After a sustained period of four or five years with the Brent Crude index above US$100, oil prices have fallen dramatically since the summer of 2014. The index hit a low of around US$45 in January before recovering slightly and stabilizing to trade in the US$50 to 60 range during February and March 2015.

Not only has the fall in crude oil prices reduced the cost of oil-based fuels such as petrol, diesel, jet fuel, fuel oil, and naphtha, it has significantly impacted prices in the global LNG market and long term pipeline gas contracts.

Historically, gas and LNG have been priced regionally. The price formula in long term Asian LNG import contracts were linked with a lag of several months to crude prices – usually to the JCC (Japanese Custom Cleared) price, sometimes the Brent index and the official Indonesia Crude Price. This was also true of long term import contracts into Europe from Russia, Algeria, and Norway. The position in Europe has changed significantly over the last five to ten years, with the establishment of gas trading hubs, particularly in north west Europe and spreading further afield. The divergence between prices at gas hubs and oil-linked import prices for the last five years has imposed huge financial pain on European gas utilities holding oil-indexed long term import contracts, who have been squeezed by long term input prices which are out of money. This has led to numerous price renegotiations and arbitrations and an insistence (resisted by Gazprom amongst other producers) by many European utilities on hub price linkage for any new long term import contracts, whether for gas or LNG.

Asian buyers have also been feeling the pain of high LNG prices, driven by crude oil linkage and growing LNG demand, especially the additional Japanese demand resulting from the Fukushima disaster in 2011.

Meanwhile the U.S. has been enjoying cheap gas prices as a result of the U.S. shale revolution. This has given U.S. industry a major global competitive advantage in energy input and feedstock prices, demonstrated for example by the re-birth of the petrochemical industry in the U.S.

These global gas price differences and the new abundance of gas production in the U.S. formed the base case for U.S. LNG export projects pioneered by Cheniere Energy and others. However, the price arbitrage between U.S. and Asian gas prices is not as attractive as it might seem at first glance, once you have adjusted for the costs of liquefaction (say US$3 per MMBtu) and LNG shipping costs to Asia (another US$3 per MMBtu). So a Henry Hub price of US$3.50 per MMBtu becomes a landed price of US$9.50 per MMBtu in Japan.

The price comparison still supports U.S. exports whilst Asian import prices are above US$16 per MMBtu, as they have been consistently since 2010. However the crude price fall over the last eight months is now feeding into long term Asian LNG prices, which had fallen below US$9 per MMBtu in January. So even though the U.S. Henry Hub gas price has fallen below US$3.00 per MMBtu, the U.S./Asian price arbitrage has disappeared for the time being.

Demand implications

On the positive side, for Asian buyers the fall in oil prices is resulting in much cheaper landed LNG. This has provided much needed relief to buyers who had been suffering from the high prices since the tightening of the market associated with Japanese nuclear shutdown in 2011.

The recent fall in the oil price though is unlikely to result in immediate expansion of LNG import capacity in Japan or Korea, or a shift in demand from competing fuels (over-and-above the expected gradual increase in demand), unless the LNG buyers foresee a long term fall in prices. Buyers would need to see a structural long-term fall in oil prices before using that to underpin investment in infrastructure to increase LNG imports and consumption. On the other hand, Asian LNG demand growth is likely to be driven strongly by China and (to a lesser extent) India over the next 10 years, and so for Asia's new economic giants a period of crude and LNG price weakness could be an opportunity to drive a harder bargain and lock-in some value for the future (e.g. additional volume flexibility, lower slopes on oil-indexed elements, price ceilings or pivot points, possibly a mix of indices).

LNG supply implications

For LNG producers and exporters, the low oil price, and its translation into lower LNG prices, has a number of significant effects:

Operating projects

Lower revenues for those recent projects that have been financed or taken Final Investment Decision (FID). Current oil prices are likely to be well below the base case pricing pack used when the financing was structured and received sign off from the banks' credit committees. For the short term the banks are likely be tolerant, as many experts predict an oil price recovery within the next 12 to 18 months. However, if oil prices remain (or look likely to remain) low for a longer period, then restructuring of financing arrangements may be required for some projects.

Development projects

The projects that have already taken FID and are being developed are likely to continue their construction phase and should still come online over the next few years. There are a considerable number of liquefaction projects in Australia and the U.S. in this position leading to a potential LNG supply glut around 2020. The majority of this LNG has already been committed to buyers, but significant portions were left uncommitted for trading purposes, and these volumes may struggle to find a home.

Many of the recent projects anticipated a high oil price and, in some instances, have been characterised by substantial cost and time overruns. So, to the extent the projects depend on crude-linked LNG prices, they are coming to the market at a bad time to achieve their expected return on investment.

The U.S. projects that are already being developed may be underutilized in the initial years and volumes exported may be more likely to land in Europe than in Asia (depending on the price environment when they come online) given shorter shipping distances.

New projects

FID for large, capital intensive greenfield projects in areas considered to be high-cost (e.g., Australia, Canada) are likely to be postponed. Sponsors (often International Oil Companies), whose revenues and profits have been drastically reduced by the crude oil price fall, are cutting back on capex spending. Banks are probably less likely to take a risk on expectations of oil prices increasing in the next 12-36 months than oil companies might be. Projects in Australia and Canada, for example, are likely to need higher oil prices to be economic. The delay in the FID for the Pacific Northwest project in British Columbia is a sign of this.

In the current period of uncertainty, there also may be a delay in new FIDs for U.S. LNG export projects, at least until there is greater certainty or confidence in oil price trends, even though their pricing is not tied to crude. The attractiveness of U.S. export projects (whether structured as LNG sales or tolling projects) will be challenged by the current market dynamics and the erosion of the Asian LNG price arbitrage. The multitude of potential U.S. projects, competing for customers and financing, will be whittled down. Willing and creditworthy customers will be harder to find, particularly in Asia, and the active buyers will recognize their leverage to drive a harder bargain.


This analysis suggests a few further potential consequences and trends:

  • Better prospects for those projects in lower cost regions where development costs are expected to be less and so can still be economic with lower oil price (Mozambique, Papua New Guinea), especially if is expansion of brownfields (e.g. PNG T3, Tangguh T3).
  • A shift towards smaller, less risky or capital intensive projects, away from the mega-projects of the past decade.
  • A shift from debt to equity funding, giving more opportunities for infrastructure funds and private equity players who have capital ready to deploy (and who also need returns to be realised earlier, and so would prefer smaller sized projects).

Projects where LNG offtakers are also in the upstream and/or liquefaction project perhaps have a greater chance of taking FID as they may benefit from the overall vertical economics of the project, including any liquids revenue stream.

Many Asian buyers are still looking for a balanced portfolio of LNG that includes a mix of supply sources and a mix of oil and gas linked prices, as a hedge against future price developments.

Over the past decade, there have been a number of instances of oil producers seeking to re-negotiate LNG prices which were set in the low oil price environment in the early 2000s and imposed low caps on crude prices in the pricing mechanisms. By the same token the change in market conditions, with the emergence of gas-linked prices into Asia, as well as low oil prices and an expected LNG supply glut, could lead buyers who are stuck on high priced LNG contracts to seek to renegotiate their prices down. Producers and buyers will both be carefully examining the timing of price re-openers in their LNG supply contracts and the wording of the price review mechanism.