Monetising stranded gas: What’s different about FLNG SPAs?

Article by Kristian Bradshaw, Counsel at Allen & Overy

The potential advantages of Floating LNG (FLNG) are well documented. Among others, the prospect of smaller-scale projects with a lower project cost and smaller environmental footprint, means that FLNG is likely to gain in popularity as companies come under increasing pressure to drive down costs, in light of the sustained low oil price, and to develop more environmentally friendly methods of project execution, in light of COP 21 and related global trends.

However, there are also a number of FLNG-specific risks that will require an innovative approach to LNG SPAs from these projects, particularly in order to achieve a bankable long-term SPA that is able to underpin a limited recourse project financing of an FLNG project – many of the first wave of FLNG projects (including Petronas’ PFLNG-1 in Malaysia and Shell’s Prelude in Western Australia) are being financed on a balance sheet basis, but this is likely to evolve.

The allocation of those risks requires new approaches to the drafting of FLNG SPAs compared to conventional LNG SPAs.

Some of the FLNG-specific issues to be considered are as follows:

  • FLNG technology is not fully tested, which means the risks of construction delay and performance issues cannot be ruled out. For example, the facility may not be built on time or it may not function at nameplate capacity. It is unlikely that these risks can be fully passed to the EPCIC contractor, so (notwithstanding that there may be a completion guarantee in place to protect the lenders) how might these risks best be catered for and allocated in the FLNG SPA, for example in terms of the provisions dealing with start-up, force majeure, build-up, quantity flexibility, operational tolerances, sanctions for delivery failure and termination mechanisms?
  • The offshore location can be a hostile environment and it is likely to mean that weather delays will have a greater impact, particularly in terms of cargo loading on a ship-to-ship basis. How might this risk impact the demurrage and force majeure provisions?
  • Maintenance and downtime is likely to be greater in view of both of the above observations. How can these risks be catered for and allocated in the FLNG SPA, for example in terms of maintenance schedules, force majeure scope and timing, quantity flexibility and source flexibility?
  • Due to their compact nature, condensing complex technology into an area a fraction of the size of an equivalent capacity onshore project, storage space is limited and FLNG projects are therefore less able to accommodate requests for flexibility from the buyer – the risk is that tank-top is reached and that production may have to be turned down or shut in unless the seller has alternative means of disposing of the LNG quickly (and this is not a given). Scheduling will be critical, as will having buyers with the requisite operational experience to manage the project’s complexity. The typical take-or-pay structure with buyer make-up rights may also need to be adapted in recognition of the constraints on the seller’s headroom to produce excess LNG. Might it even be appropriate to require the buyer to take certain midstream and downstream force majeure risks that it would not typically take in a conventional LNG SPA?
  • The limited space on board may also compound the maintenance and downtime issues mentioned above by making it more arduous and slower to perform even routine maintenance.
  • On an FOB structure, issues of compatibility between the project (which uses bespoke design) and the buyer’s LNG carriers will also be in sharp focus and the risk will need to be appropriately allocated between the parties. There will likely be many pages of provisions in the LNG SPA dealing with such issues. As a practical point, bespoke vessel configuration issues may also impact on the seller’s ability to sell to divert cargoes to other buyers and therefore the seller may attach less importance to such seller diversion rights.

As alluded to above, it is likely that the buyer will be expected to assume considerably more technical and operational risk in an FLNG SPA than in a conventional LNG SPA. As a result, the long-term buyers will need to be robust enough to absorb such risks, for the right reward. The flexibility required by FLNG sellers is likely to better suit buyers such as portfolio players than, for example, the ‘new’ LNG buyers in places like Southeast Asia, who will generally require a baseload supply with minimum capacity to absorb FLNG sellers’ requirements.

Given that it is difficult enough in the current market to secure buyers for conventional LNG projects, FLNG sellers will no doubt need to offer buyers broad and innovative incentives such as new pricing structures (including potentially different prices for different tranches according to the firmness of the supply commitment) and full destination flexibility in order to secure suitable long-term buyers.

Kristian Bradshaw, Counsel at Allen & Overy

 

 

 

 

 

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