Over the last few years, the concept of floating liquefied natural gas (LNG) production has attracted growing interest from market participants seeking alternatives to the traditional onshore multi-train liquefaction project. Drawing upon years of related experience in the ship-to-ship transfer of petroleum products, floating liquefaction technology aims to provide sponsors with the potential to efficiently unlock stranded gas reserves or monetise flared gas and convert those reserves into a valuable commodity offshore.

As larger liquefaction projects have become capital-constrained and more difficult to carry out in emerging economies, industrial sponsors and international oil companies have begun to seriously explore floating LNG as a viable option. Shell recently announced plans to employ floating liquefaction technology to convert associated gas in – of all places – Iraq. But floating LNG projects may also have a strategic role to play in the global LNG industry, by offering producers the opportunity to expand their LNG presence through smaller-scale production increases.

The commercial-scale application of floating liquefaction technology remains unproven and, like all LNG production projects, floating LNG projects will be highly capital intensive. As such, the availability and terms of external financing may be critical to determining what role this technology can play. With the first commercial floating LNG production vessels expected to float out of dry-dock in 2012, sponsors and lenders alike will need to address several key issues to structure a successful financing for projects that use offshore liquefaction technology.

Floating the concept

Floating LNG projects use an offshore LNG production vessel to which natural gas is transported via pipeline from onshore or offshore locations. Once the natural gas reaches the vessel, it is pre-treated, liquefied (by cooling it to roughly -163° C), and stored, until it can be offloaded in its liquefied state to LNG carriers through cryogenic loading arms and hoses. Although details of proposed floating LNG production vessels remain sketchy, current designs call for between 1.7 and 2.5 million tonnes per year (tpy) of production capacity, along with sizeable onboard LNG storage and gas treatment facilities.

From an economic perspective, floating LNG production technology is best used to monetise two sources of natural gas that cannot be efficiently converted through onshore LNG projects: (1) onshore and offshore stranded natural gas reserves that remain undeveloped due to remoteness or difficulty of extraction and (2) associated gas found in oil fields and recovered along with oil, which in many cases is simply flared into the atmosphere. Unlike onshore liquefaction facilities that are developed around large non-associated gas reserves, the transferability and lower capital cost of floating LNG production vessels make them ideally suited for stranded or associated gas reserves of between one and four trillion cubic feet. Additionally, for offshore reserves, floating LNG production avoids the requirement to construct a pipeline to transport such gas to an onshore liquefaction facility.

The potential applications of floating LNG production are not only vast but also financially attractive. Discovered stranded gas reserves – although widely dispersed throughout onshore and offshore locations around the world – are in the aggregate equal to almost 400 trillion cubic feet. Many such reserves lie in developing nations threatened by political instability and violence, where onshore liquefaction projects are by definition more challenging. In addition, significant volumes of associated gas are still flared in a number of oil producing regions, leading to significant greenhouse gas emissions. Monetising such gas volumes through floating LNG production could represent a substantial improvement over presently available (and expensive) methods of mitigating flaring, such as reinjection of associated gas for enhanced oil recovery or transportation by pipeline to power stations for conversion to electricity.

Floating LNG production could potentially benefit many different industry participants. With more national oil companies seeking to take advantage of downstream opportunities, floating LNG production might enable them to market their stranded reserves without working through the oil majors. Downstream investors could build a profile in production as the developer of a floating LNG production vessel without having an ownership position in upstream reserves. International oil companies could apply floating LNG production not only to stranded and associated gas reserves, but also to the early development of larger fields while onshore liquefaction trains are under development and/or construction. Finally, for portfolio players that rely on a liquid LNG market, floating LNG production, by increasing global LNG supply and in the number of cargoes at sea, yields greater opportunities for arbitrage and destination swaps.

A financing model for floating LNG

In many respects, the financing of a floating LNG project should follow the same well-defined parameters of a financeable onshore LNG project. Such projects are generally structured around a long, integrated value chain that starts with the upstream gas resources at the site of exploration and production and ends with the customers of regasified LNG at the destination of delivery. Each component of the chain, from upstream to shipping to regasification, is critical to the project's success, since the absence of any component could disrupt the cash flow generated by downstream LNG sales.

Financeable LNG projects typically adopt one of two primary contractual structures with respect to the ownership of various parts of the value chain. Projects are either integrated, with the sponsors holding interests in most if not all portions of the value chain, or based on separate liquefaction and marketing entities, which oversee different pieces of the value chain. Within the marketing function, sponsors may elect to operate through a single marketing entity or buy LNG through affiliates in some related proportion to their ownership of, or capital commitments to, the liquefaction project. In case of the former, the liquefaction part of the value chain can be isolated and separately financed as a provider of tolling services to the upstream resource holders.

When applied to floating LNG, the tolling model would permit the owner of the floating LNG production vessel to charge a fee for the service of converting natural gas to LNG and offloading it to LNG carriers. This fee might be flat, volume-based, or a combination of the two, but would be structured to repay scheduled debt service as well as provide a modest but stable rate of return to the project owners. The remainder of the activities, from the extraction of natural gas upstream to the shipping of LNG downstream, would be in the hands of other participants. The upstream resource holders would sell the LNG to the purchasers, with delivery taken at the offshore vessel. The credit behind the floating LNG financing is that of the resource holder paying the tolling fee, whose revenues are in turn based on the sale of LNG or natural gas to downstream participants.

Given their lower construction and operating costs, and the variety of potential investors, floating LNG projects are likely to be more amenable to the tolling model. However lenders will nevertheless need to ensure that the toll counterparties are creditworthy and will earn sufficient revenues to meet their commitments. The presence of proven and certified upstream reserves, robust long-term LNG sales contracts and reserved regasification capacity in markets with sufficient demand are paramount among lenders' concerns.

The tolling model is also attractive because, in light of the relative glut of capacity in world shipping and regasification markets, floating LNG producers should be able to readily secure shipping and regas capacity. In particular, whilst shipping companies have in recent years increased their LNG fleets and a variety of market participants have invested in expanding regasification capacity around the world on the promise of greater global LNG trade, global LNG production has stagnated. In fact, most terminals serving the Atlantic Basin market are operating at far less than full capacity.

Specific lender issues

Floating LNG projects present some unique challenges and opportunities that may require lenders and sponsors to revisit conventional LNG financing terms. Most importantly, because floating LNG production has not yet been commercially deployed, unproven technology represents the greatest additional risk to be addressed in the financing of a floating LNG production project. This attracts outsize concern even though construction and operation of a liqueaction train is, from a technical perspective, one of the lower risk activities in the LNG value chain (when compared to, for example, upstream production). Moreover, a number of similar proven technologies and comparable experience exist in the oil and gas industry, which could give comfort to financial institutions that consider lending to floating LNG projects.

In particular, exploration and production companies have for decades used floating production, storage and offloading vessels to transfer crude from offshore platforms to tankers. Onboard liquefaction has also been proven, as new Q-Max LNG carriers are able to liquefy on board the boil-off gas typically lost during the voyage of conventional LNG carriers. Natural gas has been successfully regasified from its liquid state aboard ships – most recently, Petrobras delivered already regasified LNG to a subsidiary's import terminal in Brazil's northeastern state of Ceará. Finally, although this is not a common practice, LNG has in some instances been transferred in liquid state between LNG carriers.

Nevertheless the critical components of LNG transfer from an offshore production vessel to an LNG carrier through cryogenic loading arms and hoses are completely untested on a commercial scale. Moreover, because the hulls and liquefaction infrastructure which comprise a floating LNG production vessel are likely to be designed and constructed by a consortium of companies, the design approach to the operating risks associated with liquefaction and transfer and the shipping risks associated with ship-to-ship moorings may not be perfectly coordinated. Any number of additional marine issues, such as collisions, berthing, sloshing and adverse weather conditions, may complicate ship-to-ship transfer of LNG. With limited storage capacity onboard, difficulties in offloading LNG or any non-performance by offtakers could lead to temporary production shut-downs and inefficient use of production capacity. LNG producers may retain the right to make spot sales of excess cargoes, but the class of shippers capable of doing so may be limited if the Q-Flex and even larger Q-Max carriers used by the larger producing states are unable to moor alongside a floating LNG production vessel.

Project lenders to a floating LNG project can obtain some comfort against such risks by requiring that the components of vessel construction be contractually wrapped and that the sponsors extend their debt service undertakings beyond the customary loading of first cargo until the end of some initial period of commercial operations. However, the normal aversion of project lenders to assuming any technology risk suggests that they will likely be looking for at least one reputable sponsor or contractor to successfully test floating LNG transfer before financing a new project.

Second, while project lenders are accustomed to offering longer loan tenors on LNG projects, given their long design life and high capital costs, it remains to be seen what debt maturities will be considered appropriate for floating LNG projects. As discussed above, floating LNG projects are best applied to smaller, stranded reserves or gas flaring-avoidance scenarios where the relevant reserves may be depleted after five to ten years. Project lenders would not typically extend debt maturities beyond the expected production life of a reserve, and in fact are likely to insist on additional protections as loan maturities approach, all of which act to accelerate debt repayment and reduce internal rates of return in the early years of production.

Project lenders could mitigate these risks by taking a collateral security interest in the vessel, and recovering their outstanding balances, while the floating LNG vessel accesses other, potentially nearby stranded reserves, all the while maintaining a lien on the asset. Assuming that the offtake arrangements are not adversely affected, such multiple-field financings should in theory be possible so long as the exploration risks are appropriately addressed through identifying and certifying the recoverable reserves in pre-agreed back-up fields. Floating LNG vessel manufacturers have noted that the liquefaction equipment will be designed to handle a wide range of gas compositions and specifications and pressures, allowing floating LNG vessels to service multiple fields.

The ability to relocate a floating LNG production facility only mitigates against upstream production and onshore political risks. Whilst this represents an improvement on conventional onshore LNG projects, and offers the potential to obtain longer loan tenors, it does not insulate lenders from other critical project risks, such as the technology risk described above, the downstream demand for natural gas, the availability of sufficient shipping capacity, and the viability and sustainability of the LNG offtakers.

On the other hand, some features of a floating LNG project may diminish or eliminate some of the concerns with which lenders frequently grapple in financing onshore LNG projects. Most significantly, the location of a floating LNG project offshore obviates the need for the large, coastal project site and as such should isolate it from a number of important site-related risks. Among other things, an offshore facility can be expected to require fewer licenses and operating permits, as well as avoid import duties and taxes normally incurred when bringing capital equipment to a project location onshore. The relocation of native populations to accommodate a project – often a focus of multilateral lenders – is minimised when liquefaction is carried out offshore. Because the production vessel is constructed in a ship yard under controlled conditions, the project will not contend with numerous issues such as geological conditions, seasonal climate events, and civil unrest that might interrupt construction or otherwise delay project completion.

In more politically unstable environments, a floating LNG project's offshore mooring should eliminate the risk of nationalisation or expropriation by a host government and substantially reduce the risk of political violence or other criminal activity. The economic benefits of physically removing lenders' collateral from areas of acute political risk should not be understated. The sponsors of the OKLNG project in Nigeria, for example, plan to pipe gas at considerable expense over 280km to a remote site in order to isolate their liquefaction facility and shipping routes from the hostile Niger Delta. The cost savings from such separation in an Iraqi offshore project may be even greater.

Prospects

In light of the significant capital costs and the associated access to upstream resources and downstream markets, one might conclude that integrated international oil companies must play a significant role in supporting any a floating LNG production project. With construction cost estimates of between $550-750 per tonne of LNG, or roughly $1.1-1.5 billion for a 2.0 million tpy vessel, floating LNG projects are, on a per tonne basis, cost-competitive with onshore facilities and well within the (albeit shrinking) capital expenditure budgets of the oil majors. The reputation and experience of international oil companies in tackling complex projects may also be critical in relieving some lender anxiety over this relatively untested technology.

Nevertheless, despite the interest of international oil companies and the many potential applications for floating LNG production in the oil and gas industry, we are unlikely to observe a successful project financing for a floating LNG project in 2009. The continuing uncertainty over the length and depth of the global recession, the competition for credit and the overall reduction in capital spending among industry participants all point to a dampening in the LNG supply markets. The inability of project sponsors to estimate the near-term gas demand in key markets, and hence the value of marginal tonnes of LNG, further supports a wait-and-see approach. Even the most promising multi-train onshore projects under development, though still several years away from commercial production, look vulnerable. However, as economic conditions improve, floating LNG projects may be an ideal tool to gradually meet recovering global demand.

Keith Larson is a partner in the Washington, DC office of Hogan & Hartson. The views expressed in this article are solely those of the author.