It’s expected to be a big year for U.S. LNG. The U.S. was the top monthly exporter of LNG for the first time in December 2021 and is expected to hold onto that crown as new capacity at Sabine Pass and a new terminal, Calcasieu Pass, begin service this year. The chaos of European gas markets has made U.S. exports particularly attractive, especially after a year or more of high global demand, sky-high global gas prices, and an undersupplied market that has left offtakers clamoring for more. Last year saw those offtakers come back to the negotiating table for long-term sales and purchase agreements (SPAs) from new U.S. LNG capacity and several projects now have a realistic path to a positive final investment decision (FID) in 2022. In today’s RBN blog we begin a series taking a closer look at some of the projects most likely to reach FID this year, starting with arguably the most likely next contender, Venture Global’s Plaquemines LNG.
Posts from Lindsay Schneider
Global natural gas prices went through the roof in December, and while prices are back down from those highs, they remain incredibly strong compared to years past and the economics for U.S. LNG exports are riding high. LNG exports have been in the money for quite some time, but feedgas deliveries to U.S. export terminals throughout the spring and summer of 2021 were somewhat lackluster as maintenance and operational issues at terminals and nearby pipelines kept feedgas from hitting its full potential. Gas deliveries to those terminals began climbing in the fall, first back to full utilization levels, and then beyond. Much of the record feedgas demand has been from commissioning activity at Sabine Pass Train 6, which produced its first LNG in December and is on track to begin full service early this year. But beyond that, operators have been pushing the existing fleet of terminals to operate at peak levels and produce additional cargoes, likely for sale in the spot market or on short-term contract, an extremely profitable endeavor given the prices in Europe, where most if not all destination-flexible cargoes have headed. In today’s RBN blog, we look at what’s driving LNG feedgas demand to its recent highs and how much higher it could go.
Global natural gas prices are once again at record levels as escalating tensions between Russia and the Western world have re-ignited fears over gas shortages in Europe this winter. The global gas market is in the midst of an epic bull run that has been going on for more than a year, taking prices from all-time lows in the summer of 2020 to repeated all-time highs. And while strong demand for gas and LNG has underpinned prices and tied global gas markets together, Europe has been the driving force behind most of the headlines and panic-driven price run-ups. Prices in Europe have climbed to nearly $60/MMBtu as market fears around Russian gas supplies into Europe have been renewed by threats of new U.S. sanctions on Russia over aggression toward Ukraine, delays to the startup of the controversial Nord Stream 2 pipeline, continued low gas flows from Russia to Europe on existing infrastructure, and now Europe is facing its first real cold snap of the season. In today’s RBN blog, we take a look at the situation in Europe and its impact on the global gas and LNG markets.
It has been an epic year for U.S. LNG. After COVID-19 and the subsequent global market crash brought LNG development to a standstill and shut-in production from existing terminals in 2020, this year has seen global prices repeatedly smash previous record highs, driving existing terminals to operate at peak levels and renewing interest in new LNG buildout. U.S. feedgas demand and LNG production will close out the year at all-time highs, but with just a few weeks left it looks like 2021 will be the first year since 2017 that no new LNG terminals will achieve a positive final investment decision. But that’s driven more by the tailwinds of 2020 — the back half of 2021 has seen a tremendous amount of commercial activity in the LNG sector. More than 21 million metric tons per annum of medium- and long-term capacity from planned LNG projects has been sold this year, creating enough forward momentum for multiple projects to move toward FID in 2022. We cover all the latest developments in our LNG Voyager Quarterly report, and in today’s RBN blog we take a look at some of the recent LNG deals and what they tell us about the future of North American LNG.
It has been a chaotic couple of years for North American LNG and the global gas market. In a short time, international gas markets went from oppressively oversupplied balances, high storage inventories, and historically low prices for much of 2020 to reckoning with panic-inducing supply shortages, low inventories, and multi-year or all-time high prices in the biggest LNG-consuming regions. The resulting whiplash has transformed key aspects of the LNG market, making a profound impact on the way existing LNG terminals operate, how projects secure funding and capacity commitments, and what offtakers expect for the next generation of LNG capacity buildout. The tight market appears to have settled the question of whether more export capacity is needed, at least for now, but the market’s sharp U-turn has also put potential offtakers on edge and underscored the need for contractual flexibility. Additionally, pressure to reduce greenhouse gas (GHG) emissions is higher than ever, and LNG offtakers are increasingly demanding greener solutions to address government regulations and public concerns. This convergence of factors has put the LNG market at a crossroads. Taking all of the lessons learned from the last two years and before, the industry must now forge a new path forward. In the encore edition of today’s RBN blog, we discuss highlights from our recent Drill Down report, looking at the major trends that will define the North American LNG market in the coming years.
After a record-breaking year in which the Japan-Korea Marker topped $30/MMBtu, it looks like 2022 could finally be the year when multiple projects in the long-awaited “second wave” of North American LNG export facilities reach final investment decisions. Developers, financiers, and offtakers are all taking their time, however, to make sure projects make sense in the long term. The recent run of high prices comes after years of price declines and a COVID-related price collapse in 2020, which reduced the spreads between U.S. production and LNG destination markets, slowing the pace of LNG project development. One thing’s clear: Asia — always the focus of LNG demand growth — will become even more important going forward, and perhaps the best way to attract Asian offtakers to U.S., Canadian, and Mexican projects is to export from the Pacific Coast, assuming that feedgas can be sourced and delivered easily. In today’s RBN blog, we conclude our series on Pacific Coast LNG export development, this time focusing on projects in Western Canada.
After years of waiting on the so-called “second wave” of North American LNG, 2022 could finally be the year that sees multiple LNG export projects reach a final investment decision (FID). Global gas fundamentals have been bullish for about a year, and prices hit record highs throughout the summer and fall. Offtakers around the world are clamoring and competing for LNG cargoes, anticipating a volatile and undersupplied winter. But with Russian piped exports to Europe expected to increase dramatically as the controversial Nord Stream 2 pipeline finally comes online, likely early next year, North American LNG is looking for ways to be more attractive to Asian offtakers. One option on the table for North America is to go west and export from the Pacific Coast, which cuts the voyage time to Asia in half. Exporting from the Pacific Coast is not without its challenges, however, including where and how to source the feedgas required for liquefaction. In today’s RBN blog, we continue our series looking at Pacific Coast LNG export developments, this time focusing on feedgas and infrastructure for the LNG projects in Mexico.
For years, industry experts warned that the global LNG market was entering a period of extreme oversupply that would last until mid-decade. And up until late last year, that bearish scenario seemed to be materializing. Global gas prices had fallen as more LNG export capacity came online, and then COVID-19 decimated global markets and caused existing LNG terminals to shut-in production. But just as quickly as it collapsed, the market flipped. The world is now left scrambling to secure LNG/gas supply ahead of the heating season and global gas prices have hit record highs in recent weeks, signaling a turbulent winter ahead. Suffice it to say, utilities and governments have energy security and reliability on the mind, not just for prompt winter but for the longer term, and that pressure is unlikely to let up anytime soon. That’s brought previously commitment-wary LNG offtakers back to the negotiation table for new LNG export developments — cautiously and with a sharpened focus on de-risking long-term commitments amid heightened uncertainty. One way to do just that is to capitalize on the economic advantages of North America’s Pacific Coast projects. In today’s RBN blog, we continue our series looking at the state of LNG development on the North American Pacific Coast.
Last week, panic over gas availability and energy reliability this winter sent international natural gas and LNG prices above $30/MMBtu for the first time. Asia’s Japan Korea Marker (JKM), Europe’s Dutch Title Transfer Facility (TTF) and the UK National Balancing Point (NBP) once again had multiple days in a row of all-time high settlements, as the undersupplied market struggles to find balance. The global shortage has also impacted the gas-rich U.S. market, which is linked to it through LNG exports. The U.S. markets are tight and might also face undersupply this winter, albeit, probably not to the point of triggering reliability issues that are already emerging abroad. If it did, the U.S. exports nearly 10 Bcf/d of LNG, which could be throttled back to free up additional supplies for domestic use. Nonetheless, Henry Hub prices climbed to nearly $6/MMBtu last week and hit post-2008 record highs. This is by no means the first-time various markets have faced considerable imbalance. In fact, last year at this time we were coming out of a period of widespread oversupply and record-low gas prices. But it’s certainly foreboding that it’s not even winter yet, and prices are skyrocketing to new heights. So the big question on everyone’s mind is how bad could this get? The answer of course is complicated and heavily dependent on weather. In today’s RBN blog, “To the Moon and Back – U.S., International Gas Markets Strap in for Wild Winter Ride,” Lindsay Schneider takes a look at how we got here, how LNG has intertwined the international energy markets more than ever, and what that means for the winter ahead.
With multiple energy markets around the world facing natural gas shortages, buyers are clamoring for more LNG. Pre-winter panic-buying has sent global gas prices to record highs yet again in the past couple of days, and even hauled Henry Hub gas futures up to new post-2008 records above $6/MMBtu in after-hours and intraday trading. With the incredible run in global gas prices, U.S. export economics have looked extremely attractive for nearly a year now, and you would think that buyers would be lining up for new liquefaction capacity in the U.S. Well, it has certainly drawn prospective offtakers back to the table. But they are wary of rising export costs and committing to projects long-term given the questionable future for hydrocarbon markets. Additionally, Europe’s rising piped gas imports from Russia and overall declining demand in the region have put long-term prospects for European LNG imports, in particular, on shaky ground. So, access to Asia is more important than ever for new LNG development, a key selling point for projects on North America’s Pacific Coast, both because of proximity to Asian markets and the absence of canal fees or constraints versus the Gulf Coast. There are no LNG export terminals on the Pacific Coast currently, but two projects — LNG Canada in British Columbia and Sempra Energy’s Energía Costa Azul (ECA) LNG in Baja California, Mexico — are under construction and due online mid-decade. Those projects are unlikely to be the last, given the more than $1/MMBtu in cost savings due to shorter voyage times and canal-free access to Asia. In today’s RBN blog, we begin a series looking at the state of LNG development on the North American Pacific Coast.
Global gas and LNG prices are currently at record high levels. If we sound like a broken record, it’s because this epic bull run that started in the spring, has been roaring in recent weeks and showing little sign of slowing down. European prices have hit new post-2008 or all-time highs more than 25 times since late June, and prices in Asia, which had been at seasonal all-time highs for most of the spring and summer, finally last week also topped its previous all-time record from last January. A confluence of bullish factors, including high global demand, low storage inventories, weather events, and supply outages, have all contributed to the surge in gas prices. While many of these are near-term drivers and will eventually flip in the other direction, there is one bullish driver of global gas demand — European carbon prices — that will remain a constant in the years to come. That is by design because the carbon market is meant to serve as an incentive for the industry to seek greener solutions over fossil fuels. In today’s RBN blog, we look at the European Union’s Emission Trading System (EU ETS) and how it interacts with the global gas market.
It has been a chaotic 18 months for North American LNG and the global gas market. In a short time, international gas markets went from oppressively oversupplied balances, high storage inventories, and historically low prices for much of 2020, to reckoning with panic-inducing supply shortage, low inventories, multi-year or all-time high prices in the biggest LNG-consuming regions. The resulting whiplash has transformed key aspects of the LNG market, including making a profound impact on the way existing LNG terminals operate, how projects secure funding and capacity commitments, and what offtakers expect for the next generation of LNG capacity buildout. The tight market appears to have settled the question of whether more export capacity is needed, at least for now, but the market’s sharp U-turn has also put potential offtakers on edge and underscored the need for contractual flexibility. Additionally, pressure to reduce greenhouse gas (GHG) emissions is higher than ever, and LNG offtakers are increasingly demanding greener solutions to address government regulations and public concerns. This convergence of factors has put the LNG market at a crossroads. Taking all of the lessons learned from the past 18 months and before, the industry must now forge a new path forward. Today, we discuss highlights from our new Drill Down report, looking at the major trends that will define the North American LNG market in the coming years.
Global natural gas and LNG prices have spent the summer going from high to higher to the highest on record. The major European indices hit post-2008, and then all-time highs multiple times throughout the summer — even surpassing Asian prices on a handful of days. At the same time, Asian prices have set all-time seasonal records and are now sitting just below the previous single-day high settle from this past January. Usually, as the weather cools heading into fall, so do prices, but that’s unlikely this year as the European gas storage inventory is at the lowest level for this time of year than we’ve seen in recent history, and the time to replenish stocks for the winter is rapidly running out. The incredible bull run for global gas prices has been underpinned by high demand for LNG and the cascading effect of a supply squeeze in Europe, brought on by the triple threat of low domestic production, decreased imports from Russia, and a scarcity of incremental LNG cargoes. Not only is this driving record-high gas prices and increased volatility now, but the low inventory means sustained high prices for the heating season ahead. In today’s blog, we take a look at recent global gas price trends and the precarious European storage situation ahead of what is shaping up to be an incredibly bullish winter.
U.S. LNG is in the midst of a record-breaking year. Total LNG feedgas has averaged nearly 10 Bcf/d so far in 2021 and the country is on track to export somewhere around 1,000 cargoes this year, 40% more than last year. Although pipeline maintenance and flow constraints have knocked feedgas off the all-time highs seen earlier this year, feedgas and exports are likely to hit new record levels to close out the year as Sabine Pass Train 6 and Calcasieu Pass prepare to start service in early 2022. The strength in U.S. LNG export demand this year is underpinned by an incredibly bullish global gas market, which has led prices in both Europe and Asia to hit all-time highs. This has not only benefited the existing fleet of terminals, but the prolonged bullish global gas market has accelerated commercial activity for future LNG projects. Since May, more than 12 MMtpa of capacity from LNG terminals or liquefaction trains under development has been sold, pushing several prospective LNG projects closer to a final investment decision (FID). RBN covers all of the latest in our LNG Voyager Quarterly report, but in today’s blog, we take a look at some of the highlights from the report, focusing on the biggest changes in LNG development this summer.
Global gas prices have had a record-breaking year so far, with JKM in Asia hitting all-time seasonal highs in spring, and TTF in Europe last week reaching the highest level since 2008. Prices have been spurred on by a global LNG market that is undersupplied and hunting for additional cargoes. If you were just looking at U.S. feedgas levels over the past several weeks, though, you would never know that we are in the middle of an incredible bull run. U.S. LNG feedgas deliveries have trailed below full-utilization levels for more than a month due to a combination of spring pipeline maintenance, LNG terminal maintenance, and operational issues. The reduced availability of pipeline and liquefaction capacity led feedgas deliveries in June to average 9.35 Bcf/d, or about 85% of full capacity. However, this was just a small and short-lived setback before what is likely to be a breakthrough summer for U.S. LNG. Feedgas demand is already back above 95% utilization and is poised to head even higher over the next few months both from new liquefaction capacity coming online and potentially from spot market cargo production. In today’s blog, we take a look at the impact of spring maintenance on U.S. LNG production and potential feedgas demand growth in the months ahead.
