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LNG-to-Power: Key Bankability Considerations for FSRU-to-IPP Project Structures.

The growth of ‘LNG-to-power’, by which we mean the use of regasified LNG as a feedstock fuel for power generation, is largely attributable to a combination of economic, political and technical factors. Importantly, a number of integrated LNG-to-power projects under development are opting to utilise FSU or FSRU technology.

King & Spalding (Singapore) LLP

27 March 2017

Richard Nelson and Nick Kouvaritakis

Introduction / synopsis

The growth of ‘LNG-to-power’, by which we mean the use of regasified LNG as a feedstock fuel for power generation, is largely attributable to a combination of economic, political and technical factors, which can be broadly categorised as follows:

  • growth in electricity demand and consumption, leading to development of new power generation facilities, particularly independent power producer plants (“IPPs”);
  • climate change and air quality policy making favouring natural gas over less environmentally friendly fuels for electricity production (for example, new OECD rules which have recently come into effect limit the circumstances under which certain financial institutions can provide funding for new coal-fired power plants)[1];
  • plentiful global supplies of LNG and favourable LNG and natural gas pricing relative to other fuel sources;
  • rapid commercialisation of marine LNG regasification solutions, including floating storage units (“FSU”) and floating storage and regasification units (“FSRU”), allowing the development of flexible small and mid-scale LNG regasification infrastructure with lower capital costs and shorter lead times than traditional land-based terminals.

Importantly, a number of integrated LNG-to-power projects under development are opting to utilise FSU or FSRU technology.

The growth of FSRUs as a leading solution for LNG import projects has been well documented over the past few years. Of the four[2] countries that began importing LNG in  2015, three of them—Pakistan, Jordan, and Egypt— opted to do so using FSRUs rather than building full-scale onshore regasification facilities. Similarly, of the five[3] countries that began importing LNG in 2016, three involve FSRUs, two of which are deployed in integrated LNG-to-power projects. As depicted in Figure B below, many more FSRU-to-power projects are currently envisaged. In this paper, we will examine some of the critical issues to consider in structuring LNG-to-power projects utilising a marine based LNG regasification solution (FSRU or FSU).

Financing structure: Integrated vs separate financing models?

A crucial ingredient for the success of integrated LNG-to-power projects is the alignment of multiple components from fundamentally different industries: long-term LNG supply, offshore regasification vessels, midstream transportation / pipelines (and in the case of FSUs, onshore regasification facilities), power plants and associated transmission infrastructure. It is essential that the risks associated with each component part of the value chain are fully understood and allocated appropriately between the various stakeholders: the host government, the project developers, the suppliers and contractors and the project lenders. In most cases, project finance lenders will require detailed assurances from project sponsors that all technical and operational interface issues between the various project components have been addressed: for example, synchronising (i) completion, testing, commissioning and acceptance of the FSRU with the power facility and interconnecting infrastructure; and (ii) FSRU maintenance / dry-docking with scheduled power plant maintenance to minimise any potential delay or outage penalties under the power purchase agreement.

The treatment of the FSRU is a critical bankability issue that has fundamental implications for any project financing structure. The approach to the FSRU needs to be fully considered, as  conventional FSRU project financing differs significantly from  a  traditional IPP project finance model.

Invariably the FSRU is essential to the viability of the overall LNG-to-power project, as such projects are often located in areas where no alternative gas/fuel supply is available and the costs of a land-based regasification terminal are deemed prohibitive. To address this interdependency, the equity and financing interests should ideally be as aligned as possible, meaning that the same or similar equity (shareholders) and debt providers (lenders) are involved in the FSRU and the power generation owning entities, which in most cases are project special purpose vehicles (SPVs). In this way, IPP sponsors and IPP lenders derive the control they require over the FSRU to prevent gas supply interruptions and preserve downstream (PPA) revenue flows.

Principally we have seen two distinct project finance structures emerge.

Firstly, the “fully integrated” financing structure whereby the FSRU and power plant are financed by the same group of lenders. This can be achieved either through a “co-borrower” model (IPP SPV and FSRU SPV both take out loans from the same group of lenders), or an “on-lending” structure whereby IPP SPV borrows the entire amount of the debt for the power plant and the FSRU from a single lending group, and then subsequently on-lends a portion of that debt to the FSRU SPV to finance the FSRU.  Under both structures, a single group of lenders would seek to take security over both the FSRU and the power project assets, which is essential for the bankability of the integrated project. An example of such integration is the 1.5GW Sergipe power project in Brazil in which Golar (as FSRU sponsor) recently invested directly as a shareholder. The project represents the first time an FSRU sponsor has taken a direct equity investment in the downstream power project.[4]

Figure A – on-lending structure diagram

In contrast, FSRU sponsors typically favour a “non-integrated” financing structure which envisages IPP sponsors obtaining financing for the power plant and FSRU sponsors separately raising financing for the FSRU. The fundamental disadvantage of this structure is the lack of integration between the power plant and the FSRU, which in turn is likely to create inter-creditor issues between the two sets of lenders. Typically, the lenders to the IPP (if different) will seek preferential step-in rights and some form of security over the FSRU, which may not necessarily be compatible with the terms of the financing to the FSRU. Also, each lending group will most likely seek quiet enjoyment rights over their respective project (i.e. the power plant or the FSRU). This friction between two sets of lenders can cause significant delays to achieving financial close for the project.  The project involving the Penco Lirquén LNG terminal and the Central El Campesino power plant in Chile is an example of a “non-integrated” structure which envisages separate groups of lenders for the FSRU and the power plant.[5]

Electricity dispatch: LNG procurement and FSRU inventory management considerations

The dispatch merit order and profile of the power plant to which regasified LNG is supplied (i.e. peak, mid-tier or baseload), is likely to have significant ramifications with respect to the LNG procurement and inventory management strategy for IPP sponsors.

Power plants dispatched on a peaking basis (often based on daily or seasonal demand fluctuations) create a degree of uncertainty as to the level of LNG demand and consequentially the required level of inventory to be maintained on-board the FSRU. Careful consideration of the power purchase agreement is required to understand precisely how the power plant is dispatched (i.e. whether on a firm or non-binding basis and whether daily, monthly, or yearly). However, in many cases, a ‘peaker’ PPA may not be prescriptive in terms of how the offtaker may dispatch the plant (or individual units) or what level of gas may be nominated in a given period. The challenge therefore is modelling sufficient LNG volumes to meet electricity demand / dispatch requirements throughout the year: in other words, what baseload (LNG) volume is required and how will any shortfall or surplus (of LNG) be addressed.

There are various ways for IPP sponsors to mitigate against fluctuations in dispatch levels via its LNG sale and purchase agreements, including annual contract quantity (ACQ) reductions/increases, downward and upward quantities tolerances, call options for additional quantities, cargo cancellation rights, cargo deferment rights, diversions, and variations to LNG ship sizes. The ability to procure spot cargoes is also an important mitigant to address a shortfall scenario (where the baseload LNG volumes are insufficient). This calls for a highly specialised LNG procurement strategy and a bespoke LNG SPA or SPAs which fit the specific demand profile and requirements of the power facility in questions.

However, it is important to note that not all LNG sellers will be willing to accommodate a high level of LNG supply flexibility. LNG portfolio suppliers are generally better placed to meet a more flexible procurement profile than a point-to-point/project seller. It should also be noted that LNG sellers are more likely to price in any increase in purchasing flexibility.

Peaking power plants present significant challenges in relation to the inventory management of the FSRU. Modern-day FSRUs have limited storage capacity: new-build FSRUs typically have a capacity of between one hundred and seventy thousand cubic metres (170,000 cbm) and one hundred and eighty thousand cubic metres (180,000 cbm), although MOL is set to take delivery of a two hundred and sixty three thousand cubic metre (263,000 cbm) FSRU later this year.[6] The usage of a single floating solution (FSU or FSRU) for a peaking power plant presents IPP sponsors with material inventory constraints, which can prove especially challenging to manage if the power purchase agreement permits short-term (intra-day) fluctuations in dispatch levels. The IPP sponsor will need to ensure that sufficient LNG quantities are scheduled and available for delivery to meet short-term demand peaks and also that the FSRU owner is able to vary the regasification nominations at short notice.  Typically FSRU owners will be able to provide meet these short-term variations, but in return they may require relief from certain performance warranties under the time charter party (“TCP”) or bareboat charter (“BBC”), such as the fuel usage warranty (depending on the extent of the regasification nomination fluctuations).

Alternative mitigation strategies include: (i) utilising the FSU/FSRU in LNG carrier mode to help manage the potential scheduling and inventory management constraints and (ii) developing supplemental storage capacity, either via an additional FSU facility offshore, or onshore storage tank(s).

In the case of (i), in order to mitigate against LNG supply related failures (or, as the case may be, force majeure events) the FSRU could potentially be deployed as an LNG carrier and utilised to receive cargoes on a free-on-board (FOB) basis. Further, if there are predictable periods where short-term downstream demand is zero, the FSRU could switch to operate in LNG carrier mode so as to sell any surplus LNG to a third party buyer. From an operational standpoint, the switch from FSRU mode to LNG carrier mode (and subsequent demobilisation) is manageable, with the mobilisation/demobilisation process typically taking between 24 and 30 hours, based on a conventional mooring system.

However, from a contractual standpoint there are a number of issues that need to be considered, namely that the FSRU sponsor would usually seek to be held harmless by IPP sponsor (as charterer) in respect of any incremental costs arising as a result of the operation of the FSRU in LNG carrier mode (i.e. taxes, port charges, etc.). The FSRU sponsor and IPP sponsor would in most cases agree a separate charter party agreement which relates to the operation of the FSRU in LNG carrier mode, which would contain a number of market standard concepts including: (i) a procedure for the mobilisation/demobilisation of the vessel as an FSRU, (ii) an acknowledgement that the regasification/boil-off warranties that apply to the FSRU in regasification mode would not apply to the use of the vessel in LNG carrier mode, and (iii) dispensation from the permitted maintenance/dry-docking regime (i.e. the requirements for a vessel operating in dual-usage mode may not be the same as for a vessel operating solely in FSRU mode).

‘Project-on-project’ liabilities?

A fundamental issue for IPP sponsors to consider is the disproportionate nature of the contractual liabilities faced by IPP sponsors (under the PPA) and the FSRU sponsors (under the TCP or BBC). The scale of penalties and damages potentially payable under a PPA are of a much higher order of magnitude than those payable under a TCP or BBC.

Whilst IPP sponsors will need to assess how to allocate liability for the failure of multiple parties (LNG supplier(s), FSRU owner(s), EPC and O&M Contractor(s), electricity offtaker(s)), the FSRU owner will in most cases seek to limit its liability to events caused by its own failure; that is to say, performance of the FSRU.

The problem that IPP sponsors face is that a performance failure of the FSRU (for example, a failure to regasify LNG at the rate nominated by IPP sponsor) can lead to IPP sponsors incurring significant liabilities under their upstream (LNG SPA) and downstream (PPA) contractual arrangements. However, the liability of the FSRU owner(s) under the TCP or BBC will almost always be capped at a percentage of the total hire amount payable, meaning that the IPP sponsors are unlikely to have recourse against the FSRU owner(s) for the full amount of the liabilities that they are exposed to under the LNG SPAs and/or the PPA.

In the pre-operational phase, a failure of the FSRU supplier to successfully commission the FSRU by the required commercial start date can potentially expose IPP sponsors to  take-or-pay liabilities under their LNG sale and purchase agreement (subject to mitigation measures such as a diversion, rescheduling of the cargo/cancellation etc.) and delay liquidated damages (“LDs”) under their power purchase agreement.

In the operational phase, a performance failure of the FSRU vessel could result in IPP sponsors incurring outage penalties under their power purchase agreement, if the IPP sponsors are unable to meet the dispatch requests of the electricity buyer.

Historically, FSRU owners have been reluctant to accept LDs for performance failure that exceed the daily rate of hire (i.e. capital costs plus operating costs). This mind-set is largely derived from LNG shipping market practice whereby the risks that the vessel owner is willing to take on should be commensurate with the return that it receives under the charter party. Generally speaking,  this mind-set is slowly changing as there are more instances, particularly in the context of integrated LNG-to-power projects, of FSRU owners agreeing to  assume some (but only some) responsibility for liabilities incurred by IPP sponsors resulting directly from FSRU-related performance failure.

Notwithstanding this shift towards a more favourable liability regime under the charter party agreement, IPP sponsors are often left with significant residual liabilities, some of which  they may be able to mitigate via insurance, such as delay-in-start up insurance (pre-operational phase) and business interruption insurance (operational phase), but it is unlikely that such insurances will fully cover such residual liabilities as the policies will contain various deductible periods, sub-limits and exclusions. Project finance lenders may require that IPP sponsors themselves cover any remaining residual liabilities that cannot be covered by the FSRU owner or insurance.

Payment in advance vs payment in arrears

A further challenge for IPP sponsors is to align the payment mechanism under its power purchase agreement(s) with its payment obligations under the FSRU charter agreement (i.e. to ensure that IPP sponsor receives payment from the power purchaser prior to hire payments being due under the FSRU charter agreement). In the FSRU industry this is often referred to as a “pay-when-paid” regime. FSRU owners typically require payment of hire in advance, to ensure that the FSRU owner has sufficient available cash to cover all operating expenses (including payments to be made to third party service providers).  In an integrated project context, the IPP sponsors will be using revenues received under the PPA to make those hire payments to the FSRU owner (subject to the relevant payment waterfall).

Project finance lenders will typically prefer that IPP sponsor is first put in funds by the power purchaser before it is obliged to make payments to the FSRU sponsor, or, if this is not achievable, that the payment terms (i.e. periods) are aligned and/or that IPP sponsor maintains a working capital/hire reserve account to ensure that it is able to meet its hire payment obligations to FSRU sponsor. Also, to the extent that the underlying payment obligations under the PPA are supported by credit instruments such as SBLCs or sovereign / government guarantees, lenders would prefer that the IPP SPV borrower retains the ability to call on such credit instrument(s) before becoming liable to pay the hire instalments, subject to a requirement to pay the FSRU owner any amounts recovered under those instruments.

The FSRU-to-power market is still evolving in this regard, and from our experience FSRU sponsors are moving towards a broader “pay-when-paid” regime subject to IPP sponsor agreeing to certain conditions with respect to the credit support/guarantee arrangements, such as posting a SBLC in respect of [x] months of hire and agreeing to claim against and to pass through the benefits of any credit support provided by the power off-taker.

Emergence of a multi-user terminal model?

A further notable development is the advent of ‘multi-user’ FSRU-IPPs (i.e. where the FSRU is intended to be utilised by the IPP and also by other downstream customers). This could be as a result of mandatory or regulated third party access requirements under the laws of the jurisdiction in which the project is being developed.

Multi-user FSRUs present a number of technical and operational challenges, particularly given the size and storage constraints of FSRU vessels. From a credit perspective, the FSRU owner would likely prefer that a single (creditworthy) charterer stands behind the hire payment obligations, as opposed to multiple charterers with separate hire payment obligations (although, in the final analysis this will depend on the creditworthiness of the proposed charterers). Multi-user FSRU terminals also give rise to complicated storage and send-out capacity allocation issues, as between the various users, as well as LNG quality and contamination issues in the context of potential commingling of LNG supplies in a single storage tank.

In structuring multi-user FSRUs, a robust terminal use agreement is imperative to the bankability of the project. This may follow the form of onshore RGT terminal use agreements, although particular consideration will need to be given to the specification and configuration of the individual FSRU facility. However, despite the notable challenges, multi-user FSRUs may be favoured in geographically remote locations (for example, the archipelagos in Indonesia and Philippines) where a ‘storage and reload’ model to deliver to multiple plants utilising small or smaller scale LNG ships is preferable.

FSRU-to-Power project opportunities on the horizon

Despite the multitude of technical, legal, financial and commercial challenges facing  integrated LNG-to-power projects and the tension between the conventional business model of the FSRU owners on the one hand and the IPP sponsors (and project finance lenders) on the other, we expect that, assuming the fundamental economics remain viable, the number of these projects to grow exponentially over the next few years. We have set out below a brief snapshot of some selected FSRU-to-power project opportunities currently in the market.


 *Based on certain assumptions on gas required for power gen and plant efficiency

[1] Annex IV to the Arrangement on Officially Supported Export Credits dated 1 February 2017 (Sector Understanding on Export Credits for Coal-Fired Electricity Generation Projects) limits the ability for export credit agencies of OECD member countries to finance new coal-fired power plants. Available at

[2] World’s Commitment to LNG, Energia16, Mar. 27, 2017. Available at

[3] The five countries are Poland, Jamaica, Indonesia, Barbados and Finland, and the LNG-to-power projects are those in Jamaica and Indonesia. See Karen Thomas, Supply Glut Opens New LNG Markets, LNG World Shipping, Oct. 6, 2016. Available at,supply-glut-opens-new-lng-markets_44890.htm

[4] Golar Power reaches a Final Investment Decision on Sergipe Power Project and signs a 25 year FSRU agreement, Stockhouse. Available at

[5] Karen Thomas, Höegh LNG secures financing for its seventh FSRU, LNG World Shipping, Feb. 29, 2016. Available at,hegh-lng-secures-finance-for-its-seventh-fsru_42038.htm; Central El Campesino Financing in Flux, Latin Finance, Feb. 6, 2017. Available at

[6] MOL finalizes charter deal for Uruguay FSRU project, LNG World News, Jul. 22, 2016. Available at

[7] LNG in World Markets, Vol 28, No.10, Poten & Partners (supplemented with select additional projects)

[8] Summit Group wins contract to build $500m LNG terminal offshore Bangladesh, ONG Update. Available at

[9] Verity Ratcliffe, Kenya Revives Mombasa FSRU Plan, Interfax Global Energy, Interfax Global Energy, Oct. 18, 2016. Available at

[10] Large Scale Power Station Project Takes Off, Central America Data, Jan. 19, 2016. Available at

[11] Petronet LNG Plans $3 billion Investment Outside India, Energy Sector, Jul. 15, 2016. Available at

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