Liquefied natural gas (or LNG) has been commercialised for more than 50 years, but in the past several decades there has been substantial growth in its use, and it now accounts for about a third of the global trade in natural gas. Liquefying natural gas (which involves cooling it to approximately -161C°) allows it to be transported by ship, which has enabled countries with large gas reserves not linked by pipeline to other markets to sell gas around the world. Terminals for receiving and regasifying LNG have been built in many parts of the world, and the market for LNG has grown from North America and Europe to include Asia, the Middle East, South America and, as of 2015, Africa. LNG plays different roles in different parts of the world. In some markets it is the primary source of gas supply; in others it helps make up for decreases in domestic production; in yet others it balances or complements other sources of gas.
Constructing the facilities required to extract, liquefy and export gas such as LNG, including liquefaction trains, requires substantial capital investment. Because of the need to finance these facilities, producers have historically sought to enter into long-term contracts. However, LNG is also increasingly sold through short-term or ‘spot’ agreements (e.g., a single cargo may be sold) or medium-term agreements (e.g., a number of cargos or a certain volume of LNG sold over the course of a number of months or several years). In some instances, LNG supplied under a long-term contract may be sold and delivered to customers in different destinations. Companies may also enter into swap agreements to create efficiencies, including through savings on shipping costs.
Because LNG can be transported to markets in different parts of the world, differences in gas prices between markets can create arbitrage opportunities. In the past 10 years, as LNG production increased as new facilities came online, demand for LNG in different markets has changed significantly. In the mid-2000s, the growth of shale gas production in the US meant that volumes of LNG originally expected to be delivered to the United States were delivered to Europe instead, and there were also opportunities to send LNG to Asia and South America as demand in those markets increased. After the global financial crisis in 2008, while LNG deliveries increased supply, demand for gas decreased in Europe and Asia, and there were fewer opportunities for shorter-term sales. However, Asian demand increased significantly following the Fukushima nuclear disaster in March 2011, when Japan’s nuclear power plants were shut down, and over the next several years, substantial volumes of LNG were sent to Asia. Those imports subsequently decreased as price differences reduced. Further shifts in the supply and demand balance will inevitably occur, creating new arbitrage opportunities.
Many of the disputes that arise in connection with other long-term gas supply contracts, and which may result in arbitration, also arise with long-term LNG supply contracts. In particular, most long-term LNG supply contracts include price review provisions that allow a party to request an adjustment or revision of the price when there have been changes of circumstances as defined in those provisions. Rather than focus on those general pricing disputes, this chapter will focus on issues that are more specific to LNG contracts. In particular, the chapter discusses issues that arise because LNG can be delivered to different destinations and can be re-exported after it is delivered.
Features of long-term LNG supply contracts
Historically, most LNG supply contracts have been in the form of long-term sale and purchase agreements (SPAs) with a contract term of 20 years or more, and an option to extend or renew. As noted above, the capital costs for building the facilities and equipment required to extract gas and then transform, transport and distribute LNG, can be many billions of dollars. At least in part to obtain financing for such projects, producers wanted to contract with buyers who would commit to purchasing substantial volumes over a long time-period and would provide regular revenues. At the same time, many buyers were monopoly or semi-monopoly gas merchants, with substantial downstream obligations in their home markets, and they were interested in diversifying their supply portfolio and having a secure supply of gas (and many buyers continue to have those interests even in liberalised gas markets, although LNG is increasingly being sold through shorter term contracts).
Certain key features of long-term LNG SPAs are discussed below.
Price and price review provisions in LNG SPAs
Outside of North America (where gas contracts are usually priced using the ‘Henry Hub’ gas market price), many LNG SPAs were priced using formulae with a base price and indexation referring to competing sources of energy like fuel oil, gasoil, and coal (and some LNG contracts have been priced by reference to wholesale electricity prices). More recently, some LNG SPAs have been priced using gas hub prices or using formulae with a mixture of hub prices and alternative fuels. The contract price may also be linked to other economic indicators such as inflation or tax rates.
Like other long-term gas supply contracts, LNG SPAs usually include a price review or reopener provision, which will generally provide for periodic dates when either party may request a price revision or adjustment when there has been a change of circumstances meeting certain requirements in a defined market within a defined period of time (or ‘review period’). Providing for periodic price reviews in a long-term supply contract balances two competing concerns:
- it allows the price to be adjusted to maintain the parties’ original commercial bargain over the lifetime of the contract because circumstances may change; and
- it avoids ‘imposing price reviews too frequently which may have the adverse effect of increasing contractual uncertainty’.
There are different approaches to how a price review is triggered. For example, while it is less common in LNG SPAs, the parties may include a provision providing for automatic price adjustments at regular intervals based on the levels of published fuel prices or tax rates. More commonly, many LNG SPAs provide that a party may request a price revision where certain criteria have been established, such as a substantial and unforeseen change in circumstances that was beyond the parties’ control. The price review provision will usually define the market in which the change must take place (e.g., within a specified geographic market, the buyer’s end user market in a certain geographic area, the buyer’s market more generally, specific segments of a market). As discussed below, whether and how the price review clause refers to the relevant market may be significant when a dispute arises about whether sales of LNG to other markets can trigger a price revision.
As liquid traded gas markets have developed, a number of buyers have brought price review requests seeking to introduce gas hub pricing into the price formulae in their LNG SPAs (usually in place of or in addition to price formulae linked to oil products). Following the liberalisation of European gas markets during the 2000s, a number of requests for price adjustments resulted in arbitrations, and similar disputes have and will take place as gas markets develop in other parts of the world. Other pricing disputes have arisen because of alleged regulatory or other changes. Price review disputes in relation to the sale of LNG cargos to other markets have also resulted in arbitrations. These are discussed below.
Because producers wanted buyers that would commit to purchasing substantial volumes over a long time-period and provide regular revenues, long-term LNG SPAs have typically required the buyer to take a very substantial annual quantity and include a take-or-pay provision, which requires the buyer to pay for a certain amount of the annual contract quantity (sometimes 100 per cent but often a percentage of that quantity, e.g., 85 or 90 per cent), whether or not the buyer takes that quantity.
While these long-term SPAs sometimes are described as ‘sea pipelines’, the practicalities of delivering LNG can make it a different and less ‘flexible’ product than gas delivered by pipeline. A full cargo of LNG on a conventional LNG tanker is a significant quantity of gas (more than sufficient to supply a small city for a year, for example). It takes time to load, transport and unload a cargo, and shipping must be scheduled (including potentially to include sufficient time for a vessel to make the return voyage). Deliveries are usually on a regular schedule (although weather and other events can disrupt that schedule). As a result, gas volumes delivered as LNG may not closely match the demands of the buyer’s customers throughout the year (which can vary substantially depending on a number of factors, including the season), and there may be limited storage capacity available for the buyer to store excess gas.
Because of this, parties may include provisions in a long-term LNG SPA that allow the buyer to shape its offtake profile to better match the market demand for gas and reduce its exposure to take-or-pay risks. The parties may also provide for destination flexibility so that the LNG may be delivered to different terminals. Destination flexibility helps the buyer manage the take-or-pay risks arising from its volume commitment by enabling it to sell to additional markets and, as with other mechanisms intended to create offtake flexibility, also creates the opportunity for the buyer to engage in price arbitrage (by selling to higher priced markets).
The amount of destination freedom a buyer has will depend on the specific terms of the SPA. As discussed below, some SPAs may include destination restrictions that require the buyer take delivery at a specified port or only sell the LNG in a specified geographic area (although many contracts do not include such restrictions and they may be illegal in certain jurisdictions). Other SPAs will have detailed provisions providing for delivery to other destinations.
Shipping terms and title to the LNG
Most LNG SPAs will include a provision identifying the delivery point and shipping terms that stipulate that title, custody and risk transfer from the seller to the buyer at that point; both title and shipping terms are relevant to determining how much destination flexibility a buyer has.
The allocation of costs and risk between the seller and buyer is usually specified by reference to the Incoterms shipping rules published by the ICC. The most commonly used delivery terms in LNG SPAs are delivery ‘free on board’ (FOB) and delivery ‘ex ship’ (DES). (The DES term was eliminated from Incoterms 2010 and parties appear now to be using ‘delivered at terminal’ (DAT) in more recent agreements.)
If LNG is delivered FOB, title and risk will shift to the buyer when the LNG is loaded on to the ship and the buyer is responsible for arranging the vessel. Accordingly, unless there are other contractual provisions that purport to limit the buyer’s ability to resell or send the LNG to whatever destination it chooses, under an FOB contract, the buyer may have almost complete destination freedom (subject to shipping and other commercial constraints).
By contrast, if LNG is delivered DES (or DAT), the seller retains title and risk until the LNG is unloaded at its destination, and the seller is responsible for shipping costs. In such a case, the SPA will identify a specific delivery port (often in the buyer’s home market) and the buyer may have no destination freedom at all, unless the parties have added provisions providing that the buyer may request delivery to other destinations, often referred to as diversions (or deviations). Diversion provisions are discussed in more detail below.
Destination restrictions in LNG SPAs
In addition to designating the delivery point, historically, many long-term LNG SPAs contained destination restriction clauses. Such provisions restricted the buyer from reselling the LNG outside of a designated geographic market (usually, the buyer’s home market). However, such restrictions have become less common and, as discussed below, the European Commission has said that such provisions are not permitted in contracts for the sale of LNG to European buyers.
A seller may want to prevent a buyer from being able to deliver cargos to other destinations because the seller does not want the buyer to compete with it in other markets or to compete with its other buyers. A seller may also be concerned about the costs of delivering to alternate destinations and the potential disruption to its transportation logistics and schedule, or that delivery to a different market than the one designated in the contract may violate trade restrictions or the terms of the seller’s financing.
In contrast, a buyer may view the right to deliver LNG cargos to different destinations as essential to mitigating the take-or-pay risk created by its volume commitment (because it may not have sufficient customer demand in the designated delivery market to sell gas there at a profit or to avoid a take-or-pay penalty). A buyer may also have obligations to supply customers or its own facilities in different locations (for example, a buyer may own facilities such as combined cycle gas turbines in other places) and it therefore may want to have the contractual right to deliver to multiple destinations. More generally, a buyer may want destination flexibility to manage its overall portfolio (which may include different sources of supply with different pricing and other terms) and to pursue arbitrage opportunities.
The European Commission has conducted a number of investigations (involving both LNG and pipeline contracts) in which it has said that ‘territorial restriction clauses (re-export prohibitions) and mechanisms having similar effects’, including the effect of reducing the opportunity for the buyer to pursue arbitrage sales, constitute a ‘severe restriction’ on competition. The Commission has made clear that it considers such provisions in contracts between non-EU producers and European buyers to constitute a ‘serious breach’ of European competition law because they prevent cross-border trade and undermine the goal of a single integrated gas market in Europe, and has entered into a number of settlements requiring gas producers to change the terms of supply contracts.
The Commission has also stated that profit-sharing mechanisms where ‘the buyer/importer [has] to share a certain part of the profit with the supplier/producer if the gas is sold on by the importer to a customer outside the agreed territory’ have been used as an alternative to territorial restriction clauses and may restrict competition by dissuading purchasers from selling cargos outside a designated market even if such provisions do not expressly prohibit such sales. In 2007 the Commission stated, in settling an investigation of Sonatrach that, in its view, profit-sharing mechanisms are not permissible for LNG sold on an FOB basis. The Commission indicated, however, the use of profit-sharing mechanisms may be permitted where an SPA provides for delivery on an ex-ship basis and ‘title of the gas remains with the seller until the ship is unloaded’.
Destination restrictions are thus generally not included in LNG SPAs with European buyers and diversion provisions requiring profit sharing are generally understood to only be permissible while the seller retains title of the LNG. It is not clear whether destination restrictions or profit-sharing mechanisms in FOB contracts violate antitrust or competition laws in other jurisdictions or how arbitral tribunals will address claims that a particular contract provision (with a European buyer or otherwise) violates antitrust or competition laws, although this issue has been raised in arbitrations.
Diversion provisions in LNG SPAs
The option to sell LNG cargos in alternative destinations may be an opportunity to create additional value for the buyer and the seller. In addition to obtaining a higher price, sending a cargo to a new destination may result in substantial savings in shipping costs. Because of this, parties often cooperate in identifying and sharing the benefits from diversion opportunities even if there is no provision in their SPA requiring that they do so. However, sellers and buyers can have different views as to whether diversions should be permitted as a right in an SPA and, if so, under what circumstances a buyer should be permitted to divert cargos to other destinations.
Provisions addressing the possibility of diverting cargos are increasingly common in LNG SPAs, and help parties structure diversion rights in order to accommodate their competing commercial interests. The Association of International Petroleum Negotiators (AIPN) issued an updated version of its Model Contract Master LNG Sale and Purchase Agreement in 2012, which contains an optional diversion provision.
Some diversion provisions are very brief, while others are very detailed. There is a wide range of approaches to such provisions: (1) some permit the buyer a certain number of diversions (and some also permit the seller to divert); (2) some set out circumstances in which the buyer may request diversions and the seller must agree; and (3) some provide that either the buyer or the seller may propose diversions and the parties will discuss such proposals in good faith. Many SPAs provide for a combination of these options.
Diversion provisions may also include other limitations or conditions: (1) some limit the volume of cargos that a purchaser may send to alternate markets; (2) some limit the number of diversions to which a party is entitled; and (3) some limit the particular destinations to which cargos may be diverted. The parties may also agree on other conditions as to when diversions may be permitted or refused. For example, the parties may stipulate that the buyer may not be entitled to divert cargos to alternate markets unless the market price for gas in the designated market falls below the contract price. More commonly, the parties may stipulate that the buyer may not have a right to divert a cargo unless the diversion will not increase the shipping distance or costs, or impair the seller’s vessel from returning to the loading port in time to make its next scheduled delivery. The parties may also stipulate that the buyer is obligated to pay for any additional costs that the seller incurs in order to deliver LNG to an alternate destination.
There are different approaches to pricing or sharing the economic benefit from diverted cargos. For example: (1) the parties may have an agreed profit sharing mechanism for diverted cargos; (2) the parties may need to agree on a price (or a profit sharing mechanism) each time a cargo is diverted or on a profit sharing mechanism; or (3) where the parties have identified permitted diversion destinations in the SPA, they may also include pricing provisions for cargos delivered to specified markets (and these price formulae can be very different from the contract price for non-diverted LNG).
These pricing provisions may also be subject to revision in the event of a change in the diversion market (and the price review provision for the diversion markets may have different standards).
Disputes relating to LNG diversions
As the LNG market has grown, and as short-term changes in demand and supply have created more opportunities for price arbitrage by sending LNG to other markets, there have been an increasing number of price disputes relating to deliveries to other destinations and diversions.
In some instances, sellers have argued that a buyer’s use of diversions justifies revising the SPA’s price formula. In these cases, the seller may argue that the contract price was negotiated in light of the parties’ mutual understanding that the gas supplied under the contract would be sold only in a particular market, such that a destination restriction effectively constitutes an implied element of the parties’ bargain. The seller may therefore contend that the diversion of cargos to other markets alters the bargain reached by the parties.
Parties also have sought adjustments to the price formulae used in some SPAs to price LNG delivered to alternate destinations (often on the same or similar grounds as in other pricing disputes, including that formulae based on competing sources of energy should be revised to include gas market prices). There have been a range of other disputes, including as to whether the seller has the right to refuse a diversion proposal and whether (and how) the parties have agreed to share profits on cargos delivered to other destinations.
Most disputes relating to LNG SPAs are confidential and therefore publicly available details about disputes relating to diversions are limited. However, the arbitral award in a dispute concerning diversions between a Trinidad producer, Atlantic LNG, and a Spanish buyer, Gas Natural, was made public as part of court proceedings in the US, and illustrates some of the issues that can arise with regard to diversions.
The dispute arose out of a long-term SPA for the sale of approximately 40 per cent of the LNG produced at Atlantic LNG’s facility. In the award, the tribunal found that the parties had negotiated their contract price ‘on the assumption that the LNG would be delivered to and sold in Spain’, including by modelling the contract price on various aspects of the Spanish energy market. The SPA nevertheless permitted Gas Natural to divert some or all of the LNG cargos to New England in the US, but it did not provide for any change to the contract price if Gas Natural did so.
When a price difference made selling to the US sufficiently attractive, Gas Natural elected to divert cargos to New England. Atlantic LNG claimed that these diversions entitled it a price review under the terms of the SPA (which referred without specifying to the whether the contract price ‘reflected the value of Natural Gas in the end user market’) because the contract price reflected the Spanish market and not the New England market. The tribunal agreed and imposed a revised price formula that was intended to ‘be adaptable depending on the Buyer’s end user market at the time’. The revised price formula required Gas Natural to pay a New England-based price in the event that it elected to divert a specified percentage of cargos to the New England market.
While widely cited, the decision in is controversial, including because the tribunal appears to have imposed a remedy that neither party proposed. It also turns on the specific contractual provisions in the SPA and the tribunal’s findings concerning the parties’ expectations. It nonetheless reflects some of the issues that can arise concerning diversions, particularly where the parties have not included detailed diversion provisions.
Potential issues relating to the re-export of LNG
LNG terminals are often capable of both unloading and loading LNG. As supply and demand has shifted in international markets, some buyers have re-exported LNG after taking delivery of it to sell it to higher-priced markets. A buyer that has imported LNG may export LNG because it does not have a contractual right to divert cargos (or the seller has refused to do so) or because sufficient LNG is available in the import market and it can be sold more economically to a different market.
In order to export LNG, the buyer may be able to make a ship-to-ship transfer (usually to smaller vessels). LNG also may be unloaded and sent to storage facilities at the LNG terminal, where it is commingled with LNG in the storage tanks. A buyer may then use the commingled LNG from several deliveries (or purchase LNG from other importers) to load a cargo onto a vessel or vessels to sell to another destination. Some terminals in the US have been used to load LNG for delivery to other destinations (rather than regasifying it) since the 1970s. LNG terminals in Spain began loading larger volumes of LNG in the late 1990s; other LNG terminals in Europe and elsewhere have begun to load LNG more recently.
While these activities are sometimes referred to as ‘reloading’, which implies that a cargo of LNG has been unloaded by the buyer and that cargo has then been transferred to a new vessel for re-export, the reality of exporting LNG is more complicated. Due to the ‘boil-off’ of LNG while it is transported, unloaded and stored, there will not be sufficient LNG from one cargo to load a full cargo onto another LNG tanker.
Like diversions, the ability to load LNG provides a buyer with the ability to mitigate its take-or-pay risks, manage storage constraints, manage its supply portfolio and engage in price arbitrage. Unlike a diversion, however, a buyer loads LNG after it takes title and loading does not involve additional costs or risks for the seller (as the seller is not involved in the loading operation or the delivery of the loaded LNG to another destination). Moreover, unlike a diversion, where it may be possible to reduce shipping costs, loading LNG typically involves incurring additional shipping costs (because the LNG is delivered twice), as well as the costs of storing and loading the LNG, which can be substantial. Because of these added costs, ‘a premium well in excess of shipping costs is required to incentivize the re-exporting of gas’. There also can be other logistical constraints which limit a buyer’s ability to export LNG (including having sufficient LNG, timely access to the LNG terminal and available shipping capacity).
Thus, while the ability to load LNG may allow a buyer with limited or no diversion rights to sell LNG to other markets, loading LNG is usually less efficient than diverting LNG. Indeed, in many cases where it would have been profitable to divert a cargo to another market, it will not be economical to load LNG to pursue the same opportunity. Because of this, LNG cargos began to be loaded in larger amounts from Spain, for example, only when very substantial price differences developed between Europe and Asia and South America.
There have been a number of recent disputes involving loading of LNG for delivery to other destinations. While the details of those disputes are not public, where the SPA does not permit diversions or limits their availability, a seller may argue that loading LNG is inconsistent with the parties’ expectations or an attempt to evade contractual limitations. However, in many SPAs, there are no limits on what the buyer may do after it takes title to the LNG. Moreover, the rationale for sharing the benefit gained when parties agree to divert a cargo does not apply when LNG is loaded by the buyer after title has shifted to it and the buyer bears all the costs and risks of the loading and subsequent sale.
Profit sharing in these circumstances also potentially raises competition law issues. Indeed, the European Commission reasoned that it was impermissible to share profits on diversions where LNG was sold on an FOB basis because the diversion takes place after delivery to the buyer when the seller no longer has title to the LNG. That logic would appear to apply equally to LNG that is re-exported after delivery to a market.
As loading of LNG becomes more common, it is likely that there will be more disputes about its consequences for existing supply contracts. Arbitral tribunals are just beginning to address these issues, and it is not clear to what extent, if at all, sellers will be able to seek to revise the contract prices in long-term SPAs because the LNG delivered may be re-exported to different markets.
As global trade in LNG continues to evolve, there will be more disputes relating to the delivery and re-export of LNG, particularly under SPAs that may have only addressed such issues in broad terms, if at all. Moreover, as parties shift away from long-term supply contracts and enter into shorter and more flexible agreements, new and different disputes will arise. As with the disputes that have already resulted in arbitrations, the specific contractual language agreed by parties regarding the destination and use of the LNG will be critical in resolving these disputes.
 International natural gas trade accounted for about 30 per cent of global consumption, with LNG exports totalling approximately 340 billion cubic metres in 2015 (compared to approximately 700 billion cubic metres exported by pipeline). See BP Statistical Review of World Energy 2016, at pp. 4, 29. LNG exports in 2016 were sufficient to supply power to approximately 500 million homes. Shell LNG Outlook 2017, available at http://www.shell.com/energy-and-innovation/natural-gas/liquefied-natural-gas-lng/lng-outlook.html#vanity-aHR0cDovL3d3dy5zaGVsbC5jb20vbG5nb3V0bG9vaw.
 The largest producers of LNG are now Qatar, Australia, Malaysia, Nigeria, Indonesia, Algeria, Russia, and Trinidad and Tobago. See International Gas Union, World LNG Report – 2017 Edition, at p. 9. Eighteen countries exported LNG in 2016. See International Gas Union, World LNG Report – 2017 Edition, at p. 9. Australia and Indonesia opened new facilities in 2015.
 In 2016, more than 70 per cent of LNG imports were to the Asia-Pacific and Asia regions. See International Gas Union, World LNG Report – 2017 Edition, at p. 8. The number of countries importing LNG has continued to grow, with 35 countries importing LNG in 2016. The biggest importing countries include Japan, South Korea, China and India. See Shell LNG Outlook 2017, at p. 9.
 Liquefaction facilities can cost as much as US$20 billion to construct and maintain and regasification facilities can cost as much as US$1 billion. See ‘Financing LNG Projects and the Role of Long-Term Sales-and-Purchase Agreements’, Discussion Papers, DIW Berlin, No. 1441, dated January 2015, at p. 3. See also World LNG Report – 2014 Edition, International Gas Union, at p. 21. As a less costly alternative, floating regasification and storage units (FRSUs) are increasingly being used.
 See, generally, ‘The New LNG Trading Model Short-Term Market Developments and Prospects,’ Poten & Partners, dated 2010. In 2016, approximately 25 per cent of LNG was traded through non-long term contracts (e.g., through spot, short or medium term contracts). See World LNG Report – 2017 Edition, International Gas Union, at p. 15.
 In a simple swap agreement, where seller 1 is contracted to deliver to buyer 1, and seller 2 is contracted to deliver to buyer 2, seller 1 would deliver to buyer 2, and seller 2 would deliver to buyer 1. For example, one company may send a cargo from Trinidad to the US, rather than to Spain, and the other company send a cargo from Algeria to Spain, rather than the US, and share the additional value created by saving on shipping costs. See A Patten and P Thomson, ‘LNG trading’, in P Griffin (ed.), The Law and Business of LNG, 1st ed, 2008, at pp. 62-64; ‘The New LNG Trading Model Short-Term Market Developments and Prospects,’ Poten & Partners, dated 2010; ‘Market insight: swapping strategies,’ World Gas Intelligence, dated 17 July 2002.
 See ‘The US Shale Gas Revolution and its Impact on Qatar’s Position in Gas Markets,’ Columbia/SIPA Center on Global Energy Policy, dated March 2015. See also International Gas Union, World LNG Report – 2016 Edition, at p. 8.
 See ‘Financing LNG Projects and the Role of Long-Term Sales-and-Purchase Agreements,’ Discussion Papers, DIW Berlin, No. 1441, dated January 2015.
 See P Weems, Overview of issues common to structuring, negotiating and documenting LNG projects, 8 International Energy Law & Taxation Review 189, 193-194 (2000); See ‘Financing LNG Projects and the Role of Long-Term Sales-and-Purchase Agreements,’ Discussion Papers, DIW Berlin, No. 1441, dated January 2015, at pp. 2-7.
 Henry Hub is a physical meeting point of various gas pipelines in Louisiana, USA, from which collated trading data is used as a price-setter for North American gas markets. See P Roberts, Gas and LNG Sales and Transportation Agreements: Principles and Practice, 4th ed, 2014, at p. xxvii.
 Many SPAs provide for the right to request a price review at specified intervals (e.g., every two or three years), and often provide that both parties have the additional right to a limited number of unscheduled price review requests over the term of the contract (often referred to as ‘wild card’ or ‘joker’ requests). When a party requests a review, the contract may obligate the parties to engage in discussions to determine whether a revision is justified, and if it is, to agree on an appropriate revision reflecting the change of circumstance. Most SPAs provide that if the parties cannot agree, the parties may resolve their dispute through arbitration.
 M Clarke, T Cummins, and F Worthington, ‘The price isn’t right – gas pricing disputes’, 1 Int’l Energy L Rev 13, at pp. 15-16 (2015).
 See, e.g., Gas Natural Aprovisionamientos SDG, S.A. v. Atlantic LNG Co. of Trinidad and Tobago, No. 08 Civ 1109, 2008 WL 4344525 (SDNY 16 September 2008). Some SPAs may also provide for a price revision where certain objective criteria have been satisfied. Such a clause might stipulate a certain return for the buyer, for example, that triggers a price review when it is not met. The price review clause may also identify certain criteria that must be taken into account when revising the contract price, including the price of other gas imported under long-term contracts.
 Mechanisms for doing so include ‘make-up’ clauses that enable a buyer to defer taking the stipulated annual quantity in one year and to make up the deficit in a subsequent year on favourable payment terms; ‘downward quantity tolerance’ clauses that allows a buyer to reduce the number of lifted cargos (e.g., by 5-10 per cent), which can reduce the annual contract quantity; ‘delivery flexibility’ so deliveries are scheduled flexibly over the course of the year (to correspond to periods of higher demand); and swing flexibility in supply (e.g., 10 per cent up or down). See P Roberts, Gas and LNG Sales and Transportation Agreements: Principles and Practice, 4th ed., 2014, at paras. 12-005, 17-002.
 Although title, custody and risk will ordinarily be transferred at the delivery point, they are distinct and the parties may agree bespoke terms under which title, custody and risk pass at different points. For example, an SPA may provide for custody and risk to transfer ex-ship, while nonetheless providing that title will shift to the buyer immediately before the LNG reaches the country in which the port of unloading is located. Such an arrangement is intended to relieve the seller of any tax liabilities that may be triggered when the LNG reaches its point of destination. See P Roberts, ‘Effective title transfers in international LNG trades’, 7 International Energy Law & Taxation Review 99, at pp. 99–100 (2007).
 Free on board ‘means that the seller delivers the goods on board the vessel nominated by the buyer at the named port of shipment or procures the goods already so delivered. The risk of loss of or damage to the goods passes when the goods are on board the vessel, and the buyer bears all costs from that moment onwards.’ See International Chamber of Commerce, Incoterms 2010, ICC Publication No. 715E, at p. 87.
 Delivered ex ship ‘means that the seller delivers when the goods are placed at the disposal of the buyer on board the ship not cleared for import at the named port of destination. The seller has to bear all of the costs and risks involved in bringing the goods to the named port of destination before discharging. If the parties wish the seller to bear the costs and risks of discharging the goods, then the DEQ term should be used.’ See International Chamber of Commerce, Incoterms 2000, ICC Publication no. 560, at p. 97.
 The Association of International Petroleum Negotiators’ Model Contract Master LNG Sale and Purchase Agreement (2012) (the AIPN Model LNG SPA) uses the terms ‘Buyer Delivery Sales’ and ‘Seller Delivery Sales,’ which are similar to FOB and DES respectively. See AIPN Model LNG SPA, Art. 1. Another option is delivery ‘Cost, Insurance, and Freight’ (CIF), which ‘means that the seller delivers the goods on board the vessel or procures the goods already so delivered. The risk of loss of or damage to the goods passes when the goods are on board the vessel. The seller must contract for and pay the costs and freight necessary to bring the goods to the named port of destination. The seller also contracts for insurance cover against the buyer’s risk of loss of or damage to the goods during the carriage. The buyer should note that under CIF the seller is required to obtain insurance only on minimum cover. Should the buyer wish to have more insurance protection, it will need either to agree as much expressly with the seller or to make its own extra insurance arrangements.’ International Chamber of Commerce, Incoterms 2010, ICC Publication No. 715E, at p. 105.
 Delivered at Terminal ‘means that the seller delivers when the goods, once unloaded from the arriving means of transport, are placed at the disposal of the buyer at a named terminal at the named port or place of destination. The seller bears all risks involved in bringing the goods to and unloading them at the terminal at the named port or place of destination.’ See International Chamber of Commerce, Incoterms 2010, ICC Publication No. 715E, at p. 53.
 See P Roberts, Gas and LNG Sales and Transportation Agreements: Principles and Practice, 4th ed., 2014, at para. 11-007.
 Id. at para. 4-015.
 See ‘Evolution of Long-Term LNG Sales Contracts: Trends and Issues’, King & Spalding LLP, dated 29 August 2005, at p. 6. See also S Farmer, ‘LNG Sale and Purchase Agreements’, in P Griffin (ed.), The Law and Business of LNG, 1st ed, 2008, at p. 52.
 See P Roberts, Gas and LNG Sales and Transportation Agreements: Principles and Practice, 4th ed., 2014, at para. 4–016. See also S Farmer, LNG Sale and Purchase Agreements, in P Griffin (ed.), The Law and Business of LNG, 1st ed., 2008, at p. 52.
 See S Farmer, ‘LNG Sale and Purchase Agreements’, in P Griffin (ed.), The Law and Business of LNG, 1st ed., 2008, at p. 52.
 The Commission indicated in its 2002 settlement of its investigation of Nigeria LNG that ‘once the gas is delivered and paid for, the buyer is free to re-sell the gas wherever it wishes.’ See European Commission Press Release, ‘Commission settles investigation into territorial sales restrictions with Nigerian gas company NLNG’, dated 12 December 2002, IP/02/1869.
 See European Commission Press Release, ‘Commission and Algeria reach agreement on territorial restrictions and alternatives clauses in gas supply contracts,’ dated 11 July 2007, IP/07/1074.
 In doing so, the Commission specifically referred to clauses that restrict LNG buyers from selling LNG ‘into terminals located in a different member state.’ See European Commission Press Release, ‘EC settlement with E.ON Ruhrgas and Gazprom’, dated 10 June 2005, IP/05/710.
 See European Commission Press Release, ‘Commission and Algeria reach agreement on territorial restrictions and alternative clauses in gas supply contracts,’ dated 11 July 2007, IP/07/1074. See also E Wäktare, ‘Territorial restrictions and profit sharing mechanisms in the gas sector: the Algerian case,’ 3 Comp Pol Newsletter 19, 20 dated 2007 (‘By requiring the importer to share part of the profit gained through the deviation of the gas to a more profitable destination, the [profit-sharing mechanism] may have an anti-competitive effect, if it removes or reduces the importer’s incentive to deviate the gas.’). Previously, as a condition to the conclusion of the Commission’s investigation into its use of territorial restrictions, Nigeria LNG Limited agreed not to introduce profit-sharing provisions in its SPAs with European purchasers. See European Commission Press Release, ‘Commission settles investigation into territorial sales restrictions with Nigerian gas company NLNG,’ dated 12 December 2002, IP/02/1869.
 The AIPN Model LNG SPA takes a similar approach: its model diversion provision applies only to a ‘Seller Delivery Sale,’ not to a ‘Buyer Delivery Sale.’
 See AIPN Model LNG SPA, at Clause C17. The AIPN model diversion provision provides that a buyer may request that a cargo be diverted to an alternative discharge port if the diversion will not affect that seller’s shipping schedule and if the parties are able to agree on a profit-sharing mechanism or other price revision.
 See AIPN Model LNG SPA, at Clause C17.
 See E Wäktare, ‘Territorial restrictions and profit sharing mechanisms in the gas sector: the Algerian case’, 3 Competition Policy Newsletter 19, at p. 19 (2007) (‘Typically the contracts provide for a 50/50 split of the additional profits’). As discussed above, the European Commission has indicated profit sharing is permissible when LNG is diverted under a DES contract where the seller retains title and bears the costs and risks of shipping to a different destination).
 See C Bell, ‘United States: what happens when your gas contract price is linked to one market but you are delivering into another?’, 1 International Energy Law Review 10, at pp. 10-11 (2009).
 Gas Natural Aprovisionamientos SDG, S.A. v. Atlantic LNG Co. of Trinidad and Tobago, No. 08 Civ. 1109, 2008 WL 4344525 (SDNY 16 September 2008). The tribunal’s Final Award was exhibited in the proceedings (referred to below as Atlantic LNG v. Gas Natural, UNCITRAL, Final Award).
 See Atlantic LNG v. Gas Natural, UNCITRAL, Final Award, at paras. 9, 23.
 See Gas Natural Aprovisionamientos SDG, S.A. v. Atlantic LNG Co. of Trinidad and Tobago, No. 08 Civ. 1109, 2008 WL 4344525, at *1, *2 (SDNY 16 September 2008).
 See Atlantic LNG v. Gas Natural, UNCITRAL, Final Award, at para. 60. See also Gas Natural Aprovisionamientos SDG, S.A. v. Atlantic LNG Co. of Trinidad and Tobago, No. 08 Civ. 1109, 2008 WL 4344525, at *2 (SDNY 16 September 2008).
 See ‘Case study: LNG terminals under regulation: the Spanish experience’, Enagas, dated 25 March 2014, at p. 44.
 LNG was re-exported from ten countries in 2016. See International Gas Union, World LNG Report – 2017 Edition, at p. 10.
 See ‘Atlantic Basin LNG reloading trend could develop soon in Asia market’, Facts Energy Global, dated 14 February 2014.
 ‘Will European LNG reloads continue?,’ Timera Energy, dated 26 August 2013, at p. 4.
 See European Commission Quarterly Report on European Gas Markets, Vols. 6-7, 2013-2014, p. 14 (noting that buyers loading cargos ‘face a number of logistical constraints and associated costs ... such as reloading times, energy lost via boil-off and how long gas can be kept in terminal before it needs to be discharged.’).
 See ‘Spain Plans 30% Hike in Third-Party LNG Reload Costs’, Downstream Today, dated 27 June 2012, at p. 1. See also ‘Gas price convergence stalls Spanish LNG exports’, Reuters UK, dated 29 April 2015, at p. 1.
 See ‘Secondary Markets for LNG Exports: Legal implications of ‘reloads’ for LNG Sales Agreements’, HWL Ebsworth, dated 27 February 2014 (suggesting that ‘A buyer who obtains an advantage through arbitrage opportunities via ‘reloads’ may potentially be found to be in breach of its LNG Sale and Purchase Agreement if it is found to have engaged in strategic behaviour designed to evade contractual obligations. This may potentially occur where the buyer engages in a systematic series of trades which are found to have the effect of injuring the right of the seller to receive a benefit under the agreement. Much will turn on the provisions of the contract itself and the activities undertaken, however, there is potential for a buyer to be found to be in breach of its implied duties of good faith and fair dealing under the contract in these circumstances.’).
 As discussed above, commentators have therefore interpreted the Commission’s settlements in the Nigeria LNG Limited and Sonatrach investigations as precluding a seller from restricting the buyer’s use of LNG or sharing in profits after delivery by the seller. See E Wäktare, ‘Territorial restrictions and profit sharing mechanisms in the gas sector: the Algerian case’, 3 Competition Policy Newsletter 19, at p. 21 (2007) (‘Once title and risk pass to the buyer the PSMs should not be applied.’). See also European Commission Press Release, ‘Commission and Algeria reach agreement on territorial restrictions and alternative clauses in gas supply contracts,’ dated 11 July 2007, IP/07/1074; European Commission Press Release, ‘Commission settles investigation into territorial sales restrictions with Nigerian gas company NLNG,’ dated 12 December 2002, IP/02/1869.