Posts from Richard Pratt

China regained its place as the world’s largest LNG importer in 2023, a title it lost in 2022 due to COVID-related shutdowns. Given that China only started importing LNG in 2006, the country’s demand growth — imports last year totaled 71.3 million metric tons (~9.5 Bcf/d), just under 18% of globally traded demand — can only be described as spectacular. But this unprecedented growth story is undergoing fundamental changes which are likely to result in major impacts to LNG commerce not only in China but in the Far East and possibly beyond. In today’s RBN blog, we look at some of these changes and ask how the Big Three national oil companies (NOCs) — CNOOC, PetroChina and Sinopec — could change their business models as smaller provincial gas utility buyers pursue their own LNG imports. 

LNG commerce is composed of two primary models. One is the traditional point-to-point model, on which the industry was founded and still accounts for more than 60% of LNG trade. More recently, the portfolio model has emerged, pursued by upstream oil and gas majors, that would allow them to monetize their gas reserves by converting them to LNG and shipping the product worldwide in vessels under their control — an attractive strategy that also would allow them to increase their exposure in the LNG market to take advantage of international arbitrage opportunities. As such, they are always long in LNG and in the ships required to move it. However, the portfolio model is being infiltrated by a buyer community looking to become short-side portfolio players and increasingly committing to long-term offtake agreements or FOB sales, then shipping LNG not only to meet their domestic market needs but to take advantage of regional pricing differentials. In today’s RBN blog, we look at the rise of the short-side portfolio player model and ask who might prevail in a potential clash of titans over market share and dominance. 

Many have argued that U.S.-sourced LNG can be instrumental in combating climate change by helping countries around the world replace coal-fired generation with natural gas-fired power. While this argument carries a lot of force in the eyes of many politicians and LNG marketers, the questions of exactly how — and to what extent — LNG can replace coal need to be asked. In today’s RBN blog, we’ll look at the challenges that the expanded use of LNG faces in countries with high coal utilization and the possible means of overcoming them. 

LNG export projects looking to take a positive final investment decision (FID) need to sell a high proportion of their nameplate capacity under long-term contracts to ensure sufficient cash flows to underpin the project and obtain financing. U.S.-based projects (new and expansions) totaling more than 350 million tons per annum (MMtpa, 48.3 Bcf/) — against a current global market of 400 MMtpa (52.9 Bcf/d) — are vying for creditworthy offtakers from multiple markets in their pre-FID deliberations. The sense of urgency among project sponsors has been boosted by the Russia/Ukraine war and a potentially resurgent Chinese economy, both of which should promise a bright future for new projects. Plenty of those have reached FID in the last couple of years, but what is holding others back from taking the same step? In today’s RBN blog, we’ll look at some of the factors impacting those decisions and the long-term implications that flow from them. 

Cargo ships move more than 80% of the world’s internationally traded goods, making them essential to the global economy, but they’ve traditionally been fueled by heavy fuel oil or marine gasoil, both of which are emissions-intensive. With 60,000 or so ships in service, they account for an estimated 2.8% of global greenhouse gas (GHG) emissions, a percentage the International Maritime Organization (IMO) would like to reduce. At the 80th session of the IMO’s Maritime Environment Protection Committee (MEPC) in July, the group adopted a provisional agreement to eliminate GHG emissions from shipping by a date as close to 2050 as possible, with intermediate goals for emissions reduction by 2030 and 2040. Clearly, radical innovations will be required to meet the IMO’s goals. In today’s RBN blog, we look at some of the initiatives directed at emissions reduction in shipping and the challenges to (and opportunities for) operational improvements, especially regarding LNG carriers.

In the period between Russia’s invasion of Ukraine in February 2022 and the end of last year, LNG sales and purchase agreements (SPAs) totaling 47.23 million tons per annum (MMtpa; 6.3 Bcf/d) were signed between buyers and nine U.S. LNG projects under development. Of those, the projects that will ultimately secure a critical mass of reputable offtakers and achieve a final investment decision (FID) must also secure permitting and financing. Two project FIDs were taken in 2022: Cheniere’s Corpus Christi Stage III in Texas and Venture Global’s Plaquemines Phase 1 in Louisiana. Although two more FIDs have recently been announced — Plaquemines Phase 2 and Sempra’s Port Arthur Phase 1 — there can be a timing disconnect between the commitments LNG buyers are prepared to make and the ability of project sponsors to deliver on their plans. In today’s RBN blog, we focus on the increasingly important role of financing in the implementation of U.S. LNG projects and the challenges that project developers and sponsors face.

From its origins as a specialized energy source sold under long-term, point-to-point contracts to primarily Asian destinations, LNG has become progressively more commodified as its global reach has spread, with 44 countries now importing it. An increasing proportion of cargoes are destination-flexible and can be sent to the market that offers the best price, and the marginal price of LNG is set by supply and demand factors. The spectrum of commercial players has grown and come to resemble more closely the oil market, with not only international oil companies as major participants but also traders and utility buyers, all of whom are contributing to a vibrant international LNG marketplace. But unlike oil and other established commodities, LNG lacks a global reference or benchmark price, and instead is priced regionally, with the divergence in regional market prices giving rise to very profitable arbitrage opportunities for those controlling both product and ships. In today’s RBN blog, we look at the pricing indices used to make LNG trading decisions and two initiatives being implemented by the European Commission (EC) that are intended to improve price transparency for LNG trades and prevent price spikes in European gas markets through a consortium-purchasing approach.

Russia’s invasion of Ukraine in February 2022 caused panic in European gas markets that were already on the brink due to low winter inventories. Near-term supply/demand balances suddenly took on a heightened urgency, and everyone knew that policy and infrastructure changes were needed, pronto. The most immediate concern was the very real possibility that the winter of 2022-23 could see gas rationing within the European Union (EU) due to supply shortages. However, with winter now in retreat, Europe is emerging with record volumes of stored gas accompanied by prices that have fallen to pre-invasion levels. This is no time for complacency, though. While it’s many months away, the winter of 2023-24 looms, with dire warnings that things could be considerably worse in gas markets. In today’s RBN blog, we evaluate how European gas and LNG markets have managed over the last 12 months and discuss the implications for the next year. In particular, we look at the European Commission’s (EC) efforts to inject reforms into European gas markets, not only to accommodate supply disruptions but also to set the stage for a gas market no longer reliant on Russian supplies.

2022 was a particularly significant year for the global LNG industry, distinguished by a sharp increase in LNG demand in Europe tied to the reduction in flows of Russian pipeline gas after Putin’s invasion of Ukraine. Whereas Europe had historically been the last market option for many LNG sellers, it became the most highly priced market in the world and pulled in LNG from multiple locations, including a cargo from Australia delivered in October. Paying premium prices enabled European buyers to fill the continent’s underground storage at an unprecedented rate — as of mid-January, storage there was over 80% full. A mild winter, at least to date, coupled with conservation efforts and fuel switching have reduced European natural gas demand by 10% to 15% and helped avoid a gas shortage. Now, gas prices (and LNG cargo prices) have fallen to pre-invasion levels and prompted market observers to suggest that, with China emerging from pandemic-related lockdowns, Asia may start pulling large volumes of LNG its way. In today’s RBN blog, we examine LNG cargo movements within the Asia Pacific and Atlantic regions and what rising Asian demand could mean for European gas supplies going forward.

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.

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.

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.