Debt and Optionality in U.S. LNG Export Projects.

• Author: Hartley, Peter R.
• Position: Liquefied natural gas

1. INTRODUCTION

   Compared to previous liquefaction developments, recent U.S. liquefied natural gas (LNG) export projects have more of their output exposed to spot trades. For example, data from the International Group of Liquefied Natural Gas Importers (GIIGNL) reveals that while around 32.5% of LNG trade over the period 2016-2020 was spot and short-term (contracts of less than 3 years duration), about 68% of U.S. LNG exports were so designated. Several characteristics of the U.S. projects have favored more spot trading.

   On the one hand, spot trading allows the U.S. projects to capture the value of many embedded real options. On the other hand, reducing the long-term contract share constrains the use of debt finance. We investigate this trade-off by developing a stylized stochastic model of a hypothetical U.S. LNG export project.

   We demonstrate that U.S. LNG export projects have an opportunity, and stronger incentives, to leave output uncontracted, to remain flexible about where and when they ship cargoes, and to exploit arbitrage opportunities provided by imperfectly correlated spot price movements. We find that the modal operating profits for the representative U.S. LNG export project are unlikely to cover fixed costs, interest, and taxes at usual leverage ratios. Nevertheless, exploitation of real options via spot trading produces a strong right skewness of the cash flow and implies that the mean real equity return is likely to be positive. We then examine influences on the debt capacity of the project and decisions to assign anticipated output to long-term contract versus spot trades.

   Our results should be of interest to actual and potential developers of U.S. LNG export projects. However, we also argue in the next section that expanded spot and short-term trades from U.S. LNG export terminals will accelerate recent changes to LNG markets.

2. RECENT DEVELOPMENTS IN NATURAL GAS MARKETS AND LNG TRADE

   Figure 1 depicts global LNG imports and exports by country and region. Just over 20% of total LNG exports in 2020--notably the U.S. at 13% and Russia at 8%--came from regions with well-developed pipeline markets. Historically, LNG export growth mainly occurred where natural gas resources face limited market opportunities either because domestic gas markets are underdeveloped or pipeline access to markets is absent or insufficient. As a result, the opportunity cost of exporting natural gas as LNG was often quite low. Moreover, natural gas is often co-produced with liquids that largely underwrite upstream development. If re-injection is undesirable and there are controls on flaring, the opportunity cost to export natural gas as LNG might even be negative.

   The developed economies of the Organization of Economic Cooperation and Development (OECD), Japan and South Korea in particular, have been the prime LNG importers. As recently as 2000, 56% of global gas consumption was in the developed OECD economies of North America, Europe, and Asia, with LNG imports even more lopsided toward the OECD. In 2000, Japan accounted for 53% of global LNG imports, South Korea accounted for 15%, and Europe 23%, which totals to just over 90% of all LNG imports.

   Tremendous growth in the developing world has significantly changed the scale and composition of demand over the last 2 decades. Global gas demand was about 60% greater in 2020 than in 2000. International trade in natural gas has almost doubled since 2000, and LNG trade is about three and half times larger. LNG trade thus now accounts for about half of all traded gas volumes, as opposed to 25% in 2000 (see Figure 2). Almost 60% of the growth in LNG imports came from developing non-OECD economies, primarily in Asia. China now rivals Japan as the largest LNG importer globally.

   LNG trade is now critical to linking global natural gas markets. Neumann (2009) provided an early analysis of this issue. She observed that the development of trading hubs for natural gas with a high proportion of spot trading was a necessary pre-condition. She noted instances of active arbitrage between natural gas market hubs in North America, the U.K., and Continental Europe as LNG shipments were re-directed in response to variations in spot prices. She then presented statistical evidence of convergence of prices in the trading hubs over time, noting that it was more prevalent in the winter months when spot trading in the hubs was also much greater.

   As Mu and Ye (2018) emphasize, arbitrage of LNG prices between the Atlantic and Pacific basin markets is needed to obtain a linked global market for natural gas. They note that, as of 2008, there were few LNG flows between the two basins. By 2015, however, Nigeria alone shipped 45% of its LNG exports to the Pacific basin. Growth of Qatar as the leading exporter of LNG dramatically expanded arbitrage opportunities because of its ability to ship to either basin at a similar transport cost. Mu and Ye argue that, in a well-arbitraged LNG market, spot prices in two locations should not differ by more than the cost of transporting LNG between them. They examined this condition using weekly averages of four regional spot LNG price indices over the period August 2, 2010 to February 23, 2015. They found that the large increase in demand for LNG following the Fukushima incident in 2011 caused a large divergence in East Asian and European spot LNG prices on average, although the prices still tended to comove over the short term. Furthermore, the four indices converged toward the end of their sample period, with the linkage between the South American and East Asian indices being stronger than the links to the two European indices. Echoing Neumann's results, Mu and Ye also found stronger links between prices in winter months when spot trading was more active.

   Within the Atlantic basin, Mu and Ye found the South American index to be more closely linked to the Iberian than the Northwest Europe index, possibly reflecting a strong role of Spain on the export side, and Argentina and Brazil on the import side, of the re-export trade from 20122015. Mu and Ye also observed, however, that limited pipeline capacity between Spain and southern France enabled the Iberian and Northwest Europe indices to separate. Even in the well-arbitraged North American natural gas market, price differentials can exceed transportation cost when demand surges overwhelm pipeline import capacity or pipeline takeaway capacity expansion fails to keep up with expanding production. Capital investments are needed to link markets.

   Historically, LNG projects required large upfront investments in field development, liquefaction plant, port facilities, and specialized ships. Debt finance was sought to reduce financing costs, but lenders required a substantial fraction of anticipated sales to be covered by long-term contracts (see Hartley (2015)). Given their duration, such contracts needed to allow for price adjustments without having to re-open contract negotiations that could create hold-up problems for large project-specific sunk investments. The solution was indexation to oil prices. Over the longer term, these are highly correlated with movements in energy prices more generally, and thus are relevant to buyers using natural gas in competition with other energy sources. Oil prices also are relevant to sellers who rely on oil markets to take their liquids production, or who must compete with oil producers for many inputs into their industry. The oil market also has very liquid derivatives markets that allow the parties to the contracts to hedge price risks.

   Recent developments have challenged this traditional paradigm. For some older LNG projects, debt and the long-term purchase and sale contracts underlying that debt finance have expired. The liquefaction plant owners can now supply LNG to a wider range of customers on short-term contracts with more flexible terms. The latter include removal of destination clauses, which have been outlawed as anti-competitive in some jurisdictions, more flexible scheduling of shipments, and different price indexation arrangements. Some suppliers of LNG have established themselves as "portfolio traders" with long-term contracts to supply customers but with flexibility to source the LNG from different locations depending on availability and price. (1) Some importers have also invested in LNG storage capacity beyond their immediate needs that they rent to traders wishing to arbitrage anticipated LNG price movements.

   The development of U.S. LNG export projects should accelerate these changes not least because such projects have involved much more spot and short-term trading, as noted in the Introduction. Four key factors have favored spot trades from the U.S. projects.

   First, the U.S. projects draw natural gas from the largest, most competitive, and most densely connected natural gas market in the world. It has many suppliers and demanders and competitively determined natural gas prices that are largely unaffected by the relatively small LNG exports from one project. Extensive storage facilities support intertemporal arbitrage that limits seasonal price fluctuations despite large seasonal demand swings. Derivatives trading is also well-developed. Spot LNG trades linked to the Henry Hub market price therefore can provide price stability and predictability, and an ability to hedge price risks. This makes them a viable alternative to long-term contracts with oil-linked prices. In addition, ready access to a liquid, locally traded price, such as Houston Ship Channel, Henry Hub, etc., together with the expanding volume of global LNG spot trade, enables holders of capacity at U.S. LNG export facilities to link global LNG spot prices to U.S. prices. They can sell abroad or domestically, depending on spot prices. As happened in the February 2021 freeze event in Texas, even if a contract requires LNG delivery when the local price is more attractive, spot LNG can be used to...