The accurate demand forecasting and project schedule is certainty a key factor in the current market environment which has low spot market prices and significant pressures on gas due to competitive oil pricing. Here is stated an example of mismatch demand calculation and project ineffectiveness. In early September 2015, CNOOC issued a tender to sell two October-November cargoes from the 8.5MTPA Queensland Curtis LNG project in Australia.
As reported by ARGUS: CNOOC was also looking to sell more Queensland Curtis LNG cargoes over the next three years, which is indicating that it has more LNG supply capacity than it needs. Sinopec has contracted to buy 7MTPA from the 9MTPA Australia Pacific LNG plant, which is expected to start up by October 2015 but Sinopec is not expected to absorb all its contracted volumes as it faces construction delays at two new 3MTPA import terminals, (Wan,2015).
Interestingly fact today, the LNG production capacity and delivery infrastructure in existence corresponds almost exactly to global LNG contractual demand. Excess capacity tends can be full fill only on a temporary basis linked to timing differences in the construction of dedicated supply and demand infrastructure. Although we have seen an increase in spot and short term market cargoes to around 35 percent of the global LNG market.
It needs to be understood that the majority of these cargoes were delivered within the existing logistic chain and that the spot market bidding process was used to establish the spot/short term cargo prices outside the already contractually committed volumes. Some industry players observed that less than half of the spot/ short term cargo was actually available to offtakes outside the established logistic chains.
In June 2018, spot prices for LNG in Asia, a region that makes up around two-thirds of all LNG demand with that demand growth set to increase amid more gas usage in China, spiked again, reaching $9.60 per MMBtu, an increase of some 32 percent since mid-April. At the beginning of June, prices for the fuel reached near the $10/MMBtu mark.
Higher oil prices and China's continued buying of spot cargoes this year is also supportive. This is driven mainly by three factors: lower domestic gas production due to maintenance at gas fields, industrial demand due to fuel switching away from oil, and early stock building to prepare for the coming winter
In contrast to the current underlying difficulty in competitive gas pricing in comparison to oil, the long term trends for gas demand still indicate growth of 1.5 percent per annum world wide and 2.8 percent per annum (almost double!) for South East Asia. Shale gas production growth and renewable energy depend greatly on policies and the associated sovereign risk LNG that developers face from policy uncertainty, and remains one of the key risk issues to be considered for long-term project viability.
Markets and Microeconomics: The challenges of individual terminal economics are 1.terminal flexibility 2.terminal availability and 3.economic viability.
The economic viability of a terminal is driven by the types of markets serves. There are generally two types of markets such as seasonal load markets like in the northern hemisphere (Europe and North America) and base load markets of equatorial countries.
In seasonal load markets, the regasification terminals are generally designed to provide gas during cold periods for heating. In this market, gas is generally provided by a main supply source (such as pipelines), with the floating regasification terminal providing the supplemental gas supply to cater for peaks in the seasonal demand. It is further expected that as the local economy grows, the base loading would grow in parallel with the economy in order to satisfy its energy demands.
The life cycle of a floating regasification terminal is classically 20 - 30 year. If the annual power demand increases 10% that means it would doubling of power demand approximately every seven to eight years. In this case, the regasification capacity needs to increase from a nominal 1.5 MTPA of LNG during the initial years of operation, to 3.5 MTPA over a 20 year life cycle.
The design of base load regasification terminals needs to consider not only the potential doubling of regasification capacity but also needs to meet the daily demand fluctuations by having the ability to ramp-up and ramp-down gas production. Long-term commitment and market instability require the lowest possible cost for regasification.
The graph shows that the typical levelized cost of energy (LCOE) per mmBTU for a typical FSRU regas terminal and small scale solution at the lower throughput end utilising small scale LNGC and minimum infrastructure facilities. Generally the leasing of FSRUs provide 20-30% better LCOE's especially for short term projects (7-15 years) partly because the underlying FSRU lease rate is commonly more in line with shipping time charter leases that use a longer finance and higher residual values at the end of lease than fully amortized at end of lease non-recourse finance projects. The graph depicts typical LCOEs (50% probability accuracy, i.e. equal chance of over-run or under-run) that can be achieved by full scale floating storage terminals and small scale re-gas terminals. The LCOE below considers lease of the FSRU/FSU a 10% equity in infrastructure with 90% finance of infrastructure.
Figure: LCOE vs Throughput for floating regas terminals
The graph clearly shows that the curve flattens at 1.0 to 1.25 MTPA and that to be able achieve tolling tariffs of less than $1.50/mmBTU the terminal needs to operate a throughput of more 1.2 MTPA. For small scale regas terminals, even with their minimal infrastructure it will be extremely difficult to achieve tariffs of less than $1.50/mm BTU. The economic viability of the regasification terminal needs not only to consider capital expenses (CAPEX) and operating expenses (OPEX), but the life cycle costs associated with sourcing and delivery of LNG to the regasification terminal. These are necessary in order to ensure that supply of LNG maintains a high availability and to ensure that the increasing base load demands are met.
Evaluation of the life cycle cost can be carried out in two stages. The first stage is to identify LNG supply terminals that would provide gas matching the specification requirements of the local power plants and terminals that would provide the required volume of LNG to meet the gas demand. Gas specifications would include gas molecular composition and heat values. Where the gas specifications do not match the requirements of the power plants, additional process equipment could be added to the regasification terminal or the power plants to ensure compatibility, although this would be at an additional cost.
Having identified suitable LNG supply terminals, the next stage is to manage the logistics of delivering LNG to the regasification terminal. To achieve an optimized logistics chain, a large number of factors need to be considered, including the size and type of LNG carriers, storage capacity of the regasification terminal, route selection and so on. This would typically entail a large number of scenarios to be considered during the initial planning stages, in order to fully understand and identify the key drivers of the life cycle costs.
Terminal flexibility: Terminal flexibility is a big challenge for keeping up with annual base load demand growth, as well as the routine daily demand fluctuations. Catering for future base load demands during the design of floating regasification terminals is not only capital intensive, it is also operationally inefficient as the regasification equipment is operated below capacity (at least during the initial years of operation), not to mention the higher maintenance expense that will be incurred in the meantime.
To provide an economically attractive solution and to cater for the increased demand, a flexible design that allows the terminal regasification capacity to be staggered is required. This not only provides savings during the initial capital works, but the flexible design allows the terminal to keep up with actual market demands (as opposed to projected market demands). To design for daily demand fluctuations, detailed knowledge of the nature of fluctuations is required. This allows correct sizing of key regasification components (such as pumps and vaporizers) and the development of operational philosophies to provide ramp-up and ramp-down capability.
Terminal availability: Terminal availability is a measure of the time where the terminal is online and supplying gas to the onshore power plants/gas distribution grid.
Availability is commonly expressed as a percentage on an annual basis. For example, a terminal with 98% availability annually will mean that the terminal is supplying gas approximately 358 days of the year.
For base load regasification terminals, high availability is driven by market demands and is a strict requirement (generally above 98%). This high availability means that the terminal either has to be permanently moored or the facility has to utilize two regasification vessels that can be alternated; the latter solution would incur significantly higher capital expenditure and operational cost. In contrast, the availability for seasonal load markets would only have to be 40 - 60% annually (market dependent) to satisfy the seasonal demands and for these markets a permanently moored facility is therefore not required.
The requirement of a permanently moored terminal means that it is not possible to remove the facility for lengthy service periods in a dock/shipyard. This necessitates careful consideration during the design process, especially in the design of the regasification (process) equipment and LNG storage tanks. The challenges in designing regasification equipment lie in the marinization process (adapting land based regasification technology for the offshore environment) and in ensuring high availability of the equipment.
Both of these challenges can be addressed by a design centered on minimizing downtime (via designing for operational flexibility that allows continuous operation during partial equipment failure) and minimizing maintenance/repair operations offshore. Another challenge is the selection of the appropriate LNG cargo storage system. The challenges associated with LNG storage tanks are not only sloshing related, but also relate to the maintainability/routine inspection of the storage tanks without bringing the facility into a dock/shipyard (H. Kelle, 2014).
The financing risk can be summarized for floating regas terminals as the credit and payment risk, risk of non-payment, LNG or gas offtaker creditworthiness, charterer creditworthiness, liquidity Risk, cost-overruns, invoice and cash-flow mismatches, commissioning and ramp-up periods, and force majeure, unforeseeable risk, acts of God, inter-dependency of force majeure clauses throughout LNG supply chain, force majeure clauses frequently not back-to-back, role of state in supply and transportation and offtake.
In contrast to investments backed by state-to-state agreements among high investment grade major oil companies and equivalent rated utilities, new LNG Floating storage regas terminals investments rely on below investment grade entities to ensure sufficient long-term revenues to support a multi-million dollar investment chain, i.e. non-recourse or limited - recourse financing.
The non-recourse or limited recourse finance is backed by the contracted cash flow of the asset. Hence, the lender will look in great detail at project specific asset, strength of the charter contract, strength of charter counterparty and the longest tenor financing possible.
The financing tenor of the assets is usually limited to the contractual time limits. The need for strong EPC and charter contractors with strong balance sheet make it necessary to find the right partners to ensure project success. Apart from the project specific assets design, construction and management, the focus when selecting partners is on market liquidity, balance sheets and strong contractual cash flow.
From a lenders point of few the following due diligence areas will be focused upon:
Liquidity, Balance sheet strength, cash flow, Technical robustness, Legal structures and framework, Insurance, and The Tax/commercialization Model.
The issues are compounded by the approach being taken towards the financing of the different in country components of the chain; the LNG port/import terminal/regas and storage (FSU) on the one hand and the distribution network and power plants on the other hand, with the emphasis being placed on the private sector, IPPs and Clean Energy Development.
Due to this complexity none of the players in an LNG-related activity will fully launch an investment in a component piece or disburse significant funds until it has received formal confirmation that every other actor involved is equally committed.
Many projects fail due to complex contractual matters and the inability to limit project risk allocated to the terminal company as well as a lack of well-defined project risk allocation and control methodologies. Because of this there is a preference in the gas off taker industry for tolling models. The tolling model transfers some of the LNG import business risks, such as supply and market risk, on foreign or third parties.
The writer is Deputy General Manager in MJL Bangladesh Limited. Email: Shahin.email@example.com
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