Success and failure factors of Floating Storage Regasification Unit --I -The Asian Age

In 1873, German engineer Carl von Linde built the first compression refrigeration machine for liquefaction experiment of natural gas. First experimental plant designed to store LNG (Virginia, USA) in 1912. LNG market is originated during 1940-1970 and LNG demand grows during 1972-2000.

The goal of LNG market create during 2008-2014 and in 2014 the LNG global market celebrates 50 years of history with about 80,000 transfers without significant accidents. Moheshkhali Floating LNG (MLNG) is the world's first fully integrated turnkey floating LNG terminal in Bangladesh which is launched in 2018 whereby all services are provided under a single contract by a single provider Excelerate Energy.

Floating regasification units are increasing steadily in the highly populated areas where space for shore facilities is limited. Beginning of 2009, it has been seen variations of the traditional floating storage regasification unit (FSRU).

As a result comes in jetty and shore based regasification with floating storage units (FSU). Initially the majority of terminals were designed for seasonal demand but overtime FSRUs have proven to be robust and able to deliver base load regasification.

FSRU and Nearshore Projects (NSP) are the most conceptual now and it's around half of all intended FSRU and nearshore regasification projects are progressed beyond concept stage in the world due to lots of obstacles, challenges and risks FSRU and NSP are facing with the roles technology, investors, lenders, operators, shipping companies and LNG suppliers, pipeline operators and energy policy plays in the establishment of nearshore regasification terminals.

During 2005 to 2015, there are around 50% of the world's FSRU and NSP projects have been planned, committed, completed and cancelled. H Kelle in 2015, measured a statistical data from 30 projects during mentioned period, whereas 38% are completed or committed (EPC/Lease contract signed), 17% being in planning stage for future selection and the remaining 45% are shelved or cancelled. There are lessons to be learned and to identify the common challenges due to the high rate of early resignation of FSRU projects in the world.

LNG storage transportation and discharging challenges: All FSR terminals are receives Liquefied Natural Gas (LNG) at ambient pressure and at cryogenic temperatures of around - 160ºC. The FSRU stores the LNG and then regasifies the LNG usually by heating it to around 3ºC to 7ºC and pressurizing it to natural gas pipeline pressures which can range from 40 barg to above 100 barg.

A full scale floating storage regasification unit / floating storage unit's storage volume of LNG on board vary from 120K m3 to 266K m3. FSRU/FSU terminals usually have a mooring system. This system is suitable to moor the large LNG carrier either permanently or temporarily within set limits of the required gas availability per annum.

The high pressure gas is then either transferred from the FSRU to shore via a (subsea) pipeline or to a regas unit mounted on an offshore platform (most commonly on the FSU jetty) or to a regasification plant onshore. The high pressure gas from the offshore facility is transferred via a subsea pipeline to an onshore receiving facility. In this facility is often where gas metering, or further gas heating and conditioning takes place, and the tie-in into existing gas networks is controlled.

The re-gas capacity for full scale FSRU and FSU application ranges between 0.5 and 6.5MTPA with majority of facilities operating around the 1.2.-3 MTPA range. These facilities range from micro facilities of less than 0.1MTPA to just under 0.5MTPA and are likely to be used to service insular markets and power generation facilities of up to 300MW.

The storage of small regasification unit can vary greatly such as the range of 8K m3 to 15K m3. A key benefit of small storage vessels is reducing capital expenditure significantly due to smaller infrastructure requirements and lesser draught requirements, compared to the full scale version which has to be placed in deeper water and therefore often further offshore.

The modern combined cycle gas turbine (CCGT) has a thermal efficiency of between45% to 55%. Therefore, a 100MW power station consumes approximately 800m3 of LNG per day or over 24K m3 per month. The report outlines conversion and new build forecasts for CCGT, single cycle gas turbines and reciprocating gas fueled power stations.

Relatively little work has been done to develop cost effective storage tank sizes for the LNG to Power market. Tank sizes greater than 160K m3 is required to receive a standard export LNG carrier which would provide 10 months of storage for a 100MW CCGT.

Floating Storage Regasification Terminals Success factors: The success of FSR terminals still is driven by the availability of proven technology and Ease of Finance and Contracting. The market of floating storage regasification unit has been speeded up since leasing option has been developed of LNG project.

The financial ability to lease close to 50-80 percent of the total investment cost. Leaves the more difficult nonrecourse financing to minimal fixed infrastructure such as mooring, pipelines and onshore receiving facilities (ORFs). The relative simplicity in which an FSRU can be hired using standard shipping lease contracts and the relatively small onshore footprint have made these types of terminals attractive for emerging economies.

Risk sharing: There are various risks have to be considered to successfully deliver floating re-gas terminals such as market risk which can be both downstream and upstream. The downstream threats are natural gas pricing, buyer credit risk, competing fuels, lack of market demand, regulatory system and the upstream supply threats are insufficient reserves, failure of supply.

The global LNG industry is more accumulated of contractual monopolies due to enormous investment and rigid contractual relationships throughout the LNG value chain and complexities of global LNG market. Still contractual agreement is a big challenge for future sustainable markets and efforts are currently underway to commoditize LNG and to create LNG Hubs in Asia.

The gas price is a main current reference points concerning which dependable on the Henry Hub price in the United States, the NBP in the United Kingdom, and the average Japanese LNG import price. In terms of level and geographical coverage, they fail to reflect the diversity price of gas as an important benchmark.

Whereas developing countries are facing challenges for pricing, while standard references are relevant for developed countries. In the IEA report in 2014 (Anne-Sophie et al) gas prices are determined according to different gas pricing mechanisms. Since 2005, the International Gas Union (IGU) has been reviewing the evolution of gas price levels and has pricing mechanisms across the world in its wholesale gas pricing survey.

There are few different gas pricing mechanisms (IGU-2014, wholesale gas price survey) are: 1. Oil escalation: The gas price is linked to oil or oil products, 2. Gas-to-gas competition: The gas price is determined based on supply/demand fundamentals, 3. Bilateral mechanisms: The price of natural gas is agreed upon between two governments for a certain duration, 4. Netback price: The natural gas price is linked to the end product; this happens sometimes in the case of methanol, 5. Regulation cost of service: The level of the gas price covers the costs of production and transport plus a certain margin, 6. Regulation social and political: The gas price is decided on an ad-hoc basis by the relevant ministry, 7. Regulation below cost: In other terms, the gas price is subsidized, and 8. No price: The gas is given for free; this tends to disappear.

From the IGU study, it was highlighted two very important facts for pricing mechanism at the wholesale level such as gas-to-gas competition represents around 43 percent of the gas sold globally, which is twice as much as oil-indexed gas around 20 percent and all of other different types of regulated gas prices comes together around 33 percent, (The Asian Quest for LNG in a Globalizing Market, NOV 2014), Further the IGU report states that more than 71 percent of LNG imports are priced based on oil indexation, while for pipeline gas this reduces to 48 percent.

The gas price mechanism based on oil indexation has existed for several decades which governed imports and gas production. The mechanism was first adopted in the 1960s when the Netherlands was looking at exporting part of its natural gas production from the Groningen field. The underlying aim of oil indexation is to establish pricing on a "market value principle".

Atypically an oil-index pricing formula for gas (IFRI in 2011):
Pm = Po + 0.60 x 0.80 x 0.0078 x (LFOm - LFOo) + 0.40 x 0.90 x 0.0076 x (HFOm - HFOo) + K
In this formula, Pm represents the gas price in month m. Po is the reference gas price, while LFOo and HFOo are the reference prices of light fuel oil and heavy fuel oil. LFOm and HFOm represent the prices for the month m, but actually are usually the averages of the previous six to nine months with a time lag of one to six months. The coefficients 0.60 and 0.40 represent the shares of the market segments competing respectively with light fuel oil and heavy fuel oil. The coefficients 0.80 and 0.90 are pass-through factors. K is a fixed factor.

In September 2015, the WTI was the lowest in 5 years ($37/bbl) causing significant downward pressure on the LNG price. It appears that when in 2013/2014 the WTI prices were consistently above the US$100/bbl mark due to Japan's shut down their nuclear power plants and a rush to buy LNG. Since 2015 the price is averagely upward trend, now in September 2018 the price is around US$68/bbl. Some LNG buyers have over-contracted, and are likely to dispense of leftovers in the LNG spot market.

The writer is Deputy General Manager in MJL
Bangladesh Limited.
Email: Shahin.alom@mobilbd.com