Ending the LNG Drought
By Nikos Tsafos
Investment in new projects to produce liquefied natural gas (LNG) fell sharply in 2016 and 2017: the industry-sanctioned under 10 million tons of annual capacity in two years, an 80 percent reduction relative to 2011–2015. This slowdown raises many questions. Is the industry investing enough to meet future demand, and if not, will that lead prices to spike later? Governments are asking whether they should offer concessions to support projects; and if so, how far should they go, especially given pressures from constituents who were promised jobs, investment, and revenue from projects that are now stalled. And at a geopolitical level, strategists are asking what places will win and what places will lose—and with what consequences? What might the world’s energy map look like in 10 or 20 years?
![Shell released its 2018 LNG outlook saying it “sees [a] potential LNG supply shortage as global demand surges.”](/media/6277/lng-supply-shell.jpg)
To answer these questions, we must first understand why investment has slowed down. In part, this is just a cycle: periods of high investment are often followed by periods of low investment. This cycle is amplified by a mismatch between prices and costs—prices have fallen by much more than costs, and so, many projects in the development queue are not profitable enough to be sanctioned. Some projects have even been cancelled outright, a rarity in LNG where projects usually just languish. This is how bad the market has been in recent years.
But this is not just a cyclical correction. There are three broad forces that further hinder investment. The first is price uncertainty. Historically, gas prices in much of the world have been linked to oil. The uncertainty in oil prices has thus meant uncertainty for gas prices. More importantly, there is a slow move away from oil-indexed prices: in 2005, 63 percent of the gas that crossed a border was priced in relation to oil; in 2016, it was 49 percent. This move is welcome—gas should have its own price. But this is a planning nightmare: how to forecast a price with less history and more unknowns? In a world with tight margins, even modest price uncertainty can be a big obstacle.
The second uncertainty is demand. This is partly demand writ large: how much gas will the world use, especially given competition from coal and renewables? But demand is also uncertain at the company level since many markets are opening up. In Europe, incumbents lost significant market share due to liberalization. No Asian market is that far advanced in its liberalization schedule or quite as far-reaching in its liberalization ambitions. But companies that buy LNG from a new project are placing 25-year bets, which is long enough to make any planner think twice.
Third, the market is becoming more liquid (even though, from 2012 to 2016, the spot and short-term market for LNG did not grow). Companies are becoming more comfortable relying on the short-term market, and there is a growing market for reselling gas on a long-term basis. All this means that buyers are not just thinking whether they might need gas in the future; they are also wondering whether they should commit to
There is, in other words, a cyclical correction, as the industry digests high levels of investment during 2011–2015. But this cyclical correction is amplified by an imbalance between prices and costs and by deep uncertainty about prices, demand, and future liquidity.
When might this drought end? We do not know, but three concurrent forces will lead investment to restart.
First, the cycle will eventually turn. Projects now under construction will come online, and there will be a gap between supply and demand—a gap that might come sooner if demand proves as resilient as it did in 2017. At that point, companies will see an opportunity. The most robust projects will move first—the ones that can leverage existing infrastructure, or economies of scale, or have other political, regulatory, or commercial advantages. There are signs already that the market might be turning. Several projects reached major milestones in early 2018—from securing government approvals (Mozambique), to signing long-term sales contracts (
Second, companies are looking for new ways to manage risk. Many of the practices now common—long-term sales contracts, oil-indexed pricing, destination flexibility in sales contracts—spread in order to manage risk. More recently, we have seen gas companies sign long-term contracts without a secured market. In doing so, these companies offer what new projects need (demand certainty) at a time when traditional buyers are hesitant to sign new contracts. Another innovation has been to allow buyers to not take gas without having to pay for it in full, as was the practice so far. Instead, they can pay a fee to cover the return on investment for the export infrastructure. On a smaller scale, there are efforts to reallocate risk—either by compartmentalizing it, so that each player takes on exactly the risk they want; or by spreading it, creating complete alignment among buyers, sellers, and investors. Even these small tweaks can help a project that just needs a slight push in order to be sanctioned.
Third, governments are stepping in to try and help projects. Different governments will use different tools. Some might offer lavish support: Russia, for instance, passed a tax holiday for the Yamal LNG project, paid for the port infrastructure, and supported the project’s icebreaking fleet. In Canada, British Columbia signed a fiscal stabilization agreement with the Pacific
Success, therefore, will come at the confluence of three forces: a change in market fundamentals that makes companies more open to investment; adaptations in business models that make today’s risks seem more manageable; and support from sovereigns that help address the challenges that projects face on the ground.
Nikos Tsafos is a senior associate with the Energy and National Security Program at the Center for Strategic and International Studies in Washington, D.C.
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