Contents...There are both on-shore and off-shore solutions available for the LNG receiving terminals today. As for the LNG terminals, the power plants can also be built on-shore or

1

LNG to Power in remote locations- the optimal way

Authors: (Version: 09-07/2016)

Kenneth Engblom, Director, Sales & Marketing, LNG Infrastructure solutions

Wärtsilä Energy Solutions

Contents

1. Summary ......................................................................................................................................... 2

2. Introduction .................................................................................................................................... 3

3. LNG logistic chain ............................................................................................................................ 6

4. LNG Terminal solutions ................................................................................................................. 11

5. Power plant solutions ................................................................................................................... 13

6. Case ............................................................................................................................................... 15

7. Conclusion ........................................................................................................................................ 26

Legal disclaimer This document is provided for informational purposes only and may not be

incorporated into any agreement. The information and conclusions in this document are

based upon calculations (including software built-in assumptions), observations,

assumptions, publicly available competitor information, and other information obtained by

Wärtsilä or provided to Wärtsilä by its customers, prospective customers or other third

parties (the ”information”) and is not intended to substitute independent evaluation. No

representation or warranty of any kind is made in respect of any such information. Wärtsilä

expressly disclaims any responsibility for, and does not guarantee, the correctness or the

completeness of the information. The calculations and assumptions included in the

information do not necessarily take into account all the factors that could be relevant.

Nothing in this document shall be construed as a guarantee or warranty of the performance

of any Wärtsilä equipment or installation or the savings or other benefits that could be

achieved by using Wärtsilä technology, equipment or installations instead of any or other

technology.

2

1. Summary

Demand for gas is increasing and especially in the form of LNG. The drivers behind this is that

gas is environmentally cleaner than oil and laws are being enforced to phase out coal and oil

and replace by renewable energy. Furthermore gas is giving stability to energy prices with an

alternative market in the process of de-linking from oil market. A major “cost adder” to bring

LNG to the final destination comes from the infrastructure requirements and thereby cost of

the LNG logistic chain. The logistic chain includes the steps starting with the liquefaction of

the natural gas, loading the LNG carrier for the ocean transport, unloading the LNG carrier to

the receiving terminal via a jetty and unloading systems and regasification or other means of

further re-distribution of LNG with trucks or barges. It is in the end users interest that this

logistic chain is as cost efficient as possible. There are several things that can be done to

optimize the logistic chain. The cost of natural gas in the final destination will be dependent

on parameters like: The size of the ship(s), shipping route(s), size and location of receiving

terminal(s), utilization of BOG in the process and finally the customer’s gas dependence and

gas availability and reliability requirements. In order to optimize the logistic chain, Wärtsilä

has developed a special tool. The end user requirements and the infrastructure constraints

are used as inputs for this tool. It can also be used to do sensitivity analysis on the LNG price

vs. the main parameters of the LNG value chain.

There are both on-shore and off-shore solutions available for the LNG receiving terminals

today. As for the LNG terminals, the power plants can also be built on-shore or off-shore.

Wärtsilä has developed various sales ready concepts for both on-shore and off-shore

terminals and power plants. Wärtsilä is using flexible and efficient gas and dual-fuel medium

speed gas engines as prime movers for both the on-shore and off-shore solutions. With

introduction of intermittent renewable energy like wind and solar, the duty of the gas power

plants has increasingly become to provide the grid reliability and support for the renewable

energy. The running profile of the existing plants is changing from baseload operation to a

more flexible and peaking operation. This is an important change to consider when designing

new LNG infrastructure. Storing gas as LNG gives a greater flexibility for a varying load and

power factor by not being dependent on the natural gas pipeline fixed capacity.

When planning an LNG receiving terminal it is important to try to include as many off-takers

as possible sharing the same terminal. Larger throughput lowers the specific cost of the

investment. Including more export options in the terminal makes it more expensive, but if

this in return increases the throughput, it might still reduce the specific cost of LNG

Finally by calculating the cost of electricity produced by LNG for a fictive case based on a few

islands in South East Asia, we illustrate the practicalities around planning the optimal logistic

chain and choosing the LNG receiving terminal and power plant solutions in order to convert

LNG to Power in the most cost efficient and optimal way.

3

2. Introduction

2.1 Natural Gas & LNG Markets Most experts predict that natural gas demand will see continuous growth in the future, increasing at a compound annual growth rate somewhere in the region of 2-4%. Natural gas (NG) is gaining market share from other fossil fuels when it comes to power generation. NG is gaining popularity in other sectors, especially transport –both in marine and onshore. Also cars and smaller machines are using an increasing amount of natural gas in its compressed form (CNG). According to World Energy Outlook by IEA, natural gas will make up 25% of the total energy demand by 2035. (see figure 1) The attraction of gas as an energy source – whether for heating, transport or power generation – is clear. Its price relative-to-energy content is favourable when compared with other fossil fuels, and it significantly reduces SOx and CO2 emissions when replacing coal and oil in power generation.

Figure 1. The Natural Gas forecast - World Energy Outlook by IEA.

A crucial factor in enabling the spread of natural gas into new sectors is the development of NG distribution networks. Today, the most common method of distributing NG is via pipeline. However, the construction of pipelines requires significant resources in terms of investment and time, as well as overcoming bureaucracy. Also, for these pipelines to be profitable gas volumes must be large. Another way of increasing the availability of NG is through the use of liquefied natural gas (LNG). Global LNG trade has been growing by about 6% per year (vs. 2% for Natural gas in general) and is expected to constitute 15% of all gas traded by 2035 according IEA (international Energy Agency). (see figure 1)

Both production and receiving capacity must grow simultaneously due to the nature of LNG. Since 2011 the LNG production or trade has been quite stable around 220- 230 MTPA nor has there been any new capacity added. But starting from late 2015 and continuing during 2016, we are seeing lots of new capacity taken into use, especially in US and Australia. According to IGU (international Gas Union), the nameplate LNG production capacity was 308

4

MTPA by the end of 2015. This means that there is a substantial production overcapacity today. Exactly how much extra capacity we really have depends how close to nameplate capacity the existing liquefaction plants are able to operate. Despite today’s overcapacity, more production is being planned to cater to the anticipated increase in LNG consumption. A substantial part of this growth will come from the development of small and medium size LNG consumers and corresponding infrastructure. This demand is particularly relevant in places where the gas infrastructure is under-developed but where the demand for gas-fired power generation and natural gas for other industrial uses is large.

Figure 2. LNG trade volumes as well as importing and exporting countries 1990-2015

The re-gasification capacity today is around 780 MTPA, which means that many terminals are not running at full capacity today. The terminals are also not always located where the demand is. With a current glut of gas in the world, and new technologies in the LNG sector, bringing cleaner, lower grade of emissions, there has never been a better time to substitute fossil fuels such as coal and oil, with a more environmentally friendly fuel such as LNG. LNG is an ideal fuel for new power plants and other industrial applications of all sizes and provides access to gas in countries and locations currently heavily reliant on coal or heavy fuel oils for power production. The investments made so far have typically been in large receiving terminals not meant for minor consumers. However, during the last few years, we have seen an steep increase in small and medium scale LNG activity including regional storage hubs from where small scale LNG carriers, highway LNG trucks and bunkering vessels distribute LNG to the smaller end user. 2.2. LNG logistics chain The LNG logistics chain, from gas well to consumer, is complicated and investment intensive. This adds a considerable amount of cost to the end user. The economies of scale play a big role in LNG logistics. Larger liquefaction plants, larger LNG carriers and larger terminals all contribute to a lower unit cost. However, to be able to deliver LNG to smaller consumers that are unable to utilize the large terminals or receive a large LNG carrier in their small harbour, there needs to be a medium & small scale logistic chain in between before they can get their gas.

5

The LNG logistics chain can be divided into three sizes:

-Large scale (the conventional LNG logistic chain) -Medium scale -Small scale

Let’s explain a bit more in detail how we define the difference between these three.

Figure 3. The Large, Medium and Small scale LNG value chains

2.2.1 Large scale LNG operations Liquefaction plant: A large scale LNG operation typically include production trains with single capacities between 1 to 6 MTPA (Million Metric Tons Per Annum). They can include multiple trains. For example, in Qatar, world biggest supplier of LNG, Quatargas and Rasgas has a total production capacity of 77 MTPA in their production site. Cheniere’s newly opened Sabine Pass liquefaction plant will have a nameplate capacity of 27 MTPA when they have opened all 6 trains of about 4,5 MTPA each. Large liquefaction sites are always located in coastal areas since the only practical method of large scale transportation is via LNG carriers with capacities ranging from approx. 120,000 m3 (54,000 Ton) in older vessels up to as much as 267,000 m3 (120,000 Ton) in the largest Q-max vessels. As an example, this means that Cheniere’s Sabine Pass plant could deliver more than a Q-max vessel of LNG every second day. Receiving terminal: Conventional receiving terminals (LNG hubs) in the large scale LNG chain are also located by the coast so LNG carriers can arrive and unload the cargo. Main hubs include LNG storage facilities typically in the range of 120,000 m3 or larger designed to receive at least the full capacity of the allocated LNG carrier. The LNG is re-gasified at the hub and the main distribution channel for the consumers is normally a national high pressure NG pipeline. 2.2.2 Medium scale LNG operations With the medium size LNG logistics chain, we mean terminal sizes up to 120,000 m3, which are supplied by small scale LNG carriers starting from sizes of 1000 m3 up to around 40,000 m3. Here again, vessel size and loading frequency play an important role in determining storage.

6

Medium Scale Liquefaction is not so common today due to the challenge with high specific production costs. But anyhow these will probably play a larger role in the future for decentralized solutions where extending the large scale logistic chain would not be feasible.

2.2.3 Small scale LNG operations With the small scale LNG logistics chain we include LNG distribution to local users. In practice this means highway truck transportation or small sea-going vessel distribution to end user local LNG tanks, which can be from the smallest container sizes of 20 m3 up to a set of pressurized steel tanks with total capacities up to a few 1000’s of m3. Small scale liquefaction is becoming popular due to the liquefaction of biogas and other smaller pockets of stranded gas. The small scale liquefaction can be modularized and to some extent standardized. The systems are similar to the re-liquefaction process used in large terminal to handle the BOG (Boil of Gas).

3. LNG logistic chain

3.1 Logistic Chain “Cost adders” As described in previous chapter, the final cost of LNG in the final destination will largely be dependent on the length of the logistic chain with the main parameters like: source cost of LNG, location of the LNG liquefaction plant versus the final destination, size and route of the LNG carrier, size and location of receiving terminal(s), the utilization of BOG in the process and the end customers’ requirements on gas availability.

Figure 4. Typical values for the cost contributors or “add on costs” in the LNG logistic chain.

Let’s go through the example in Figure 4 above. Starting with the Henry Hub price of 2.0 USD/MMBTU, which is the natural gas in gaseous form in the Southern US gas network, let’s assume we would like to consume this gas on an island somewhere in Asia. To make this possible there are a few steps on the way. First of all, the gas need to be purchased and sent to one of the liquefaction plants in southern US. The cost for liquefaction depends on the cost of transferring the gas from the Henry Hub priced pipeline gas to the liquefaction plant. Then we have the investment and running cost of the liquefaction plant plus storing the LNG

7

to have it ready for an LNG carrier to come and load it. The combined “add on cost” for all of this could be in the +2.6 USD/MMBTU range. Then while loading the LNG carrier there will be some port fees and potential canal fees. Going thru the Panama canal with a 173,000 m3 vessel will cost around 380,000 USD which would impact the LNG cost with 0,1 USD/MMBTU. Anyhow, the major cost of shipping will come from the fuel used during the journey plus the daily ship charter rate. The total cost of all shipping related things will depend on the ship size and length of journey. In this example we have assumed an add on cost of +1.1 USD/MMBTU for the all-inclusive shipping. After reaching the destination, the LNG carrier is unloading to the receiving terminal. The cost for the investment and operating a receiving terminal and harbour can add another +0.8 USD/MMBTU to the LNG cost. Then we can assume about 0.1 USD/MMBTU for regasification and another 0.2 USD/MMBTU fee for the pipeline. This will then all add up to a gas price of about 6.8 USD/MMBTU for the consumer at the end of the gas pipeline. If the end user needs smaller amounts of LNG than the large LNG terminal is willing or able to sell, he will need to go through the medium scale operators. In that case he would be able to buy LNG for 6.5 USD/MMBTU from the large terminal and adding the mid-scale logistic costs the final price for the mid-scale consumer would be in the 9.2 USD/MMBTU range. Finally when it comes to the small scale user, he would have another smaller storage and have the LNG shipped either through small size carrier or LNG truck/ISO Container. The final price for him might be as much as 11.5 USD/MMBTU. So in this fictive example, for the small gas user on an island somewhere in Asia, the Henry Hub price of 2.0 USD/MMBTU, will end up at 11.5 USD/MMBTU at his final destination. As a comparison, LNG sold in ISO containers FOB Miami ranged from 10- 16 USD/MMBTU when American LNG sold to Barbados this year. Most of the time the price was 10 USD/MMBTU. 3.2 Logistic Chain Optimization As the major cost of producing electricity is the fuel there is a huge difference if the cost of fuel is 2 USD/MMBTU instead of 11.5 USD/MMBTU. It is in the end users interest that this value chain is as cost efficient as possible. There are several things that can be done to optimize the LNG logistic chain in order to reduce the cost of LNG or gas in the final destination. The small scale logistic chain which incorporates both the large scale, medium and small scale chains can be very complex. To be able to optimize this complex chain with lots of variables Wärtsilä has developed a LNG Value chain optimization tool. This tool estimates, through an iterative process, the cost of LNG in the final destination(s). The tool need various inputs like:

- the consumers (location(s), consumption profile, cost vs. feasibility) - gas availability requirement - supply (location(s), suitability, cost) - receiving terminals (need for break-bulk, location, type, sizes, Investment cost) - shipping (route, shipping, charter-rate, fuel consumption) - Boil Of Gas (BOG) handling - financing (ownership arrangements, cost of capital, pay-back time)

8

The tool works so that you start by defining the consumers, the locations and the anticipated consumption profile. Based on this you analyse the logistics, deciding where to get LNG and where the receiving location(s) are. There can be several different end terminals and consumer locations. Dependent on the exporting terminal compliance with smaller ships, you also decide if a large breakbulk terminal is needed in between. Then based on the number of terminals and their sizes included in you can finally propose the size of ships and the route. Then with all basic parameters in place and the basic set-up the optimization/iteration starts where the parameters like LNG purchase price, terminal EPC cost and charter rates are simulated to work out the optimal solution that gives the lowest cost of LNG in the final destination dependent on various scenarios. 3.3 LNG consumption & load profiles When optimizing the logistic chain we need to start from the consumers because without consumers there is no business case. It makes sense to cluster together as many consumers as possible to improve the economy of scale in the LNG logistic chain. In an area previously lacking gas or LNG, the LNG consumption typically comes from industry, power plants or transportation both on land and sea. Industries can benefit from changing from any other fossil fuel to LNG which is always a cleaner fuel and in some cases, largely depending on the economics of the LNG logistic chain, even lower cost. From new gas power plants and from existing diesel or HFO power plants comes probably the biggest potential for increasing gas consumption. Also the marine industry are faced with new legislations that will force them to start changing from HFO to a cleaner fuel like LNG.

Figure 5. Typical consumption and storage size for gas power plants. When considering power plants, it is important to understand the running profile and corresponding gas consumption. Most gas power plants today will not run baseload but rather compensate for the intermittent production from renewable energy or following the varying load of the residential and service sector. In other words, the actual gas consumption will not be the same as the rated max capacity multiplied by the specific fuel consumption of the power plant. This is important to understand when designing the LNG infrastructure. An advantage with gas stored as LNG, is that it gives a greater flexibility for a varying load and power factor and not being dependent on the natural gas pipeline fixed capacity.

9

Figure 6. Dispatchable energy production supporting wind and solar.

By clustering together several consumers and increasing the volumes we can potentially buy LNG at a better price and utilize larger ships with a lower specific shipping cost. But at the same time, with several consumers in the loop, you add complexity to the logistics and need a plan for how to break up the distribution of the larger amount of LNG into many smaller consumers. This might call for some additional infrastructure to be built. Additional cost of this infrastructure has to be balanced versus the lower cost of the source LNG. Consumers will, unless forced by legislation, normally decide whether it is worthwhile changing fuel based on the estimated cost of LNG. At the same time the cost of LNG will depend on how many consumers that are ready to start using LNG. This is an iterative process where adding more consumers will make the value chain more economical reducing the final LNG price, which will further attract more consumers. But due to heavy investments in order to get the LNG logistic chain started it is always difficult to be the first consumer in a new place with an un-developed logistic chain. This is the classical chicken and egg situation that can best be resolved by finding a major anchor customer and appointing a strong project leader. 3.4 LNG Supply World LNG prices are determined by a few regional pricing mechanisms. Let’s have a quick look on the typical set up in various regions. Americas: In the western hemisphere (North and South America) prices are based on the so-called Henry Hub system. This price is relatively low today, 2-3 USD/MMBtu and under pressure to stay low due the large amounts of shale gas in the US. US liquefaction capacity is also decoupled from the ownership of gas molecules. Consequently, LNG prices can be kept low and contracts flexible. Europe, Russia, Africa: In Europe, Russia and North Africa the gas market is a mixture of some LNG and mostly pipeline natural gas. The LNG price in Europe is in some cases oil-linked and in some cases linked to the two major gas exchange hubs called NBP and TTF. Gas price in these European main hubs are today in the range of 7-8 USD/MMBtu. Asia: The Asian market has traditionally been very LNG dependent, led by Japan, South Korea and China. The LNG prices in Asia have been the highest in the world, but have during last 2 years dropped from levels of 14-18 USD/MMBtu down to European levels of USD 7-8/MMBtu.

10

When it comes to LNG supply, it is important to understand that it is only a few of the existing export terminals that are able to take small size (<40,000 m3) LNG carriers. Therefore in order to get LNG in smaller amounts, there needs to be a break-bulk terminal in-between. There are some technical issues to overcome with the jetties planned for large carriers in order to handle the smaller carriers, but the main reason why the large terminals do not take small size carriers is the risk of disturbing the large scale operations. The delivery terms and cost of LNG are the most important factors when choosing the supplier. Especially large scale contracts can be done in quite a few ways today, with possibilities to choose oil price linkage, market based pricing or a combination of both. As a small scale buyer you will probably not have the same flexibility. A stable, fairly short-term contract with a minimum take or pay contract probably get you the lowest price today. For the large scale customers that are able to buy spot cargos, that might still be a vice decision and wait with signing long term contracts as there is a lot more production now coming online that puts downward pressure on prices. 3.5 LNG terminal The receiving and redistribution terminal can be of many types. The choice of terminal will depend on the site locations and the volumes required. For large onshore terminals, flat bottom concrete tanks are the most commonly used. For the small sizes the pressurized steel tanks (or Type-C bullet tanks) are becoming popular. For large scale terminals there are possibilities to employ an off-shore solution with an FSRU (Floating Storage and Re-gas Unit) or an FSU (Floating Storage Unit) with a re-gas unit mounted on the jetty. Projects have also been planned using old LNG carriers serving as FSUs. These old LNG carriers can be purchased at a low price because they are not economical to use as carriers anymore due to their old inefficient steam engines. In locations where an on-shore location is not suitable and the gas amounts are too small to make an FSU or FSRU feasible, Wärtsilä’s LNG storage and re-gas barge can be the best alternative. We will discuss LNG terminals in more detail in chapter 4. 3.6 LNG shipping The large scale shipping is well established and today there is an overcapacity of large scale carriers. For the older less efficient LNG carriers we have seen a drastic reduction of charter rates during the last year. But when it comes to small scale carriers there is a lack of ships today and in many cases the charter rate for the small scale carriers might be the same as for an older larger carrier. LNG shipping between the FOB sales hub and new terminal can be arranged in three ways:

1) operating your own LNG carrier; 2) contracting a carrier from the market place 3) arranging transport through an LNG provider.

For the first two options, freight volumes should be significant in order to establish in-house organisations to manage this. The third option is the norm when volumes are small or moderate. In this case the entire supply chain and associated risks can be sub-contracted as one package to LNG providers.

11

4. LNG Terminal solutions 4.1 Terminal solutions Let’s now focus on the mid-scale and small scale LNG terminals and see what needs to be done in order to find the most optimal solution for the logistic chain.

Figure 7. Principle solutions for LNG terminals based on their size and location.

Large scale terminal One of the main questions to be addressed is the technology to be used for the LNG storage facility. If we talk about a large terminal the two main solutions are:

- Stationary on-shore terminal - Floating Storage Re-Gasification Unit (FSRU) or Floating Storage Unit (FSU)

The decision what to go for is based on the economics of the lifetime of the project. Some of the main factors to be considered are: project life time, geographic and maritime conditions, local licensing bureaucracy, land lease/purchase conditions, investment costs vs. possible FSRU/FSU rental fees. The FSRU/FSU might be a better choice if the solution is temporary or if the site is unsuitable for an on-shore solution while the on-shore solution might be the preferred one if we look for a long term solution with a low operating cost. For a large scale on-shore terminal typically two main technical solutions are considered. These are either large atmospheric full containment tanks or single containment in multiple set-ups according to capacity needs. A single containment tank is less expensive to build but requires a larger safety area around it because possible LNG leakage will directly come out in the atmosphere. Which tank type to use, will be based on a comparison of the storage tank cost & construction time versus the safety requirements and available space at the site. An FSRU is a ship that is purpose-built or later fitted with the necessary heat exchangers (re-gas system) for converting the liquid into gas. The gas is transported to land by a gas pipeline, which has flexible connections between the FSRU and jetty. An FSU is like an FSRU,

12

but does not have a re-gas unit. In this case the re-gas system is on the jetty or somewhere on-shore. FSU and FSRU storage capacities are typically 120,000-175,000 m3. Medium & Small scale terminal For an onshore solution in the mid-scale LNG, flat bottom concrete tanks might still be the right solution, but as we go down in size, the pressurized steel tanks (also called bullet tanks) become more interesting. As a rule of thumb we can say that below 10,000m3 a pressurized steel tank is a cheaper option. This of course depends on the project circumstances. If there at the site, there is good availability of concrete, building cranes, labour and other construction related infrastructure at a competitive price, a concrete tank solution will probably be a better option. When considering an off-shore small to medium scale terminal you will not find a small enough FSRU on the market today. Therefore Wärtsilä has been developing an LNG storage & re-gasification barge solution. Feasibility of smaller FSRUs has been discussed for several years, but still no solution has been found due to the technical complexity including propulsion system and the full crew requirement. An LNG storage and re-gasification barge on the other hand, is a simple structure that is very similar to an on-shore solution, but being built on a barge which is fixed to a jetty or shore. An LNG storage and re-gasification barge is not designed for open sea and is therefore to be placed in a safe area protected from large waves. Wärtsilä’s LNG storage and re-gasification barge design criteria have been based for sites: - that are not well suited for construction due to bad soil, - with permitting problems - lacking local infrastructure, e.g. islands, tourist centres, distant or less populated areas - with shallow waters -LNG storage volumes of 5,000- 30,000 m3 or multiple of those Compared to an FSRU which is built as a ship with a V-based bottom requiring substantial draught, a barge is a flat bottom construction that requires very little draught. Wärtsiläs standard LNG storage & re-gasification barges have draught requirements of only 3.5- 5 m depending on size.

Figure 8. Wärtsiläs LNG storage and re-gasification barge solution

The barge can be equipped with either of or both storage and re-gas system on-board. With an integrated barge solution most of the high tech work can be done in a controlled environment in a shipyard and the site related work is left to a minimum.

13

5. Power plant solutions 5.1 Power plant solutions Then let’s have a look at the typical main LNG/ natural gas consumers, the power plants. Almost all power plants in operation today have been built on-shore. But there are a few power barges and power ships in operation around the world. Wärtsilä has delivered almost 20 power barges since 1993 and delivered the gen-sets for the majority of the power ships.

Figure 9. Wärtsilä’s power plant solutions for on-shore and off-shore

The reasons why people choose an off-shore power barge over a traditional on-shore power plant are typically the same reasons as for choosing an LNG storage and re-gasification barge instead of an on-shore terminal e.g: -Need for a temporary solution -Need for a quick delivery time, where the site work would be on the critical path -Need for flexibility and the possibility to move the plant -Building on a site that lacks infrastructure and labour for effective construction -Problem site, with bad soils or difficult to permit. Wärtsilä power plants are based on combustion engines of unit sizes from 4- 22 MW. Typical plant sizes are from 20- 500MW. The largest plant built by Wärtsilä based on the combustion engine technology is 573MW site-rating (= >600MW ISO-conditions rating).

Figure 10. On-Shore 100 MW power plant layout with full plant infrastructure including switch yard and high voltage transformers, liquid fuel tanks for possible dual-fuel set-up as well as all other service and storage facilities needed.

14

The power plants can be either gas, diesel, HFO or dual fuel based. The dual fuel option is a

very popular solution in locations where the gas or LNG infrastructure is not reliable or under

planning. With a dual fuel solution you can start up and produce power on HFO immediately

while the LNG infrastructure is under construction. As soon as LNG/gas is available, the plant

will be ready the same day to switch fuel. Even during operation on LNG/gas, you have the

option to an instant switch to diesel or HFO in case there would be any disturbance in the LNG

delivery.

Figure 11. Off-Shore 100 MW power barge. This power barge is excluding the fuel storage switch yard and high voltage transformers which in this case would be located on the shore side. 5.2 RES integration with SPG As described earlier, the duty of many power plants is changing from providing baseload to more load following. With the large amount of Renewable Energy Sources (RES) being put in operation during the last couple of years, the role of fossil fuelled plants and especially gas power plant, has increasingly become to stabilize the grid and provide the flexible capacity needed during those hours or days when there is no sun or wind. The large share of intermittent renewable energy in the grids today increases the net load variations for the fossil fuel power plants in the grid. See the Figure 12 below for how the gas power plants in Germany, that has a large share of wind and solar capacity, are used to compensate for days without wind and sun.

Figure 12. Gas power plants supporting wind energy in Germany one week of January 2015. (Source: 50HZ, Amprion, Tennet, Germany)

15

Another reason for increased volatility, especially in the developed countries, is that an increasing part of the electricity is now going to the service and residential sector which has large daily load variations compared to the more stable baseload in the manufacturing industry.

Wärtsilä’s on-shore or off-shore power plant solutions based on combustion engines, is well suited for meeting these challenges by providing the best possible combination of efficiency and flexibility. These flexible and efficient power plants that Wärtsilä has branded as Smart Power Generation (SPG), can start in a minute and reach full load in less than 5 minutes with a simple cycle efficiency of close to 50%. This maximises the benefits of intermittent renewable energy while keeping the power grid stable. Combining SPG together with renewable energy like wind or solar, is one of the cheapest way of meeting the CO2 reduction targets while maintaining or even improving the grid stability.

6. Case 6.1 Background

Now let us illustrate the LNG to Power solutions discussed so far through a couple of fictive sites in South East Asia. We will compare different requirements and try to find the most optimal way to convert LNG to Power for that specific site. As an example we have taken a few site locations on the Indonesian islands. For each site we will propose the most cost effective LNG terminal solution and estimate the landed LNG cost. Then based on this landed LNG cost, we will calculate the price of electricity produced.

Figure 13. The case study with 4 fictive sites. The only real location is the Sengkang LNG export terminal, all other locations are made up for this case only.

16

6.2 The sites As per the map in Figure 13 we have selected 4 different sites. The main parameters of the locations are described below. Site 1: Medium size town (100,000 habitants) with basic industry and some tourism. LNG consumers:

1) 100MW power plant running at Pf =75% (average load 75MW) Will provide power for local village residents and industry

2) Various Industrial users: Site quality: Existing port with quay and small jetty with depth of 5 m, hard soil, closest residents >1 km, Marine data: 5- 10 m sea depth outside jetty, Harbour, some wind, minor swell

Existing navigational channel Other Infrastructure: The town has some construction companies and basic construction material available.

Site 2: Small village (5,000 habitants) with substantial and growing tourists business. LNG consumers:

1) 30MW power plant running at Pf = 33% (average load 10MW). Plant stopping at night, mainly there to follow the residential load

Site quality: Only sloped water front, depth of 2m, very soft soil, closest residents <1 km, Marine data: Only 2- 4 m sea depth 50 m out, well protected from wind, no swell Other Infrastructure: The village has nothing else than minor agriculture and tourist bars.

Site 3: Small town (30,000 habitants) with large tourist centre. Has a 30MW Solar Park. LNG consumers:

1) 60MW power plant running 3- 12 hours per day depending on the production from solar park. Following net load of hotel and local restaurants and service after solar production is extracted. Pf =33% (average load 20MW)

Providing power for tourist centre together with the 30 MW solar park. Load typically only in morning and evening. Site quality: Existing fishing harbour, quay with depth of 3m, very soft soil, closest residents <1 km, Marine data: 3- 8 m sea depth, heavy wind, some swell, existing breakwater Other Infrastructure: The town has some construction companies

Site 4: Large town (250,000 habitants) with minor industry but major tourist business. LNG consumers:

1) 120MW Power Barge running at Pf = 50% (average load 60MW) 2) Various Industrial users and services

Site quality: Existing port with small bulk carrier and fishing boat traffic, depth of 5m, very soft soil, closest residents >1 km, Marine data: 5-8 m sea depth, quite well protected from wind, no swell Other Infrastructure: The town has only minor construction companies with limited construction material available

17

Site Site 1. Medium size town (100,000 habitants) with basic industry and some tourism.

Site 2: Small village (5,000 habitants) with substantial and growing tourists business.

Site 3: Small town (30,000 habitants) with large tourist centre & 30MW Solar Park.

Site 4: Large town (250,000 habitants) with minor industry but major tourist business.

Power Need 100MW at 75%Pf 30 MW at Pf 33% 60 MW at 33% Pf 120 MW at 50% Pf

Power LNG Consumption

105,500 TPA 14,300 TPA 28,500 TPA 86,300 TPA

Other LNG Consumption

40,000 TPA (Industry) 5,000 TPA (Marine) 30,000 TPA (Industry)

Total LNG Consumption

145,500 TPA (27,800m3 /month)

14,300 TPA (2,730 m3/ month)

33,500 TPA (6,400 m3/month)

116,300 TPA (22,2000m3/month)

Table 1: Calculation of total LNG consumption in each site 6.3 LNG consumption LNG/Gas volumes constitute the basis for designing the optimal total solution and affects therefore the gas cost analysis. The total annual volume of LNG is a factor of power plant size, power plant load profile and other possible off-takers. As per Table 1, the total LNG consumption would be 145,500 + 14,300 + 33,500 + 116,500 = 309,600 TPA. The density of LNG we have assumed at 436 kg/m3, which means that the total volume is 710,255 m3 / year. To make a first evaluation of the logistics we have to assume a refilling rate. Storing LNG too long will change the quality of the LNG as the lighter hydrocarbons and nitrogen evaporate as BOG first. As all of these sites will have a steady consumption, the BOG can easily be utilized, but with a too long storage the remaining LNG in the tank will start seeing an increased heating value and reduced methane number. By refilling tanks with new LNG every 2nd week we can keep the BOG at a minimum and maintain a stable quality of the LNG. A two week storage is also quite suitable from inventory point of view. Based on a 2 week storage for each of these sites, the estimated refilling rate would be 710,255 / 365 x 14 = 27,240 m3 every second week. 6.4 LNG supply LNG needs to be sourced from somewhere where you can load a small scale LNG carrier. Based on the consumption above, we talk about a small scale LNG carrier of min. 27,240 m3 net capacity. The map below shows the small scale export terminals available and planned in South East Asia as of today. The closest terminal to these 4 sites is the Sengkang LNG plant and export terminal. Sengkang terminal is very well located for supplying LNG to these 4 sites. As an alternative Tangguh or even the Singapore terminals could be possible. The LNG FOB price at the Singapore terminal would probably be cheaper, but due to the longer distance we now assume for this case that Sengkang will give the best price of delivered LNG delivered to site. If the volumes would be larger, Singapore could be an interesting option. In reality all export terminals should be compared with the corresponding shipping routes.

18

Figure 14. LNG Terminals in the South Asia Region that will be able to receive small scale carriers below 80,000 m3 in the near future. For this case we have now selected Sengkang as the source for LNG. Based on the example in chapter 3.1 the FOB price is assumed to be: 9 USD/MMBtu (Valid for volumes of >50,000m3 / month) 6.5 Shipping We estimated the demand to about 27,240 m3 every 2nd week. We then have two options, either we could go with a 15,000 m3 carrier every week or a 30,000 m3 carrier every 2nd week. We quickly calculate that the second option will be a cheaper option as the LNG carrier will be able to serve other customers in-between and these sites will only be charged for the time they use the carrier. Based on these assumptions we decide to do the initial evaluation with a LNG carrier of 30,000 m3 doing the “milk run” 2 times / month. From Figure

15 below we estimate that the 30,000m3 LNG carrier chosen for this case will have a length of 175m, design draught of 8.5 m, design speed of 15,5 knots and fuel consumption of 25 TPD.

Figure 15. Main dimensions and draught requirement for various sizes of Wärtsilä standard LNG carriers.

19

We realize that most of the sites do not have enough draught to receive LNG carrier with an 8.5 m draught requirement in their current condition. To allow for this we need to have a harbour depth of min. 10 m. This means that extensive dredging will have to be done, especially on site #3. When comparing the cost of using a larger ship (30,000 m3) running less frequent plus the additional dredging vs. a smaller ship (15,000 m3) running more frequently the savings with using a larger ship is reduced. Anyhow, for this case we decide to go for the larger carrier despite a bigger design draught and go for additional investment in the dredging. One thing that favours this decision is that all of these sites will see an increasing LNG consumption in the near future. Also, in reality, carrier options are likely to be limited. Therefore it will be worthwhile planning the harbour & jetty for a slightly larger LNG carrier already now. For Site #2, it would not be possible to build a suitable harbour for a reasonable price, while the volumes are quite small, so there we can take the decision to arrange logistics with truck from Site #1.

Figure 16. Shipping logistics between the sites and the Sengkang terminal.

Table 2. Calculation of the LNG carrier utilization If we combine and cluster all of these sites, as per Figure 14, the total route will be 300 + 400 + 500 + 350 = 1550 km = 850 nautical miles. The average ship speed we have assumed to be

Transportation capacity / unit m3 of LNG 30 000

Lifetime 20

Transportation speed knots 15

Distance (roundtrip) nautica l mi les 850

Hours at Sea (roundtrip) hours 56.67

Round Trip Duration (hours) Laytime Loading Sengkang Unloading 4 sites Total

Loading (hours) - 14.00 20.00 34.00

Port Arrival (hours) - 4.00 6.00 10.00

Transportation time (at Sea/Road) 56.67

Total Hours Round Trip 100.67

Total Days Round Trip 4.19

Number of Trips / Year 23.68

Interval 15.42

Days in use 99.30

Days chartered 180

20

15 knots/hour. Loading 30,000m3 of LNG in Sengkang will take about 14 hour. Navigating in and out as well as berthing at the Sengkang terminal and will take about 4 h. Unloading the LNG at the 3 sites will take 8 h each for site #1 and site #4 as well as another 4 h for site #3. This means a total unloading time of 20 hours for all 3 sites. Navigating in and out of these 3 harbour sites will take 2 hours each or a total of 6 hours. Based on these assumptions, the route will take 56.7 hours and when including the average berthing & unloading time the total journey or “milk run” will take 100.67 hours = 4.2 days. In order to serve the 4 sites with their total consumption of 710,255 m3 / year with a 30,000m3 LNG carrier it will have to do a “milk-run” every 15.42 days. As the journey takes 4.2 days, the LNG carrier will in theory be able to serve other customers during those 15.4 – 4.2 = 11.2 days in between. The ship will be in use for these sites only 99.3 days per year. We have assumed that we can share the charter with another customer and only pay for 180 days per year. 6.6 LNG Terminal configurations An LNG terminal can be a major investment. The capital expenditure (Capex) is typically divided into: land, land preparation, storage tanks, re-gasification and other process equipment, re-distribution systems and marine and off-shore infrastructure. Sometimes the off-shore infra structure is the most expensive part and can be as much as everything else together. In those cases it can be worthwhile to look for another site. Always when possible the terminal should be established in connection with an existing harbour infrastructure to minimize the dredging, breakwater and jetty investments. On-shore the storage tank is often the major part of the investment. The parameters for determining the minimum tank size are: gas consumption, refill rate, LNG carrier size and minimum safety inventory and tank minimum reserves. The initial LNG inventory is also considered as part of the investment. In this case we have assumed a refilling rate of 2 times per month. The LNG carrier will do partial unloading at each of the sites. For matching the LNG carrier volume there is not one single site minimum tank size in this case, but rather the total combined tank sizes of all 4 sites has to be able to absorb the total cargo of the LNG carrier twice month. Site #1 tank will have to initially contain the need for site#2 which will be filled from Site #1. It is assumed that the bi-weekly consumption is in average almost 30,000 m3. Besides this each of the sites would like to keep a 7-10 days emergency inventory in case the LNG carrier would be up-held or that the consumption would momentarily be more than usual. Minimum tank size is calculates based on the 15.4 days refilling interval plus a 5- 10 day minimum reserve totalling 20.4 – 25.4 days of consumption. Finally we have included an 8% heel requirement i.e. the level that the LNG in the tank should never fall below. This secures the cryo-temperature (-160°C) in the tank at all times. Resulting minimum tank sizes can be found in Table 3 below.

Table 3. Calculation of the minimum LNG tank sizes

LNG Offtaker 1 LNG Offtaker 2 LNG Offtaker 3 LNG Offtaker 4 TOTAL

LNG offtake/year ton 145 458 14 292 33 583 116 338 309 671

m3 333 619 32 780 77 025 266 830 710 255

MMBtu 6 501 832 638 839 1 501 128 5 200 196 13 841 995

m3/ month 27 802 2 732 6 419 22 236 59 188

AVERAGE Consumption / day m3 914 90 211 731 1 946

Required minimum reserve days 10 5 7 7

Minimum storage size net m3 23 232 1 834 4 731 16 388 46 184

Heel requirement % 8% 8% 8% 8% 0

Minimum storage size gross m3 25 252 1 993 5 142 17 813 50 200

21

6.7 Initial configuration and financial modelling Based on the assumptions up to now, we will have the power plant solutions together with LNG terminal selection as presented in Table 4. below.





Power Need 100MW at 75%Pf 30 MW at Pf 33% 60 MW at 33% Pf 120 MW at 50% Pf

Power LNG Consumption

105,500 TPA 14,300 TPA 28,500 TPA 86,300 TPA

Other LNG Consumption

40,000 TPA (Industry) 5,000 TPA (Marine) 30,000 TPA (Industry)

Total LNG Consumption

145,500 TPA 14,300 TPA 33,500 TPA 116,300 TPA

Tank size Min. 25,300 = 30,000 m3

Min. 1,990 = 2,000 m3

Min. 5,140 = 5,000 m3

Min. 17,800 = 18,000 m3

Load Quite stable Daily on-off Un-regular, Varies a lot from day to day

Regular daily variation

Site type Hard soil Very soft soil Very soft soil Very soft soil

Harbour Existing jetty with 5-10m depth

Jetty not available, 2-4 m depth

Existing harbour 3-8m depth, no jetty

Existing fishing harbour 5-8m depth

Local Infra Good availability Good 50 km away. Not available, Tourist centre only

Some availability

Proposed power plant

100MW Flexible Baseload Gas Plant (6 x 18V50SG)

30 MW flexible Gas Plant (3 x 20V34SG)

60MW peaking plant (6 x 20V34SG)

120 MW Power Barge- Flexible Gas plant (12x 20V34SG)

Proposed Tank size

30,000 m3, Flat bottom, full containment.

2 x1,000 m3 Pressurized steel tank Tapping from Site 1, with Truck

5 x 1,000 m3 pressurized steel tanks

18,000 m3 , LNG storage and re-gasification barge

Site work Major, preparing on-shore for heavy construction. Utilizing existing jetty with some dredging to 10 m.

Minimal, prepare site for light constructions only. No off-shore activities

Minimal on-shore preparation. Light construction only. Extensive off-shore work with extension of jetty and dredging to min 10m.

Minimal on-shore preparation. Light construction only. Extend jetty out and dredging to min 10 m.

Table 4. The initial configuration and main parameters like power & gas consumption and site infrastructure

With the reasonable technical solutions proposed we can move into the first round of economic modelling with the economic parameters as described in next chapter. The modelling was performed in two steps. First we estimated the landed price of LNG starting from the FOB price showing the “add on price” for each step in the LNG value chain. This estimate was performed for all 4 sites which all had different type of site infrastructures and therefore ended up with totally different terminal solutions. Regarding shipping, site #3 is furthest away and site #2 doesn’t have an own sea access but taps LNG of the terminal at site #1. Next we took the landed LNG price converted into gas at the power plant inlet and performed another calculation to find out the price of electricity based on this price together with the site specific power plant performance parameters, investment and operation cost.

22

Figure 17. Example of an on-shore 100 MW power plant with dedicated “Single Purpose” LNG terminal.

6.8 Financing assumptions Construction period is estimated at 12 months for each of the projects except site #1, where we estimated 24 months due to the large 30,000m3 site built flat bottom concrete tanks. The power plants can in these cases be built faster than the terminals and will therefore not be on the critical path. The project lifetime is estimated to 20 years, which is used for calculating depreciation. Weighted average cost of capital (WACC) is calculated as 7.5% based on a 75% loan and 25% equity financing, where the loan interest rate is 5% and Return on Equity (ROE) is set at 15%. 6.9 LNG “add on costs” The “add on costs” of LNG starting from the FOB price to power plant inlet price is derived from the following factors and summarized as USD/ MMBtu and shown in Table 6. Shipping cost In the case, shipping was provided directly by a shipping company that could arrange a carrier that was not dedicated to this cluster only, but can also serve other customers in-between. The charter rate is estimated to 35,000 USD / day and the ship is in operation only 96 days / year. By sharing the carrier with another client we only pay for 180 days per year. The carrier sailing time at design speed is 56 days/year while total time in operation is 96 days/year. Annual fuel consumption is calculated on 56 days at design speed with a fuel consumption of 25 TPD plus the additional fuel consumed while operating in the harbours. This totals 1500 ton LNG per year valued at 780,000 USD/year. The port charges for Sengkang are assumed to 25,000 USD/berthing. With all of this plus a number of other minor costs involved, the total cost of shipping ends up at 8 MUSD / Year. This is then split between the sites/clients based on their share of the total distance. (See Table 5)

Site #1 350 / 350+300+(350+400) 25.9%

Site #2 Not included as they buy LNG from site #1 0%

Site #3 (350+400) / 350+300+(350+400) 51.8%

Site #4 300 / 350+300+(350+400) 22.2% Table 5: The Logic for sharing the shipping costs between the sites.

23

LNG Terminal & Jetty including Civil works (CAPEX total) For the terminal we have split the cost between the terminal top side (mainly process equipment and tanks) and the civil works for both the on-shore and off-shore work. With a problematic site or sea shore, the cost of the civil work can be more than the terminal top side. Therefore it is important to select a site with good soil bearing capacity and an existing harbour protected from winds and with draught enough for the intended ship size. Sometimes it is not possible to choose the perfect site. In these cases it is important to adapt the terminal solution to the site. As an example, site 4, which in this case has very bad soil bearing capacity and would have needed extensive piling or soil exchange, an off-shore solution, that is not dependent on the soil quality, will be a much cheaper option. Total cost is the combination of the terminal top-side, the civil work related to the terminal and jetty and an assumed 5-10% development fee. Working capital for LNG inventory As basis for the working capital invested in LNG we have assumed the volume of the LNG carrier of 30,000 m3 split on the 4 sites based on their share of the total system tank capacities. LNG terminal operating costs (Terminal OPEX, including possible BOG losses) Operational expenditure (OPEX) is made up of manpower costs and maintenance costs. The manpower needed in terminals of various sizes is more or less the same for the basic operation. There could be some synergies between the terminal operations and power plant operations, especially in control and monitoring functions. This is particularly true when the terminal and power plant are located at the same site. Annual maintenance costs depend on the size and capacity of the terminal. We have assumed that maintenance cost for these facilities is around 2% of the terminal top side investment cost per year. In these sites there will be no BOG losses as all of these power plants will have a steady consumption of gas. Site #3 has the most un-regular consumption profile, but in this case we use a pressurized tank that can withhold BOG for up to 30 days.





CAPEX LNG terminal

75 MUSD 30,000 m3, Flat bottom, full containment.

6 MUSD 2x 1000 m3 Pressurised Steel tank tapping from Site 1, with truck

12 MUSD 5 x 1000 m3 Pressurised Steel tank

50 MUSD 18,000 m3 , LNG-Storage & Re-gas Barge

CAPEX Civil work: Terminal and Jetty

40 MUSD Major, preparing on-shore for heavy construction. Utilizing existing Jetty with some dredging to 10 m.

1 MUSD Minimal, Prepare site for light constructions only. No off-shore activities

15 MUSD Minimal on-shore preparation. Light construction only. Extensive off-shore work with extension of Jetty and dredging to min 10m.

20 MUSD Minimal on-shore preparation. Light construction only. Extend Jetty out and dredging to min 10 m.

24

Investment in 14 days of LNG reserve

2,24 MUSD 0,28 MUSD 0,51 MUSD 1,79 MUSD

Development fee:

10 MUSD 1 MUSD 3 MUSD 7 MUSD

Interest during construction

5,06 MUSD (24 months)

0,15 MUSD ( 12 months)

0,56 MUSD ( 12 months)

1,44 MUSD ( 12 Months)

CAPEX Total 131,9 MUSD 8,4 MUSD 31,1 MUSD 80,2 MUSD LNG “add on costs” contribution in USD/MMBTU.

(Excluding all taxes and import duties) LNG FOB 9 11,55 9 9

Shipping 0,33 0,64 (Truck) 2,82 0,35

Terminal CAPEX fee

1,99 1,29 2,03 1,51

LNG in tank CAPEX

Incl. in above Incl. in above Incl. in above Incl. in above

Terminal OPEX 0,23 0,19 0,16 0,19

Cost of Gas at PP inlet

11,55 13,67 14,01 11,05

Table 6: LNG “add on costs” based on terminal investment & operating costs, LNG Inventory and logistics from export terminal to receiving terminal.

6.10 Cost of electricity produced by the power plants Below we list the estimated EPC costs for the various power plants including the civil work and possible soil preparations. We have used Wärtsilä power plants typical values for efficiency and operating cost, showing their impact on the price of the produced electricity. The basic assumption is that the jetty, terminal facilities and power plant systems are located in the same area. This will be very effective when the entire project is being executed under a single EPC contract, allowing both LNG terminal and power plant to be constructed in parallel to shorten overall construction time. The cost of fuel which is the biggest cost contributor, especially in baseload power plants, is then calculated based on the power plant efficiency and the gas price at power plant inlet from Table 7: The average power output is the actual electricity available for sale after the high voltage transformer at the point of connection to the purchaser’s electrical grid. As these plants run at a variable load, depending on their power purchase agreement and actual demand from the grid, this is then converted into an annual average load. Power plant average efficiency (average fuel consumption) is also adjusted to the same operational conditions with lot of efficiency losses coming from start and stops and part loading. Total power plant CAPEX Total power plant investment comprises the EPC contract value, mobilisation costs and other up-front costs, such as project development, land purchase and connection costs. Power plant operating costs (OPEX) The biggest operating cost is fuel. Other operating costs are lube oil consumption along with variable and fixed operation and maintenance (O&M) costs. Wärtsilä combustion engines typically consume around 0.3 g/kWh of lube oil during operation. Lube oil typically costs around 1.50 USD/litre.

25

Variable O&M cost for these type of plants are around 6 USD/MWh; including consumable spare parts and manpower for service activities and operation. Fixed O&M cost which includes operators and administrative duties at the plant is between 0.5 – 1.2 MUSD dependent on the size, operational requirements and automation level of the plant. Table 7 shows the weight of each of the elements of the final electricity sales tariff including the share of the 15% ROE requirement.

Site Site 1. Large town with basic industry and limited tourism

Site 2: Small village with growing tourists business.

Site 3: Village and growing tourist centre with Green image and solar park.

Site 4: Large town with some industry and limited tourism.

Total power plant CAPEX (Incl. mobilisation cost, but excluding land purchase and grid connection costs)

80 MUSD 100MW Flexible Baseload Gas Plant (6 x 18V50SG)

28 MUSD 30 MW flexible Gas Plant (3 x 20V34SG)

50 MUSD 60MW peaking plant (6 x 20V34SG)

105 MUSD 120 MW Power Barge- Flexible Gas plant (12x 20V34SG)

Development cost 10 MUSD 4 MUSD 7 MUSD 10 MUSD

Annual Power Factor (PF)

75% 33% 33% 50%

Power plant average

net heatrate

(efficiency) as new.

7800 kJ/kWh (46.2%) Stable full load most of the time, only weekly start and stop)

8200 kJ/kWh (43.9%) (Part loading + daily staring & stopping)



Lifecycle aging factor 1% 1% 1% 1%

Fixed costs USD/Year 1,0 MUSD 0,5 MUSD 0,75 MUSD 1,2 MUSD

Electricity tariff calculation USD/MWh

(Excluding grid connection costs, all taxes & import duties)

Fuel cost (from table 6)

86,25 107,32 109,99 85,69

PP CAPEX fee 6,31 16,99 15,14 10,08

PP fixed share 1,52 5,77 4,32 2,28

PP variable OPEX 6,53 6,53 6,53 6,53

ROE 5,21 14,04 12,51 8,33

Total cost of Power 105,83 150,65 148,48 112,91 Table 7: Price of electricity derived from power plant investment, operating & fuel costs.

26

7. Conclusion When planning an LNG to Power project, it is important to understand how the whole LNG logistics and value chain will affect the final cost of power. To illustrate the process and the alternative solutions we have taken a few different type of requirements and site locations where we aim to convert LNG to Power in the most optimal way. The study shows that the cost of produced electricity can be kept at a reasonable level by careful selection of the site. A good site should have existing structures that can be utilised – e.g. harbour facilities, deep enough water for LNG carrier access, existing industrial area making development and construction easier, good land access and a location with good soil bearing capacity. All of this will help reduce the initial infrastructure investment. After selecting the site it is important to choose the most optimal solution based on the conditions at the site. The landed cost of LNG can be drastically reduced by clustering together several consumers and thereby increasing the volumes. This allows for better purchasing price and using larger sized LNG carrier which is reducing the specific shipping costs. Looking at the fuel cost the purchase price of LNG has the biggest impact and it is worth shopping around to find the cheapest supplier. The terminal investment cost has also quite a big impact on the final cost. The shipping component of the cost may contribute to an even bigger part of the final LNG cost, unless it is well planned. In this example, however, we managed to plan ideal logistics by clustering 4 sites together sharing the same carrier. This resulted in a very low shipping component. Then regarding the final electricity tariff, it can be seen that fuel cost dominates the tariff in the plants with a high power factor, while the fixed costs are almost neglectable. In a power plant with a low power factor (for example peaking plants or renewable energy followers), the CAPEX and fixed costs play a much bigger role.

Table 8: Graphical illustration of the price of electricity for the 4 different sites.

27

END OF PAPER.

Documents

Contents...There are both on-shore and off-shore solutions available for the LNG receiving terminals today. As for the LNG terminals, the power plants can also be built on-shore or