Oil's volatility hastening decline in oil-indexed LNG pricing
The pricing of often decades-long liquefied natural gas (LNG) contracts is becoming more unpredictable as a result of oil price swings
Driven by rising supply and expansion in export capacity from Qatar, Australia and more recently the US, the diversification of LNG supplies is driving an evolution of the contractual terms through which it is sold.
Buyers now have greater bargaining power when negotiating contracts, and with the recent volatility in oil prices, there is extra uncertainty about what level of oil-indexation will be required in new contracts. Ultimately, it seems certain that sellers will look for alternative ways of selling their contracted volumes.
Since the LNG industry's birth in the 1960s, when natural gas started being used in Europe and North East Asia as an alternative to oil products for power generation, contracts have been indexed to oil. This oil-indexation has remained commonplace for suppliers outside of the US, but with LNG production growing from 249 bn cm in 2008 to more than 450 bn cm in 2018, buyers have managed to negotiate better contractual terms.
This in turn has led to indexation dropping from a level of 14-15pc for legacy contracts to approximately 10-11pc for some of the contracts signed most recently. Indexation has also been reduced to make new liquefaction projects more competitive versus US projects.
US LNG suppliers have preferred to use an indexation to Henry Hub to reduce risk when sourcing gas for liquefaction in the US market. The contracts typically add a 15pc administration fee and a fixed fee to cover capex, in the range of $2.00 to $3.50 per mn btu. Based on these terms, the estimated price for US LNG delivered into Asia results in an average Henry Hub indexed price of $9.40 per mn btu (see Figure 2 below). This level is expected to remain relatively flat in the future, as abundant supplies of natural gas and low breakeven prices for natural gas production should enable Henry Hub prices to remain below $4 per mn btu in the medium to long term.
In the race to take a Final Investment Decision for new liquefaction projects, suppliers need to attract buyers by offering competitive terms. New projects in Qatar, Russia, Australia and Africa, therefore, need to compete against marginal supplies from the US that range between $8.60 and $10.20 per mn btu, delivered to Asia.
Some of the latest oil-indexed contracts have been signed with an indexation of 11pc. With an $80 per barrel price this would result in an LNG price delivered to Asia of $8.80 per mn btu, meaning it would be in line with the lower cost-range of US supplies. But the recent decline in oil prices due to strong growth in oil production has resulted in the expectation of a long-term Brent price closer to $65 per barrel, which in turn would equate to an LNG price of $7.20 per mn btu.
If prices were to remain at the level of $58 per barrel at time of press, then the LNG price would drop as low as $6.00 per mn btu. Whilst being competitive for buyers, this low-price scenario would represent a great loss in potential revenues for LNG suppliers.
As Figure 3 illustrates, at times of lower oil prices contracts have been signed at a higher indexation. One example of this is the contract between Qatargas and Pakistan State Oil, signed in February 2016 when the oil price was as low as $30 per barrel. This contract had an indexation of 13pc.
The wide range of indexation levels seen during the past few years highlights the uncertainty that prevails with regard to oil prices going forward. If we believe in a long term Brent price of $65 per barrel (in line with Rystad Energy's base case forecast), an oil-indexation of around 13pc would be needed to be competitive versus the average US projects (see Figure 4). If new contracts continue to be signed with an indexation of 10-11pc, average oil-indexed prices would gradually drop towards $6 per mn btu as legacy contracts expire.
Alternatively, non-US suppliers could try to move away from the oil-indexed contracts and use a "cost plus" model similar to the ones being used by US suppliers. This model would be especially attractive for suppliers sourcing their natural gas from non-associated fields that want to eliminate the risk from oil price movements. Selling gas through gas-hub indexation to Asian buyers is still challenging due to the lack of a liquid gas hub in the region.
According to the recent Rystad Energy commentary Tightening LNG market sets the scene for a major shortfall, it is looking increasingly likely that strong demand growth - particularly in Asia - will create a major LNG shortage by 2025. LNG buyers' increased willingness to commit to new long-term sales and purchase agreements signals expectations of a tighter market going forward.
Some sellers have used sales in the spot market as an alternative. According to the International Gas Union, the volume of LNG sold on the spot market increased from around 20pc in 2008 to 30pc last year. However, the largest share of LNG is expected to continue to be sold through long-term contracts, as project developers can increase their debt capacity by reducing cash flow variability. Most developers rely on finance to develop their capital-intensive liquefaction projects.
Data source: Rystad Energy Gas Market Analytics; Rystad Energy UCube
Carlos Torres-Diaz, Head of Gas Markets Research at Rystad Energy, is based in Oslo, Norway. For more information, click here.