Traditionally, long-term take-or-pay “ToP” LNG sale and purchase agreements (“LNG SPAs”) provide the foundation for the development of an LNG export project. These are contracts with terms of 20 years or longer. A buyer under an LNG SPA with ToP provisions must take and purchase an annual contract quantity of LNG and, if it fails to so take, it must nonetheless pay for the quantity not taken but retains the right to take that quantity at a later time.
The advantage of the ToP feature is best understood in context of the overall development of an LNG export project. Historically, LNG export projects have been developed in connection with discoveries of stranded gas reserves – i.e., reserves that are located at a remote distance from available markets for the gas, potentially due to a lack of domestic gas demand or infrastructure. An LNG export project is the means by which producers can monetize the reserves by liquefying the gas and shipping LNG to consuming markets. The costs for an LNG export project, and particularly the LNG plant infrastructure, are high. 1 Thus, producers will not undertake the development of (and lenders will not project finance) a project unless and until they can be assured of revenues to cover costs plus a suitable return on investment.
Aside from the LNG plant itself, other major cost components must be considered such as the costs for (i) upstream production and pipelines to deliver the gas to the LNG plant, and (ii) constructing or chartering ships, if the producers are responsible for delivering the LNG to the consuming market. A ToP LNG SPA provides a reliable stream of revenues to support all these costs.
The success of an LNG Project rests on securing unconditional ToP LNG SPAs covering sufficient annual contract quantities to provide the level of revenues to cover project costs and return on investment. Further, these ToP LNG SPAs must be with creditworthy buyers to assure timely payment of revenues. And, for project financing purposes, certain “bankable” terms must be included in the ToP LNG SPAs to meet the requirements of project lenders.
U.S. LNG Supplies
During the past few years, all eyes have been on the development of LNG export projects in the U.S. The increased supply of gas from shale has transformed the U.S. gas market. Where the market previously focused on imports and the need for design and construction of import terminals, the market has now shifted to exports with the design and planning of more than five export projects under construction plus 15 additional projects that are seeking permitting approval. 2
As the first of these projects have achieved positive final investment decisions and begun construction, these projects have impacted the LNG industry in various ways. And developments in proposed LNG SPA terms may be rooted, at least in part, in these U.S. LNG projects. To understand how U.S. LNG projects may influence the development of the Latin American LNG industry, it is important to understand how these projects differ from traditional LNG export projects.
Uniqueness of U.S. Gas Market
Traditional LNG export projects are developed to monetize stranded gas reserves. This aspect is the most significant difference between the U.S. LNG projects and traditional LNG projects. The U.S. has a long-established domestic gas market, with strong demand and an extensive network of infrastructure to deliver gas from the production fields to the ultimate consumers.
The well-developed U.S. gas market means that U.S. LNG projects are developed not as a necessary component to monetize stranded gas reserves, but as businesses in and of themselves. In traditional LNG projects, the upstream gas producers sponsor the LNG project and obtain a return on both the upstream gas production and the liquefaction and sale of such gas as LNG. In U.S. LNG projects, the project developer typically has no stake in the upstream gas production and may purchase gas supplies from any number of gas producers or marketers. U.S. LNG projects are to date owned by entities other than the upstream gas producers and obtain revenues from the rendering of liquefaction services either through tolling models or through the direct sale of LNG, as described below.
A well-developed gas market in the U.S. means liquidity (i.e., a producer can easily find a buyer for its gas production and a buyer can easily find a gas supplier) and price transparency. Sales and purchases of gas are often transacted through online exchanges and priced based off of published indices, such as NYMEX Henry Hub. Indeed, the Henry Hub index is what first drew the attention of traditional Asian LNG buyers. The prices of traditional LNG SPAs are linked to oil indices such as Brent and thus subject LNG buyers to fluctuations in LNG prices for factors that affect the oil markets but have little or no relation to the supply and demand of gas. Henry Hub allows LNG buyers to clearly segregate the value of the underlying gas commodity from the cost of the LNG plant infrastructure and thereby a more transparent way to price the LNG.
Project Structures – Tolling versus LNG Sales Model
The predominant model for U.S. LNG export projects is a tolling structure. 3 Under a tolling structure, the project developer of the LNG plant provides liquefaction services to the customer. The U.S. LNG project receives gas delivered by the customer, treats and liquefies such gas and delivers the resulting LNG to customer at the berth for loading. The customer pays a fee for the right to use such services and typically incurs additional costs based on its actual use of such services. The customer, and not the project developer, is responsible for procuring gas for delivery at the inlet to the LNG plant. The customer is also responsible for procuring LNG tankers and any downstream marketing and resale of the LNG.
The other model for U.S. LNG export projects is Cheniere’s LNG sales structure. 4 Under this structure, Cheniere agrees to deliver LNG at the berth to its customers pursuant to LNG SPAs. This means that Cheniere purchases the gas from producers, liquefies such gas and then sells LNG to buyers. What differentiates Cheniere’s LNG SPAs is that it has offered many of its customers a right that is not found in traditional LNG export projects sales contracts – the right to pay a fixed charge and cancel scheduled quantities, in exchange for a “cancellation fee”. This fixed charge is effectively equivalent to a tolling fee and covers the capital and other fixed costs of the LNG plant. Thus, Cheniere’s LNG sales structure is more appropriately characterized as a synthetic tolling structure.
In both models, the customers (tolling) and the U.S. LNG project (LNG sales) do not depend on one sole source of supply (e.g., an upstream stranded reserves export project) but rather they have the flexibility of the well-developed U.S. gas market. As LNG pricing is largely a function of the gas commodity plus liquefaction costs, low shale gas prices triggered the boom in the development of U.S. LNG export projects.
Considerations in Electing a Project Structure
While both the U.S. tolling and synthetic tolling/LNG sales structures require customers to pay a fixed fee to cover the fixed costs of the LNG plant, there are differences between the two structures which warrant careful consideration by project developers and customers alike. There are variations within each of these two main structures and the project structure can and should be tailored for each LNG project depending on the participants involved and their respective goals and risk appetites. That said, a few of these differences are described on a high-level below to illustrate the importance of the choice of project structure.
(i) Who is responsible for upstream gas and transportation arrangements? Under a tolling structure, the customer takes on this responsibility. Some non-U.S. customers view this responsibility as an opportunity to have a stake in upstream gas production, in part, as a natural hedge against their short position on gas as a gas consumer. Indeed, some of the Asian LNG buyers to first sign on as tolling customers with U.S. LNG projects have made such announcements. 5 However, other non-U.S. customers may prefer not to have a presence in the U.S., including the need to establish an office in the U.S. and exposure to U.S. regulators necessary in connection with gas procurement and transportation activities. For those customers, the LNG sales structure would be preferable as the project developer assumes the upstream responsibilities.
(ii) How much working capital does one wish to devote to the LNG project? A project developer may desire taking on the upstream responsibilities and, along with those responsibilities, a potential for higher overall returns under an LNG sales structure. This will, however, require the project developer to procure additional working capital necessary in connection with upstream contractual commitments. Under a tolling structure, the project developer can focus on financing for the LNG plant infrastructure only. In some cases, working capital requirements for LNG tank heel may also be passed on to the customers.
(iii) How much volume flexibility does a customer want? In this case, both structures are fairly similar. Under a tolling structure, the customer is paying for the right to liquefy gas at the LNG plant but generally has no obligation to do so. The customer effectively has an option to receive U.S. LNG. This may be to the customer’s benefit if, as illustrated by the depressed oil prices of today, the customer can purchase a spot cargo at a cheaper oil-linked price. While the LNG sales model can be structured (as Cheniere has done) to provide the customer cancellation rights, as discussed above, this is really a synthetic tolling structure; therefore, the customer has cancellation rights but, these cancellation rights under an LNG sales model are likely to provide less overall volume flexibility than that of a tolling model. For example, the cancellation might be subject to more advanced notice so that the LNG seller/ project developer has sufficient time to mitigate its upstream obligations (e.g., cancel, resell or not purchase gas for liquefaction). So, although quite similar, it seems that the tolling structure is more flexible with respect to volume commitments.
LNG Industry in Latin America
Latin American countries (including those in the Caribbean) are no strangers in the LNG industry (see diagram below for a list of existing Latin American LNG terminals). Atlantic LNG commenced operations on its LNG export project in Trinidad and Tobago in 1999, followed by additional trains in 2002, 2003 and 2006 and the nation supplies just over 5% of the global LNG demand in 2013. 6 Peru LNG has liquefied gas from the Camisea field since June 2010. The project consists of a 4.2-ton gas liquefaction plant, a 408 km pipeline built across the Andes and a marine terminal on the coast of the Pacific Ocean at Melchorita. 7 Currently Pacific Stratus (a subsidiary of Pacific Rubiales) is developing a floating liquefaction, regasification and storage unit (FLRSU) to be provided by Exmar which will be the first LNG project in Colombia. 8
On the demand side, the Latin American countries of Argentina, Brazil, Chile, Dominican Republic, Mexico and Puerto Rico make up about 8% of global LNG demand. 9 Recent developments in the Latin American LNG industry indicate that the region may supply additional LNG for the industry but there are also indications that more imports will be required, mainly as a result of conversion of power plants from fuel to gas or hydro to gas. For LNG suppliers, the Latin American LNG consuming market has unique characteristics that may affect the negotiation of LNG SPAs.
Source: International Group of Liquefied Natural Gas Importers
a. Characteristics of Latin American LNG Consuming Market
The Latin American LNG demand market is quite unique and its characteristics may influence LNG SPA terms and contracting practices. First, the recent growth in LNG demand in Latin America is driven in large part by the conversion of existing power plants from burning fossil fuels to gas. With these conversions, the power plants gain fuel switching capability and are not totally dependent on gas. Second, recent LNG import developments have skewed towards the use of floating LNG regasification vessels as opposed to land-based LNG import terminals. The floating vessels are less capital intensive but also provide lower storage and regasification capacities. Such lower capacities translate into smaller LNG cargoes, longer time required to unload a cargo and overall less operational flexibility. Because of the reduced operational flexibility, operations may be particularly affected by seasonality or other changes in downstream demand. Third, LNG buyers in Latin America are often times national utilities or electrical companies, in many cases with credit ratings that do not satisfy project financing requirements as their revenues are dependent on downstream power contracts at fixed or subsidized prices. All of these issues affect the terms and conditions of LNG SPAs which need to address these distinct market characteristics.
In part because of the above reasons, existing Latin American LNG buyers have relied almost entirely on spot and shorter-term LNG purchases. While those buyers are benefiting from today’s low LNG prices, they were also paying some of the highest spot prices a few years back. For those emerging Latin American buyers seeking for more pricing certainty through long-term LNG purchases, the development of the U.S. LNG export market may result in new opportunities to negotiate shorter term LNG SPAs that address the needs of Latin American LNG buyers.
b. Effect on LNG Contracting
As indicated above, the traditional ToP LNG SPA may not be suitable for the needs for Latin American LNG buyers in many respects. First, the typical 20 year term of a ToP LNG SPA may seem daunting to a power company that is used to buying its fuel oil or diesel a few cargoes at a time. At the same time, if the power company is buying LNG in conjunction with the development of a new LNG import terminal, it must understand that an LNG SPA of sufficient duration is required to support the financing of the import terminal. Given such a power company’s time horizon, it may be better suited as a customer for LNG portfolio sellers or sellers that will deliver using overbuild capacity – i.e., where the power company’s LNG SPA is not part of the seller’s financing package for the seller’s LNG export project. As discussed above, the tolling customers of U.S. LNG projects appear to fit the foregoing criteria. These customers have already committed to pay for tolling services, regardless of whether or not they actually utilize those services to liquefy U.S. gas, and do not need their downstream LNG SPAs to support the financing of the U.S. project. Accordingly, while such tolling customers would ideally like to have LNG SPAs that match the term of their tolling contracts, they arguably can provide an LNG SPA with a term of less than 20 years.
Second, like other LNG buyers, Latin American LNG buyers are likely to seek volume flexibility. In particular, Latin American LNG buyers may want LNG deliveries to meet their seasonal demand. Such flexibility is not typical in a ToP LNG SPA, which generally provides for deliveries on a ratable basis over the year. In addition, such a buyer may want to take advantage of the fuel switching capability of its power plants. One way to do so under an LNG SPA is through cargo diversion rights, whereby the buyer may request that a scheduled cargo be delivered to another LNG import terminal. Customers of U.S. LNG projects (of either the tolling or LNG sales model) are not restricted by their contracts with the U.S. LNG projects from providing such cargo diversion flexibility to Latin American buyers. As discussed above, their tolling contracts and LNG SPAs with the U.S. projects are not subject to any destination restrictions other than those required by law. Another option is to establish cargo cancellation rights, allowing the LNG buyer to cancel a cargo in a very wet year and with a short term notice, granting it more flexibility in operation of its power plants.
Third, as these buyers are entering the LNG market for the first time, they are unproven as far as reliability in taking and paying for LNG. Further, these buyers often rely on payment of downstream electricity purchases by the state to support their power plants. This presents a challenge to LNG sellers that are accustomed to the high creditworthiness of the traditional Asian LNG buyers and typical security in the form of parent guarantees or letters of credit. These emerging power generation buyers in Latin American may simply not have the financial capability to meet the traditional credit support requirements. Thus, creative credit alternative proposals may be required in order to finalize a long-term LNG SPA with such buyers. Credit support for the Latin American buyers is likely one of the more heavily negotiated terms, even for an LNG seller that is a customer of a U.S. LNG project. While such customers of U.S. LNG projects do not require their downstream LNG SPAs to support the financing of the U.S. LNG project, they will nonetheless require assurance that their downstream LNG buyers will take and pay for the contracted volumes so that they can gain their expected economic benefit from such sales. A mutually agreeable credit support regime may be one of the key hurdles for Latin American buyers to procure U.S. LNG on a long term basis.
The implementation of U.S. LNG export projects creates new opportunities for Latin American LNG buyers. LNG may be available to existing and new Latin American markets, under more flexible terms and potentially better prices, reducing the use of spot sales. Existing power plants may be transformed to use clean LNG, instead of diesel and other fossil fuels, capturing the goal of local governments. The downside for the region is that despite the vast natural gas reserves in Argentina, Brazil, Colombia and especially in Venezuela, the development of Latin American LNG export projects will be tougher to justify.
“This paper was originally published by the Rocky Mountain Mineral Law Foundation in the manual of the Special Institute on International Mining and Oil & Gas Law, Development, and Investment (Institute) (2015),”
1 LNG export projects are multi-billion dollar ventures, and recent capital costs for an LNG plant range from US$300-1,200 tonnes per annum. See Brian Songhurst, LNG Plant Cost Escalation, The Oxford Institute for Energy Studies (February, 2014), available at http://www.oxfordenergy.org/wpcms/wp-content/uploads/2014/02/NG-83.pdf.
2 Based on reports from the Federal Energy Regulatory Commission as of March 4, 2015, available on http://www.ferc.gov/industries/gas/indus-act/lng.asp.
3 These include Freeport, Cameron, Cove Point and Jordan Cove.
4 The sales model is used for Cheniere’s projects at Sabine Pass and Corpus Christi.
5 See Osamu Tsukimori, Japan’s Chubu plans to buy stake in U.S. shale gas field, Reuters (June 25, 2014); and Eric Watkins, Sumitomo Corp. acquires more U.S. shale gas acreage, Oil & Gas Journal (September 1, 2010).
6 International Group of Liquefied Natural Gas Importers, The LNG Industry (2013).
9 International Group of Liquefied Natural Gas Importers, The LNG Industry (2013)