LNG imports

New England is hell-bent on decarbonizing quickly, and it’s been making some progress. But like it or not, the region still depends heavily on natural gas for both power generation and space heating, and gas supplies are stretched to the limit during periods of extreme winter demand. Worse yet, the Everett LNG import terminal, which for years has fed a big, soon-to-close gas-fired power station and supported the Boston area’s gas grid, may be on the verge of shutting down. Well, help may finally be on the way. Enbridge recently proposed an expansion to its 3-Bcf/d Algonquin Gas Transmission pipeline system. The question is, can it get built in a region notorious for its opposition to energy infrastructure projects? In today’s RBN blog, we discuss Enbridge’s Project Maple and the role it could play in New England’s aggressive plan to reduce its greenhouse gas (GHG) emissions.

Russia’s invasion of Ukraine last February upended long-standing expectations about natural gas supplies to Europe and resulted in elevated global gas prices as countries bid for LNG to fill the void. But U.S. suppliers can only produce so much LNG, and how much of it ends up in Europe versus Asia or other gas-consuming regions in 2023 and beyond will depend largely on market forces — in other words, who needs the LNG more and is willing to pay up for it. At the center of these market-based decisions about LNG cargo destinations are large portfolio players like Shell, BP, TotalEnergies and Naturgy and short-side portfolio players like Japan’s JERA. In today’s RBN blog we look at these two types of players, the roles they play, and their contributions to energy security.

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.

Imported liquefied natural gas from the U.S. is helping Mexico address major challenges facing its gas sector. For one, LNG shipments from the Sabine Pass export terminal in Louisiana to Mexico’s three LNG import facilities have been filling a gas-supply gap created by delays in the country’s build-out of new pipelines to receive gas from the Permian, the Eagle Ford and other U.S. sources. Imported LNG also is playing — and will continue to play — a key role in balancing daily gas needs within Mexico, which has virtually no gas storage capacity but is planning to develop some. Today, we consider recent developments in gas pipeline capacity, gas supply, LNG imports and gas storage south of the border.

With liquefaction capacity and supply of liquefied natural gas on the rise and LNG demand flat, prices for super-cooled, liquefied gas are low and may well stay low into the early 2020s. That’s a concern for LNG suppliers, who (like all suppliers) would prefer it if demand was soaring and supply was a little tight. There are some rays of hope, though, in what many have seen as a gloomy time for the LNG sector. After all, with spot LNG prices below $5/MMBtu (far lower than they were 30 months ago) and ample supplies of LNG available, a growing list of nations are looking either to become LNG importers or to significantly expand their LNG imports. Today, we continue our review of the LNG market with a look at the new demand that may be spurred by supply surpluses and low prices.

Mexico has emerged as an important and growing market for U.S. natural gas producers, and for U.S. midstream companies scrambling to develop gas pipelines to serve Mexico’s gas consumers. Meanwhile, U.S. gasoline, diesel and liquefied petroleum gas (LPG) exports to Mexico are also up. Petróleos Mexicanos (Pemex)—the state-owned hydrocarbon giant, now in the midst of a major reboot—is on the hunt for private-sector partners to help revive Mexico’s sagging oil and gas production, and U.S. oil producers and Pemex are planning their first swaps of crude. Today we highlight RBN Energy’s latest Drill Down report examining the changing yins and yangs of cross-border energy relations.

Depending on whom you believe, the international liquefied natural gas (LNG) market is either struggling through a period of oversupply and rock-bottom prices or poised for a new round of demand growth based on that low-cost supply abundance. (Hint: The answer may well be both of the above.) For electric and natural gas utilities that want to become LNG importers as quickly—and as cheaply--as possible, an increasingly popular option is buying or (more likely) chartering a floating storage and regasification unit, or FSRU. Today, we look at the growing use of FSRUs and how they may boost the LNG market.

The much-discussed shortfall in natural gas pipeline capacity into New England has been largely mitigated this winter because generators—encouraged by low oil prices and incentives to lock in backup supplies of oil and LNG—are ready, willing and able to switch their dual-fuel power plants away from pipeline natural gas and onto oil and LNG-sourced gas if market conditions warrant. But now that prices for those fuels are more attractive, could switching to oil and imported LNG during winter’s coldest days and nights actually be a longer term solution to New England’s pipeline capacity problem instead of just a stopgap until new pipelines are built? Today, we begin a look at the changing economics of burning oil and LNG-sourced gas to help power New England when the region turns arctic, and what they may mean for proposed pipeline expansion projects.

It would be an understatement to say that the worldwide market for liquefied natural gas (LNG) is in flux. LNG production is up and heading higher, oil—and LNG--prices are down sharply from a few months ago, and Japan and other big consumers of LNG are more interested than ever in mitigating price and supply risk. All this comes as Japan, a primary target of prospective U.S. and Canadian LNG export projects, is grappling with the need to restart dozens of idled nuclear units so it can reduce the oil and LNG imports that have hurt its trade balance since the Fukushima disaster nearly four years ago. Today we consider recent developments and how they may affect Japan and its potential LNG suppliers on the North America side of the Pacific.

Chemicals, gas-to-liquids (GTL), steel and other industries that consume large volumes of natural gas either directly or as a fuel, expecting the new era of low and stable gas prices to continue are planning tens of billions of dollars in new or expanded facilities in the U.S. But how many of those plans will become a reality? Could the much-anticipated industrial renaissance be undermined by the higher gas prices that might come with the approval of a few more LNG export terminals, new environmental regulations that spur still more gas-fired power generation, and higher natural gas exports to Mexico? Those are critically important questions to gas producers and marketers, who are struggling to figure out just how quickly—and how much—demand for gas will rise. Today we continue our exploration of industrial demand for natural gas.