Here at RBN, we’ve built our analytics around the concept that hydrocarbon commodity markets — crude oil, natural gas, and NGLs — are fundamentally and closely linked. That’s why in all that we do, we emphasize that, in order to have an understanding of one market, you must also be competent in the others. That can be difficult at times when not only the market structure, but the very rules governing the upstream, midstream, and downstream sectors of oil and natural gas transportation are so different from each other. For example, consider the many contrasts between how oil and natural gas pipelines are regulated. Today, we look at how federal oversight of pipelines has evolved and why it matters for folks trying to move a barrel of crude oil or an Mcf of natural gas from Point A to Point B.
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Daily energy Posts
Canadian natural gas storage levels finished the most recent injection season at a record high. With what has been a fairly mild start to the heating season so far in North America, you might be tempted to think that Canadian storage levels would have been slow to draw down. On the contrary: so far, gas is being withdrawn from storage more quickly than might be expected from the winter weather alone, partly because of structural developments that have been emerging in the Canadian market. And these changes will help to draw storage levels down closer to historical averages by the end of the current heating season in March 2021. Today, we consider these structural changes and what the current heating season might have in store for the Canadian gas market.
Natural gas economic shut-ins! Shutting off a producing well on purpose, because the market won’t take the produced volume at a reasonable price. There was a time, back before gas commodity decontrol, when shut-ins were standard operating procedure, but that practice went the way of the dodo bird 40 years ago. Until earlier this year that is, when amid crushingly low prices, Appalachian producers said: enough is enough — and shut off the spigot themselves. In the months that followed, various producers have continued to see-saw their production in response to weather-related demand and regional market prices. The behavior signals that Appalachia’s shale gas producers are increasingly employing a light-switch approach in dealing with short-term weakness in demand and prices. Today, we take a closer look at the price-driven curtailments in the Northeast and potential implications for the market.
Closing midstream deals has been a bit of a challenge in 2020, to say the least. In fact, this has been a year when many projects have been sidelined or cancelled outright, with most decisions on even the best prospects getting pushed to next year. But it hasn’t been all bad news. In a few cases, assets with advantages have made it across the finish line, even in the land of liquefied natural gas (LNG) export projects. Despite this summer’s collapse in U.S. LNG exports, driven by a compression of the spreads in global gas prices, Sempra Energy recently announced that it is going ahead with Phase 1 at its Costa Azul liquefaction project in Mexico’s Baja California. How did they pull this off in such a tumultuous year? Well, Costa Azul isn’t your everyday LNG export project. Today, we detail the most recent U.S. LNG export project to receive a final investment decision (FID) to proceed.
On the 8th of October, the LNG carrier Golar Penguin loaded a cargo for RWE at the Freeport LNG terminal in Texas. Five days later, on October 13, the vessel was sitting just north of Panama. But then, the ship abruptly changed direction on the 14th and headed towards the Cape of Good Hope to deliver to the Far East. The reason for the diversion was that the vessel did not have a passage booked in the new locks of the Panama Canal and would have had to wait approximately nine days for its turn to transit, before heading across the Pacific Ocean to Asia. Since then, as queues of LNGCs for Panama Canal transits, both northbound (ballast) and southbound (laden) have developed, more ships have opted for the longer route. In today’s blog, we look at the delays that have developed surrounding the Panama Canal and the implications that its operations hold for global LNG trade.
You wouldn’t know it from the $2.50-plus/MMBtu Henry Hub prompt natural gas futures prices in the past couple of months, but the U.S. gas market this injection season just barely managed to avoid a complete meltdown. Despite gas production volumes trailing year-ago levels all summer long, it wasn’t until the last month or two of the traditional injection season (April through October) that the market tightened enough to escape a major storage crunch. In reality, it took the multi-pronged effects of production cutbacks — in part from hurricane-related disruptions — higher LNG and pipeline exports, and cooler fall weather, to make that happen. Today, we review the U.S. natural gas supply/demand balance and implications for 2021.
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.
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.