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LNG-to-power project development

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LNG Industry,

LNG-to-power is being considered seriously across multiple jurisdictions as a new, alternative, medium to long-term power solution.

The falling cost of LNG is a key driver behind this development, but although the cost of LNG is reducing, it is still not a cheap fuel source. Per kWh, power from LNG is less expensive than liquid fuels such as diesel. However, it cannot yet compete with coal on cost alone. In countries with no price on carbon, it often makes greater short-term economic sense for governments to back coal-fired power projects. A case in point is Indonesia, which has significant domestic coal reserves that can be used for power generation, instead of importing ‘expensive LNG’. However, the potential impact of COP21 on energy infrastructure in developing markets could be significant, to the extent that a global deal on carbon dioxide emissions can be reached. Whatever the outcome of COP21, there is a sense of momentum building as countries submit their climate change commitments, which is likely, in time, to see a reduction in support for coal-fired power generation by multilateral financing institutions that are key to the success of projects in emerging markets. For these reasons, LNG-to-power as a concept is on the agenda for many governments in different markets around the globe.

Geographical market demand


Egypt started commercial operations of its first floating storage regasification unit (FSRU) in April 2015 and has already signed a deal for a second FSRU, mainly to supply its electricity sector. The market has indicated that a third project is already in the planning stage. Perhaps the most comprehensive LNG-to-power programme being considered is that of Morocco, which is understood to comprise of up to 6.3 GW of combined-cycle gas turbine (CCGT) power plants and related gas industries, all of which would be fuelled by LNG imports.

There are already a number of projects in the pipeline in West Africa, most notably Ghana, where the case for imported LNG is particularly interesting, given the level of investment in Ghana’s offshore Jubilee and offshore Cape Three Points gas reserves. Senegal is also stated to be planning an FSRU based LNG receiving terminal and an associated 400 MW power station in the port of Dakar.

South Africa is another candidate for LNG-to-power projects, with its significant power deficit but a lack of domestic gas. South Africa’s Department of Energy recently issued a request for information, which includes the possibility of structuring power projects using imported LNG as the fuel source. South Africa could potentially import LNG from East Africa or the US. One of the challenges, however, is its ability to meet significant dollar-denominated fuel costs, a risk that needs to be given significant consideration for any economy that is not substantially dollarised.

And beyond

The move to LNG-to-power is in no way limited to the African continent. Reliance Power and the Bangladesh Power Development Board are reported to have signed a Memorandum of Understanding (MoU) to develop an FSRU-based LNG receiving terminal and a Combined Cycle Gas Turbine (CCGT) power project. Structurally, this appears to be similar to Morocco’s plans to promote the use of LNG in multiple power stations in diverse locations across the country. Indonesia is planning a sizeable expansion of its regasification infrastructure, through the development of small scale LNG projects to deliver gas to power stations across 32 locations. It is proposed that gas will be supplied by a group of counterparties backed by a shipper who will provide the vessel, and also that there will be separate Independent Power Project (IPP) developers for the power stations.

In Malta, ElectroGas Malta is developing a new 210 MW CCGT project fuelled by LNG imported through a mid-sized FSU, which will also supply an existing 149 MW plant. Chile is also leading the way with firm plans to procure gas-fired power capacity from four plants, fuelled by imported LNG, with a combined capacity in the region of 1700 – 2000 MW. The country benefits from an existing regasification facility which is proposed to be expanded from 15 to 20 million m3/d as part of a separate project.

This snapshot of global activity in the LNG-to-power space also gives some indication of the level of variety that exists in the structures for these capital intensive projects.

Project structures

LNG-to-power is a complex and capital intensive undertaking. Demands are specific to markets and the risks across different structures need to be considered for the right model to be applied to introduce LNG-to-power successfully into a new market. The fundamental question is what relationships to create between the LNG importation function and the regasification and power infrastructure? The answer in each market will turn on a combination of technical, economic, legal and political factors.

Gas sales model

The first consideration is perhaps the scale of the developing domestic demand for gas (for power and other potential domestic and industrial uses) and the appetite and strategy for developing gas distribution infrastructure. In a market with existing consumers of gas, there is likely to be more flexibility of offtake for gas. Here it may be possible to establish an LNG importation project in which the same entity imports the gas and sells it to customers, so as to underpin demand. The same sponsors might separately develop an IPP whilst seeking to secure a long-term offtake arrangement for the power (unless market fundamentals would support a merchant project).

Regas tolling model

An alternative approach would be for the IPP to import LNG itself, under a long-term purchase agreement with an LNG shipper, and to buy capacity rights in a regasification facility to convert the LNG to gas. This enables the regasification facility to be financed on the basis of long-term stable revenues under the throughput agreement with the IPP (again, potentially developed by the same sponsors as the IPP). Excess regasification capacity can be sold to other IPPs or gas industries. This is likely to be more appropriate where the regulatory regime imposes open access requirements and, therefore, a portion of any regasification capacity must be reserved for the market. It is equally applicable where the power project is the primary driver behind both projects, as opposed to the gas importation and sale business being dominant. This is perhaps the most conventional approach to structuring the projects and might well be the most appropriate solution for Morocco, where the government has historically required developers to take the fuel supply risk on its other thermal power projects. Likewise, the scale of the development means that there will be multiple gas customers, thereby creating a portfolio effect for the regasification project, which helps to mitigate its exposure to any individual IPP.

Integrated model

A third permutation would be for a single entity to procure both the regasification and power infrastructure under a single financing, and for it to import LNG for the sole purpose of producing power in a dedicated power plant. This is a somewhat higher risk, less flexible option, but one which is workable for smaller scale developments. This approach was the basis for a 250 MW LNG-to-power project that was planned for Walvis Bay in Namibia, but which appears to have fallen by the wayside. This approach may not, however, be workable in jurisdictions where generation and gas distribution licence conditions prevent cross-collateralisation of assets or where third party access rights must be made available.

Government buyer model

Finally, a solution that might be more appropriate for a country experiencing high growth rates but with potentially uncertain long-term demand for gas and power might be for the host government to act as an intermediary between LNG shippers and consumers, including IPPs. In this case the regasification infrastructure could be financed on the basis of a throughput agreement with the utility, and the IPP would purchase gas from the government, or the government could toll its gas through the power plant, whilst using excess regasification capacity to stimulate local industry or domestic gas consumption. This is the approach currently being taken in Egypt, where EGAS imports LNG and sells it on to IPPs.

Risk mitigation

Project-on-project risk

In all but one of these scenarios, the regasification and power infrastructure is financed separately and on a limited recourse basis, and in the first two cases, there is a significant interdependency between the projects, thereby creating ‘project-on-project’ risk. This means that a default by one half of the overall project (e.g. the regasification project) will lead to an inability to generate cash flow in the other half (here, the power project). However, the limited recourse nature of both halves means there is no creditworthy entity ultimately backstopping the risk.

Take, for example, the conventional basis for calculating delay liquidated damages under a construction contract – the rate of liquidated damages and the overall cap should be sized to keep debt and equity whole for a reasonable period corresponding to a maximum foreseeable delay. That works for the project to which the construction contract relates, but the same level of liquidated damages will not compensate debt and equity on, for example, a downstream power project if the delay is suffered in the upstream regasification project (or vice versa).

This characteristic of many LNG-to-power projects places a higher value on flexibility – the ability to mitigate adverse effects experienced in one element of the project on the other element of the project. Even the fully integrated third structure is potentially weakened by the lack of flexibility. For example, there are no alternative gas customers if power dispatch is insufficient to support the volumes of LNG contracted.

Technology as a solution

Small to medium scale developments offer the opportunity to utilise FSRU vessels as the regasification infrastructure. Capital cost can be minimised by using old vessels which have been converted for this purpose. Additionally, the current levels of competition in the vessel chartering market mean that financing new builds or conversions is relatively straightforward and flexible (in terms of the structural requirements of vessel financing lenders). FSRUs are chartered by the entity operating the regasification portion of the project and are generally financed separately from the other infrastructure.

Vessels offer an LNG-to-power project the flexibility to mitigate construction delays or major equipment breakdown during operations of the power project by delaying the FSRU’s delivery date (within reason) or even through redeployment of the vessel as an LNG carrier to generate extra revenue pending completion of the IPP.

Most CCGT plants are capable of being configured to operate on liquid fuel as a back-up when natural gas is unavailable. However, this has adverse performance effects and increases both operation and maintenance costs to varying degrees depending on the gas turbine technology and fuel costs per kWh of electricity generated. However, subject to the management of this risk under the power purchase agreements, this offers the IPP the ability to mitigate its exposure to delays in completion of the regasification infrastructure and to short-term LNG unavailability (throughout operations).

Demand risk

A 20-year take-or-pay contract for LNG is a significant financial commitment. It will generally require the buyer to lift LNG volumes in accordance with a fairly restrictive schedule (essentially imposing a take-or-pay obligation on the buyer). Gas-fired IPPs in emerging markets will almost always put dispatch risk with the offtaker (insofar as capacity charges will be payable for availability, regardless of power demand). However, seeking to recover from a local power utility take-or-pay payments that are passed through from the LNG supply chain for power not actually required, creates a significant financial burden. The global market for LNG helps mitigate this risk to an extent by providing a means of selling excess LNG cargos at spot. An independent developer in control of the full value chain will be able to manage these risks more efficiently than some of the smaller developers or even national utilities normally involved in IPPs in emerging markets.

Written by Chris Down and Claire Wilby, Norton Rose Fullbright LLP, UK.

Edited by David Rowlands

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