The energy market dislocations of the COVID era have accelerated consolidation in the midstream sector as oil and gas gatherers — and gas processors — in the Permian and other basins seek greater scale, improved reliability, and the potential to direct more hydrocarbons through their takeaway pipelines. New evidence of this trend came just last week, when Enterprise Products Partners announced it has agreed to acquire privately held Navitas Midstream Partners, a fast-growing gas gatherer and processor in the Permian’s Midland Basin, for $3.25 billion. As we discuss in today’s RBN blog, the acquisition will give Enterprise its first gas gathering and processing assets in the heart of the Midland and may boost volumes on its residue-gas and NGL pipelines there.
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.
Among the 21 countries able to liquefy methane and export LNG, Australia, Qatar, and the U.S. are the hands-down leaders, holding more than half the world’s liquefaction capacity among them. For now, Australia holds the top position but its capacity buildout is all but complete. While a number of liquefaction projects are planned Down Under, only one has reached the final investment decision (FID) stage in 2021, and it’s relatively small. Future growth seems much more likely to come from the two other big guns. Developers in the U.S. are cautiously thawing the plans for LNG projects they put on ice in mid-2020, when global natural gas prices slumped along with economies during the early months of the COVID-19 pandemic. And in February, Qatar, which was runner-up to Australian capacity until it slipped to third place due to recent U.S. additions, took FID on the first of two supersized projects to expand its LNG capacity. In today’s RBN blog, we discuss Qatar’s expansion plans and how they relate to developments elsewhere.
For the next few years, New Englanders will remain heavily dependent on natural-gas-fired generation — and keep their fingers crossed regarding the availability of piped-in gas for power during periods of frigid winter weather. But the power sector in the enviro-conscious six-state region has ambitious plans to gradually ratchet down its reliance on gas and other fossil fuels and increase the role of wind, solar, and battery storage. Over time, that could help to alleviate the gas-supply risk associated with New England’s seasonally insufficient gas pipeline capacity. However, front-and-center roles for highly variable renewable energy sources could pose reliability challenges of their own. In today’s RBN blog, we discuss the evolution of the region’s electric grid and what it may mean for natural gas producers and midstreamers.
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.
Japan’s strategy for LNG imports has been based on security and reliability of supply, with JERA, the country’s largest LNG buyer, reliant on supply contracts that can last for 20-25 years. Those deals have been of paramount importance since imports to Japan started in 1969, but things are changing in a big way. In parallel with Japan’s plan to decarbonize its economy, JERA has made clear its intention to reduce its dependence on long-term LNG contracts and instead focus more on short-term deals supplemented by spot market purchases. This decision will have several important effects, and in today’s RBN blog, we look at what it may mean for the LNG industry.
In early December, natural gas production in the Permian has been averaging a record 14.2 Bcf/d, a gain of 1 Bcf/d in only six months. That rapid pace of growth is putting pressure on every aspect of midstream infrastructure — gas gathering systems, processing plants, and takeaway pipelines — and resulting in a variety of efforts aimed at ensuring there will be sufficient capacity in place to support the increasing gas volumes being produced. New gas-gathering mileage is being added, some new processing plants are being built, and at least a couple of new large-diameter pipelines from the Permian to the Gulf Coast are being considered. However, reflecting the midstream sector’s financial discipline, there’s also a big push to make fuller use of existing assets, in some cases by relocating processing plants, compressors, and other assets to where they are needed most. In today’s RBN blog, we discuss the latest gas-related infrastructure developments in the Permian’s Midland and Delaware basins.
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’s no secret to anybody paying attention to U.S. natural gas markets that Appalachia has long been bedeviled by midstream constraints, often leading to deep gas price discounts. There have been brief respites when new capacity has come online, allowing more gas to flow out, but if you've been reading our blogs and natural gas reports lately, you know we've been sounding the alarm about the growing specter of constraints reemerging. Across the country, the boom in pipeline reversals, greenfield projects, and pipeline expansions that characterized much of the 2010s is pretty much over, with just a couple of approved expansions left, and it’s gotten much harder for projects offering additional capacity to gain traction, especially in the Northeast. In today’s RBN blog, we consider the big questions facing the region: how fast will Appalachian gas production grow, how much running room do producers have left, and what are the implications of midstream constraints for forecast supply growth?
There’s been a slew of high-profile shipments of “carbon-neutral LNG” the past few months, typically involving the use of carbon credits to offset, ton-for-ton, the carbon dioxide equivalent of greenhouse gases released during the production, piping, and liquefaction of natural gas, the shipping of LNG, and often the regasification and ultimate consumption of the gas too. The problem is, there is no widely agreed-to definition for carbon neutral, nor is there a consensus on how to quantify and validate the GHG “footprint” of a specific LNG cargo. Now, an international group representing the world’s LNG importers has established a framework for “GHG-neutral LNG” that it hopes will gain widespread acceptance. Elements of the proposal are sure to be controversial, however, as we discuss in today’s RBN blog.
The Permian has been a leader in domestic oil and gas production for decades but the Shale Revolution made it a global superstar. In the past few years, thousands of miles of new crude oil, associated gas, and produced-water gathering systems have been installed in West Texas and southeastern New Mexico, as have dozens of new gas processing plants and a number of new takeaway pipelines for oil, gas, and NGLs. Lately, there has also been a lot of consolidation among Permian midstream companies, mostly with the aims of increasing scale, improving reliability, and directing more hydrocarbons through the combined companies’ gathering, processing, and takeaway assets. In today’s RBN blog, we continue our review of recent, major pipeline-company combinations in the Permian and the benefits participants expect to realize from them.
Determining whether to approve plans for interstate natural gas pipeline projects has never been an easy task for the Federal Energy Regulatory Commission. There are so many things to consider, chief among them the need for the pipeline, impacts on the environment and landowners along the route, and what it all means for gas customers. But as complicated as the decision-making process may be, at least pipeline developers, gas producers, and customers knew that once a new pipeline was approved by FERC, permitted, built, and put into service that the matter was closed — that is, the pipeline was here to stay. Now, in the wake of a groundbreaking court ruling on a new gas pipeline near St. Louis, things are not so certain. As it turns out, we’re intimately familiar with the matter, having just made the case that the 65-mile Spire STL Pipeline is an important addition to the regional pipeline network that provides supply diversity, improved reliability, and access to lower-cost gas. In today’s RBN blog, we consider the evolution of FERC regulation of gas pipelines and the new uncertainty that all affected parties face.
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.
The number of floating storage and regasification units in operation has nearly doubled in the last few years, but that’s hardly a shock given the growth in the global LNG market. What might be a surprise is how a number of these specialty vessels are being utilized and what it could mean for the shipowners and the wider LNG market. In today’s RBN blog, we look at specific projects to gauge the progress made in the FSRU space, the recent slowdown in orders, some of the challenges the sector faces, and the trends emerging for new and converted FSRUs.
As the new heating season in North America gets under way, the natural gas sector in Canada, the U.S., and even globally, is experiencing a surge in gas prices to levels unseen in many years. In Canada and the U.S., you would have to go way back to 2008-09 to find the most recent instance of $5/MMBtu-plus gas heading into a heating season. As for the rest of the world, it has never experienced prices at the levels reported in the past few months — north of $30/MMBtu in some places. The big question, as always, is: where do we go from here? In today’s RBN blog, we review our 2021 pricing outlook for Canadian gas and discuss our forecast for 2022.