Perspective: LNG buyers and sellers – Looking to break the impasse

Last month we highlighted the fall in global LNG contracting: suppliers and buyers find themselves at an impasse as buyers believe they can wait in an oversupplied market. Yet despite the shorter-term surplus, the market also has a need for future supplies. So this month the latest paper from our LNG team explores innovations in contract terms that may break through the 'Catch 22', as we have designated it.

Despite uncertainties ranging from the oil price outlook to the impending acceleration of supply competition, there is still keen interest in commercializing gas reserves through LNG. International oil companies, mineral resource-holding governments, and project development companies are looking to avoid peaks and troughs in their project development cycles. But buyers feel that they can bide their time given the significant amount of supply available on either a short- or long-term contract basis during the remainder of the decade.

The industry knows that this could lead to a boom-and-bust scenario, which is not in the interests of either buyers or sellers. The challenge for each is to develop a business model in which new projects can be developed to meet the expected demand for LNG capacity in the early 2020s. For industry players facing supply-demand gaps in the post-2020 period, redefining traditional LNG contract structure expectations will become critical to bringing buyers and sellers together. We explore a host of options including not just different forms of price exposure, but also volume and destination flexibility, and contract duration.

Our October market analysis on North America primarily focused on the high storage inventory levels which hang over the short-term market-a theme common across many commodities. Gas storage inventories will likely reach a new record high this year owing to continued Appalachian production growth as more Marcellus/Utica pipeline expansions come online. This will keep Henry Hub prices tame below $3 per MMBtu.

But it is important to remember that not all markets enjoy low hub prices. The North American gas team have looked in depth at the New England market which has traditionally suffered from winter price spikes because of constrained pipeline connections. Will the wider build out of pipeline infrastructure extend to one of the last hold-outs? We have evaluated the economics of building this new infrastructure, but firm transportation capacity could also be attractive as it provides greater cost certainty and protection against significant basis spikes.

European gas pricing remains opaque as the market continues its evolution from long-term oil indexed contracts to spot and hub-based pricing. Over the past six years the pricing of gas in Germany has been transformed: long-term contracts have been renegotiated and traded volumes on the continental European hubs have increased six fold. For remaining legacy oil-indexed contracts the discount factor applied has increased significantly. German importers have been able to achieve these price reductions as a result of the diversified portfolio supplied by direct connections to the Netherlands, Norway, and Russia.

The change in the indexation of import contracts switches the risk allocation in the European gas value chain. Since 2008 buyers have been carrying significant price risk and sellers significant volume risk. The increase in spot indexation brings back a more traditional risk allocation by realigning the indexation in the purchase and sales contracts for midstream companies. Sellers are now faced with the vagaries of the global gas market rather than the global oil market, creating an alternative exposure to price and volume risk. We may be one step closer to a global gas market.

Michael Stoppard, Chief Strategist, Global Gas, IHS Markit
Posted 11 November 2015

This article was published by S&P Global Commodity Insights and not by S&P Global Ratings, which is a separately managed division of S&P Global.