Editor’s Note: This column is part of a regular series by industry veteran Brad Hitch for NGI’s LNG Insight dedicated to addressing the complexities of the global natural gas market.
Evaluating the European gas market is one of the natural first steps for anyone looking to measure the impact of LNG on the U.S. natural gas market.
Europe’s natural gas market is the world’s largest outside of North America. It is home to significant underground storage capacity and well-developed liquefied natural gas supply infrastructure. It also attracts a great deal of attention, especially nowadays.
The European gas trade has found itself in the crosshairs of the Ukraine conflict. Moreover, the European energy industry has long been at the forefront of efforts to eradicate carbon emissions and push the boundaries of decarbonization altogether. The war and the continent’s energy transition have conspired to make the European gas market the focal point for evaluating tradeoffs between energy security and net-zero emissions goals.
Europe is a good place to take the next part of this series, which I’ve dedicated to exploring how global gas fundamentals and LNG impact U.S. gas flows and prices, among other things.
Beyond the current news cycle, European gas data is likely to attract attention from U.S. gas market analysts for the more pedestrian reason that information is readily available. Starting with the UK’s National Balancing Point, Europe has had a commoditized spot market with published prices almost as long as North America.
Over the last decade, the European Union has also made great strides in making gas market data broadly available. For example, underground gas and LNG storage levels, pipeline flows, and maintenance outages are all collected and put into the public domain.
Unlike other sectors of the global gas market, much of the challenge in measuring Europe’s impact on U.S. natural gas production is knowing what details matter and when. With that in mind, the very first thing to figure out with relation to Europe at any point in time is whether it is on the margin of LNG flows.
Supply Push vs Demand Pull
European gas companies in France and Belgium were among the very first importers of LNG in the 1980s, but large gas discoveries offshore Norway, Netherlands and the UK stymied the need for LNG around that time.
Things started to change at the turn of this century, however, and Europe experienced a large buildout of new LNG import terminals in the Netherlands, France, Italy, and the UK, as well as an expansion of the Zeebrugge terminal in Belgium.
Despite the buildout of LNG infrastructure from the mid-2000’s, import volumes into Northwest Europe remained very sporadic until 2019. In the years since, Europe has seen larger import volumes on a much more consistent basis, but not for consistent reasons.
Increased LNG flow into Northwest Europe prior to 2021 was primarily a supply-push phenomenon. That compares to LNG import volumes over the last fourteen months, which have been driven by the need to balance the European gas market in the wake of missing Russian imports.
The regime shift can be illustrated by the relationship between underground storage levels and LNG import flows.
Before Russia amassed troops on the Ukraine border, Gazprom had been very slow to fill its storage capacity in Central and Western Europe under the guise of prioritizing domestic Russian storage. Consequently, Europe entered the 2021-2022 winter with storage levels lower than they had been at the start of any winter since 2013-2014.
By the start of injection season in 2022, storage levels were still low, but not to the point of being a historical outlier. Storage was lower in 2018 than in 2022, but last year there existed the prospect of a winter with little or no pipeline imports from Russia.
What happened next is probably familiar to anyone that has been paying attention to the LNG market over the last couple of years. Europe carried on an aggressive and extended injection season in 2022 that was supplied in no small part by increased LNG imports, which hit record levels last year.
What stands out is the summer of 2018, or the last time the European injection season started with lower storage levels. It was also the last time LNG import levels were low through the entire injection season. In many ways, 2018 and 2019 represent the perfect encapsulation of the relationship between LNG and European gas that predated the Ukraine conflict.
Northwest European LNG imports remained modest in the summer of 2018 despite a somewhat urgent need for injections. However, once the Asian LNG market became oversupplied starting in 3Q2018, LNG imports into Northwest Europe hit levels never seen before. The large 2018 increase in imports helped to trap gas underground, eventually leading to historically high storage levels at the beginning of the 2019 injection season.
Nevertheless, the well-supplied LNG market continued to push volumes into European terminals through the following summer and winter, eventually culminating in a new record for season-ending storage levels in the spring of 2020.
The Covid-19 pandemic was in full swing by then, of course, and without recourse to healthy Asian markets, excess LNG continued to plough into European terminals through May 2020.
With storage filling early, there was nowhere else for the LNG to go, and U.S. liquefaction terminals entered a period of significant market-induced shut-ins amid lackluster demand, a supply glut and plummeting global gas prices.
LNG import history shows that demand pull wasn’t the primary factor in determining European regasification levels until the start of the war in Ukraine. Whether and to what extent the demand pull regime can last through the injection season of 2023 will be very interesting to see.
Europe is about to enter an injection season with storage levels not seen since 2020. This year, it looks like inventories will come in just below where they were at the start of the 2020 injection season and way above any other year.
Using 2020 as a proxy, the year-on-year reduction in demand for injections this season could be in the vicinity of 300 TWh, or the equivalent of approximately 300 fewer cargoes of LNG required to fill storage. Spread over a six-month injection cycle, that equates to 50 cargoes per month – or about half of current U.S. export levels.
Does this mean that we should expect to see an immediate decrease in the call on U.S. LNG imports? Not necessarily.
What it certainly means is that there will be LNG available to fill demand in Europe and elsewhere that has lately been served by more carbon-intensive fuels or shut-in altogether by high prices.
Whether the anticipated reduction in European injection demand could go so far as to push back on U.S. exports this summer has to be thought of in the context of global LNG fundamental factors that we will cover in later columns of this series.
In the next column, we will finish our look at Europe by examining Norwegian and other suppliers. We’ll also explore how to think about European demand at lower price levels and consider whether to expect a regime shift away from an LNG market that is currently being driven by Europe.
Brad Hitch has spent more than 23 years working in LNG and natural gas trading from London and Houston. He currently works as an adviser to new market entrants, and he has held senior trading and origination positions at Barclays, Cheniere Energy Inc., Enron Corp., Merrill Lynch and Williams. With experience that includes establishing one of the first LNG trading desks, he has participated in various stages of the global gas market’s evolution. During his time at Merrill Lynch, he worked as head strategist on the European gas desk and led an initiative to enter the LNG trading market. Prior to returning to Houston, he worked for Cheniere in London and was primarily responsible for establishing and managing a derivative trading function. He holds an MBA from the Wharton School at the University of Pennsylvania and a BA from the University of Kentucky.