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Competing for LNG demand

Hydrocarbon Engineering,

Fifteen Canadian LNG projects have been proposed and another two dozen has been proposed in the US. Seven US projects, with a total of approximately 9 billion ft3/d of export capacity (equivalent to more than 12.5% of current US natural gas production) have received full export approvals. Approved export project capacity could top 10 billion ft3/d by the end of 2014, according to EY.

One of the approved projects is already under construction, with first exports expected in later 2015. Seven Canadian projects have already received export permits with the expectation that many more will be approved. In total, current proposed Canadian projects represent more than the equivalent of Canada’s current daily production of approximately 14 billion ft3/d. Clearly, all projects will not proceed.

Though the proposed US projects are ‘transportation disadvanted’, they have significant cost advantages in that they are brownfield projects that will leverage existing LNG import infrastructure, including marine jetties, storage capacity, pipelines and utilities. Many will also have tackled important regulatory and permitting challenges.

EY highlights that the opposite is true in Canada. Proposed Canadian projects have a distinct advantage when it comes to transportation proximity to Asian demand markets. However, the infrastructure challenge is also much more pronounced for Canada’s greenfield projects. According to EY, this means that costs of supply will matter.

Pricing flexibility

The last few years have seen record divergence in regional gas prices, driven by both supply and demand factors, including the US shale gas boom, the European financial crisis and the Fukushima nuclear disaster. Now, diverse potential new supply sources are challenging the LNG status quo, with Asian buyers presumably looking to modify or possibly replace their long-standing and relatively expensive pricing model of gas prices tied explicitly to oil prices.

High LNG development costs have typically required long-term off-take agreements – agreements that have historically been based on the price of oil. Recent high oil prices and oil-indexed LNG contracts have resulted in high LNG prices for Asian buyers that appear much higher than what North American gas prices would suggest should be the case.

According to EY, the market is now witnessing the conflict of increasingly more expensive projects trying to sell to increasingly more price-sensitive buyers. High oil prices and low natural gas prices have strained the traditional ‘oil-indexation’ LNG pricing approach. Asian buyers now assert that oil-indexed LNG prices are untenable, while LNG project developers argue that contracts based on the current low North American natural gas price will not create acceptable project economics.

EY explains that the supply side of the LNG business needs to be assured that it will be able to achieve netback of approximately US$ 10 – 11/million BTUs, or approximately US$ 12 – 13/million BTUs delivered. Given a broad assumption that long term oil prices average between US$ 80/bbl to US$ 90/bbl, this would imply that seller would seek oil-linked contracts with slopes in the range of 14 – 16% - approximately where they currently are. However, the possibility of spot gas-linked contracts from North America could upset the traditional pricing structure.

According to EY, spot pricing increases buyers’ choices, adds liquidity to markets and allows buyers to hedge financially and physically. The historic justification of oil linkages was the security of supply, but with increasing liquidity in the LNG market, some of the security ‘premium’ becomes harder to justify. Growing liquidity also gives suppliers confidence to sanction projects before locking in off-take agreements – resulting in the emergence of major portfolio LNG players.

How is the market responding

In its report, EY observes that some LNG buyers have already signed contracts for future US-based cargoes at Henry-Hub linked prices. These volumes are a fairly small part of their gas supply portfolio (generally less than 20%). While these volumes appear very attractive at the margin, they are likely less well suited for base load supply.

North American gas prices can be extremely volatile. While greater contract flexibility is certainly a big attraction, spot pricing may simply interject more volatility for buyers and cause project developers to have higher internal return thresholds to account for that volatility risk.

EY also raises the question as to whether Canadian and US shale gas development can be sustainable over the medium or longer term at under US$ 5/million BTUs (which is above current prices), given the expected increases in costs associated with increasing decline rates and increasing re-investment demands.

Going forward over the medium to longer term, EY expects to see a gradual but only partial migration away from oil-linked pricing to more spot and hub-based pricing. They do not expect to see a paradigm shift in pricing. Oil linked pricing will not totally go away, but more pricing alternatives will be available.

Adapted from a press release by Emma McAleavey.

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