The European gas year commenced October 1 with expectations of high winter demand and commensurate gas and LNG prices. However, in recent days the press — both trade and mainstream — have remarked on the number of laden LNG carriers that have been circling, anchored or drifting around the Mediterranean and East Atlantic. This flotilla, currently numbering about 30 cargoes, or 2.1 million metric tons (MMt) of LNG, has been growing since late September and includes some cargoes that have been at sea for over a month. Although floating storage ahead of winter demand is nothing new, the scale of the current phenomenon is unprecedented. In today’s RBN blog, we explore the implications for European gas pricing and market dynamics.
Posts from Richard Pratt
With international gas prices ranging somewhere between ridiculous and ludicrous since last fall, the entire global trade of LNG is going through an unprecedented period of change as gas-consuming nations try to cope with the current situation and seek protection from tight supplies and high prices in the future. The problems of Europe in securing supplies for the imminent winter have been well documented here and elsewhere in the trade press. In addition to being a major struggle for consumers and a headwind to economic development, there are also numerous, less-obvious consequences of the tectonic shifts in gas fundamentals, including countries’ individual plans for long-term energy supplies, potential tax-related issues, the contractual structures used to transact LNG, and even the assessments of the commodity price itself. These issues aren’t new and, in many cases, have been discussed for years. What’s changed is that extremely high prices have thrown into sharp relief any inefficiency or risk that exposes market participants. In today’s RBN blog, we consider the impact of high global gas prices on countries in Asia and Europe and how pricing mechanisms might be affected.
Two of the biggest challenges that Europe faces in the race to wean itself off Russian natural gas are the need to develop new pipeline connections between the continent’s many isolated gas networks and to integrate the European Union’s multiple gas markets. Addressing these won’t be easy. Unlike the U.S., whose pipeline systems were designed to transport gas long distances and across jurisdictional lines, Europe’s networks are more regional or even local in nature, and only recently has the EU been taking steps to link the continent’s markets. Oh, by the way, U.S. producers and LNG exporters should care about all this, because if Europe gets its act together, it could become an even larger and longer-term recipient of gas originating from the Permian, Haynesville, Marcellus/Utica and other shale plays. In today’s RBN blog, we discuss the prospects for tying together the EU’s gas pipelines, gas storage facilities, LNG import terminals and gas markets.
The Russian war against Ukraine has focused Europe on the issue of energy security, especially as it relates to natural gas. The continent has previously relied on Russia for more than 40% of its gas, but it now must scramble for new suppliers and alternative forms of energy. The matter is particularly urgent in a few countries along or very near the Russian border, including Lithuania, Poland and Ukraine itself. Fortunately, almost two years ago the three countries formed the “Lublin Triangle,” an alliance of sorts with the aim of enhancing military, cultural and economic cooperation while also supporting Ukraine’s prospective integration into the European Union and NATO. In today’s RBN blog, we discuss the potential for developing a “New Gas Order” in Europe.
In the nearly 60 years since its inception, the LNG industry has changed significantly. Once a market in which cargoes were sold under long-term, point-to-point contracts in dedicated ships, it has evolved into one in which destination flexibility accounts for an increasing share of LNG trade, with more volumes being sold under short- and medium-term contracts. The changes reflect a trend toward the increasing commoditization of LNG, with the similarities between the LNG and crude oil markets becoming apparent. In today’s RBN blog, we look at the differences in how the oil and LNG markets have developed, whether LNG might achieve the same commodity status as oil, and why the major market players may not want LNG to follow the path of its older cousin.
In response to Russia’s invasion of Ukraine, Europe is planning massive and rapid changes in its natural gas supply, including a significant increase in LNG deliveries from the U.S. But there are major challenges and implications associated with this shift. For example, how can the U.S. government prod U.S. exporters to send more LNG to Europe? How can LNG buyers — or sellers — collaborate without running afoul of European Union antitrust laws? Can the development of new LNG import terminals be fast-tracked? And can long-term contracts for Russian pipeline gas be breached without penalty now that Russia has suspended deliveries to Poland and Bulgaria for not paying in rubles? In today’s RBN blog, we discuss what U.S. and European efforts need to overcome.
The first wave of LNG projects has done more than just catapult the U.S. to the top tier of LNG exporters, it has reshaped markets, helped move LNG closer to being a true global commodity, and spurred changes in everything from ship sizes and routes to contract types and pricing formulas. Talk about having an impact! And, with new projects still coming online in the U.S. and final investment decisions expected on new terminals and expansions this year, the U.S. LNG industry’s effect on the global gas trade is sure to grow. In today’s RBN blog, we look at the practical impacts that have accompanied growing U.S. production with an emphasis on logistics and, perhaps most important, the changes to LNG pricing in Asia.
As recently as the mid-to-late 2000s, the U.S. was expected to become a major importer of LNG. Instead, the opposite occurred. Once forecast to need tens of millions of metric tons of LNG each year to meet its own power needs, the U.S. is now producing about the same amount and sending it out to Asia, Europe, and other overseas markets. That swing — from the expectation of being a major LNG importer to the reality of being a top-tier producer/exporter — has had a huge impact on the global market, and the influence of that reversal cannot be overemphasized. In today’s RBN blog, we look at how U.S. production has moved LNG closer to being a global commodity, the effect of growing U.S. production on the market, and prospects for future growth.
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.
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.
A major driver for global growth in natural gas use, including LNG, derives from the power-generation sector. Large Japanese utilities introduced LNG into the power fuel mix in the early 1970s. More recently, a number of utilities in other countries have increased their use of gas-fired generation — and their imports of LNG — largely due to gas’s lower emissions profile and the flexibility that gas plants offer in balancing variable demand loads with variable dispatch profiles, including wind farms and solar facilities. The growing availability of LNG has also spurred interest among independent power producers (IPPs) in developing similar gas-fired projects, but so far fewer than 10 such projects have come online and some do not operate at their full potential. Why has LNG-to-power made such little headway in the independent-power segment? In today’s RBN blog, we examine the special nature of IPP-owned LNG-to-power projects and the challenges they pose not only to their sponsors but to LNG suppliers.
Of the 10 Bcf/d, or more than 75 MMtpa, of nameplate LNG export capacity currently operational in the Lower 48, Japanese companies form the largest single group lifting U.S. cargoes. Their commitments total ~2 Bcf/d of U.S. liquefaction capacity. However, Japan’s LNG consumption has been falling over the past two years, and in 2019 and 2020, U.S. LNG accounted for only 0.6 Bcf/d and 0.8 Bcf/d of Japanese imports, respectively, or about 20% of the country’s total LNG demand in each year. In other words, Japanese companies have made commitments for incremental LNG from their remotest supply option against a backdrop of falling domestic demand. In all cases, the Japanese players have opted not to buy FOB from producer projects, but instead have booked capacity at the Cove Point, Cameron, and Freeport LNG export facilities — all plants that require offtakers to secure and transport the feedgas supply for LNG production. This type of arrangement carries with it the need to set up gas trading desks in the U.S., with front-, middle- and back-office personnel, plus operations staff, representing additional fixed costs. What was the motivation for these commitments, made by no less than seven of Japan’s major LNG buyers, how successful have they been, and what lies in store for these volumes that the country does not appear to need? Today, we look at where these volumetric commitments fit, not only in the portfolios of the capacity holders but within the broader context of LNG commerce and commoditization.
IMO 2020, the mandate that ships plying most international waters slash their sulfur emissions starting in January of last year, was only another step in the International Maritime Organization’s long-running effort to ratchet down the shipping industry’s environmental impact. The group’s next focus, as you might expect, is reducing shippers’ carbon footprint — while no specific rules have been set, the IMO in 2018 laid out the goal of cutting ships’ carbon dioxide emissions by 40% from their 2008 levels by 2030. One way to move toward that goal would be fueling more ships with LNG, which emits 20-25% less CO2 than very low sulfur fuel oil. But as we discuss in today’s blog, shippers could augment those emission reductions by moving from the LNG trade’s traditional point-to-point model to optimization through cargo swapping.
On the surface, it may seem that the LNG market has normalized after the past year’s tumult, and it’s true that many of the day-to-day disruptions that plagued LNG offtakers and operators have subsided. Mass cargo cancellations are a distant memory, and U.S. LNG exports have been flowing at record levels. Global demand has recovered, and buyers are back to worrying more about what they normally worry about: storage refill and securing enough supply for the next winter. However, in other ways, the pandemic and the more decisive shift toward decarbonization measures in many ways have fundamentally changed how deals for future LNG development will get done. Today, we look at what the global initiative to reduce greenhouse gas emissions will mean for LNG project financing.
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.