CYPRUS NATURAL GAS EVALUATION ALTERNATIVES

Transcription

1 CYPRUS NATURAL GAS EVALUATION ALTERNATIVES A Report Prepared By: Prof. Dr. Tahir ÇELİK & Ali POURBOZORGI For submission to the authorities of Turkish Republic of Northern Cyprus Gazimağusa April 2014

2 Preface Discovery of natural resources can change the financial and political climate for any country. This is especially true if monetizing such resources is carried out with much dedication and care. Decision making should therefore be based on alternative evaluations on a set of possible solutions so that, the most suitable option can be chosen for further project definition. Apart from the domestic consumption and its corresponding generated revenue, the majority of revenue is made through export. Especially in the case of Cyprus, exporting the natural gas to the European market would prove to put Cyprus into a strategically important position. This pertains to natural gas discoveries in Exclusive Economic Zone (EEZ) of Republic of Cyprus as well as any future discoveries in the territorial waters of Turkish Republic of Northern Cyprus. The aim of this report is to evaluate 4 different options for exporting Cyprus s natural gas - regardless of how the political issues between the Greek Cypriots and the Turkish Cypriots are tackled from the Life Cycle Cost Benefit (LCCBA) perspective. These options are: - LNG (Liquefied Natural Gas) - CNG (Compressed Natural Gas) - Pipeline - GtW (Gas to Wire) The current status of Cyprus natural gas reserve according to U.S. based Novel Energy Company is at 3.1 Tcf obtained from exploration in block 12 of Aphrodite field in the Republic of Cyprus EEZ (Cyprus-Mail, 2014). And therefore all analysis in this report will be based on the aforementioned manifested estimate amount of reserves. i

3 Table of Contents Preface... i Table of Contents... ii Table of Figures... iv List of Tables... v Glossary of Acronyms and Abbreviations... vi 1. Introduction Aim of the Study Project Development Options Alternatives Analysis and Comparison Methodology Limitations Assumptions Objectives Natural Gas Perspective Global Perspective of Natural Gas Global Reserves of Natural Gas Conventional Natural Gas Reserves and Supply Unconventional Natural gas Resource and Development Impacts on Global Prices of Natural Gas European State of Natural Gas Import Turkey s State of Natural Gas Import Cyprus s State of Natural Gas Cyprus-Israel cooperation Liquefied Natural Gas Properties of LNG Current Status of LNG Plant Cost LNG shipping Costs Compressed Natural Gas Properties and technology of CNG Input Data for LNG and CNG General Input Data Economic Indicators Plant Construction Costs Shipping Costs ii

4 5.5. Summary of Input Data Data Analysis for LNG and CNG Ships Export Capacity and Revenue Capital Cost (CapEx) Operation Cost (OpEx) Capital Repayment Life Cycle Cost Life Cycle Benefits Life Cycle Net Benefit Analysis The Net Present Value (NPV) Internal Rate of Return (IRR) Cost Benefit Ratio (CBR) Sensitivity Analysis Total Life Cycle Cost-Benefit Analysis Pipeline Pipeline Overview Seismic Map of the eastern Mediterranean Data Analysis for Pipeline to Turkey via Cyprus Calculation Scenarios Scenario Results Life Cycle Cost Benefit Analysis (LCCBA) for Pipeline Gas to Wire (GtW) Export price of Electricity in EU Electricity Production from Natural Gas Revenue and Cost Calculations Calculation of Revenue Life Cycle Cost Benefit Analysis for GtW Discussion and Conclusion Discussion Financial Aspect Non-Financial Aspect Conclusion References iii

5 Table of Figures Figure 1: Natural Gas export possibilities... 2 Figure 2: Natural Gas Constituents... 4 Figure 3: Global Supply and Demand for Natural Gas... 5 Figure 4: Global Shale Gas Reserves... 6 Figure 5: Gas Price Development... 7 Figure 6: EU 27 natural gas suppliers Figure 7: European import trend forecast... 9 Figure 8: Turkey pipeline layout Figure 9: Levant basin Figure 10: Cyprus EEZ and Field Blocks Figure 11: Cyprus s Gas Fields Exploration Companies Figure 12:LNG Onshore Facility Cost Breakdown Figure 13: LNG, Gas to Gas Capital Cost Share Figure 14: LNG Vessel Costs Figure 15: Ideal Transportation Means Figure 16: CNG Loading-Unloading Buoy Figure 17: CNG Value Chain Cost Share Figure 18: Value Chain of CNG vs. LNG Figure 19: Ideally Suited Regions for CNG Application Figure 20: Cumulative Life Cycle Costs Figure 21: Present Value of Life Cycle Costs Figure 22: Cumulative Life Cycle Benefits Figure 23: Present Value of Life Cycle Benefits Figure 24: Life Cycle Net Benefits Figure 25: Net Present Value Figure 26: Internal Rate of Return Figure 27: Cost Benefit Ratio Figure 28: Eastern Mediterranean Seismic map Figure 29: Seismicity map of Cyprus Figure 30: Eastern Mediterranean Gas pipelines Figure 31: Pipeline Segments Wellhead to Turkey Figure 32: Pipeline quick sizing procedure Figure 33: NPV of all alternatives Figure 34: Basins in the proximity of Cyprus, source: EIA iv

6 List of Tables Table 1: EU Average estimated import shortfall... 9 Table 2: LNG Projects Capital Expenditure Table 3: CNG Value Chain Cost Table 4: Input Data Table Table 5: Vessel Capacity, distance and speed Table 6: Travel, Loading, Unloading and Contingency Time Table 7: Total Delivery Time per Scenario and Generated Revenue Table 8: Total Gas Reserves Required during the Operation Period (for export) Table 9: Reserves, Export, Consumption Table 10: LNG CapEx Table 11: CNG CapEx Table 12: LNG OpEx Table 13: CNG OpEx Table 14: Sensitivity Analysis: Discount Rate and Change of NPV Table 15: Sensitivity Analysis: Natural Gas Price Variation and Change of NPV Table 16: Sensitivity Analysis: Construction Cost Variation and Change of NPV Table 17: Total Life Cycle Cost-Benefit Analysis Table 18: Scenario Table 19: Scenario Table 20: Scenario Table 21: Scenario Table 22: Scenario Table 23: Scenario Table 24: Summary of all Scenarios Table 25: Life Cycle Costs and Benefits (pipeline) Table 26: Input data of electricity generation Table 27: Electricity generation revenue Table 28: LCCBA of GtW Table 29: Alternatives NPV & IRR v

7 Glossary of Acronyms and Abbreviations Used Bbl Bcf Bln. BTU CapEx cf CNG LNG Mln. MMBtu MMcf MMcfa MMcfd MMcm MMscf mtpa Mwh OpEx Tcf Meaning Barrels of oil Billion Cubic Feet Billion British Thermal Unit Capital Expenditure Cubic Feet Compressed Natural Gas Liquefied Natural Gas Million Million British Thermal Unit Million Cubic Feet Million Cubic Feet per Annum Million Cubic Feet per Day Million Cubic Meters Million Standard Cubic Feet Million Tons per Annum Mega Watt-Hour Operation Expenditure Trillion Cubic Feet Unit Conversions 1 barrel of oil 5,800 cubic feet of natural gas 1 cubic meters 35.3 cubic feet 1 cubic meters CNG 200 cubic meters of natural gas 1 cubic meters LNG 600 cubic meters of natural gas 1 knot (speed) km/h 1 MMBtu 1,000 cubic feet 1 MWh MMBtu 1 Quadrillion 1000 trillion 1 cf of natural gas 127 kw 1 ton of LNG cubic meters of LNG vi

8 1. Introduction 1.1. Aim of the Study The aim of this study is to evaluate Cyprus s options for exporting its newly found natural gas under current estimated amounts of reserves. The evaluation is carried out from life cycle cost benefit analysis perspective. Recent discoveries off the coast of Cyprus have the potential to open a new era in the island s peace talks between Greek Cypriots and Turkish Cypriots. In this regard, the export of natural gas will help to boost the economy of the island as a whole and put Cyprus into a strategically important position - especially with the EU - with more focus on the on-going political conflict between Russia and Ukraine. Therefore, Cyprus s natural gas monetization would have both internal and external effects in multiple areas such as geopolitics of both governments within Cyprus and that of EU-Israel- Turkey-Greece relationship; which consequently contributes and increases the sensitivity of the subject. Although a new report from the International Crisis Group (ICG) suggests two independent states (ICG, 2014), it may be more advantageous for Cypriots to reach to a final settlement of Cyprus problem as a virgin united federal state as member of EU to attain the maximum affluence for them. However, plans should be developed based on both current and new discoveries and estimates for oil or gas reserves falling into the land and territorial waters of entire island of Cyprus. The majority of the natural gas can be exported resulting in a considerable cash flow into the economically weakened island as well as mitigating a large portion expenditure on fuel imports. These all emphasise on the importance of having a clear overview of the possible options and their financial contribution and requirements. Furthermore, although the analysis conducted in this report pertain to Cyprus they can be applied to entire Eastern Mediterranean region Project Development Options There are several generic alternatives for exporting the natural gas (see figure 1) out which Liquefied Natural Gas (LNG), Compressed Natural Gas (CNG), Pipeline and Gas to Wire (GtW) are chosen for further analysis in this report although other measures can be pursued in later stages and which would depend on the industry development on the island of Cyprus. 1

9 Figure 1: Natural Gas export possibilities, source: Thomas and Dawe (2003) 1.3. Alternatives Analysis and Comparison Methodology Life Cycle Cost Benefit Analysis (LCCBA) is a method through which total cost of ownership including acquisition, operation and decommissioning costs as well as life cycle benefits can be assessed. LCCBA is extremely useful especially when alternatives fulfilling the same overall results with different acquisition and operation costs are to be evaluated. Using LCCBA; Net Present Value (NPV), Internal Rate of Return (IRR) and other appropriate financial indicators can be calculated (NSW-Treasury, 2004;Fuller, 2010;Stanford, 2005) Limitations This report is constructed for preliminary estimation of each alternative and therefore a deviation of approximately from +/- 10% to +/-50% should be allowed for all calculations. Results of this report are to be used for the sole purpose of project selection from a pool of alternatives; those projects which qualify for further processing should be investigated with more accurate data at detail activity level. The cost of onshore / offshore natural gas processing plant are omitted from this report as the aim is to illustrate export options and not the whole of the value chain. Nonetheless the cost for extraction and wellhead processing plant should be almost the same for all options Assumptions For the purpose of this report certain financial parameters were assumed. These assumptions are: discount rate at 12%, prime commercial lending rate at 7%, Project life 20 years, 2

10 inflation rate (CPI) at 2.59% per year (uniform) and the initial capital is obtained from a loan and hence a debt where no equity is involved Objectives In fulfilling the aim of this report, it is first important to evaluate some other aspects rather than solely the financial matters. Therefore the following objectives are constructed and met by the end of this report. 1- Evaluating global, European, Turkish and Cypriot natural gas perspective and stand. 2- Evaluating different technologies for transportation of natural gas. 3- Obtaining financial indicators either through calculations or from the publications. 4- Calculating the life cycle costs and befits for each option. 5- Squaring the financial results with other findings such as market positions, competitions, etc. 6- Recommending the best and the second best possible options for Cyprus natural gas export. 3

11 2. Natural Gas Perspective 2.1. Global Perspective of Natural Gas Natural gas in its purest form (the form delivered for consumption or pipe-line quality) consists almost only of methane (CH 4 ). However, when raw and freshly extracted from the wells as it is shown in figure 2, it is a combustible hydrocarbon gas mixture of predominantly methane, ethane, propane and few other gasses in addition to water and other impurities (Durr et al. (2005). Deposits of natural gas can be found in depths of approximately 2000 meters below the ground, that is, in case of offshore explorations, the depth of the water plus ~ 2000 meters. This makes exploration a very costly, dedicated and precise job. Once the gas is found and proven, it is then transferred through pipeline to a plant for further processing. Figure 2: Natural Gas Constituents, source: Durr et al. (2005) When raw natural gas is initially collected from a well, before it goes to a processing plant, free liquid water and gas condensate are removed. After natural gas arrives at the processing plant, it has to be further processed to meet pipeline quality requirements. While processing the natural gas, several by-products or so-called natural gas liquids or NGLs can be obtained (Tobin et al., 2006) Global Reserves of Natural Gas Natural gas reserves are classified in two categories; conventional and unconventional. Conventional reserves are those that can be found in deep underground buried layers whereas 4

12 unconventional reserves are those which can be found trapped in shale or coal beds and for extracting them, more technical expertise are required (Naturalgas.org, 2011;CAPP, 2013). According to International Energy Agency (IEA) quoted in ExxonMobil s the outlook for energy 2013, there are globally 28,000 Tcf of conventional and unconventional both proven and estimated reserves of natural gas out of which there are 6,800 Tcf proven conventional and 7,300 Tcf proven unconventional technically recoverable reserves exist. This is believed that at the current consumption rate, this would be enough to meet the global demand for at least the next 100 years (ExxonMobil, 2013;EIA, 2013c) Conventional Natural Gas Reserves and Supply According to the U.S. Energy Information Administration (EIA), British Petroleum (BP) and ExxonMobil in their latest outlook and review of the world energy from 2012 to 2040, the proven conventional natural gas reserves of the world in 2013 is around trillion cubic meters or 6,800 trillion cubic feet (Tcf) with Iran and Russia holding the largest amount of reserves with combined amount of almost 30% of total world reserves (BP, 2013;EIA, 2013e;ExxonMobil, 2013). There are nonetheless, around 2200 Tcf of stranded reserves from this total of 6,800 Tcf (Economides and Mokhatab, 2007). The global productions and consumptions of natural gas in billion cubic meters from 1987 to 2012 are illustrated in Figure 3. Figure 3: Global Supply and Demand for Natural Gas, source: BP (2013) 5

13 Unconventional Natural gas This is the natural gas trapped in shale, coal beds, etc. According to U.S. Energy Information Administration (EIA) there are about 7,300 Tcf proven and technologically recoverable shale natural gas resources in the world with China at the top place. This is almost equivalent to proven conventional natural gas reserves of the world (EIA, 2013g). Moreover, it is expected that unconventional natural gas will have a 40% share of total global supply by 2040 (ExxonMobil, 2013). A global geographical map of shale gas reserves is shown in figure 4. Figure 4: Global Shale Gas Reserves, source: A.R.I. (2013) & EIA via Reuters Resource and Development Impacts on Global Prices of Natural Gas Traditionally gas price was interrelated with the price of crude oil, but since 2008 when the gas prices fell while oil prices raised, a new hypothesis started to emerge for how to determine the gas prices in volatile and unstable markets. A fairly sound set off hypotheses were proposed by Asche et al They proposed two hypotheses, first one indicated that gas prices are determined by supply and demand which is more valid for short terms and the second one is that since the demand is primarily for energy and price of substitutes have considerable effect on the price of natural gas (Asche et al., 2012). Considering the supply and demand pricing schema, Asian pacific is currently offering the highest, North America 6

14 the lowest and Europe the middle purchase price for natural gas as shown in see figure 5 (BP, 2013). This is well justified since North America has produced Bcf or 98.8% of its 906 Bcf domestic demand in 2012 whereas Asia pacific (including Australia) has produced Bcf or 78.4% of its 625 Bcf of consumption (EIA, 2013f;BP, 2013). Figure 5: Gas Price Development, source: BP (2013) This indicates two important factors of distance and reserves for pricing of the natural gas. Mainly due to maturity of North America s conventional and unconventional gas exploration and processing industry while Asia Pacific s industry is still (with exception of Australia) underdeveloped, (Aguilera et al., 2013). The second hypothesis can also be verified for the same region as alternative energy sources are more abundant in North America than Asia Pacific. This is especially important when looking at shale gas developments in the U.S. versus China; although China is thought to have larger shale gas reserves, it is still not technologically capable of fostering its resources (ExxonMobil, 2013). Furthermore, an agreement between the U.S. and Japan, who is one of the largest gas consumers in Asia pacific, to supply Japan with it shale gas will further influence the prices of conventionally exploited natural gas in terms of alternative availability impact (Wakamatsu and Aruga, 2013). Moreover, the impact of France and Poland shale gas exploration as an alternative source will significantly influence the European price of natural gas in the near future (Asche et al., 2012). It is further expected that the demand for energy will increase from 542 7

15 quadrillion BTUs in 2010 to 820 quadrillion BTUs in 2040, out of which 85% occurs in developing nations outside OECD with a natural gas share of 70% of the total (EIA, 2013d). Abundance of natural gas as well as low environmental pollution among the other forms of fossil fuel has tremendously contributed to widespread use of this resource. It is estimated that global gas supply will increase 65% by 2040 and also natural gas will overtake coal by 2025 to be the second most consumed fuel after oil (ExxonMobil, 2013). The annual consumption of natural gas is expected to increase from 113 Tcf in 2010 to 185 Tcf in Tight gas, shale gas and coal bed methane will also account for 80% of Canada and China s domestic production by 2040 (EIA, 2013d) European State of Natural Gas Import Europe as one of the largest consumers of energy is dependent on import of fossil fuels from various parts of the world. Europe (EU27) consumed 16,612,000 Terajoules of natural gas equivalent to Tcf annually or 43 Bcf per day in 2012, from which 9 Tcf was imported from Russia, Algeria, Qatar and Nigeria (as shown in figure 6) accounting for almost 58% of total import (Eurostat, 2014;Belkin et al., 2013). Figure 6: EU 27 natural gas suppliers, source: Eurostat 2014 Furthermore, European import for natural gas is according to the report by MacDonald is on an increasing trend. That, in combination with the decreasing trend of European natural gas 8

16 production (excluding future possibility of shale gas extraction in France and Poland), would mean that EU needs to find additional sources to meet its natural gas demand (MacDonald, 2010). Figure 7: European import trend forecast, source: MacDonald (2010) According to the same report, EU needs to import an average additional 74 bcm (2.6 Tcf) by 2020 to fulfil its needs (see table 1). This opens a window of opportunity for Cyprus natural gas export. Table 1: EU Average estimated import shortfall, source: MacDonald (2010) Primes Reference bcm 15 bcm 35 bcm Eurogas Environmental bcm 133 bcm 218 bcm Average 0bcm 74 bcm 126 bcm 2.3. Turkey s State of Natural Gas Import Due to rapid economic growth in Turkey, like many other resources, the demand for natural gas has increased tremendously from approximately 14.4 bcm per year in 2000 to 45.3 bcm per year in This is equivalent to 4.37 Bcf per day of natural gas import (EIA, 2013b;IEA, 2013) although Turkey has 0.63 Bcf domestic production of natural gas per year, to fulfil its domestic needs it must still rely more than 98% on import. 9

17 Due to Turkey s Geographical location, it has been a hub for supply of natural gas (as well as oil) to central Europe. The national transmission pipeline in Turkey is operated by Botas and is approximately 9,500 km. Turkey has 4 international pipelines with a total capacity of 46.6 bcm per year as well 2 LNG terminals. The total lay out of pipelines and LNG terminals are shown in figure 8. Figure 8: Turkey pipeline layout, source:iea (2013) As illustrated in figure 8, there are neither import terminals nor a major import pipeline in the south and southwest regions which offers an exclusive opportunity for Cyprus in terms of exporting its natural gas to Turkey. 10

18 2.4. Cyprus s State of Natural Gas For the past decades much of hydrocarbon resources in the Mediterranean Sea region were undiscovered mainly due to ultra-deep-water (1,500+ meters) location of resources. Recent technological innovations and advancements in combination with high prices of hydrocarbons directed attentions towards discovery of such resources (Gürel et al., 2013). In 2007, the government of Republic of Cyprus (RC) began investigations for hydrocarbons explorations in its Exclusive Economic Zone (EEZ) through international tender for hydro carbon exploration offering the option for exploration of most of its 51,000 sq. kilometres of EEZ. In 2011 Novel Energy, a U.S. based company found natural gas in block 12 of RC s exclusive economic zone waters. The exploratory well initially revealed an approximate amount of 5-8 Tcf (NaturalGasEurope, 2013;Gürel et al., 2013). However, later on December 1 st, 2013 the Israeli based company, Delek Drilling and Anver Oil Exploration claimed that new data showed lower amounts than estimated to 4.1 Tcf, equal to 0.063% of global conventional reserves (Reuters, 2013) and later on January 3 rd 2014 the amount of possible and recoverable reserves were lowered to 3.1 Tcf by Nobel Energy (Cyprus-Mail, 2014). Levant basin located at the east of Mediterranean (figure 9) falls partly into Republic of Cyprus s EEZ (Aphrodite field) in which RC is hoping to find substantial reserves of gas and oil. Political impacts of RC s natural gas discoveries and development for Europe can be substantial as for the first time ever Europe can use the opportunity to decrease supply dependability on Non-EU regions such as Russia and the Middle East (DefenceGreen, 2011). Apart from exploration s options and extraction possibilities, the issue of how to link these resources to markets has been the topic for many on-going debates. A widely, by far accepted economical solution by experts, is the pipeline to Turkey. Although this is an attractive and beneficial solution, due political complications is unlikely to be realised at this stage (Gürel et al., 2013;Paltsev et al., 2013). There are a set of remaining options as explained before, however the most attention receiving solutions are: Liquefied Natural Gas (LNG) and Compressed Natural Gas (CNG) with a recently emerging GtW (Gas to Wire) possibility through Eurasia interconnector underwater electricity cable project from Israel to Greece via RC (Cyprus-Mail, 2013b).. 11

19 Figure 9: Levant basin, source: EIA (2013a) According to U.S. Energy Information Administration (EIA) and U.S. geological survey the Levant basin (figure 9) should hold around 1.7 billion barrels of oil and 122 Tcf of natural gas. The Levant basin is shared between a few countries at the Eastern Mediterranean i.e. Cyprus, Israel, Palestine, Lebanon, Syria and Turkey. Explorations are currently underway and more exploration options are being negotiated (Famagusta-Gazette, 2013) and although the preliminary estimation for RC natural gas reserves is currently at 3.1 Tcf, but considering exploration of all 13 blocks (see figure 10) should greatly increase this number. 12

20 Figure 10: Cyprus EEZ and Field Blocks, source: Yalibnan (2012) The Aphrodite gas field (in block 12) is located approximately 100 km from the shore of Cyprus and 1700m below the sea level. The RC has so far issued several exploration licenses to some major international companies for gas exploration in different blocks of its gas fields as shown in figure 11. Figure 11: Cyprus s Gas Fields Exploration Companies, source: Paltsev et al. (2013) 13

21 From geopolitical point of view the Island of Cyprus is located favourably with Europe, Middle East and Africa in a very close proximity. For the Republic of Cyprus (RC) - or if the solution is reached between the two sides of Greek Cypriots and Turkish Cypriots, for the whole island - this discovery is significant since the Island is firstly, dependent on imports of fuel and second, due to recent financial crisis, generating revenue and increasing the national GNP would ensure the stability of the country from financial point of view. An interim report by Massachusetts Institute of Technology (MIT) suggests that even if RC converts most of its industry to gas it will still have enough resources to export (Paltsev et al., 2013). This might be lucrative if export options are considered wisely. RC imported approximately 67,000 of oil barrel equivalent per day of oil and gas in 2012 (EIA, 2013a) At the conversion rate of 5.8 in terms of BTU this would equal to almost 140 Bcf of natural gas per year. The latest statement from the RC government indicates the need for approximately 31 Bcf (~0.88 bcm) per annum of natural gas from 2016 to 2022 (Cyprus-Mail, 2013a). However, two major factors need to be taken into account; the first is that it would be almost impossible to convert an entire economy to gas and second is the possibility of unification of both sides (North and South) which would ultimately increase the consumption / demand. Evaluation of export options for RC has been a major topic since its discoveries and different suggestions have arisen from different reports, however since this is an unfolding issue results continue to change by each new discovery data. A group of researcher jointly from Massachusetts Institute of Technology (MIT) and Cyprus institute are conducting an extensive research on this issue. Their initial result showed that, the favourable option for export was LNG at an estimated mean reserve of 7 Tcf, but the final remarks stated as half of it (Paltsev et al., 2013). A second report from The German Marshall Fund of the United States, has evaluated the options for RC where the option of LNG has been viewed as an optimistically way of looking at export options, mainly due to high costs and low reserves (Henderson, 2013). RC has already shown their interest for an LNG project to be constructed in Vassilikos although no final contract has been confirmed yet Cyprus-Israel cooperation A possible option for Cyprus in increasing its potential specifically for an LNG plant is through cooperation with Israel who as of January 2014 has natural gas reserves of 10.1 to 17 Tcf (EIA, 2014a) out of which 40% is decided to be exported (Henderson, 2013). The cooperation will be in a form of transporting Israeli gas to Cyprus via a pipeline; a way through which there will enough gas to make a single or a double train LNG plant an 14

22 economically viable option. In this way Cyprus would become a natural gas exporting hub. This option however heavily depends on timing of Cyprus gas monetisation as Israelis are moving fast on monetising their reserves through cooperation with companies such as US Nobel Energy and recently Australian Woodside petroleum (Scheyder, 2014) and overcoming technical difficulties of offshore pipe lying on relatively hostile terrains. An additional difficulty is Israel s persistence on sustaining full control over its own energy sector (Denise, 2012). 15

23 3. Liquefied Natural Gas 3.1. Properties of LNG Liquefied natural gas (LNG) is the pipeline quality natural gas which is condensed into liquid by reducing its temperature to -161 degree Celsius (-256 F) at the atmospheric pressure. Through this process the volume of gas is reduced to 1/600 of its original volume and becomes a colourless, odourless liquid weighing half the weight of water making transportation of natural gas economically viable across long distances using especially designed vessels (Foss, 2012). Properties of LNG in essence are no different than the pipeline gas used for industrial and household (Marks, 2003) Current Status of LNG Plant Cost An LNG value chain is a capital intensive investment. In a report from Ernest & Young division, EYGM limited quoted from Deutsche bank, it is assumed that although historical prices for an LNG projects are averaged at $1,200 per million ton per annum (mtpa), however for a newly sanctioned LNG project it would be no less than $2,600 per mtpa of capacity. Further, in the same report Credit Suisse and Deutsche bank suggest this price for North America and East Africa LNG projects to average below $2,000 per mtpa (Ernst&Young, 2013;Paltsev et al., 2013) and for Australian LNG projects over $3,000 per mtpa (see table 2). These required large amounts of investment are forcing suppliers to consider assigning long-term contracts with purchasers to mitigate risks and financial drawbacks. New emerging changes in the markets are however, changing this trend by moving more and more towards spot and short-term contracts. Moreover, as the plant capacity, size and production increases the total cost decreases (Paltsev et al., 2013). As a general rule of thumb the minimum train size (liquefaction unit) for an economical LNG plant is around 4 to 4.5 mtpa. That is equivalent to a minimum of 195 Bcf of natural gas per year or 534 MMcfd (million cubic feet per day) requiring a reserve of ~4.5 Tcf for a 20 year period (Durr et al., 2005). Inter Oil published information regarding few of the on-going projects and their costs per unit capacity on September 2012 as shown in table 2. The most prevalent cost structure as a portion of total cost for a generic LNG onshore facility is shown in figure

24 Table 2: LNG Projects Capital Expenditure, source: Visaggio (2012) Figure 12:LNG Onshore Facility Cost Breakdown, source: Habibullah et al. (2009) Ultimately, acid gas removal, fractionation, mercury removal and dehydration are conducted at the raw gas processing plant and pipeline quality is sent to the LNG facility. When considering the portion of LNG value chain as it is depicted in figure 13, from natural gas before liquefaction at the source to after gasification at the destination, the cost portion of liquefaction is 50% of the total (Economides and Wood, 2009;Economides et al., 2008). Although some recent data would suggest this to be even higher at 80% as the cost for LNG 17

25 plant has increased from $ 600 per mtpa in 2008 to over $ 2,000 in 2013 (Ernst&Young, 2013;RiceGlobal, 2011;Enersea, 2006). LNG: Capital Costs 50% 11% 39% Shipping Offloading (unloading) Figure 13: LNG, Gas to Gas Capital Cost Share, source: Economides et al. (2008) 3.3. LNG shipping Costs The latest pricing for LNG ships was obtained from Barry Rogliano Salles (BRS, 2013) and indicated in figure 14. Figure 14: LNG Vessel Costs, source: BRS (2013) 18

26 4. Compressed Natural Gas 4.1. Properties and technology of CNG Compressed Natural Gas (CNG) is the pipeline quality natural gas, compressed at a pressure of 2,000-3,600 psi (150 to 250 bar) at which the original volume of the gas is reduced to 1/200. Some new technologies, in combination with compressing also chill the gas to 40 degrees Celsius which results in both lower pressure and higher volume reductions (Wang and Marongiu Porcu, 2008). Although, no commercial sea transportation project is currently operational, the use of CNG in small scale transportation dates back to 1930s after the World War II when Italy used natural gas as a transportation fuel. There are currently around 14.8 million vehicles using natural gas as fuel in the world with an average growth rate of 30% from 2000 (CleanNG, 2012). In 1969 the first attempt was made to build the first CNG transportation carries with a capacity of 1.3 mmcf however, due to extremely low gas prices and the amount of investment required the project was terminated (Economides et al., 2008). Furthermore, with gas prices at current level and more than 2,200 Tcf of stranded natural gas reserves, see figure 15, the proposed solution for monetising stranded resources while having a physically mobile investment is CNG marine transport technology (Economides and Mokhatab, 2007;SeaNG, 2012). Figure 15: Ideal Transportation Means, source: SeaNG (2012) 19

27 In contrast to its benefits, since no real operational project has been commissioned, there are many doubts and questions regarding the technology. One major challenge is the weight of CNG carries; a typical 140,000 m³ LNG carrier has a light ship weight of approximately 35,000 tons whereas for the same amount of natural gas a CNG vessel would have a dry weight (light ship weight) exceeding 200,000 tons. Although this would not be in line with the concept of CNG as it aims to transport smaller volumes, however solutions have been proposed to use buoys some distances away from the shore (Blikom and Danielsen, 2010). The technology of buoy (See figure 16) and its compatibility has already been approved by the US government as mentioned in global LNG outlook conference back in 2006 (Enersea, 2006). Figure 16: CNG Loading-Unloading Buoy, source: Enersea (2006) The main component of CNG marine transportation is the shipping as the rest of the technology simply consists of compressor, de-compressor and storage facility. Ships account for less than 20% of total cost of a complete value chain for LNG whereas shipping accounts for more than 80% of a CNG value chain (Nikolaou, 2010;Economides et al., 2008). This is the main reason for critics around CNG technologies to be focused on the shipping / vessel technologies as it concerns the main investment. 20

28 Figure 17: CNG Value Chain Cost Share, source:economides and Wood (2009) The typical cost breakdown for LNG value chain as portion of total cost can be found in many literatures, however the indication of cost breakdown for CNG value chain in the same manner has only been limited to a very few available literatures. This is mainly due to absence of an operating facility (Kotzot et al., 2007;Ernst&Young, 2013;White, 2012). Further to the aforementioned costs breakdown, the Centre for Marine CNG Inc. proposed the possible costs for a CNG supply chain to be as shown in table 3. Table 3: CNG Value Chain Cost, source: MarineCNG (2006) Offshore CapEx MM$40-60* Transportation CapEx: MM$205/Ship (4X$ 205) Unloading CapEx: MM$20-60 Total Investment $ billion O&M MM$25/yr. (est.) * Conservatively due to uncertainties this number is assumed at $ 100 million for onshore CapEx and $50 million for the buoy system which accumulates to a total of $ 150 million. A typical CNG value chain is shown in figure 18. Figure 18: Value Chain of CNG vs. LNG, source: Marongiu-Porcu et al. (2008) 21

29 Risk issues of CNG project would undoubtedly be concentrated around the uncertainties regarding the shipping technologies as well as loading and unloading. Though these technological uncertainties have been claimed resoled by the aforementioned companies, nonetheless unless commissioned and operational it cannot be 100% assured. Apart from that, the investment on its own can be divided into two sections; the on-shore plant and the vessels. Onshore CNG plant s cost portion of the investment is assumed to be less than 15% of the total (Economides et al., 2008), the rest of the investment pertains to the ships which is a movable investment as ships can re-deployed and reassigned once the reserves are either depleted or ceased to be economical with ease, in contradiction to LNG where the majority of investment is tied onshore and hard to relocate (with the exception of yet to be completed floating LNG plant Prelude ). This way, stranded natural gas resources can also be easily harvested without large capital investments and more ease of application. Ideally suited regions of the world for CNG applicants are illustrated in figure 19 (Economides and Wood, 2009;Economides and Mokhatab, 2007;Economides et al., 2008;Blikom and Danielsen, 2010;SeaNG, 2012). Figure 19: Ideally Suited Regions for CNG Application, source: SeaNG (2012) 22

30 5. Input Data for LNG and CNG 5.1. General Input Data These data pertain to general terms and assumptions for calculation and analysis. Study Period The study period chosen for the analysis was assumed to be 20 years. Rational behind this was that in most studies a range between 15 to 25 years was used (Hurriyet-News, 2013;Economides et al., 2008;Paltsev et al., 2013) and therefore a mid-point was chosen. Plant Efficiency Ratio This was obtained from various literature reviews and set to be 92% which equals to 336 effective days per year of production (Perez et al., 1998). The ratio would also depend on the ambient temperature (Kotzot et al., 2007) and the technology used and used (single or double units, gas or electric motors, etc.) (Durr et al., 2005) these were not considered in this dissertation. Fuel Loss Factor This ratio is an average loss of fuel during the transportation. This ratio was obtained from various literatures and assumed to be at 8% of the total input. (Kotzot et al., 2007;Durr et al., 2005;Perez et al., 1998;Paltsev et al., 2013) Economic Indicators These indicators were used for all calculations however they differ in essence from the general input data. Discount Rate The discount rate was obtained from a series of literature reviews and manual interpolations and was assumed as 12%. The rationale behind this decision came from two specific case studies which were chosen and used to set the lower and upper boundaries. The first was the 2013 case study of Cyprus by MIT and Cyprus Institute (Paltsev et al., 2013) using a discount rate of 10% and the second was the 2008 case study of Indonesia by Economides Consulting (Wang and Marongiu Porcu, 2008) using a discount rate of 15%. Considering the first one is more recent and investment confidence in the region, the discount rate was set as 12%. 23

31 Interest Rate Commercial bank prime lending rate for Cyprus was obtained from the website of Indexmundi (2013) and indicated to be 7% annually, also the loan payback period was assumed as 12 years. During the construction period no interest is charged and no repayments are made. Inflation rate This was obtained by taking mean average of Customer Price Index (CPI) from the historical inflation data for Cyprus of the past 15 years. An alternative to this would be to create a customised index per year by taking a base year, however since the results are historical and the rate did not exceed much (only 4%) between two consecutive years, the proposed approach was thought to provide sufficient accuracy at 2.59% per year (Eurostat, 2013b;Index-mundi, 2013), Natural Gas Prices 1. The prices of natural gas for each category were determined and are explained below: Natural Gas Price Increase This price increase was obtained from Annual Energy Outlook 2013 (AOE2013) early release overview on page 5, where the expected price for 2030 to 2040 was from $5.40 to $7.83 per million Btu (EIA, 2013i) which in terms translates to an annual average of ~2% increase from the current wellhead price of $3.35 per MMBtu. The proof of calculation is 3.35*(1.02) 25 = $ 5.50 (within the margin). Wellhead Price This price was assumed to be $3.35 per MMBtu and was obtained from infomine website and confirmed by the U.S. EIA and Indexmundi websites (Infomine, 2013;EIA, 2012;IndexMundi, 2013). Asia-Pacific Price The price for natural gas was assumed to be $16.53 per MMBtu and was obtained from Ycharts and IndexMundi websites (Ycharts, 2013;IndexMundi, 2013). This price was obtained from averaging the results of the past 3 years. Corresponding calculations are shown below: low price = $ From the energy content perspective, natural gas contains ~25% of crude oil per volume Therefore the economy of natural gas and price comparison can be accordingly made (1:4) 24

32 European Price Average price = high price = $18.11 $ $ = $16.53 per MMBtu This price for European natural gas was assumed to be $11.98 per MMBtu and was obtained from Ycharts and IndexMundi websites (Ycharts, 2013;IndexMundi, 2013) and was based on the average of the past 3 years. Corresponding calculation is shown below: Average price = 5.3. Plant Construction Costs LNG Plant and Facility Costs low price = $ high price = $12.88 $ $ = $11.98 per MMBtu The cost for LNG plant facility was derived from various literatures (table 2) and accepted at $2,000 per mtpa (Ernst&Young, 2013;White, 2012;Visaggio, 2012). CNG Plant and Facility Costs The cost for CNG plant facility was extracted from various literatures (figure 17 and table 3) and assumed to have a total cost of $150 million (Blikom and Danielsen, 2010;Economides and Mokhatab, 2007;Economides et al., 2008;Wang and Marongiu Porcu, 2008;MarineCNG, 2006) Shipping Costs The cost of shipping for both CNG and LNG were obtained and illustrated using two scenarios. The first scenario was that ships are leased or rented and hence an all-inclusive daily price would be applied. For the second scenario ships are purchased and owned. LNG Shipping Costs Ships Rented The cost for renting as indicated by Barry Rogliano Salles in their 2013 report, was assumed to be $125,000 per day for long term contracts (BRS, 2013). 25

33 Ships Purchased The purchase price for the ships was considered to be $205 million each (figure 14). In this case since no data regarding the maintenance and operation costs was available, 50% of daily rental cost was assumed as the M&O costs (BRS, 2013). CNG Shipping Costs Ships Rented The cost of renting or the daily cost) as quoted by some companies and assumptions made were taken to be $100,000 per day (SeaNG, 2012;Enersea, 2006;Blikom and Danielsen, 2010). Ships Purchased Since no actual CNG ship exists, the exact purchase price of CNG vessels were not clear however from shipping companies and other literature a range of possible price suggestion could be extracted. Obtained prices ranged from $115 to $215 million and therefore an average of $165 million was chosen for calculations. Similarly for the M&O costs, since no exact indication of costs could be accessed, 50% of daily renting price was assumed (SeaNG, 2012;Enersea, 2006;MarineCNG, 2006;Economides et al., 2008;Wang and Marongiu Porcu, 2008). Distances to market The distances for each market are shown below: LNG to Europe is based on delivery to the west European countries such as Belgium, UK, etc. which are at an average distance of 6,000 km from Cyprus. LNG to Asia is based on delivery to east of China and west India which are at a distance of 7,500 km from Cyprus. CNG includes countries in the Mediterranean region which are within a range of 2,000 km. 26

34 5.5. Summary of Input Data To summarise the findings on input data, table 4 is constructed as the reference table for calculations: Table 4: Input Data Table ITEM RESULTS UNIT Fixed nominal capital discount rate (WACC) % annual Commercial bank prime lending rate (nominal) 7.00% annual Inflation rate (constant) 2.59% annual Total life of the project 20 years Gas price at wellhead $3.35 MMBtu Gas price Europe ( nov-2013) $11.98 MMBtu Gas price Asia ( nov-2013) $16.53 MMBtu LNG Vessel cost $ per day CNG vessel cost $ per day LNG vessel capacity M³ of LNG CNG vessel capacity 50,000 M³ of CNG LNG Vessel Speed 34.4 km/h CNG vessel Speed 28.7 km/h Natural gas price increase 2% annual Distance to European markets CNG 2000 (est.) km Distance to European markets LNG 6000 (est.) km Distance to Asian markets LNG 7500 (est.) km Plant operation efficiency 92% Per year Plant operating days 336 Per year Construction period LNG 4 Years Construction period CNG 3 Years LNG plant cost $2000 Per ton capacity LNG plant capacity mtpa CNG plant cost $ total LNG number of vessels 2 CNG number of vessels 8 Capital Loan payback period 12 years Fuel Loss factor 8% 2 WACC is the weighted average cost of capital which can in many cases interchangeably be used for Discount rate for an organisation. 27

35 6. Data Analysis for LNG and CNG Procedure in calculating life cycle cost-benefit analysis as well as NPV, IRR and CBR are orderly discussed below Ships Export Capacity and Revenue For calculating the life cycle costs and benefits the first step was to calculate export per vessel using the input data provided as shown in table 5. Table 5: Vessel Capacity, distance and speed Export per vessel Capacity (cf) Distance (km) Speed (km/h) LNG Europe 2,965,200, LNG Asia 2,965,200, CNG 350,000, Calculation method for LNG Vessel s capacity is shown below. For CNG the capacity was quoted by SeaNG for their C84 type vessel (SeaNG, 2012). 140,000 m³ 35.3 feet gas 600 (natural ) = 2,965,200,000 cf m3 LNG Loading, offloading and travel time was obtained from GRIN et al. (2005) article and the result was obtained by dividing the distance by the speed as shown in table 6. Table 6: Travel, Loading, Unloading and Contingency Time travel time (return) Loading time (days) unloading time (days) contingency time (days) LNG Europe LNG Asia CNG An additional contingency day is added for all destinations. The total travel time to each destination as well as possible generated revenue is shown in table 7. Table 7: Total Delivery Time per Scenario and Generated Revenue Total delivery time (days) Return trips per year Total delivery per year (cf) Revenue per vessel at the first operation year LNG Europe ,722,564,987 $576,574,523 LNG Asia ,127,507,828 $729,408,334 CNG ,505,176,052 $531,366,666 28

36 Calculation of total delivery capacity and generated revenue per vessel for LNG to European markets is shown below for demonstration: 6000 = (return trip) = 15 days (24 hours 34.4 km/h) 15 days + 3 days (load, unload contingency) = 18 days 365 days 18 days = 21 retrun trips per year 21 2,965,200,000 cf = 61,722,564,987 cf per vessel per year 61,722,564,987 cf ($ $3.35) ( ) (0.001) = $576,574,523 Note: Since pipeline quality gas is provided by the raw gas processing plant $3.35 is deducted as the price for wellhead gas. Inflation of 2% is added for 4 years (during construction) to project the price inflations. Natural gas is sold in million British thermal units (MMBtu) = 1000 cf, hence the multiplication For calculating the revenue (including the annual gas price increase) per vessel the current price is increased by 2% per year. In case of LNG this is 4 years and for CNG 3 years this is solely to project the future expected price based on current price. To obtain the total amount of reserves required throughout the study period for each market, the total numbers of vessels are multiplied by the capacity and then by the operation years (see table 8); those are 16 years for LNG and 17 years for CNG project and are the assumed periods after the construction is finished. Table 8: Total Gas Reserves Required during the Operation Period (for export) Total reserves required throughout the production life (for export) (cf)+8% LNG Europe E+12 =2.13 trillion cubic feet LNG Asia E+12 =1.76 trillion cubic feet CNG E+12 =2.13 trillion cubic feet To the above mentioned total amount of required reserves the 8% fuel loss is also added. Asian market shows the minimum required amount and that is due to the number of vessels 29

37 chosen; if instead of 2 vessels, 3 vessels were chosen the plant capacity would be violated and hence it was kept as stated in table 4. The plant capacity calculations are as follows: 2.5 million tons per year = (2.5) m 3 = 5.6 million cubic meters of LNG cf natural gas 600 = 121 bcfof natural gas per year m³ LNG 121 bcf 16 years = 1.94 tcf tcf 1.08 (fuel loss) = 2.1 tcf of natural gas reserves required 2.1 tcf 92% plant efficiency = 1.94 tcf of net plant production Therefore all values selected for production change within a 10% margin of plant capacity and production (110%) = tcf ok (90%) = 1.75 tcf ok Furthermore, according to current estimates of natural gas reserves the amount available natural gas for domestic consumption and its availability duration is calculated in table 9. Total Reserves (Bcf) Table 9: Reserves, Export, Consumption Required for Export (Bcf) Left for domestic use (Bcf) Domestic use (Bcf) Years of domestic use (years) 3,100 2,130 (LNG EU) ,100 1,760 (LNG Asia) 1, ,100 2,130 (CNG Med.) Domestic consumption was extracted from the latest RC government tender for natural gas at 0.9 bcm (Cyprus-Mail, 2013a) and a contingency of 30% increase (population ratio) in case both sides (Greek and Turkish Cypriots) decide to share the resources is added. The calculation on obtaining the probable domestic use is shown below: bcf per annum 30

38 6.2. Capital Cost (CapEx) Capital cost for both the LNG and CNG plants are shown in tables 10 and 11. However for the LNG, only the portion pertaining to this report is chosen for further analysis (see figure 12). Table 10: LNG CapEx LNG Plant construction cost* $5,000,000,000 (Fractioning and other refining not included = 12%) ($750,000,000)** Liquefaction (28%) $1,400,000,000 Refrigeration (17%) $700,000,000 Utilities (16%) $800,000,000 Storage & loading (27%) $1,350,000,000 Total Relevant CapEx $4,250,000,000 *: The CapEx was the product of capacity (2.5 mtpa) and the cost per unit capacity ($2,000 per tons) and the relevant components share of total were calculated (see figures 11, 12). **: Parenthesis represents the value to be deducted. Table 11: CNG CapEx CNG Plant construction costs* $150,000,000 Compression, storage and jetty $100,000,000 Loading buoy $50,000,000 Total Relevant CapEx $150,000,000 *The CapEx for CNG was obtained from the literature and as shown in table 3 and figure Operation Cost (OpEx) Operation costs for both the LNG and CNG are shown in tables 12 and 13 respectively. Feed gas price is however, only dependent on the revenue and will be calculated separately. Table 12: LNG OpEx LNG OpEx fixed Feed gas 3 8% revenue --- Other (O&M) 3% CapEx $127,500,000 Vessel (rental costs = $125,000/vessel/day) 2 vessels $91,250,000 Total OpEx - Feed gas $ 218,750,000 Vessel cost is a product of daily cost, number of vessels (ships) and 365 day in year. The cost for vessel is assumed not affected by the efficiency of the plant. Moreover, in all cases the 3 Feed gas is consumed gas for the process by the plants 31

39 operation expenditure is increased by 2.59% annually due to the inflation effect. Illustration of O&M calculation is shown below: $4,250,000,000 (CapEx) 0.03 = $127,500,000 Table 13: CNG OpEx CNG OpEx fixed Feed gas 4% revenue --- Other (O&M) 3% CapEx $4,500,000 Vessel (rental cost=$100,000/vessel/day) 8 vessels $292,000,000 Total OpEx - Feed gas $296,500,000 Feed gas cost is calculated by multiplying the revenue by 8% for LNG and 4% for CNG. The 2% annual increase in revenue would consequently increase the cost of feed gas for each year. Feed gas cost calculation for LNG to Europe in the first year of operation as a demonstration is shown below: $1,176,212,027( first year revenue) 0.08 = $94,096, Capital Repayment The principal capital was received in equal instalments during construction phase for each project. Moreover, the loan payback period was assumed to be 12 years and hence the principal capital repayments were divided by 12 equal terms. Below are the calculations: LNG Principal capital fixed instalments calculation is illustrated below: $4,250,000,000 = $ 354,166,667 per year 12 This fixed amount will be deducted from the outstanding debt starting from the end of year 5 for a period of 12 years. An example of total repayment calculations for the first operation year including the interest rate (year 5 of the study period) for LNG Europe is demonstrated below however, a complete excel sheet of calculation can be provided on demand from the authors. total account payable at the begining of the (first operation ) year = $4,250,000,000 32

40 total account payable at the end of the (first operation) year = $4,250,000,000 $354,166,166 = $3,895,833,333 Interest rate payment at the end of (first operation) year = 4,250,000,000 7% CNG = $297,500,000 total loan repaymet for this period = $297,500,000 + $354,166,166 = $651,666,667 Principal capital fixed instalment s calculation is illustrated below: $150,000, = $ 12,500,000 per year This fixed amount will be deducted from the outstanding debt starting from the end of year 4 for a period of 12 years Life Cycle Cost This cost includes the OpEx, shipping cost (leased/rented), feed gas, construction cost and the loan repayment. The total cost for each market is the sum of all aforementioned costs in their nominal value. This is illustrated in figure 20 with CNG having the lowest and LNG to Asia the highest cumulative life cycle cost. Cumulative Life Cycle Cost (Ships Hired) Cum. LCC in USD $20,000,000,000 $15,000,000,000 $10,000,000,000 $5,000,000,000 $- $16,213,478,759 $16,678,388,721 $7,618,176,285 LNG Europe LNG Asia CNG LNG Asia CNG LNG Europe Transport option Figure 20: Cumulative Life Cycle Costs Calculation of cost for the first year of operation (year 5 of the study period) for LNG Europe is demonstrated below as an indication for LCC calculations. 33

41 $224,415,625 (OpEx year 5) 4 + $94,096,962 (feed gas) + $651,666,667 (loan repayment + interest) = $970,179,254 The present value for life cycle costs are also calculated using the previously mentioned formulas and shown in figure 21 where the same observation can be made. Present Value of Life Cycle Cost PV of LCC in USD $10,000,000,000 $5,000,000,000 $- $6,933,403,226 $7,056,420,980 $2,232,009,481 LNG Europe LNG Asia CNG LNG Europe LNG Asia Transport option CNG Figure 21: Present Value of Life Cycle Costs Calculation for Present Value (PV) of the costs in the first year of operation (year 5 of the study period) for LNG Europe is demonstrated below: $970,179,254 ( ) = $550,505, Life Cycle Benefits This value includes the revenue only and is the sum of all nominal revenues generated plus the initial loan as an inflow and is illustrated for each option in figure 22 where the highest benefit (revenue) is generated by LNG to Asia and LNG to Europe and CNG generate almost the same revenues. However the following is a demonstration of revenue calculation for the first operation year of LNG to Europe: 2 (number of vessels) $532,665,736 (revenue per vessel) (Gas price increase ) = $1,176,212,027 (revenue) 4 Opex at year 5 is obtained by including the effect of inflation to the current (year 1) operating expenditure i.e. $ 218,750,000 * = $224,415,625 (here the costs escalations are assumed to be only 1 x 2.59% due to possible learning curve in the operation) 34

42 Cumulative Life Cycle Benefits Cum. LC benefits in USD $30,000,000,000 $20,000,000,000 $10,000,000,000 $- $21,923,751,490 $27,735,126,013 $21,842,844,752 LNG Europe LNG Asia CNG LNG Europe LNG Asia CNG Transport Option Figure 22: Cumulative Life Cycle Benefits The present values of the aforementioned benefits are calculated using appropriate formulations and are illustrated figure 23. It can be observed that LNG to Asia has the highest. Present Value of Life Cycle Benefits PV of LC benefits in USD $15,000,000,000 $10,000,000,000 $5,000,000,000 $- $9,028,329,914 $10,566,051,843 $6,262,203,327 LNG Europe LNG Asia CNG LNG Europe LNG Asia Transport option CNG Figure 23: Present Value of Life Cycle Benefits 6.7. Life Cycle Net Benefit Analysis To calculate the life cycle net benefits, total life cycle costs are deducted from total life cycle benefits for each market. This is expressed in terms of nominal values and illustrated in figure

43 Cumulative Net Benefit (Ships Hired) Cum. Net Benefit in USD $20,000,000,000 $15,000,000,000 $10,000,000,000 $5,000,000,000 $- $9,960,272,730 $15,306,737,292 $14,224,668,468 LNG Europe LNG Asia CNG LNG Europe LNG Asia Transport option CNG Figure 24: Life Cycle Net Benefits Calculation of net benefits for the first year of operation (year 5 of the study period) for LNG Europe is demonstrated below. $1,176,212,027 (revenue) $970,179,254 (costs) = $206,032, The Net Present Value (NPV) The net present value of the total investment is calculated by deducting the previously obtained PV of life cycle costs from the life cycle benefits (see figure 25). It demonstrates that CNG has the highest NPV and LNG to Europe the lowest. The discount rate used for primary calculations is as mentioned in the input data sheet (see table 4) at 12%. Figure 25: Net Present Value 36

44 6.9. Internal Rate of Return (IRR) To calculate the internal rate of return, the discount rate of 12% as well as the life cycle net benefit for each market were used. IRR was obtained by finding a ratio at which the NPV was equal to zero. IRR for each case is shown in figure 26. However it should be noted that this is a project internal, internal rate of return (IRR) which includes the payback of investment plus the interest and a discount rate of 12% and hence a marginal IRR and not the investment internal rate of return (IRR) which does not include the payback of the original investment specifically and should have been above the 12% discount rate or the WACC. IRR % 81.49% IRR percentage 50.00% 0.00% 6.14% 10.22% LNG Europe LNG Asia CNG LNG Europe LNG Asia Transport option CNG Figure 26: Internal Rate of Return Cost Benefit Ratio (CBR) Cost benefit ratio was calculated for each alternative using the present value of cost divided by the present value of benefits to show the cost share from the total revenue. The CBR for each case is shown in figure 27. CBR % 76.80% 66.78% CBR percentage 50.00% 0.00% LNG Europe LNG Asia Transport option 35.64% CNG LNG Europe LNG Asia CNG Figure 27: Cost Benefit Ratio 37

45 Calculation of cost benefit ratio for LNG Europe is demonstrated below as an example of calculation procedure. $6,933,403,226 (cost) = % $9,028,329,914 (benefit) Sensitivity Analysis Sensitivity analysis was conducted on 3 different cases as explained below. However due to length constraints only samples are shown. Case 1: Different discount rates ranging from 10% to 17% were applied to examine the change and impact on the magnitude of the results (NPVs). Case 2: Different gas prices from 80% to 120% of current price were applied to obtain their impact on the NPVs. Case 3: Different construction costs were applied ranging from 80% to 120% of the originally quoted values. This was to obtain the effect of construction cost variations on the results. Case 1 (Discount Rate Variation) The effect of various discount rates on the NPVs are calculated and shown in table 14. Table 14: Sensitivity Analysis: Discount Rate and Change of NPV Discount rate NPV 10% 12% 15% 17% LNG Europe $2,638,428,324 $2,094,926,689 $1,511,929,992 $1,231,818,994 LNG Asia $4,355,721,826 $3,509,630,863 $2,588,403,221 $2,138,680,886 CNG $4,828,768,174 $4,030,193,846 $3,129,882,199 $2,674,003,492 Case 2 (Natural Gas Price Variation) Since the price of natural gas has a direct effect on the NPV results, different prices with a margin of 20% from the current price were used in calculations as shown in table 15. Table 15: Sensitivity Analysis: Natural Gas Price Variation and Change of NPV Price level 80% 90% 100% 110% 120% LNG Europe $1,027,515,782 $1,561,221,235 $2,094,926,689 $2,628,632,142 $3,162,337,596 LNG Asia $2,159,279,121 $2,834,454,992 $3,509,630,863 $4,184,806,734 $4,859,982,605 CNG $2,850,908,387 $3,440,551,117 $4,030,193,846 $4,619,836,575 $5,209,479,305 38

46 The change in NPV due to increase in price of gas to 120% of the current level (100%) as a percentage change is calculated below: LNG Europe $3,162,337,596 = % $2,094,926,689 LNG Asia CNG $4,859,982,605 = % $3,509,630,863 $5,209,479,305 = % $4,030,193,846 Case 3 (Construction Cost Variation) Since the cost of construction plays a crucial role in any project, different construction cost variations with respect to the originally quoted cost are examined. That is, for LNG range of $1,600 (80%) to $2,400 (120%) per mtpa and for CNG a total cost between $120 Mln. to $180 Mln (80% to 120%). The impacts on the NPVs are shown in table 16. Table 16: Sensitivity Analysis: Construction Cost Variation and Change of NPV Initial Capital 80% 90% 100% 110% 120% LNG Europe $2,514,668,746 $2,304,797,717 $2,094,926,689 $1,885,055,660 $1,675,184,631 LNG Asia $3,929,372,921 $3,719,501,892 $3,509,630,863 $3,299,759,834 $3,089,888,806 CNG $4,046,786,003 $4,038,489,924 $4,030,193,846 $4,021,897,768 $4,013,601,689 The variations in the NPVs when the initial costs are 80% of the quoted estimates (100%) are calculated below: LNG Europe LNG Asia CNG $2,514,668,746 = 1.2 = 20 % $2,094,926,689 $3,929,372,921 = % $3,509,630,863 39

47 $4,046,786,003 = = 0.4 % $4,030,193, Total Life Cycle Cost-Benefit Analysis Below are the final results for the life cycle cost-benefit analysis of LNG projects versus CNG projects. The calculation is based on terms and conditions mentioned for Republic of Cyprus. It acts as the summery of all previously obtained results in one table (table 17). Table 17: Total Life Cycle Cost-Benefit Analysis Life Cycle 12% Discount Rate Total Construction cost $4,250,000,000 PV construction $3,227,183,681 Total LCC $16,213,478,759 LNG PV OpEx $3,706,219,545 Europe Total LCC PV $6,933,403,226 Total Life Cycle revenue $26,173,751,490 Total PV of revenue $9,028,329,914 Total NPV of Life Cycle Benefit - Cost $2,094,926,689 Life Cycle 12% Discount Rate Total Construction cost $4,250,000,000 PV construction $3,227,183,681 Operation cost $16,678,388,721 LNG PV OpEx $3,829,237,299 Asia Total LCC PV $7,056,420,980 Total Life Cycle revenue $31,985,126,013 Total PV of revenue $10,566,051,843 Total PV of Life Cycle Benefit - Cost (NPV) $3,509,630,863 Life Cycle 12% Discount Rate Total Construction cost $150,000,000 PV construction cost $120,091,563 Operation cost $7,618,176,285 CNG PV OpEx $2,111,917,918 Total LCC PV $2,232,009,481 Total Life Cycle revenue $21,842,844,752 Total PV of revenue $6,262,203,327 Total PV of Life Cycle Benefit - Cost (NPV) $4,030,193,846 40

48 7. Pipeline 7.1. Pipeline Overview Pipelines are believed to be the safest mean for transporting any stable chemicals compared to other transportation means throughout the world (Furchtgott-Roth, 2013). Generically Pipelines are the most economic transportation means for short to medium distances depending on the construction conditions. For transporting natural gas from the island of Cyprus to European markets there are two widely accepted possibilities; one is through pipeline to Turkey and the other is through the island Crete to Greece where the latter is a costly option facing much engineering subsea difficulties. However analysis has been conducted in the recent report by Massachusetts Institute of Technology (MIT) (Paltsev et al., 2013) and the cost has been estimated to be exceeding $5 billion. In this section the analysis will be conducted for the pipeline to Turkey via Cyprus. Since pipelines to and from Cyprus are offshore due to the nature of Cyprus being an island, some seismological information regarding the east Mediterranean will be provided first Seismic Map of the eastern Mediterranean The island of Cyprus is located in the proximity of three tectonic plates of Arabian, Anatolian and the African plates which put Cyprus in a relatively high seismic zone (figure 28). Figure 28: Eastern Mediterranean Seismic map, source: Ben-Avraham (2003) 41

49 Consequently according to the map of seismic activity frequencies as shown in figure 29 the safest pathway for a gas pipeline is from the north of the island of Cyprus to the south of Turkey. South of Turkey is also the area in which Cyprus could face the minimum competition due to the lack of pipeline from the countries which export natural gas to Turkey (see figure 8 and figure 30). Figure 29: Seismicity map of Cyprus, source: CGSD (2010) Figure 30: Eastern Mediterranean Gas pipelines, source: MacDonald (2010) 42

50 7.3. Data Analysis for Pipeline to Turkey via Cyprus Construction costs of pipelines are in general dependent on whether they are laid onshore or offshore (subsea). Each onshore and offshore pipeline laying activity is further dependent on the terrain conditions and especially the depth for offshore pipelines. For the pipeline to Turkey via Cyprus there are three segments (figure 31) to be considered, these are discussed below: Segment 1: from the wellhead to the shore of Cyprus (currently agreed to be in Vassilikos) a distance of ~ 130 km offshore pipeline at an average depth of 1700 meters and an assumed Diameter of 28 inches. Segment 2: from Vassilikos to Kyrenia (Girne) a distance of ~ 75 km of onshore pipeline under normal terrain conditions with an assumed diameter of 40 inches. Segment 3: from Kyrenia to Turkey a distance of ~90 km of offshore pipeline at a depth of approximately 1,200 meters with an assumed diameter of 24 inches. It is further considered that the initial pipeline is capable of transporting ~ 420 million cubic feet per day (MMcfd) or 12 million cubic meters per day of natural gas from which an estimate of 120 MMcfd is the domestic consumption of Cyprus (both North and South Cyprus). The 120 MMcfd is based on estimation for partial conversion (25%) of 60,000 Barrels (bbl.) per day oil imports in 2012 (EIA, 2014b) for the Republic of Cyprus (RC) and population ratio of the Northern part of Cyprus (Turkish Republic). The same amount is also obtained if the latest information of RC for natural gas provider tender is considered. The tender is for 0.9 Bcm of natural gas per annum (Cyprus-Mail, 2013a) which is equal to ~87 MMcfd and with a 35% increase for population of Turkish Cypriot, the total amount is about 118 MMcfd. This is excluding any possible demand increase due to industry conversion from other fuels to natural gas. 43

51 Figure 31: Pipeline Segments Wellhead to Turkey The cost of laying the pipelines has been quoted in different literatures with some deviations and therefore 6 different scenarios have been studied and applied to Cyprus case so that a better judgement can be made. Pipeline diameters are estimated based on a chart from the Zagreb University as shown in figure 32. Figure 32: Pipeline quick sizing procedure, source: Zagreb (2011) 44

52 7.4. Calculation Scenarios The following assumptions are considered for calculating the cost of pipe line: Segment 1 (from the wellhead to Vassilikos): 130 km 28 inch offshore Segment 2 (from Vassilikos to Kyrenia): 75 km 40 inch onshore Segment 3: (From Kyrenia to Turkey): 90 km of 24 inch offshore. Scenario 1 Calculations based on Ziff Energy Group (Ziff) and Wood Mackenzie (Mackenzie, 2012) for Grand Banks offshore pipeline for transporting natural gas. This is shown in table 18. Table 18: Scenario 1 Scenario 1 (woodmackinzie 2012) (onshore price is ~55% offshore through similar case comparison) USD to CAD = Distance Diamter Pipe CapEx per inch. Km Total CapEx Offshore w-c $ 166,500 $ 606,060,000 c-t $ 166,500 $ 359,640,000 Onshore $ 91,575 $ 274,725,000 Onshore facility Well development and offshore costs $ $ 25,000,000 2,500,000 $ $ 25,000,000 2,500,000 Total $ 1,267,925,000 w-c: wellhead to Cyprus (Segment 1) onshore: through the island (segment 2) c-t: Cyprus Turkey (segment 3) Scenario 2 This scenario was based on the information and predictions provided by the Oil and Gas Journal 2014 (Smith, 2014) in which the provided the anticipated costs for both onshore and offshore pipelines based on 2013 data. Calculation is shown in table 19. Table 19: Scenario 2 Scenario 2 (Oil & Gas journal 2013) Distance Diamter Pipe Offshore w-c c-t Onshore compressor and onshore facilities Well development and offshore costs CapEx per Km Total CapEx $ 4,750,000 $ 617,500,000 $ 4,750,000 $ 427,500,000 $ 2,570,000 $ 192,750,000 $ 25,000,000 $ 25,000,000 $ 2,500,000 $ 2,500,000 Total $ 1,265,250,000 45

53 Scenario 3 This scenario was based on the data provided by Gazprom (Frolov, 2012) on their average cost for both offshore and onshore pipeline construction. Gazprom also provided the cost for each wellhead to be around $2.5 million. Calculation is shown in table 20. Table 20: Scenario 3 Scenario 3 (Gazprom 2012) Euro to USD =1.38 Distance Diamter Pipe Offshore w-c c-t Onshore compressor and onshore facilities Well development and offshore costs CapEx per Km Total CapEx $ 4,140,000 $ 538,200,000 $ 4,140,000 $ 372,600,000 $ 2,500,000 $ 187,500,000 $ 25,000,000 $ 25,000,000 $ 2,500,000 $ 2,500,000 Total $ 1,125,800,000 Scenario 4 This scenario (table 21) was based on the information provided by Turcas in their 2013 (Bryza, 2012) report regarding the export of natural gas directly from the wellhead to Turkey. Table 21: Scenario 4 Scenario 4 (Turcas 2013) Distance Diamter Pipe Offshore w-c c-t Onshore compressor and onshore facilities Well development and offshore costs CapEx per Km Total CapEx $ 2,982,000 $ 387,660,000 $ 2,519,000 $ 226,710,000 $ 2,080,000 $ 156,000,000 $ 25,000,000 $ 25,000,000 $ 2,500,000 $ 2,500,000 Total $ 797,870,000 Scenario 5 This scenario was based on the report by Mott MacDonald in 2010 for European natural gas supply (MacDonald, 2010). Calculation is shown in table 22. Table 22: Scenario 5 Scenario 5 (Matt MacDonald 2010) (rate Euro to USD =1.38) Distance Diamter Pipe CapEx per Km Total CapEx Offshore w-c $ 14,076,000 $ 1,829,880,000 c-t $ 14,076,000 $ 1,266,840,000 Onshore $ 1,154,000 $ 86,550,000 compressor and onshore facilities Well development and offshore costs $ $ 25,000,000 2,500,000 $ $ 25,000,000 2,500,000 Total $ 3,210,770,000 46

54 Scenario 6 This scenario is based on the 2013 interim report by Massachusetts Institute of Technology and the Cyprus Institute (Paltsev et al., 2013) regarding monetizing Cyprus natural gas. The calculation is shown in table 23. Table 23: Scenario 6 Scenario 6 (MIT 2013) Distance Diamter Pipe Offshore w-c c-t Onshore compressor and onshore facilities Well development and offshore costs CapEx per Km Total CapEx $ 4,700,000 $ 611,000,000 $ 4,700,000 $ 423,000,000 $ 2,200,000 $ 165,000,000 $ 25,000,000 $ 25,000,000 $ 2,500,000 $ 2,500,000 Total $ 1,226,500, Scenario Results The result of all scenario in the appropriate orders and applied to the aforementioned plus an additional $ 25 million for onshore compressor and facilities and a $ 2.5 million for well development activities for the specific case Cyprus are shown in table 24. Table 24: Summary of all Scenarios Summary of Scenarios Scenario 1 Scenario 2 Scenario 3 Scenario 4 Scenario 5 Scenario 6 $ $ $ $ $ $ 1,267,925,000 1,265,250,000 1,125,800, ,870,000 3,210,770,000 1,226,500,000 Evaluating all scenarios with the aim of obtaining the more accurate result, the results from the second scenario was considered to be moderate and sensible for further calculations Life Cycle Cost Benefit Analysis (LCCBA) for Pipeline To calculate the life cycle costs and life cycle benefits for the pipeline the data provided in table 6 are used with the exception of operating cost (OpEx) which was assumed to be 5% of the total initial cost (CapEx). This was obtained from the website of an independent Dutch oil and gas consultant Dr. M.H. Nederlof (mhnederlof, 2010). 47

55 The procedure for calculating the life cycle cost and benefits is as explained for both the CNG and the LNG projects. Life cycle costs and benefits of each year throughout the economic life cycle (20 years) are shown in table 25. Table 25: Life Cycle Costs and Benefits (pipeline) 5 Year Construction Opex Revenue Benefit (before Net Benefit (Net financing) after financing) 0 1 $ 1,265,250,000 $ 1,265,250,000 $ - $ - 2 $ 63,262,500 $ 886,773,924 $ 823,511,424 $ 629,506,424 3 $ 64,900,999 $ 904,509,402 $ 839,608,404 $ 652,984,029 4 $ 66,581,935 $ 922,599,591 $ 856,017,656 $ 676,773,906 5 $ 68,306,407 $ 941,051,582 $ 872,745,176 $ 700,882,051 6 $ 70,075,543 $ 959,872,614 $ 889,797,071 $ 725,314,571 7 $ 71,890,499 $ 979,070,066 $ 907,179,567 $ 750,077,692 8 $ 73,752,463 $ 998,651,468 $ 924,899,004 $ 775,177,754 9 $ 75,662,652 $ 1,018,624,497 $ 942,961,845 $ 800,621, $ 77,622,315 $ 1,038,996,987 $ 961,374,672 $ 826,414, $ 79,632,733 $ 1,059,776,927 $ 980,144,194 $ 852,564, $ 81,695,220 $ 1,080,972,465 $ 999,277,245 $ 879,078, $ 83,811,127 $ 1,102,591,914 $ 1,018,780,788 $ 1,011,400, $ 85,981,835 $ 1,124,643,753 $ 1,038,661,918 $ 1,038,661, $ 88,208,764 $ 1,147,136,628 $ 1,058,927,864 $ 1,058,927, $ 90,493,371 $ 1,170,079,360 $ 1,079,585,989 $ 1,079,585, $ 92,837,150 $ 1,193,480,948 $ 1,100,643,798 $ 1,100,643, $ 95,241,632 $ 1,217,350,567 $ 1,122,108,935 $ 1,122,108, $ 97,708,390 $ 1,241,697,578 $ 1,143,989,188 $ 1,143,989, $ 100,239,037 $ 1,266,531,529 $ 1,166,292,492 $ 1,166,292,492 Based on the information in table 27, NPV and IRR are obtained as follows (procedure explained on pages 36-40): NPV at 12% = $5,213,626,883 IRR = 53% The Net Present Value (NPV) at 12% discount rate (or WACC) and the Internal Rate of Return (IRR) were obtained based on project internal or Design Build Operate and Maintain (DBOM) which means the initial capital was provided by a third party and the only project obligation is to pay back the loan in that matter (both interest and principal within 12 years). 5 EBT is Earning Before Tax. 48

56 8. Gas to Wire (GtW) Converting the natural gas to other products and exporting the end product is another possibility of generating revenue. Converting natural gas to electricity through a power plant located in Cyprus and then exporting that electricity to Europe using the 2000 MW Eurasia interconnector is the option which will be evaluated hereafter Export price of Electricity in EU The export price of electricity in EU from European Commission website based and on average wholesale electricity prices in Europe (Eurostat, 2013a;EC, 2014) was obtained to be 55 per MW and at an USD to Euro exchange rate of 1.38 this is ~$76 per MW. Furthermore CO 2 pollution allowance has not been considered in calculations Electricity Production from Natural Gas The online data base of US Energy Information Administration (EIA) (EIA, 2014c) provides the amount of kwh that can be obtained from 1000 cubic feet or 1 MMBtu of natural gas to be 127 kwh based on 45% plant efficiency. This conversion is of course in line with Carnot engine theory of 100% efficiency which is unpractical in real life. The efficiency quoted by different reports show the electricity generation at best to be 40% to 60% (Tweed, 2011;Nyberg, 2013;Salvadore and Keppler, 2010). Furthermore, working hours (operation hours) of the plant per year as suggested in a 2012 updated report by VBG Germany (PowerTech ev, 2012) was accepted as 6000 hours per year Revenue and Cost Calculations Although this option is different in nature, the purpose is still to export using natural gas and hence has to be evaluated in the same manner as other considered options. These will be calculated as shown below: Revenue = Production (per year) price (average EU27) Cost (to the project) 6 = OpEx + CapEx (loan payback ) 6 The cost is calculated to decide whether to undertake the project or not, this is different than the cost which should be calculated from the investor s point of view where the initial cost (investment) should be included. That would entail different terms and ROI (Return on Investment) would be of utmost importance. 49

57 8.4. Calculation of Revenue Calculations for converting gas to electricity are shown in tables 26 and 27. Table 26: Input data of electricity generation Power plant operating days (pa) 250 (68%) Plant efficiency 45% Daily gas export 300 MMcfd Production 1000 cf of NG 127 kwh European average price $ 76 Per MWh Production: Table 27: Electricity generation revenue Input cf gas 300,000,000 Net energy used (cf) Conversion to kw Fuel loss factor Nominal Production per day Real Production per day 8% kw MW kw MW 300,000,000 38,100,000 35,052,000 35,052,000 35,052 23,835,360 23,835 Revenue at daily Yearly 45% heat rate $ 1,811,487 $ 661,192,886 Furthermore based on the calculations in table 26 the required power plant has a nominal rate of 1,000 MWh 7. The operation costs of power plants are assumed to be 3% of the CapEx where capital cost is assumed to be 650 per kw capacity. At an Euro- USD exchange rate of 1.38 this is ~ $897 per kw (PowerTech ev, 2012;Tarjanne and Kivistö, 2008). CapEx and Opex calculations are as follows: CapEx: 1,000,000 (kw) $897 = $, 897,000,000 OpEx per year: $897,000,000 3% = $26,370,000 7 This is obtained by dividing the daily production of 23,835 MW by 24 hours while inefficiencies were included in the total production. 50

58 These are obtained from various literatures (EIA, 2013h;PowerTech ev, 2012). Capital cost calculations were assumed the same as other alternatives at 7% and a 12 year payback period. Another major cost for this option is the feed gas cost which is considered at a minimum price $3.5 per MMBtu which is the assumed wellhead gas price. Opex is also increased with minimum 2.59% (inflation) per year as this is the certain minimum ascertain price escalation which would possible occur and feed gas price is increases with 2% per year same as for LNG and CNG Life Cycle Cost Benefit Analysis for GtW Based on previous information Life Cycle Cost Benefit Analysis is obtained as shown in table 28. Table 28: LCCBA of GtW 8 Year Opex Feed gas costs Capex Power Total costs Revenue 3% of CapEx $ 3.5 MMBtu Plant Net Revenue (EBT) $ 879,000,000 $ (879,000,000) 1 $ - $ - $ (439,500,000) $ 439,500,000 $ - 2 $ - $ - $ (439,500,000) $ 439,500,000 $ - 3 $ 26,370,000 $ 241,500,000 $ 402,650,000 $ 661,192,886 $ 258,542,886 4 $ 27,052,983 $ 246,330,000 $ 403,035,483 $ 674,416,744 $ 271,381,261 5 $ 27,753,655 $ 251,256,600 $ 403,535,255 $ 687,905,079 $ 284,369,824 6 $ 28,472,475 $ 256,281,732 $ 404,151,707 $ 701,663,181 $ 297,511,474 7 $ 29,209,912 $ 261,407,367 $ 404,887,279 $ 715,696,444 $ 310,809,166 8 $ 29,966,449 $ 266,635,514 $ 405,744,463 $ 730,010,373 $ 324,265,910 9 $ 30,742,580 $ 271,968,224 $ 406,725,804 $ 744,610,581 $ 337,884, $ 31,538,813 $ 277,407,589 $ 407,833,901 $ 759,502,792 $ 351,668, $ 32,355,668 $ 282,955,741 $ 409,071,408 $ 774,692,848 $ 365,621, $ 33,193,680 $ 288,614,855 $ 410,441,035 $ 790,186,705 $ 379,745, $ 34,053,396 $ 294,387,152 $ 411,945,548 $ 805,990,439 $ 394,044, $ 34,935,379 $ 300,274,895 $ 413,587,774 $ 822,110,248 $ 408,522, $ 35,840,205 $ 306,280,393 $ 342,120,599 $ 838,552,453 $ 496,431, $ 36,768,467 $ 312,406,001 $ 349,174,468 $ 855,323,502 $ 506,149, $ 37,720,770 $ 318,654,121 $ 356,374,891 $ 872,429,972 $ 516,055, $ 38,697,738 $ 325,027,204 $ 363,724,941 $ 889,878,571 $ 526,153, $ 39,700,009 $ 331,527,748 $ 371,227,757 $ 907,676,143 $ 536,448, $ 40,728,239 $ 338,158,303 $ 378,886,542 $ 925,829,666 $ 546,943,123 Further to the analysis in table 28 the NPV and IRR are obtained as shown below: NPV at 12 % = $1,851,197,683 IRR = 22% 8 The net revenue is the net benefit after financing and is the EBT (Earnings Before Tax) 51

59 9. Discussion and Conclusion In this section the results of both financial and non-financial aspect will be discussed and analysed. The first section entails the financial aspects through life cycle cost benefit analysis and the second section pertains to the non-financial aspects which should consequently be taken into consideration Discussion Financial Aspect The following alternatives were considered for life cycle cost benefit analysis: 1- LNG (onshore) a- To Europe b- To Asia 2- CNG to the Mediterranean region (onshore) 3- Pipeline to Turkey 4- Gas to Wire to Europe After the analysis the Net Present Value at 12% nominal discount rate for each of the alternative was obtained as shown in table 29 and figure 33. Table 29: Alternatives NPV & IRR Alternatives % IRR LNG EU $2,094,926, % LNG Asia* $3,509,630, % CNG (Med.) $4,030,193, % Pipeline (TR) $5,213,626,883 53% GtW (EU) $1,851,197,683 22% *the amount of gas sold during the operation phase of LNG to Asia is equal to 1.77 Tcf whereas for other options this amount of 2.1 Tcf. This is due to constraints of distance, vessel capacity and number of whole vessels imposed on LNG. Increasing the amount of exported LNG to Asia to equate others (using 2.4 vessels) would increase the NPV to ~ $4.8 Billion making LNG to Asia to rank second among the alternatives. But that would be questionable as having 2.4 vessels are not possible for LNG transportation technology. 52

60 NPV of all alternatives NPV in USD $6,000,000,000 $5,000,000,000 $4,000,000,000 $3,000,000,000 $2,000,000,000 $1,000,000,000 $2,094,926,689 $4,030,193,846 $3,509,630,863 $5,213,626,883 $1,851,197,683 LNG Europe LNG Asia CNG Pipeline GtW $0 LNG Europe LNG Asia CNG Pipeline GtW Transportation option Figure 33: NPV of all alternatives From the results indicated in table 28 and figure 33 it is easily elicited that the project to pipe the gas to Turkey delivers the highest NPV at $ 5.2 billion followed by CNG to Mediterranean region with an NPV of $ 4 billion. Gas to Wire option would deliver the lowest NPV after LNG to Europe. It is however, important to bear in mind that all options except for the pipeline- which has a maximum total length of 300 km- would require a gas processing plant at the source either on shore or as a Floating Production, Storage and Offloading (FPSO) unit which was not considered in this report. For the pipeline, due to its relatively short length, processing plant could be at the destination or in Cyprus. Whichever ways for all options it was assumed as a third party s responsibility and is the reason behind deducting $3.35 per MMBtu from the total sales price Non-Financial Aspect Different aspects for evaluating the non- financial aspects of each alternative can be so vast that would not appropriately fall within the context of this report. However, some major aspects will be briefly mentioned which would be efficacious in decision making process. Shale gas The emergence of shale gas (non-conventional natural gas) extraction for which the proven reserves are believed to be almost as much the conventional reserves of natural gas (figure 4) can have a negative impact on expected capital intensive conventional natural gas investment 53

61 such as LNG projects. This is simply based on supply and demand correlation theories. A widely accepted perception is the change of United States from a net importer of natural gas to an exporter of natural gas by 2020 (BRS, 2013). Reduction of Greenhouse Gases (GHG) As Europe is striving to reduce the production of greenhouse gases the demand for natural gas will increase (figure 6). This would consequently increase the importance of Cyprus natural gas development and its adjacent demanding market. Tectonics fault lines in the Mediterranean Another subject which needs attention is the existence of tectonic fault lines due south, west, and east of Cyprus (figures 28, and 29). This puts any possible pipeline to west of the island (pipeline to Greece via Crete) at a higher margin of risk than if a pipeline was to be placed to Turkey at north. The natural gas found in Republic of Cyprus s EEZ and more specifically Aphrodite field is located on the south of Cyprean Arc (figure29); this although would some possess seismic risks but it is one that cannot be averted if the gas is to be transported in the north direction. Natural gas from RC EEZ as well as any possible reserves discoveries off the east coast of Cyprus can be more safely transported to the island if they are located at the north of Cyprean Arc. Consequently in case of a pipeline and in terms of seismic risk, it can be best transported/exported to Turkey (see figure 29) which is also a major natural gas consumer. Furthermore, current internationally import pipelines to Turkey (figure 8) leave the southern west part (due North of Cyprus) empty of any in competitors which offers a considerable and expedient natural gas market gap for Cyprus to fill. Cyrus Israeli Cooperation The cooperation between Cyprus and Israel could mean that an LNG plant is economically viable however there are some technological and political challenges which need to be resolved for this this cooperation to form. One of which being the willingness of Israel for holding full control over its energy sector. Basins in the proximity of Cyprus By a visual investigation of basins in the vicinity of Cyprus some non-technical assumptions can be made. In figure 34, the darker dots and areas are the proven reserves of oil and gas. If 54

62 these areas are connected as shown in figure 34 (black line) in leading logical pattern, the possibility for the existence of more reserves is revealed. Figure 34: Basins in the proximity of Cyprus, source: EIA 55