentially reverse, and the Texas Gulf Coast will see an influx of supply on the new pipelines. Today, we continue a series that highlights findings from RBN’s new, Special Edition Multi-Client Market Study.
When plans for LNG Canada, a big LNG export project on the British Columbia coast, were sanctioned two years ago this month, the move came as a welcome sign that Western Canadian natural gas producers might finally be able to break their long-standing reliance on just one export customer: the U.S. Access to Asian and other overseas gas markets became a high priority, in part because U.S. demand for Canadian gas had been sagging for years as production in the Marcellus/Utica and other U.S. plays came to meet the vast majority of domestic needs. But while construction on LNG Canada has steadily advanced, there are signs that delays could be mounting. Today, we begin a two-part update on this all-important Canadian LNG export project and its accompanying Coastal GasLink pipeline.
