The Shale Gale and the Future of Liquefied Natural Gas

The development of the global liquefied natural gas (LNG) market is transforming natural gas markets from a collection of segmented regional markets into an integrated global whole. This evolution has potentially major implications for global natural gas prices. BP’s 2017 Energy Outlook stresses three important dimensions of the LNG market, paraphrased below.

• Because LNG cargoes can be redirected to different parts of the world in response to regional fluctuations in demand and supply, gas markets are likely to become increasingly integrated across the world.
• U.S. LNG exports are likely to become more diversified, providing the marginal source of gas for markets in Europe, Asia, and South & Central America. For this reason, U.S. gas prices are likely to play a key role in anchoring gas prices in a globally integrated market.
• The development of a deep and competitive LNG market is likely to cause long-term gas contracts to be increasingly indexed to spot LNG prices. (57)

The global LNG market, of course, depends upon natural gas production, as well as capacity for liquefaction, shipping, regasification, and storage. A recent report published by IHS Markit (Yergen and Andrus, 2018) indicates that, during the period 2007-2017, natural gas output in the United States grew by more than 40%, in contrast to less than 1% growth during the previous decade.[2] BP’s Statistical Review of World Energy (2018) reports that, in 2017, natural gas accounted for a “record” 23.4% of global energy consumption. In its Annual Energy Outlook 2018, the U.S. Energy Information Administration (EIA) projects that U.S. natural gas production will grow by roughly 59% from 2017 to 2050 under what it refers to as the “reference case” scenario. The expectation generally seems to be that natural gas production and consumption will continue to rise. This evolution is likewise expected to have a continuing impact on the market for LNG.

Based on IHS research, Yergen and Andrus (2018) claim that “By 2025, the global LNG market is anticipated to be more than 400 million metric tons per year, with the top suppliers—Qatar, Australia, and the United States—exporting 60% of total supply”(11). Total global LNG imports in 2017 were roughly 290 million metric tons, according to The LNG Industry’s 2018 Annual Report (GIIGNL, The International Group of LNG Importers), up roughly 10% for the year. Of this, the EIA reports that U.S. exports of LNG by vessel rose from 184 Bcf (3.8 million metrictons) in 2016 to 706 Bcf (14.5 million metric tons) in 2017.

A crucial ingredient of the LNG market is the process by which prices are determined. Pricing of LNG has followed four primary models, but it is increasingly tilting towards market-based (gas-on-gas) pricing, in which prices are based on natural gas hub prices. The primary historical pricing methods are:

1. Based on natural gas hub prices (United States, United Kingdom, Canada, northwestern Europe)
2. Based on alternative fuel prices (central and southern Europe, southeast Asia)
3. Based on oil indexed prices (Japan, Korea, Taiwan, China, India)
4. Based largely on government price regulation (Russia, Middle East)

The question of gas-on-gas hub pricing versus oil indexation has attracted much attention. The benefits of hubs are that they provide physical locations for trading gas and ultimately for price discovery for natural gas sold at the hub. The most important hubs have publicly reported price indices that can serve as benchmarks for the value of gas in the larger market. These price indices in turn form the basis for futures contracts and thereby enhance the management of price risk. Fully mature gas market hubs have many independent buyers and sellers, open access to transport facilities, trading liquidity, and clear and transparent price and volume reporting by price reporting entities. Oil indexation, on the other hand, avoids the problems created when hubs are absent or illiquid. Although the debate is not settled, hub-based pricing is increasing and, as pointed out by BP, “The development of a deep and competitive LNG market is likely to cause long-term gas contracts to be increasingly indexed to spot LNG prices” (2017, 57).

Over the past 15 years, the northwestern European gas markets have developed substantially, both as trading hubs and as market-clearing exchanges supporting a greater variety of natural gas sources and increased regional trade in natural gas. Overall, natural gas trading hubs in Europe generally are exhibiting price convergence, despite an expected degree of price variation among hubs in response to local market conditions (U.S. EIA, 2017; BP Statistical Review of World Energy, 2018).

The Asia Pacific region represented roughly 73% of global LNG demand in 2017, according to GIIGNL. That region is fundamentally different from the United States and Europe, with widely dispersed and isolated national gas markets that have limited internal pipeline networks and little physical connectivity between countries. The Asia Pacific region relies heavily on LNG imports to supply individual domestic markets. The gas pipeline network in the region is limited because countries are separated by wide expanses of water. The pipeline infrastructure in the region generally serves internal markets, connecting LNG terminals to consumers, offshore production to onshore markets, or internal production to consumers. Hub development in the region is therefore somewhat problematic, although Japan’s Ministry of Economy, Trade and Industry has detailed the goal of creating an LNG trading hub by the early 2020s.

A key change in the LNG market during the last decade has been in the downstream contractual arrangements. Historically, LNG projects sought long-term (e.g., 25-year) contracts. The geographic destination was fixed as the buyers’ regasification terminal. The price was linked to crude oil with a three- to four-month lag. However, such arrangements have been evolving. For instance, global spot and short-term trades (contracts terms under four years) accounted for about 27% of total volume in 2017, compared with about 19% in 2010, according to GIIGNL. Another important development has been the emergence of portfolio players and LNG traders, as pointed out in a 2017 report by Howard Rogers of the Oxford Institute of Energy Studies. Portfolio players typically have investments in upstream fields and liquefaction plants but also long-term contracts to purchase LNG along with a range of buyers on long, medium, short, and “spot” terms based on prices related to both oil prices and gas hub prices. LNG traders, on the other hand, seek profit from short-term trading.

Learn more about the evolving LNG market through these useful resources.

Rogers, H. (2017). Does the portfolio business model spell the end of long-term oil-indexed LNG contracts? Energy Insight 10. Oxford, U.K.: Oxford Institute for Energy Studies.

U.S. Energy Information Administration (2014). An introduction to global natural gas markets, drivers, and theory. Washington, DC: U.S. Department of Energy.

U.S. Energy Information Administration (2017). Perspectives on the development of LNG market hubs in the Asia Pacific region. Washington, DC: U.S. Department of Energy.

Yergin, D., & Andrus, S. (2018). The Shale Gale turns 10: A powerful wind at America’s back. London, U.K.: IHS Markit.

[1] The phrase “Shale Gale” was originally coined by IHS Markit in the 2009 report “The Shale Gale: The Implications for North American Natural Gas Pipeline Development.”

[2] According to the U.S. EIA, total U.S. proved natural gas reserves equaled 341.1 Tcf at the end of 2016, a 5% increase over the course of the year. Statistics for year-end 2017 will not be released until November 2018.  The EIA reports that, at the end of 2015, the quantity of technically recoverable U.S. natural gas equaled 2,462.3 Tcf, while for year-end 2016, the Potential Gas Committee reported 3,141 Tcf. The United States consumed roughly 27 Tcf during 2017, according to data reported by the EIA.