LNG value chain optimisation 01

LNG value chain optimisation – Case Myanmar 

An optimal logistics chain is the key to making liquefied natural gas (LNG) affordable for the end users and profitable for the LNG solution providers. Due to the number of unknowns in the equation, planning and optimisation can be challenging. However, a case study can help estimate the cost prices of gas for project configuration options and examine the resulting effects. 

Text: Kenneth Engblom, John Reinlund, Nicolas Leong Photo: iStock, Wärtsilä


The key to making liquefied natural gas (LNG) affordable for end users and still allow some profit for LNG solution providers is to design an optimal logistics chain. Due to the increasing complexity of handling -163°C LNG as compared to +25°C diesel and heavy fuel oil (HFO), the LNG logistics chain needs a lot more consideration. Furthermore, the solutions and configurations for a small-scale logistics chain are still being developed. This makes the planning and optimisation challenging, as the equation includes a lot of unknowns. 

In parts of the world, we already see brave companies that recently got their LNG logistics up and running and are now busy looking for additional consumers – to increase their volumes and get full utilisation of their infrastructure investments. Moreover, there will be a lot more first movers continuing to shape the industry in still-developing parts of the world. By being first in a new market, thereby signing up new customers before anyone else, these first movers and entrepreneurs can build the necessary volumes to make their investments profitable. Being the first in a region and capturing the base load (or base flow) of LNG makes it hard for competitors to enter. But this is not without risk. 

As so many variables can change, there will also be first movers whose investments, for various reasons, may not be able to attract the necessary volumes and, therefore, will remain unprofitable. To reduce this risk and ensure successful projects, the team or consortium setting out to develop the project ideally should include experts from all segments, starting from the molecule providers, shipping, permitting and local community knowledge, engineering, procurement and construction (EPC) and operations & maintenance. Besides the coordination of these diverse teams, Wärtsilä’s LNG solution team can also provide the complete EPC, operations & maintenance of LNG terminals. 

In the previous In Detail (02/2016), we discussed the LNG logistics chain main parameters that determine the landed cost of LNG. Therefore, we will not discuss this again but rather will use these details in a practical case study.

In that former In Detail article, we also used a case study, where we created a fictive receiving terminal in Aruba (in the southern Caribbean) and linked it to four potential regional LNG suppliers at various distances from the terminal. We compared the landed LNG cost based on various ship sizes, chartering rates and receiving terminal storage capacities. By increasing ship size and the receiving terminal’s storage capacity, shipping and refilling frequency can be reduced. The objective of the case was to find the optimal ship and storage capacity, in relation to the shipping and refilling frequency, from each of the four supply points. Finally, we compared the four supply locations to each other.

In this case, we will study the opposite situation – where we have decided on one supplier with three potential receiving consumers. The fictive case is based on transport from the Singapore LNG terminal to various sites in Myanmar.

Fig. 1 - The LNG value chain.
Fig. 1 - The LNG value chain.


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Fig. 2 - LNG floating storage & regasification barge (FSRB). Ideal for: locations with shallow protected water, difficult site conditions and expensive local infrastructure. Advantage: a mobile and modularised asset (in sizes from 7500 m3 to 30,000 m3) that, therefore, can be multiplied or relocated if demands change.


LNG terminal solutions

The receiving and redistribution terminal can take many forms. The choice of terminal depends on the site locations and the volumes required. 

For large onshore terminals, flat-bottom concrete tanks are the most commonly used. For small sizes, the pressurised steel tanks are becoming popular.

For large-scale terminals, there are possibilities to employ an offshore solution with an FSRU (floating storage & regasification unit) or an FSU (floating storage unit) with a regasification unit mounted on the jetty. Projects have also been planned using outdated LNG carriers as FSUs. These LNG carriers can be purchased at a low price because they are no longer economical to use as carriers, due to their usually old and inefficient steam engines.

In locations where an onshore location is not suitable, and the gas amounts are too small to make an FSU or FSRU feasible, Wärtsilä’s LNG floating storage & regasification barge (FSRB) can be the best alternative. 

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Fig. 3 - Medium-size LNG terminal based on a flat-bottom concrete tank. Ideal for: terminals where a storage capacity over 15,000 m3 is required and where local labour and construction equipment are available. Advantage: a well-insulated tank and terminal that can withstand any type of weather.


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Fig. 4 - Small-size LNG terminal based on insulated bullet tanks. Ideal for: smaller-size terminals where a storage capacity up to 15,000 m3 is required or where there is not sufficient availability of local labour and construction equipment. Advantage: a solution that needs minimal site work, as most of the work is shifted to factories.


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Fig. 5 - Floating storage & regasification unit (FSRU). Ideal for: large-size storage (from 125,000 m3 and up), where there is at least 600 MW offtake. Advantage: a flexible solution that can be moved whenever demand changes.




Now we illustrate the LNG to power solutions discussed so far through a fictive case, loosely based on a few sites in Myanmar and assumptions about these sites and the logistic chain. We estimate the cost price of gas for two alternative project configurations and examine the effects of our preferences:

  •      In Alternative 1, we choose a preference for low CAPEX.
  •      In Alternative 2, we choose a preference for low OPEX.

As per the map in Figure 6, we have selected three different sites in Myanmar. The main parameters of the locations are described below.

Nga Yoke Kaung: 

Located near the city of Pathein (350,000 habitants) with basic industry, universities and some tourism.
LNG consumers:
50 MW power plant running at power factor (PF) = 80% (average load 40 MW)
Will provide power for local population and industry.
Site quality:
No existing marine infrastructure. Otherwise suitable for an onshore terminal.
Marine data:
Deep water (10 m) near shore, location fairly sheltered for winds except from the south. Risk for cyclones, flooding and earthquakes.
No tugs and no local port authority.
Other infrastructure:
Pathein offers little industry and relatively low-skill workforce.


Major city with a population of six million. It is the country’s centre for industry, trade, tourism, etc. Chronic power shortages currently limit the factories’ operating hours.
LNG consumers:
125 MW power plant running at PF = 80% (average load 100 MW).
Site quality:
Slightly sloped waterfront, soft soil, low environmental and social impact. Suitable for an onshore terminal.
Marine data:
Close to river mouth, water depth 8 m, considerable traffic. The tide is quite strong. Fairly well protected from wind in normal conditions. Risk for cyclones, flooding and earthquakes.
Pilotage required.
Other infrastructure:
Workforce capable of civil infrastructure works.


Dawei has approximately 150,000 inhabitants. Dawei is the proposed site for a Special Economic Zone (SEZ) with a deep-sea port (which, in this case study, we assume has been built already).
LNG consumers:
75 MW power plant running at PF = 66% (average load 50 MW) providing electricity for industry during the day and for the inhabitants of Dawei primarily in the morning and evening.
Site quality:
Deepwater port, good soil conditions, industrial zoning. There are plans for a large onshore LNG terminal or an FSRU (floating storage and regasification unit), but an intermediate solution is needed in order to enable industry to start producing in the SEZ. Therefore the investors have envisioned a floating storage and regasification barge (FSRB).
Marine data:
14 m sea depth, existing breakwater, sheltered quay where LNGC and FSRB can be positioned alongside the quay. Extreme monsoons may cause flooding, but cyclones and earthquakes are less likely in this part of Myanmar.
Other infrastructure:
Good availability of heavy lifting equipment.

Fig. 6 - The map showing three different sites in Myanmar.
Fig. 6 - The map showing three different sites in Myanmar.


Table 1 - Calculation of total LNG consumption at each site.
Table 1 - Calculation of total LNG consumption at each site.    


The total combined offtake is 272,500 tonnes per annum (TPA). We assume that the LNG price “free on board” (FOB) Singapore is oil-linked, according to the following formula: Brent price x 14.5% slope, which with an oil price of USD 55 per barrel would result in an LNG price of USD 7.98 per million British Thermal Units (MMBtu). This price is not based on information from the supplier, but as small-scale LNG pricing seldom is transparent, we have chosen a simplified formula.

When examining the sites and planning the logistics chain, we encounter a challenge. The size of carrier that would be needed to make possible a “milk run” delivery to all the sites cannot, according to our (fictive) site description, reach the Yangon site due to draught limitations. The solution is to create a hub terminal in Dawei and distribute the LNG from there in a smaller vessel to the other sites.

For Alternative 1, where we prefer low CAPEX, we need to keep the terminals as small as possible. We calculate that we can make do with an intermediate terminal with 22,500 m3 capacity that would be serviced by a 15,600 m3 LNGC going back and forth to Singapore. For this size of terminal, the FSRB envisioned by the investors will be possible. There will be approximately 8.5 days between filling the tank in Dawei. Moreover, a 5500 m3 LNGC would do a milk run on the route Dawei – Yangon – Nga Yoke Kaung. Such a vessel has a design draught that would enable it to travel to the Yangon site. The terminals in Yangon and Nga Yoke Kaung can make do with fairly little reserve capacity since the milk run is short and the power plant owners have opted for dual-fuel power plants which, if needed, can run on liquid fuels. 

For Alternative 2, where we prefer low OPEX, we focus on finding a less expensive way of delivering LNG. Hypothetically, we could look for a ship owner who can offer a larger LNG carrier. This would, of course, come at a higher day rate than the 15,600 m3 LNGC in Alternative 1, but this time we manage to sign a flexible agreement that allows us to charter the vessel only for the period when we need it. With a 45,000 m3 LNGC, we can extend the time between filling the tank in Dawei from 8.5 days to 25 days. The logistics for the Dawei – Yangon – Nga Yoke Kaung milk run remain unchanged.

With a longer supply interval, however, it would also make sense to have more reserve capacity at Dawei. Therefore, we increase it from four days in Alternative 1 to eight days in Alternative 2. This would require us to build a 60,000 m3 terminal in Dawei at considerably higher CAPEX. The larger LNG storage capacity available gives the power plant investors reassurance that gas will always be available, and they decide to prioritise efficiency over dual-fuel capabilities and choose to invest in a gas power plant rather than the dual-fuel power plant that they originally planned. The terminal investors also decide that, rather than having two 30,000 m3 FSRBs, it would be acceptable to build the terminal as a permanent onshore solution. Can this investment be recovered through the more flexible charter agreement?


The calculations show that the effects of the more flexible charter agreement were considerable. For Nga Yoke Kuang, we managed to reduce the cost price of gas by USD 0.60 per MMBtu, which might have a decisive impact on the financial feasibility of the entire project. For the other sites, we also managed to reduce the costs, despite the effects of a significantly higher CAPEX.

This case study shows that judging a project’s feasibility simply by looking at the CAPEX can be extremely misleading. One can make significant improvements by designing a logistical chain with a good fit with regard to distances, gas consumption and the sizes of available ships. Such optimisation also should examine the effects of even the slightest reduction of charter rates or LNG prices on the final cost price of gas. This is something that we will expand on in upcoming articles. 

Comparison: Alternative 1 (Low CAPEX)
Comparsion: Alternative 1 (Low CAPEX)


Comparison: Alternative 2 (Low OPEX)
Comparison: Alternative 2 (Low OPEX)


Authors: Kenneth Engblom, Director, Sales & Marketing, LNG Solutions, Wärtsilä Energy Solutions,
John Reinlund, Business Analyst, LNG Solutions, Wärtsilä Energy Solutions,
Nicolas Leong, Business Development Manager, SEA, Sales, South East Asia & Australia, Wärtsilä Energy Solutions,
mail: kenneth.engblom@wartsila.com, john.reinlund@wartsila.com, nicolas.leong@wartsila.com

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