“Price is always important. It is the first thing that customers want to discuss with us,” Matthew Schatzman, Next Decade CEO, told an event to launch a new report commissioned by law firm King and Spalding, in association with Petroleum Economist, on the sidelines of the Gastech conference in Houston on Monday.
But, in the increasingly competitive race between so-called second wave US LNG export plants to secure FID, Schatzman sees three other key factors where successful projects can kick on past also-rans—flexibility in contractual terms, certainty of delivery on time and on budget, and an advantaged location proximate to adequate low-cost production resources.
Perhaps unsurprisingly, he rates the firm’s Rio Grande LNG facility, in which the firm aims to take FID in the fourth quarter of this year, highly on all three counts.
On contractual flexibility, Schatzman can already point to Next Decade’s April deal with Shell for 2mn t/yr of offtake where just 25pc of the volume is linked to Henry Hub—the dominant price reference for first wave projects and even in those second wave terminals that have taken FID and have gone for an index-linked approach.
The remaining 75pc is linked instead to Brent. “No-one had done an oil-linked LNG contract out of the US before,” says Schatzman, but Shell’s experience in the global LNG markets gave Next Decade “a partner that could help structure the deal”.
It is not only the price reference that makes oil-linked agreements unique. Whereas previous tolling as well as sales and purchase agreement (SPA) deals in US LNG export gave buyers the opportunity to refuse to offtake, oil-linked deals will be take-or-pay, says Schatzman, which gives flow assurance to producers. An oil-linked take-or-pay contract “can give customers what they want, and producers what they need”, says Schatzman.
This is particularly important for producers in the Permian and Eagle Ford basins, he says, where as much as 700tn ft³ of associated gas offers just 5pc of the value, but gas evacuation constraints could shut in the production of much higher value crude and liquids. It also explains why Permian producers have “no fear” of selling gas on an oil basis, as it is where 95pc of their risk already lies.
Next Decade is also open to other price indices, including US hubs other than the Henry benchmark. These could include Rio Grande LNG’s local market, Aqua Dulce in south Texas, or a net forward from the Waha hub that provides a Permian price reference, says Schatzman.
And it has also been exploring the European TTF and east Asian JKM references, which “are on the tips of everyone’s tongue”. But he cautions that, for Henry Hub-linked first wave exporters delivering to Europe during the recent supply glut, selling on the TTF or UK NBP basis has not been the easiest experience. “The netback is effectively zero or, if you factor in the liquefaction cost, below zero,” says Schatzman.
On certainty of delivery, “the cost of delay is rarely factored in,” the Next Decade chief says. But if there is a one to two year delay to a project, leaving the buyer short of its expected supply in a market that—if other plants are also failing to keep to schedule—may be tightening, the pain can quickly compound. “If you have to pay $5/mn Btu more than expected for a year, that adds $0.25/mn Btu over the life of a 20-year contract—if it is two years, that rises to $0.50/mn Btu.”
Next Decade aims to minimise its delay risk through using US engineering heavyweight Bechtel, which Schatzman labels the world’s best constructor for its record of delivering seven trains on budget and on or even ahead of schedule, for its project.
Rio Grande LNG is located in the far south of Texas, close to the Mexican border. It has access to an “uncongested deepwater port”, which Schatzman sees as a significant advantage.
And the Rio Bravo pipeline which Next Decade is developing to link Rio Grande to the Aqua Dulce hub both benefits from and further adds to the geographical advantages. Associated gas producers are assuming that all additional oil and gas production from Texas and further afield will need to be exported so “are looking for the lowest cost route to the sea”, says Schatzman.
Pipelines south of San Antonio are advantaged by having fewer proximate population centres and landowners more than prepared to take payment for offering right of way, easing permitting issues and even saving money by requiring less thick pipelines than those that run under urban areas.
This benefits south Texas export projects compared to those in upper Texas, around the Sabine River and into Louisiana, says Schatzman.
The direct link to Aqua Dulce is also a boon for Rio Grande LNG, he continues. Two pipeline projects—the Gulf Coast Express and Whistler Pipeline—will each deliver 2bn ft³/d of additional capacity directly from the Permian to Aqua Dulce, while a third similarly-sized conduit, the Permian Highway, will have a route to Aqua Dulce as one of three options at the end of its Waha-Gulf Cast span.
All three of these new pipelines are intrastate, rather interstate, further reducing complexity, says Schatzman. And they give Rio Grande LNG key access to abundant low-cost production from the Permian, where the breakeven cost is “below zero” for associated gas.