While analysts speculate about the ultimate amount of LNG volume to be exported from North America, anticipation of this new LNG supply source is changing the way buyers and sellers manage price risk and supply portfolios. North American LNG provides heretofore unavailable vertical integration for LNG buyers beyond the traditional step of controlling LNG shipping. It allows LNG buyers to establish the costs of liquefaction and gas transportation from wellhead to export facility, leaving only commodity price volatility exposure, which reflects geologic and other exploration and production (E&P) risks in the natural gas supply value chain.
Decades ago, LNG buyers bought supply on primarily Delivered Ex-Ship (DES) terms. Certain very large buyers evolved and took an initial step toward vertical integration by controlling LNG ships to buy LNG at the supply point and achieve savings through managing their own shipping fleets; they eliminated the excess returns on the shipping/delivery component of the LNG value chain.
The Tolling Commercial Model (TCM) being sold by US LNG export plants fixes the liquefaction cost component of LNG supply and has other risks and rewards set out in Table 1. It also provides the LNG buyer with an opportunity to further vertically integrate by reserving gas pipeline transportation capacity connected to gas trading hubs where they can access established gas supply markets with deep liquidity of multiple buyers and sellers. In contrast, traditional LNG supply categorised the liquefaction and pipeline costs (from wellhead to export site) in the E&P asset class even though these assets reflected more midstream than upstream costs and operating risks. As a result, the lower-risk, LNG-related midstream investments earned a higher return, normally achieved only by E&P assets.
Table 1. Risks and rewards of LNG tolling commercial model
|The risks||The rewards|
|Source, secure, nominate and schedule gas into pipeline and LNG plant||Long-term control of gas supply needs (up to 45 years through optional term extensions)|
|Contract for pipeline capacity from sufficient liquid market points to the LNG export plant to ensure competitive gas supply||Not competing with the plant owner in marketing LNG|
|Manage a new business model with value-chain-segments upstream of liquefaction to control||Avoid power cost exposure through dedicated power plant|
|Hurricane interruptions||HH – JCC arbitrage value|
|Vertical integration beyond DES and FOB, back to wellhead|
Historical supply locations in areas such as Borneo (e.g. Bintulu, Brunei, Bontang), Australia (North West Shelf, Darwin) and coastal Algeria (Skikda, Arzew) were typically remote. There were no established midstream infrastructure owners locally positioned in these countries to independently provide pipeline and liquefaction services for prospective LNG buyers. In contrast, unconventional gas supply (shale and tight gas) in North America has changed this balance from upstream to midstream. Now midstream entities are developing LNG export infrastructure to provide services on fixed-fee-for-service terms rather than priced as an embedded portion of an E&P development.
Lower fixed cost and Take or Pay (TOP) obligations
Among the many new rewards embedded in a tolling services model for LNG buyers is effectively a lower TOP obligation. By having the obligation to ‘take-and-pay-for’ only the liquefaction services, the gas commodity becomes the only variable cost component that floats with commodity price. This is possible because a tolling facility is supplied by liquid gas markets in contrast to traditional models supplied by a dedicated gas field(s). When a dedicated gas field(s) is devoted exclusively to an LNG liquefaction plant, gas must be produced continuously to avoid reservoir damage that can reduce gas productivity and ultimate gas recovery.
For example, consider a situation where an LNG buyer wants to greatly reduce LNG consumption in a particular year. In a traditional LNG sales and purchase agreement (SPA), TOP obligations prevent any substantial reduction beyond a limited Downward Quantity Tolerance because of both reservoir management and geologic constraints and the need to service the capital for liquefaction infrastructure.
In contrast, an LNG buyer’s fixed costs are substantially lower under the TCM. Under a TCM, the fixed costs are similar to TOP obligations and continue with regard to shipping time-charter-party-agreements, liquefaction services and pipeline transportation services. However, the 70 billion ft3/d liquid US gas market provides an LNG buyer with the choice of whether or not to pay for the commodity. An LNG buyer can sell feed gas to a multitude of buyers and sellers in the US market if the volume is not needed at the liquefaction plant given sufficient lead time. The LNG buyers’ fixed costs might be further reduced by re-deploying its LNG fleet that has previously been dedicated to lifting US sourced LNG.
Buffered price volatility
Fixing liquefaction and gas transportation costs reduces the delivered LNG cost exposure for an LNG buyer because in the super-high-cost scenario, where the underlying commodity price index doubles, the Henry Hub (HH) indexed gas supply component under a TCM is a smaller portion of the DES cost of LNG than the oil indexed component of DES cost of LNG cost under traditional pricing terms.
Figure 1 shows the contrast between a TCM and oil indexed gas pricing. In a TCM example, the HH gas price is US$ 4.50/million Btu in the base case and doubles to US$ 9/million Btu in the ‘double-commodity-cost-case’. This increases the DES cost of LNG from US$ 11 to US$ 15.50 (note a 12-month forward HH gas price strip captured in January 2014 was US$ 4.34/million Btu, anchoring this example base case gas price). In contrast, in the oil indexed example, the JCC oil price is US$ 110/bbl in the base case and doubles to US$ 220/bbl in the ‘double-commodity-cost-case’. This increases the DES cost of LNG from US$ 16/million Btu to US$ 32/million Btu because all of the LNG costs are lumped into the pricing, which moves in totality with the commodity price (note 2013 JCC average oil price was approximately US$ 110/bbl and a 14.5% slope is assumed to anchor this example base case).
LNG cost resulting from doubling commodity index.
Written by Guy Dayvault. Adapted to house style by Ted Monroe
Read Part Two of this article: Unique global market impacts of North American LNG supply: Part Two
Read Part Three of this article: Unique global market impacts of North American LNG supply: Part Three.
The full version of this article is available in the April issue of LNG Industry.
Read the article online at: https://www.lngindustry.com/special-reports/10042014/unique_global_market_impacts_of_north-american_lng_supply_part_one/
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