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Comparative Assessment of Electricity

Generation Options of ARASIA Countries

a Regional Study under Project ARASIA-1 in Cooperation with IAEA

Draft Report

February 2010

Disclaimer The views expressed in this study report are those of the National Teams from the Member States participating in this project. These views may not reflect the views of the Governments of these Member States or the International Atomic Energy Agency Vienna, Austria.

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EEXXEECCUUTTIIVVEE SSUUMMMMAARRYY Many east and west Arab countries are working in building interconnections to integrate their electric grids aiming at arriving the integrated Arab electric grid which will be interconnected with the UCTE. Parts of the envisaged regional grid have been implemented, like the interconnection of the eight countries including Egypt, Jordan, Palestine, Iraq, Lebanon, Syria and Turkey and the GCC interconnection of the Arab Golf countries and the west Arab countries including Libya, Tunisia, Algeria and Morocco-. These inter-connected girds will open possibility to improve electricity supply security in the countries by resource pooling and peak loads shifting; in addition to reducing the required reserve margin of national generation systems. Furthermore, the market sizing of the regional grids will also open up possibilities for accommodating nuclear power plants. With this changing situation, there is a need to conduct comparative studies for electricity options in each country and then to integrate the regional picture. These comparative studies will help national decision makers to formulate future policies and plans for electricity development.

Following this goal the regional cooperation project entitled “Comparative Assessment of Electricity Generation Options of ARASIA1 Countries” was initiated. In the framework of ARASIA agreement the project was commenced as an IAEA's regional project (RAS/0/043) for the period 2003-2004 with participation of Syria, Jordan, Lebanon, Kingdom of Saudi Arabia (KSA), and Yemen. It was extended twice; first for the period 2005-2006 where the United Arab Emirate (UAE) joined the project in 2005 and second for the period 2007-2008 where Iraq joined in 2006. During the project implementation that sustained for the period 2003-2008 seven ARASIA member states have attended the project to fulfill the following main objectives:

• Assist Member States of ARASIA in conducting studies on comparative assessment of electricity generation options under interconnected regional electric and gas grids;

• Help national decision makers in formulating future policies and plans for development of the energy/electricity sector;

• Support ARASIA countries in elaborating sustainable energy supply strategies;

• Build regional capacities of specialists to carry out comprehensive energy system analysis using advanced energy planning tools.

As a first step, national working teams were constituted in each participating country to conduct country studies. The project coordinators defined the scope of the country studies and developed a detailed work-plan including activities to be implemented by the IAEA. During the period 2003-2004, the IAEA organized two regional training events and an 1 ARASIA: Co-Operative Agreement of Arab States in Asia for Research, Development and Training Related to Nuclear Science and Technology. ARASIA group comprises: Syria, Jordan, Lebanon, Saudi Arabia, Iraq, United Arab Emirate and Yemen [2].

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expert mission to help build local capabilities for carrying out comprehensive energy system analysis at country-level using advanced IAEA's planning tools.

Due to some administrative and logistic problems by some country teams the project suffered form interruption on 2005, so that additional regional training was organized in the year 2006 to fresh up the previous teams, to introduce and integrate the new incoming teams of UAE and Iraq in the project activities and to incorporate environmental damage costs of electricity generation in the developed national energy supply strategies. In 2007 the IAEA organized regional training course to improve and extend the experiences of working teams. During the project implementation some teams faced organizational problems as their team members were changed and new teams were established. Other teams were behind the project schedule. Thus, expert mission and group training were organized to overcome these hindrances and to enable these teams to catch-up with other teams.

IAEA organized training event in 2008 with the purposes of linking and integrating national models into a regional model and harmonizing and ensuring consistency of input data and assumptions for grid interconnection. Due to the importance of environmental impact of electricity generation options, additional training event was organized to incorporate environmental issues in the future energy supply strategies.

During the project implementation the following training activities were organized in cooperation between IAEA and ARASIA member states:

o Project Coordinators Meeting, IAEA, Vienna, 26-28 May 2003 o Regional Training Course on the use of IAEA’s energy model MESSAGE,

Beirut, Lebanon, 8-19 Dec 2003; o Follow-up Missions, Jordan, Syria, Lebanon, Saudi Arabia, June & October 2004; o Regional Training Course on analysing electricity options in interconnected grids

in the region using IAEA’s energy model MESSAGE, Amman, Jordan, 28 Nov.- 09 December 2004;

o Project Coordinators Meeting, IAEA, Vienna, 11-13 April 2005; o Regional Training Course on Assessment of Environmental Damage from

Various Electricity Generation Technologies 20-24 August 2006, Damascus, Syria;

o Project Coordinators Meeting, IAEA, Vienna, 7-9- May 2007; o Regional Training Course on incorporating Environmental Aspects into Energy

and Electricity Scenarios using IAEA’S Energy Model MESSAGE, 10-21 Feb 2007, Sana'a, Yemen;

o Regional Training Course on Harmonization of National data Inputs to MESSAGE for Regional Scale Modelling and Grid Interconnection Analyses, Dubai, UAE, 18-22 November 2007;

o Project Coordinators Meeting, IAEA, Vienna, 25-27 March 2008; o Regional Group Training on "Modelling National Energy Systems using the

IAEA’s Energy Model MESSAGE”, Damascus, Syria 4-29 May 2008; o Regional Training Course on Incorporating Environmental Aspects into

MESSAGE Analysis, Dubai, UAE, 15-26 June 2008.

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OOBBJJEECCTTIIVVEE OOFF TTHHEE CCOOUUNNTTRRYY AANNDD RREEGGIIOONNAALL SSTTUUDDIIEESS The objective of each country study is to assess competitiveness of various electricity generation options in the long-term (2003-2030) using a model of independent national energy system and a regional model with proposed interconnections of electricity grids and networks of natural gas in the region.

Many countries in the ARASIA region and around it are building interconnections to integrate their electricity grids as well as natural gas network. This integrated system will help in strengthening the security of supply and in consolidation of the regional energy market. How the national energy system of the ARASIA countries needs to be developed in the integrated energy market? What new options of electricity generation need to be explored to take the full advantage of the emerging market, which will be bigger in the size as well as diversified in terms of resources and pattern of demand? There are various similar questions that need to be investigated. The country studies carried out under this ARASIA project attempt to address some of these questions and evaluate the opportunities provided by the interconnected grids.

MMEETTHHOODDOOLLOOGGIICCAALL AAPPPPRROOAACCHH

The IAEA has been supporting its Member States in energy planning studies for sustainable development in the long-term. Development of appropriate methodologies for these studies and dissemination of computer models are part of this support. The country studies and the Multi-regional studies being carried out under ARASIA-1 project apply three models developed by the IAEA: MAED, MESSAGE and SIMPACT.

For projection of national energy demand in the study period (2003-2030), some countries have used extrapolation technique, while some have adopted data from their national institutions responsible for energy demand projection. However, Syria has applied the IAEA’s model MAED, which is based on end-use approach for projection of useful and final energy demand.

MESSAGE (Model for Energy Supply Strategy Alternatives and their General Environmental Impacts) is a model designed for optimization of an energy system (i.e. energy supplies and utilization). It belongs to the class of linear mixed integer programming model, and has been used to find out the optimum expansion path of the energy/electricity sector in a given scenario of energy sector development. The MESSAGE model provides a user-friendly environment for building the energy flows network to model the whole energy system; starting from domestic energy resources and passing through primary and secondary level to the final level i.e. energy demand. It allows modelling of current and future energy conversion technologies, import and export of energy. The MESSAGE model can also be used to assess environmental impact of energy supplies, and to model the environmental constraints in development of an energy system.

The SIMPACTS (Simplified approach for estimating environmental impacts from electricity generation) model is based on the EcoSense Methodology but in the most simplified form. The SIMPACTS model estimates the damages caused by the atmospheric emissions from electricity generations to calculate the associated damage costs i.e. external cost of electricity generation. The program uses the Impact Pathway

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Analyses (IPA), which describes route by which emissions generated by the reference technologies travel in the environment to cause damages to the human health, agricultural crops and man-made environments (building material). In the framework of this project, SIMPACTS has been applied in the national/regional studies to calculate the external costs of electricity generation from different technologies.

OOVVEERRVVIIEEWW OOFF TTHHEE EECCOONNOOMMIICC AANNDD EENNEERRGGYY SSIITTUUAATTIIOONN IINN AARRAASSIIAA CCOOUUNNTTRRIIEESS

The total area of the countries participating in the ARASIA-1 project is almost 2 million square kilometres with a population of about 100 million habitants.

Figures 1 to 3 show the historical trends of per capita GDP, energy consumption, and electricity consumption of the ARASIA countries during 1998-2003. It is evident that countries with higher per capita income have also higher energy and electricity consumption. Figures 4 and 5 present highlights of the electricity sectors of these countries; in terms of annual generation and peak load during this period.

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Figure S-1. Per Capita GDP of ARASIA Countries

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(Source: Organization of Arab Petroleum Exporting Countries, www.oapecorg.org)

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Figure S-2. Per Capita Commercial Energy Consumption (Source: Organization of Arab Petroleum Exporting Countries, www.oapecorg.org)

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Figure S-3. Per Capita Electricity Consumption (Source: Organization of Arab Petroleum Exporting Countries, www.oapecorg.org)

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Figure S-4. Annual Electricity Generation (Source: Organization of Arab Petroleum Exporting Countries, www.oapecorg.org)

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Figure S-5. Peak Load in Electricity Consumption (Source: Organization of Arab Petroleum Exporting Countries, www.oapecorg.org)

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Figure S-6. Installed Electricity Generation Capacities by Source in 2003 (Source: Organization of Arab Petroleum Exporting Countries, www.oapecorg.org) Break down of the generation capacities in 2003 (Figure 6.) shows that there is not much diversity in sources of electricity generation in the ARASIA countries. Most of these countries are mainly relying on oil and gas for electricity generation. Only in three countries (Syria, Iraq and Lebanon), have hydro-based electricity generation capacities,

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which vary from 10% to 30%. Combined Cycle is an advance and an efficient technology, it does not have significant share in the total generation capacity except in Lebanon (about 30%). Yemen is the only country that has more than 50% of the total installed capacity based on Diesel power plant.

As a result of the six-country interconnection project, there is an electricity grid connecting Egypt, Jordan, Syria, Lebanon, Iraq in addition to Turkey. In 2003, this integrated block –except Turkey- has a total installed capacity of 37 GW with the peak load of about 29 GW. The total final electricity consumption amounted to about 145 TWh.

Bahrain, Kuwait, Oman, Qatar, KSA and UAE are planning to have an interconnected grid under the Cooperation Council for the Gulf block (GCC). The installed capacity of the GCC countries is of 46.5 GW, while their electricity demand is of 192 TWh. In August 2001, the GCC created a Power Grid Authority to supervise the implementation of the project to interconnect all 6 national grids (called GCC grid project).

Three options to link the above mentioned two interconnected grids are: a) Linking of the Kuwaiti and Iraqi grids, b) Linking of the Saudi and Jordanian grids, c) Linking of the Saudi and Egyptian grids.

TTHHEE DDEEVVEELLOOPPEEDD AARRAASSIIAA EENNEERRGGYY MMOODDEELLSS AATT NNAATTIIOONNAALL AANNDD RREEGGIIOONNAALL LLEEVVEELLSS

Under the ARASIA project, seven national models are being developed; each one representing the national energy sector of the participating countries. Case studies were carried out using the national models to formulate optimal expansion paths of the energy sector in the long-term. In addition, a regional model has been developed that consists of one main region (called ARASIA) and seven sub-regions representing seven countries. In this Regional model, each national model is included with additional technologies to represent existing and possible future interconnections of the country with other ARASIA countries. These interconnections allow import/export of electricity and natural gas between the countries through the specified interconnected networks.

Based on the existing and planned interconnections, the following cases are represented in the regional model:

• The electricity interconnection among Egypt, Jordan, Syria, Lebanon and Iraq.

• The electricity interconnection between KSA and Yemen (expected begin of operation 2010).

• The planned electricity interconnection between KSA and Egypt (expected begin of operation 2013).

• The planned interconnection of natural gas between KSA and Yemen.

• The Arab natural gas pipeline connecting Egypt with Turkey across Jordan and Syria.

MMAAIINN RREESSUULLTTSS AANNDD FFIINNDDIINNGGSS OOFF TTHHEE SSTTUUDDYY

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The study deals with the formulation of optimal reference energy supply scenarios at national levels based upon reference national final energy demand projections for the period 2003-2030. Besides, a regional case study has been evaluated by integrating the single regions (countries) in one main region that includes all tie lines of interconnecting grid. The main findings of these analyses are summarized below.

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CONTENT

1. INTRODUCTION............................................................................................................................. 17 1-1 BACKGROUND............................................................................................................................ 17 1-2 PURPOSE AND SCOPE OF THE STUDY .......................................................................................... 18 1-3 OBJECTIVES OF THE PROJECT ..................................................................................................... 19 1-4 SCOPE OF THE REPORT ............................................................................................................... 19 1-5 METHODOLOGICAL APPROACH.................................................................................................. 19

2-5-1 MESSAGE Model ................................................................................................................. 20 2-5-2 SIMPACTS Model................................................................................................................. 21

2. PROFILES OF ARASIA COUNTRIES ......................................................................................... 23 2-1 IRAQ........................................................................................................................................... 26

2-1-1 Geography and Climate of Iraq ....................................................................................... 26 2-1-2 Demography of Iraq ............................................................................................................. 26 2-1-3 Macro Economy and National Accounts of Iraq .................................................................. 27 2-1-4 Main Feature of Iraqi Energy System................................................................................... 28 2-1-5 Structure of Iraqi Power Sector............................................................................................ 32 2-1-6 Iraqi Energy policy ............................................................................................................... 32

2-2 JORDAN...................................................................................................................................... 34 2-2-1 Geography and Climate of Jordan ....................................................................................... 34 2-2-2 Demography of Jordan......................................................................................................... 34 2-2-3 Macro economy and National Accounts of Jordan............................................................... 34 2-2-4 Main Features of Jordan’s Energy System........................................................................... 35 2-2-5 Structure of Electric Power Sector of Jordan....................................................................... 35 2-2-6 Energy Policy of Jordan ....................................................................................................... 38

2-3 KINGDOM OF SAUDI ARABIA (KSA) .......................................................................................... 40 2-3-1 Geography and Climate of KSA............................................................................................ 40 2-3-2 Demography of KSA ............................................................................................................. 40 2-3-3 Main Features of Saudi Energy System................................................................................ 42 2-3-4 Structure of Electric Power Sector of KSA........................................................................... 49

2-4 LEBANON ................................................................................................................................... 51 2-4-1 Geography and climate of Lebanon...................................................................................... 51 2-4-2 Demography of Lebanon ...................................................................................................... 51 2-4-3 Lebanese Economy ............................................................................................................... 51 2-4-4 Lebanese Energy Sector ....................................................................................................... 53 2-4-5 Structure of Electric Power Sector of Lebanon .................................................................... 54 2-4-6 Lebanese Energy policy........................................................................................................ 54

2-5 SYRIA......................................................................................................................................... 55 2-5-1 Geography and Climate of Syria .......................................................................................... 55 2-5-2 Demography of Syria............................................................................................................ 55 2-5-3 Macro economy and National Accounts of Syria.................................................................. 56 2-5-4 Main Features of Syrian Energy Sector ............................................................................... 58 2-5-5 Structure of Syrian Power Sector ......................................................................................... 62 2-5-6 Syrian Energy policy ............................................................................................................ 63

2-6 UNITED ARAB EMIRATES (UAE) ............................................................................................... 64 2-6-1 Geography and Climate........................................................................................................ 64 2-6-2 Demography of UAE ............................................................................................................ 66 2-6-3 Macro economy and National Accounts of UAE .................................................................. 66 2-6-4 Main Features of UAE’s Energy System .............................................................................. 67 2-6-5 Structure of Electric Power Sector of UAE .......................................................................... 67

2-7 YEMEN....................................................................................................................................... 68 2-7-1 Geographic and climate of Yemen........................................................................................ 68 2-7-2 Demography of Yemen.......................................................................................................... 68

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2-7-3 Macro economy and National Accounts:.............................................................................. 69 2-7-4 Main Features of Yemeni Energy Sector .............................................................................. 69 2-7-5 Structure of Electric Power Sector of Yemen ....................................................................... 72

3. OPTIMAL ENERGY SUPPLY STRATEGIES............................................................................. 74 3-1 OPTIMAL SUPPLY STRATEGY FOR IRAQ ..................................................................................... 78

2-1-1 MESSAGE Model of Iraqi Energy System............................................................................ 78 2-1-2 Results of Reference Energy Supply Strategy for Iraq.......................................................... 84 2-1-3 Conclusion............................................................................................................................ 92

3-2 OPTIMAL SUPPLY STRATEGY FOR JORDAN................................................................................. 93 2-2-1 MESSAGE Model of Jordanian Energy System.................................................................... 93 2-2-2 Results of Reference Energy Supply Strategy for Jordan ................................................... 100 2-2-3 Conclusion.......................................................................................................................... 112

3-3 OPTIMAL SUPPLY STRATEGY FOR LEBANON............................................................................ 114 2-3-1 MESSAGE Model of Lebanese Energy System................................................................... 114

3-4 OPTIMAL SUPPLY STRATEGY FOR KSA.................................................................................... 123 2-4-1 MESSAGE Model of Saudi Energy System......................................................................... 123 2-4-2 Optimal Saudi Energy Supply Strategy............................................................................... 127

3-5 OPTIMAL SUPPLY STRATEGY FOR SYRIA ................................................................................. 139 2-5-1 MESSAGE Model of Syrian Energy System........................................................................ 139 2-5-2 Results of Reference Energy Supply Strategy of Syria........................................................ 145 2-5-3 Conclusion.......................................................................................................................... 154

3-6 OPTIMAL SUPPLY STRATEGY FOR UAE ................................................................................... 156 2-6-1 MESSAGE Model of Emirate Energy System ..................................................................... 156 2-6-2 Results of Reference Energy Supply Strategy of UAE ........................................................ 159 2-6-3 Conclusion.......................................................................................................................... 163

3-7 OPTIMAL SUPPLY STRATEGY FOR YEMEN................................................................................ 164 2-7-1 MESSAGE Model of Yemeni Energy System ...................................................................... 164 2-7-2 Results of Reference Energy Supply Strategy for Yemen.................................................... 169 2-7-3 Conclusion.......................................................................................................................... 179

4. REGIONAL GRID INTERCONNECTION ................................................................................ 181 4-1 REFERENCE SUPPLY SCENARIO UNDER REGIONAL GRID INTERCONNECTION .......................... 183

2-1-1 Scenario's assumptions:...................................................................................................... 183 2-1-2 General data ....................................................................................................................... 184

4-2 ENERGY TRANSFORMING TECHNOLOGIES................................................................................ 185 4-3 OPTIMIZATION OF SYRIAN SUPPLY STRATEGY UNDER REGIONAL INTERCONNECTION ............ 186

2-3-1 Structure of Syrian Energy Carriers and Energy Supply Levels ........................................ 187 2-3-2 Electricity Exchange............................................................................................................... 2 2-3-3 Development of Syrian Installed Capacity under Regional Interconnection.......................... 3 4-4-1 Structure of Jordan Energy Carriers and Energy Supply Levels ................................................ 4 4-4-2 Development of Jordan Installed Capacity under Regional Interconnection......................... 7 4-5-1 Structure of Energy Supply of KSA Power System ................................................................. 8 4-6-1 Structure of Energy Supply of Yemeni Energy System .............................................................. 14 4-6-2 Development of Yemeni Power System under Regional Interconnection ............................. 15

5. EXTERNALITIES AND HEALTH DAMAGE COSTS OF ELECTRICITY GENERATION 23 5-1 INTRODUCTION........................................................................................................................... 23 5-2 IMPACT-PATHWAY APPROACH.................................................................................................... 24 5-3 ESTIMATING THE HEALTH DAMAGE COSTS OF SYRIAN ELECTRICITY GENERATION SYSTEM .... 26

2-3-4 Syrian Electricity Generation System ................................................................................... 26 2-3-5 Atmospheric Emissions:........................................................................................................ 28 2-3-6 Exposure Response Functions (ERFs).................................................................................. 29 2-3-7 Meteorological and Population Data ................................................................................... 31 2-3-8 Monetary Valuation:............................................................................................................. 33

5-4 DAMAGE COST RESULTS OF SYRIAN POWER SYSTEM ............................................................... 35

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Total Health Damage Cost ................................................................................................................. 35 2-3-9 Specific Damage factors per ton of Consumed Fuel............................................................. 37 2-3-10 Damage Cost per Generated Electricity Unit .................................................................. 38

5-5 CONCLUSION.............................................................................................................................. 40

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LIST OF FIGURES FIGURE 1-1: EURO-MEDITERRANEAN INTERCONNECTIONS [1]. .................................................................... 18 FIGURE 3-1-1: DICRETIZATION OF TIME HORIZON FOR THE STUDY PERIOD 2003-2030.................................. 76 FIGURE 3-1-1: FLOW CHART OF NATIONAL ENERGY SYSTEM (IRAQI EXAMPLE) ............................................ 81 FIGURE 3-1-2: DEVELOPMENT OF IRAQI ENERGY SYSTEM AT VARIOUS ENERGY LEVEL (SEC2: SECONDARY

ENERGY BEFORE ELECTRICITY GENERATION, SEC1: SECONDARY ENERGY AFTER ELECTRICITY GENERATION)....................................................................................................................................... 85

FIGURE 3-1-3: DISTRIBUTION OF SECONDARY ENERGY BY FUEL TYPES BEFORE ELECTRICITY GENERATION (INCLUDING ELECTRICITY IMPORT &ENS &HYDRO)........................................................................... 86

FIGURE 3-1-4: DISTRIBUTION OF SECONDARY ENERGY BY ENERGY FORM (AFTER ELECTRICITY GENERATION)............................................................................................................................................................. 87

FIGURE 3-1-5: NEW CAPACITY ADDITION OF FUTURE ELECTRIC GENERATION SYSTEM BY PERIOD AND POWER PLANT TYPE ......................................................................................................................................... 88

FIGURE 3-1-6: PEAK LOAD AND OPTIMAL EXPANSION OF INSTALLED CAPACITY FOR IRAQI FUTURE GENERATION SYSTEM BY POWER PLANT TYPE...................................................................................... 89

FIGURE 3-1-7: DEVELOPMENT OF FUTURE FUEL CONSUMPTION IN THE ELECTRICITY GENERATION............... 90 FIGURE 3-1-8: DEVELOPMENT OF IRAQI PRIMARY ENERGY BY FUEL TYPE. ................................................... 91 FIGURE 3-2-1: FLOW CHART OF NATIONAL ENERGY SYSTEM (JORDANIAN EXAMPLE) ................................... 98 FIGURE 3-2-2: DEVELOPMENT OF ENERGY FLOW IN THE JORDANIAN ENERGY SYSTEM (SEC-TOT: SECONDARY

ENERGY BEFORE ELECTRICITY GENERATION, SEC-EL: SECONDARY ENERGY AFTER THAT)................. 101 FIGURE 3-2-3: OPTIMAL EXPANSION PLAN OF ELECTRICITY GENERATION SYSTEM (BASE CASE) ............. 102 FIGURE 3-2-4: FUEL CONSUMPTION FOR ELECTRICITY GENERATION (BASE CASE) ................................... 103 FIGURE 3-2-5: FUEL SHARES FOR ELECTRICITY GENERATION (BASE CASE)............................................... 103 FIGURE 3-2-6: OPTIMAL EXPANSION PLAN OF ELECTRICITY GENERATION SYSTEM (NG CASE)................ 105 FIGURE 3-2-7: FUEL CONSUMPTION FOR ELECTRICITY GENERATION (NG CASE)....................................... 105 FIGURE 3-2-8: FUEL SHARES FOR ELECTRICITY GENERATION (NG CASE).................................................. 106 FIGURE 3-2-9: OPTIMAL EXPANSION PLAN OF ELECTRICITY GENERATION SYSTEM (NPP CASE)............... 107 FIGURE 3-2-10: FUEL CONSUMPTION FOR ELECTRICITY GENERATION (NPP CASE) ................................... 108 FIGURE 3-2-11: FUEL SHARES FOR ELECTRICITY GENERATION (NPP CASE) .............................................. 108 FIGURE 3-2-12: OPTIMAL EXPANSION PLAN OF ELECTRICITY GENERATION SYSTEM (NO-NPP CASE) ...... 110 FIGURE 3-2-13: FUEL CONSUMPTION FOR ELECTRICITY GENERATION (NO-NPP CASE) ............................. 110 FIGURE 3-2-14: FUEL SHARES FOR ELECTRICITY GENERATION (NO-NPP CASE)........................................ 110 FIGURE 3-2-15: DEVELOPMENT OF JORDANIAN PRIMARY ENERGY BY FUEL TYPE. ...................................... 112 FIGURE 3-3-1: NETWORK OF ELECTRICITY CHAINS OF THE LEBANESE NATIONAL MODEL........................... 116 FIGURE 3-3-2: EXISTING AND NEW CAPACITY ADDITION OF LEBANESE GENERATION SYSTEM. ................ 118 FIGURE 3-3-3: STRUCTURE OF TOTAL INSTALLED CAPACITY AT THE FIRST AND LAST YEAR OF THE STUDY

PERIOD............................................................................................................................................... 119 FIGURE 3-3-4 SHOWS A COMPARISON OF THE STRUCTURE OF THE TOTAL INSTALLED CAPACITY AT BEGIN AND

END OF THE STUDY PERIOD. BY THE END OF THE STUDY PERIOD, THE STRUCTURE OF THE ELECTRICITY SYSTEM WILL CONSISTS OF 14.4% COAL POWER PLANTS, 64.7% NG POWER PLANTS, WHILE THE REMAINING GOES FOR HYDRO AND WIND BY 19.3%, 1.6% RESPECTIVELY. ONE CAN SEE THAT THE SYSTEM BECAME MORE EFFICIENT SINCE THERE IS NO CONTRIBUTION OF DIESEL POWER PLANTS THAT IS VERY EXPENSIVE AND HAS A LOW EFFICIENCY, IN ADDITION TO THE FACT THAT THE SECURITY IN THE GENERATION SYSTEM WILL BE HIGHER BECAUSE OF THE DIVERSITY OF THE ELECTRICITY GENERATION RESOURCES. ....................................................................................................................................... 119

FIGURE 3-3-5: DEVELOPMENT OF TOTAL ELECTRICITY GENERATION DISTRIBUTED BY POWER PLANTS TYPE BETWEEN 2003-2030 ......................................................................................................................... 120

FIGURE 3-3-6: DEVELOPMENT OF FUEL CONSUMPTION MIX FOR ELECTRICITY GENERATION ....................... 122 FIGURE 3-4-1: FLOW CHART OF SAUDI ENERGY SYSTEM............................................................................. 126 FIGURE 3-4-2: DISTRIBUTION OF SECONDARY ENERGY BY TYPE OF CONSUMPTION..................................... 128

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FIGURE 3-4-3: DEVELOPMENT OF FUTURE SECONDARY ENERGY SUPPLY STRUCTURE BY TYPE OF ENERGY CARRIER (AFTER ELECTRICITY GENERATION)..................................................................................... 129

FIGURE 3-4-4: DEVELOPMENT OF FUTURE PRIMARY ENERGY BY FUEL TYPE. .............................................. 129 FIGURE 3-4-5: NEW CAPACITY ADDITION OF FUTURE ELECTRIC GENERATION SYSTEM BY PERIOD AND POWER

PLANT TYPE OF EAST REGION. ........................................................................................................... 131 FIGURE 3-4-6: NEW CAPACITY ADDITION OF FUTURE ELECTRIC GENERATION SYSTEM BY PERIOD AND POWER

PLANT TYPE (GT: GAS TURBINE, CC: COMBINED CYCLE)CENTRAL. ................................................... 131 FIGURE 3-4-7: NEW CAPACITY ADDITION OF FUTURE ELECTRIC GENERATION SYSTEM BY PERIOD AND POWER

PLANT TYPE (GT: GAS TURBINE, CC: COMBINED CYCLE)WEST. ........................................................ 132 FIGURE 3-4-8: NEW CAPACITY ADDITION OF FUTURE ELECTRIC GENERATION SYSTEM BY PERIOD AND POWER

PLANT TYPE (GT: GAS TURBINE, CC: COMBINED CYCLE) SOUTH. ...................................................... 132 FIGURE 3-4-9: TOTAL NEW CAPACITY ADDITION FOR THE ENTIRE KSA ELECTRIC GENERATION SYSTEM BY

POWER PLANT TYPE ........................................................................................................................... 133 FIGURE 3-4-10: DISTRIBUTION OF TOTAL NEW CAPACITY ADDITION FOR THE ENTIRE KSA ELECTRIC

GENERATION SYSTEM BY COUNTRY REGION. ..................................................................................... 133 FIGURE 3-4-11: DEVELOPMENT OF PEAK LOAD AND OPTIMALLY EXPANDED INSTALLED CAPACITY OF FUTURE

GENERATION SYSTEM BY POWER PLANT TYPE (EAST)........................................................................ 134 FIGURE 3-4-12: DEVELOPMENT OF PEAK LOAD AND OPTIMALLY EXPANDED INSTALLED CAPACITY OF

FUTURE GENERATION SYSTEM BY POWER PLANT TYPE (CENTRAL). ................................................... 134 FIGURE 3-4-13: DEVELOPMENT OF PEAK LOAD AND OPTIMALLY EXPANDED INSTALLED CAPACITY OF FUTURE

GENERATION SYSTEM BY POWER PLANT TYPE (WEST)....................................................................... 135 FIGURE 3-4-14: DEVELOPMENT OF PEAK LOAD AND OPTIMALLY EXPANDED INSTALLED CAPACITY OF

FUTURE GENERATION SYSTEM BY POWER PLANT TYPE (SOUTH). ....................................................... 135 FIGURE 3-4-15: DEVELOPMENT OF PEAK LOAD AND OPTIMALLY EXPANDED INSTALLED CAPACITY OF FUTURE

GENERATION SYSTEM BY POWER PLANT TYPE (FOR THE WHOLE SYSTEM).......................................... 136 FIGURE 3-4-16: DEVELOPMENT OF PEAK LOAD AND OPTIMALLY EXPANDED INSTALLED CAPACITY OF FUTURE

GENERATION SYSTEM BY POWER PLANT TYPE (FOR THE WHOLE SYSTEM).......................................... 137 FIGURE 3-5-1: FLOW CHART OF SYRIAN ENERGY SYSTEM INCLUDING ENERGY CHAINS, LEVELS AND

TECHNOLOGIES. ................................................................................................................................. 142 FIGURE 3-5-2: DEVELOPMENT OF ENERGY FLOW IN THE SYRIAN ENERGY SYSTEM (SEC-TOT: SECONDARY

ENERGY BEFORE ELECTRICITY GENERATION, SEC-EL: SECONDARY ENERGY AFTER THAT)................. 146 FIGURE 3-5-3: DISTRIBUTION OF SECONDARY ENERGY BY TYPE OF CONSUMPTION..................................... 148 FIGURE 3-5-4: DEVELOPMENT OF FUTURE SECONDARY ENERGY SUPPLY STRUCTURE BY TYPE OF ENERGY

CARRIER (AFTER ELECTRICITY GENERATION)..................................................................................... 149 FIGURE 3-5-5: NEW CAPACITY ADDITION OF FUTURE ELECTRIC GENERATION SYSTEM BY PERIOD AND POWER

PLANT TYPE (FSTEAM: FUEL OIL STEAM TURBINE, NU: NUCLEAR, GT: GAS TURBINE, CC: COMBINED CYCLE, RENEWABLE: WIND AND PV). ................................................................................................ 150

FIGURE 3-5-6: DEVELOPMENT OF PEAK LOAD AND OPTIMALLY EXPANDED INSTALLED CAPACITY OF FUTURE GENERATION SYSTEM BY POWER PLANT TYPE.................................................................................... 151

FIGURE 3-5-7: DEVELOPMENT OF FUTURE PRIMARY ENERGY BY FUEL TYPE.. ............................................. 152 FIGURE 3-5-8: COMPARISON OF PRIMARY ENERGY CONSUMPTION, ENERGY IMPORT AND EXPORT OVER THE

STUDY PERIOD. .................................................................................................................................. 154 FIGURE 3-6-1: STRUCTURE OF TOTAL INSTALLED CAPACITY IN 2003 AND 2030 ......................................... 160 FIGURE 3-6-2: DEVELOPMENT OF PEAK LOAD AND OPTIMALLY EXPANDED INSTALLED CAPACITY OF FUTURE

GENERATION SYSTEM BY POWER PLANT TYPE.................................................................................... 161 FIGURE 3-6-3: DEVELOPMENT OF TOTAL ELECTRICITY GENERATION DISTRIBUTED BY FUEL TYPES BETWEEN

2003-2030 ......................................................................................................................................... 162 FIGURE 3-6-4: COMPARISON OF FUEL MIX REQUIREMENT FOR ELECTRICITY GENERATION FOR 2003 AND 2030.

.......................................................................................................................................................... 163 FIGURE 3-7-1: FLOW CHART OF YEMENI ENERGY SYSTEM. ........................................................................ 168 FIGURE 3-7-2: DEVELOPMENT OF YEMENI ENERGY SYSTEM AT VARIOUS ENERGY LEVELS......................... 170

16

FIGURE 3-7-3: DISTRIBUTION OF SECONDARY ENERGY BY ENERGY FORM (AFTER ELECTRICITY GENERATION).......................................................................................................................................................... 172

FIGURE 3-7-4: DISTRIBUTION OF HEAT DEMAND FUEL DEMAND BY FUEL TYPE. ..................................... 173 FIGURE 3-7-5: DISTRIBUTION OF TRANSPORT DEMAND BY FUEL TYPE.................................................... 173 FIGURE 3-7-6: TOTAL NEW CAPACITY ADDITION OF FUTURE ELECTRIC GENERATION SYSTEM .................... 176 FIGURE 3-7-7: DEVELOPMENT OF OPTIMALLY EXPANDED INSTALLED CAPACITY OF FUTURE GENERATION

SYSTEM BY POWER PLANT TYPE. ...................................................................................................... 177 FIGURE 3-7-8: PROJECTED FUTURE GENERATION IN 2030 DISTRIBUTED BY TYPE OF POWER PLANTS (MWYR)

. ......................................................................................................................................................... 179 FIGURE 1: THE IMPACTS PATHWAY APPROACH (ATHENS,1997) ................................................................... 25 FIGURE 2: DISTRIBUTION OF AVAILABLE INSTALLED CAPACITY BY PLANT TYPE FOR THE YEAR 2005........... 27 FIGURE 3: DISTRIBUTION OF POPULATION AROUND THE SELECTED POWER PLANTS. ................................... 32 FIGURE 4: WIND ROSES OF VARIOUS POWER PLANTS CONSIDERED IN THE STUDY......................................... 33 FIGURE 5: TOTAL HEALTH DAMAGE COST BY POWER PLANT (MILLION US $).............................................. 36

0 .0

1 .0

2 .0

3 .0

4 .0

5 .0

6 .0

PM 10 1.9 2.3 1 .9 1.9 5.2 2.1 3.9 1 .5 2.4 1 .8

N itrates 1 .4 1.4 1 .4 1.4 1.4 1.4 1.4 1 .4 1.4 1 .4

Sulfates 1 .3 0.0 1 .3 1.3 0.0 1.3 1.3 1 .3 1.3 1 .3

A leppo_PPm ohardah_

PPB anias_PP

Tishreen_PP

D eir A li_PPD eir

assour_PPD eir A li

steam _PPSw edeah_P

PQ atena_P P

H asakah_PP

FIGURE 6: SPECIFIC HEALTH DAMAGE COST BY TYPE OF POLLUTANTS (1000$/TON). ......................... 38 FIGURE 7: TOTAL HEALTH COST BY POWER PLANTS (US CENTS/ KWH)........................................................ 39 LIST OF TABLES

TABLE 3-1: SEASONAL, DAILY, AND HOURLY DIVISIONS FOR DEFINING THE ELECTRIC LOAD CURVE. ........... 76

17

11.. IINNTTRROODDUUCCTTIIOONN

1-1 BACKGROUND The cooperation on the energy sector plays a key role in the envisaged Euro-Mediterranean economic cooperation to develop the future free trade area which is proposed to be created by 2010. In this regard and in order to establish a Euro-Mediterranean energy policy based on security of supply, competitiveness and protection of the environment, the Euro-Mediterranean Partners will have to face up to three major challenges in which interconnections play a major part. Priority will have to be given to [1]:

− the construction of a fully integrated and interconnected Euro-Mediterranean electricity and natural gas market,

− improving the security and safety of infrastructures, and − reducing the risks associated with the carriage of oil and gas by sea in the

Mediterranean basin. In order to strengthen the security of supply around the Mediterranean basin and consolidate the Euro-Mediterranean energy market, it is essential for the European Union and the Mediterranean Partners to have reliable, diversified energy links. Furthermore, the energy distribution system between Mediterranean Partners is still limited and the gradual introduction of a fully integrated Euro-Mediterranean energy market requires the development of South-North and South-South interconnections, when appropriate, to increase energy exchanges in the region. This objective requires the consolidation of the existing interconnections and the development of new ones. The gradual implementation of new network interconnection projects should over time include the completion of the Mediterranean electricity and natural gas ring networks (Fig. 1-1). To this must be added the importance of exploiting the transit potential of the Mediterranean region for supplying the Euro-Mediterranean area with resources from neighbouring countries, such as those from the Caspian Sea basin, Africa and the Middle East including Golf countries. In this regard and as part of Mediterranean electricity and natural gas ring networks, west and east Arab countries (south and south east Mediterranean countries) are building interconnections to integrate their electric grids as well as natural gas grids. These inter-connected girds will help to improve electricity supply situation in the countries by resource pooling. However, the trends in national electric sector development will change with the possibilities that will become available with this integration. The market sizing of the regional grids will also open up possibilities for accommodating nuclear power and desalination technologies. With this changing situation, there is a need to conduct comparative studies for electricity options in each country and then to integrate the regional picture. In this regard the role of the new established regional gas grid is also considered.

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Figure 1-1-1: Euro-Mediterranean Interconnections [1].

1-2 PURPOSE AND SCOPE OF THE STUDY The Arab countries in Asia established under the auspices of the IAEA the so-called ARASIA2 group. Under the sponsorship of the IAEA and ARASIA countries the regional cooperation project RAS/0/043 entitled “Comparative Assessment of Electricity Generation Options under Interconnected Grid (ARASIA-1)”, was initiated. The purpose of this project is to perform a comprehensive supply analysis of the national energy systems on local and regional basis for the next three decades (covering the period 2003-2030) with more emphasis on the electricity generation sector. At first step the national energy systems are analysed in stand-alone mode. To explore the impact of regional electricity and gas grid interconnection on the optimal future energy supply options, all national energy systems are then linked to an integrated multiregional system. The available and planned electric and gas interconnections (including Arab Gas pipeline from Egypt to Syria) are modelled and their role in the linked subsystems is analysed. In particular the study will help in formulate and evaluate alternative energy supply strategies consonant with pre-defined constraints including limits on new investment, fuel 2 ARASIA: Co-Operative Agreement of Arab States in Asia for Research, Development and Training Related to Nuclear Science and Technology. ARASIA group comprises: Syria, Jordan, Lebanon, Saudi Arabia, Iraq, United Arab Emirate and Yemen [2].

19

availability, environmental regulations, and market penetration rates for new technologies.

1-3 OBJECTIVES OF THE PROJECT The main objectives of the project can be short listed as follow:

• To assist member states in the region to conduct studies on comparative assessment of electricity generation options under interconnected regional grids;

• To help national decision makers in formulating future policies and plans for energy and electricity development;

• To support ARASIA countries in elaborating sustainable energy strategies; • To build regional capacities of specialists, able to carry out comprehensive energy

system analysis using advanced energy planning tools.

1-4 SCOPE OF THE REPORT The participating ARASIA countries constituted national teams representing national institutions responsible for energy and electricity issues. Under the conditions of ARASIA agreement and with the technical assistance of the IAEA, the regional technical cooperation project RAS /0/043/ was established to analyse the long-term energy supply of the participating countries, both in national and regional frame using energy planning tools of the IAEA. The participating countries comprise:

Article I. Syrian Arab Republic, Article II. Kingdom of Jordan, Article III. Kingdom of Saudi Arabia, Article IV. Republic of Yemen, Article V. Lebanon, Article VI. United Arab Emirate, Article VII. Republic of Iraq,

The project was initiated in 2003 for two years and was extended for two additional periods up to the year 2008. All countries started their participation from the beginning of the project except the last two countries, which jointed in the year 2005 and 2006 respectively.

The IAEA supported the national teams by providing technical training on the use of the IAEA’s computer codes, both at formal training courses organised by the IAEA and via on-the-job training throughout the conduct of the study. A number of expert visits in the field of energy and electricity planning were arranged by the IAEA to support the national teams during the project implementation.

1-5 METHODOLOGICAL APPROACH The study uses the IAEA’s tools MESSAGE and SIMPACTS to analyse the optimal supply options for covering the future energy demand by considering environmental and

20

financial constraints and impacts. Although the study is mainly concentrated on the analysis of the energy supply, pre-work should have been conducted to project the future energy demand. For this purposes, different tools were previously applied by the countries to estimate their national demand during the study period. Some countries used extrapolation technique or adopted data from the responsible institutions of the countries. In case of Syria the IAEA’s model MAED, which relies upon end-use approach, was used to project the future total final energy and electricity demand for the different consumption sectors in various socio-economic and technological development scenarios of the country [3], [4].

2-5-1 MESSAGE Model MESSAGE (Model for Energy Supply Strategy Alternatives and their General Environmental Impacts) is a model designed for the optimization of energy system (i.e. energy supplies and utilization). The model was originally developed at International Institute for Applied Systems Analysis (IIASA). The IAEA acquired the latest version of the model and several enhancements have been made in it, most importantly addition of a user-interface to facilitate its application [2]. The current version of the MESSAGE software consists of an User Interface for building a model; Databases; matrix generation program called mxg; An Optimization program called opt; A program for the post processing of the solution for extraction of results called cap.

The basic principle of MESSAGE depends on building the energy flows network which describes the whole energy system, starting from level of domestic energy resources (oil & gas, uranium, coal mines etc.) passing through primary and secondary level and ending by the given demand at final level, which is distributed according to the consumption sectors like household, industry and transportation. The energy levels are identified by fuel types like electricity or oil products and are linked with each other by energy conversion technologies including treatments, generation, transporting and distribution. Import and export of energy forms can be considered at the nay energy levels.

In the defined system network both existing and candidate technologies are included. Each technology is defined by activity and capacity variables including investment and O&M costs, efficiency, plant factor, operation time and other additional technical specifications.

MESSAGE is an optimization model allowing comprehensive evaluation of long-term energy/electricity strategies involving multi-commodity (e.g. electricity and water) and multi-regions/countries, while at the same time permitting assessment of environmental impacts. Environmental aspects can be analysed by accounting, and if necessary limiting, the amounts of pollutants emitted by various technologies at various steps in energy supplies. This helps to evaluate the impact of environmental regulations on energy system development that could include an enhanced role of nuclear power in the energy supply strategy (Figure 1-2).

In general categorization, MESSAGE belongs to the class of linear mixed integer programming models as all relations describing the energy system are expressed in term of linear function and has the option to define some variables as integer. A set of

21

standards solvers (e.g., CPLEX, OSLV2, OSLV3, MOSEK, HOPDM) can be used to solve the MESSAGE model [2]. The underlying principle of MESSAGE is optimization of an objective function under a set of constraints that define the feasible region containing all possible solutions of the problem. The value of the objective function helps to choose the solution considered best according to the criteria specified.

Minimization of the total system costs (value of the objective function) for the whole study period is the criterion used for optimization of the MESSAGE model. The total system cost includes investment costs, operation cost and any additional penalty costs defined for the limits, bounds and constraints on relations (like gas emissions limits). The present value is calculated by discounting all costs occurring at later points in time to the base year of the case study, and the sum of the discounted costs is used to find the optimal solution. Discounting makes the costs occurring in different points in time comparable; the discount rate defines the weights different periods get in the optimization. In principle, it should be equal to the long-term real interest rate, excluding inflation or any other opportunity costs. A high discount rate gives more weight or importance to present expenditures than to future ones, while a low discount rate reduces these differences and thus favours technologies that have high investment cost but low operation costs.

OUTPUT

MESSAGE

INPUT

• Energy system structure (including vintage of plant and equipment)

• Base year energy

flows and prices • Energy demand

projections (MAED) • Technology and

resource options & their techno-economic performance profiles

• Technical and

policy constraints

0

100

200

300

400

500

600

2000 2002 2004 2006 2008 2010 2012 2014 2016 2018 2020 2022 2024 2026

TWh

biomassgeothhydronucleargasdieselfuel oilcoal

• Primary and final energy mix • Emissions and waste

streams • Health and environmental

impacts (externalities) • Resource use • Land use • Import dependence

Figure 1-2: Formation of input and output structure of MESSAGE model.

2-5-2 SIMPACTS Model The SIMPACTS (Simplified Approach for estimating environmental impacts from electricity generation) is based on the approach of EcoSense Methodology in most simplified form. It is applied to estimate the impacts on the human health, agricultural crops and man-made environments (building material) from exposure to the atmospheric emissions (particular matter (PM), SO2, NOx, Co, and secondary species such as nitrate and sulphate aerosols) that is emitted from the electricity generations. The model also

22

calculates the associated damage in monetary term from these impacts. The program uses the impact pathway analyses (IPA) (Figure 1-3), which describes route by which emissions generated by the reference technologies travel in the environment, potentially to impact on humans. IPA approach begins by identifying the physical characteristics of the source and preparing a detailed inventory of airborne release. Impacts are characterized in physical terms (e.g., number of asthma attacks) by using Exposure Response Functions (ERF) and monetized by multiplying the number of cases by the unit costs (e.g., US$ per asthma attack). Damages are aggregated over all downstream receptors affected by a pollutant. The model includes three sub modules to estimate the impact of fossil power plants (AirPacts), nuclear power plants (NukPacts) and hydro power plants (HydroPacts).

In the frame work of this project, SIMPACTS was applied in the second part to calculate the additional costs cased by the different electricity generation technologies. These costs have been considered again in the previously developed MESSAGE model of national and regional cases in order to evaluate their influence on the structure of electricity generation options of the optimal solution.

Figure 1-3: Impacts pathway Approach of SIMPACTS

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22.. PPRROOFFIILLEESS OOFF AARRAASSIIAA CCOOUUNNTTRRIIEESS ARASIA countries are located in the east part of the Arab world (Figure 2-1). They share borders with Turkey, Iran and Egypt in addition to the surrounding Mediterranean and red sea, Arab golf and Indian Ocean. The total area is almost 2 million square kilometres with a population of almost 100 million habitants. The participating ARASIA countries in the present project comprise Syrian Arab Republic, Kingdom of Jordan, Lebanon, Republic of Iraq, Kingdom of Saudi Arabia, Republic of Yemen, and United Arab Emirate. Table 2-1 gives an overview on selected general information about the energy situation in ARASIA countries [1].

ARASIA-Countries

Figure 2-1: Geographical Location of ARASIA Countries (Courtesy of ESCWA). Table 2-1: General Information on ARASIA Countries (2003)

Per Cap Country Population

[million] Area [Tkm] GDP (PPP)3

[US$] Primary

Energy [toe] Electricity

[kWh] Jordan 5.3 90 1800 (4220) 1.0 1340 Syria 17.765 185.3 1224 (3620) 0.9 1128 Lebanon 4.4 10.45 3894 (4360) 1.6 2588 Iraq4 25.6 437 916 (3200) 1.1 1250

3 Source: Human Development Report, UNDP 2004 4 Iraqi energy data are roughly estimated.

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Saudi Arabia 25.2 865 8612 (12650) 3.8 5500 UAE 4.036 83.6 22000 (22420) 9.6 11006 Yemen 20.2 457 537 (870) 0.2 135

3670 1.86 2427 Total 102.5 2128.3 Average per Cap Status of Power Sector ARASIA countries are embedded in two blocks. The first Block (Mashreq Block) includes the electric systems of Jordan, Syria and Lebanon, which are synchronously interconnected with each other and with Egypt and Turkey. The block has in 2002 a total installed capacity of 26 GW, the annual consumption was of roughly 119 TWh and the peak load about 18 GW (Table 2-2). The total length of electrical lines is of about 15000 km, distributed on the voltage levels from 500 kV to 60 kV. The existing interconnections in this Block are part of the six countries interconnection project that includes Egypt, Jordan, Lebanon, Syria and Turkey. Palestine and Iraq are expected to be part of this area after the year 2005. Egypt was connected in 1999 to Jordan, via a 400 kV submarine cable from Aqaba (in Jordan) to Taba (in Egypt). The Jordan System was connected in 2001 to Syria through a single circuit 400 kV overhead transmission line from Amman North (in Jordan) to Der Ali (in South Syria). Furthermore, Syria is connected to Turkey via a 400 kV transmission line [1]. Besides, Syria is connected to Lebanon with a commercial capacity of 250 MW, which allowed the Lebanese system to import around 1418 GWh.

The second Block is the Arabian Gulf Block of which only Saudi Arabia and United Arab Emirates are participated in the present ARASIA project (Table 2-2). In 2001, the Gulf countries had a total installed capacity of around 84 GW with an annual electricity demand of about 342 TWh. Six of these Gulf countries - Bahrain, Kuwait, Oman, Qatar, Saudi Arabia and United Arab Emirates (UAE) - created in May 1981 the Cooperation Council for the Arab States of the Gulf (GCC). Their installed capacity is of 46,5 GW, while their electricity demand is of 192 TWh. Table 2-2: Status of power sector in ARASIA countries (2003) [1], [6]

Country Installed Capacity (GW)

Peak Load (GW)

Total Production (TWh)

Jordan 1.78 1.43 7.99 Syria 7.00 5.018 29.53 Lebanon 2.64 1.75 10.68 Iraq 8.00 6.50 34 Saudi Arabia 30 26.2 145 UAE 12.917 9.27 50.277 Yemen 0.997 0.766 4.096 ARASIA-Total 63.3 50.65 281.57

Egypt* 15 11.00 75 Turkey* 31.76 21.00 * Both countries are interconnected to ARASIA block

In August 2001, the GCC created a Power Grid Authority to supervise the implementation of their interconnection project (project to interconnect all 6 national

25

grids).The GCC Power Grid Authority, comprising representatives of all six GCC countries is based in Dammam. The first phase of the interconnection project will consist in linking the power grids of Saudi Arabia, Kuwait, Bahrain and Qatar. The United Arab Emirates and Oman will be linked in a second phase.

Studies to investigate the interconnection of the GCC Grid with the Mashreq have shown that this could be accomplished by linking the Kuwaiti and Iraqi grids, or the Saudi and Jordanian grids, or the Saudi and Egyptian grids. The first option is at present very unlikely due to political considerations. As for the other two options, more studies need to be performed, although the latter option seems to be the preferred one due to the sheer size of the Egyptian and Saudi grids, compared to that of the Jordanian grid [6]. In the following general overview of ARASIA countries on geography, demography, macro-economy and main features of national energy system is presented.

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2-1 IRAQ

2-1-1 Geography and Climate of Iraq Iraq is located in Middle East, 33 00 N, 44 00 E coordinates, and bordered by Kuwait (240km), Iran (1,458 km) , Turkey (352 km) , Syria (605 km) , Jordan (181km) , and Saudi Arabia (814km) .The country slopes from mountains over 3,000 meters(10,000ft) above sea level along the border with Iran and Turkey to the remnants of sea–level marshes in the southeast. Much of the land is desert or wasteland. The mountains in the northeast are an extension of the alpine system that runs eastward from the Balkans into southern Turkey, northern Iraq, Iran, and Afghanistan, terminating in the Himalayas. Total area of Iraq is 437072 sq km (land 432162 sq. km & water 4910 sq. km), 13.12 % of the land is arable. The climate of Iraq is mostly desert, mild to cool winters with dry, hot, cloudless summers. The average temperatures rang from higher than 48C in July and August to below freezing in January. Most of the rainfall occurs from December through April and averages between 10 and 18 centimeters (4 – 7 in) annually. The mountainous region of northern Iraq receives appreciably more precipitation than the central or southern desert region.

2-1-2 Demography of Iraq The population of Iraq was about 22.7 million in 1998 and grew during the following years by an average rate of 2.4% to arrive 25.6 million in 2003. In addition to the majority of Arab (about 80%) the Iraq contains different ethnic groups of Kurd (15%), Turcoman, Chaldean and Assyrian (5%). The official language of Iraq is Arabic and whereas Kurdish is additional official language in the north region with Kurdish majority. Table 2-II summarizes the main demographic figures of Iraq. Table 2-II: Summary of main demographic figures of Iraq. Total population of Iraq 25,6 million (2003 est.). Population in Baghdad (5.7 million, 2004 estimate). Population growth rate 2.44% (for the period 1998-2003). Ethnic groups Arab75%-80%, Kurd 15%-20%, Turcoman, Chaldean, Assyrian,

Or others less than 5% . Religions Muslim 97%, Christian 2%, others less than 1%. Languages Arabic (Official), Kurdish (Official in Kurdish regions), Assyrian,

Armenian. Birth rate 31.44 births / 1,000 populations (2007 est.) Death rate 5.26 deaths/1,000 population (2007 est.) Sex ratio at birth ; 1.05male(s)/female Under 15 years 1.032male(s) / female 15 – 64 years 1.026 male(s) / female 65 years and over 0.891 male(s) / female total population 1.024 male(s)/ female (2007 est.) Infant mortality rate, total 47.04 deaths / 1,000 live births

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Male 52.73 deaths / 1,000 live births Female 41.07 deaths / 1,000 live births Life expectancy at birth total population Male 68.04 years Female 70.65 years(2007est.) Total fertility rate 4.07 children born/women (2007 est.)

2-1-3 Macro Economy and National Accounts of Iraq Historically, Iraq's economy was characterized by a heavy dependence on oil exports and an emphasis on development through central planning. Prior to the outbreak of the war with Iran in September 1980, Iraq's economic prospects were bright .Oil production had reached a level of 3.5 million barrels per day, and oil revenues were $ 21 billion in 1979 and $27 billion in 1980 .At the outbreak of the war, Iraq had amassed and estimated $ 35 billion in foreign exchange reserves .

The Iran-Iraq war depleted Iraq's foreign exchange reserves, devastated its economy, and left the country saddled with a foreign debt of more than $ 40 billion. After hostilities ceased, oil exports gradually increased with the construction of new pipelines and the restoration of damaged facilities .Iraq's invasion of Kuwait in August 1990, subsequent international sanctions , damage from military action by an international coalition beginning in January 1991, and neglect of infrastructure drastically reduced economic activity .Government policies of diverting income to key supporters of the regime while sustaining a large military and internal security force further impaired finances, leaving the average Iraqi citizen facing desperate hardships.

Implementation of a UN oil-for-food program in December 1996 improved conditions for the average Iraqi citizen. In December 1999, Iraq was authorized to export unlimited quantities of oil to finance essential civilian needs including, among other things, food, medicine, and infrastructure repair parts. The drop in GDP in 2001-02 was largely the result of the global economic slowdown and lower oil prices. Per capita food imports increased significantly, while medical supplies and health care services steadily improved. The occupation of the US-led coalition in March-April 2003 resulted in the shutdown of much of the central economic administrative structure. The rebuilding of oil, electricity, and other production is proceeding steadily in 2004 with foreign support and despite the continuing internal security Incidents. A joint UN and World Bank report released in the fall of 2003 estimated that Iraq's key reconstruction needs through 2007 would cost $55 billion. According to the General Accounting Office as of April 2004, total funds available towards this rebuilding effort include: $21 billion in US appropriations, $18 billion from the Development Fund for Iraq, $2.65 billion in vested and seized assets of the former regime, and $13.6 billion in international pledges. The US and other nations continue assisting Iraqi ministries, to the extent requested by the IIG (Iraqi Interim Government), and offer extensive economic support. Table 2-I1 summarizes selected main economic indicators of Iraq.

Table 2-I1: Major Economic Activities of Iraq. GDP official exchange rate (2006 est.) $40.66 billion GDP per capita (2006 est.) $2,900 GDP real growth rate (2006 est.) 2.4%

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GDP purchasing power parity (2006 est.) $87.9 billon Inflation rate (2006 est.) 64.8% Unemployment rate (2005 est.) 27%

Budget (2006 est.) $33.4 billion revenues $41.0 billion expenditures.

Natural resources: Oil, natural gas, Phosphates, sulfur. Exports (2006 est.) $30 billion Imports (2006 est.) $29.7 billion

2-1-4 Main Feature of Iraqi Energy System Oil Iraq contains 115 billion barrels of proven oil reserves, the third largest in the world (behind Saudi Arabia and Canada), concentrated overwhelmingly (65 percent or more) in southern Iraq. Estimates of Iraq's oil reserves and resources vary widely, however, given that only about 10 percent of the country has been explored. Some analysts believe, for instance, that deep oil-bearing formations located mainly in the vast Western Desert region could yield large additional oil resources (possibly another 100 billion barrels or more), but have not been explored. Iraqi oil reserves vary widely in quality, with API gravities in the 22º (heavy) to 35º (medium-light) range. Iraq's main export crude comes from the country's two largest active fields: Rumaila and Kirkuk. The southern Rumaila field, which extends a short distance into Kuwaiti territory, has around 660 wells and produces three streams: Basra Light (normally 34ºAPI); Basra Medium (normally 30º API, 2.6 percent sulfur); and Basra Heavy (normally 22º-24ºAPI, 3.4 percent sulfur). Basra Blend normally averages around 32º API, 1.95 percent sulfur, but reportedly has become heavier and sourer recently at around 31.5º API and 2.7 percent-2.8 percent sulfur content. The northern Kirkuk field, first discovered in 1927, forms the basis for northern Iraqi oil production. Kirkuk, with an estimated 8.7 billion barrels of remaining reserves, normally produces 35º API, 1.97 percent sulfur crude, although the API gravity and sulfur content both reportedly deteriorated sharply in the months just preceding the war. Kirkuk's gravity, for instance, had declined to around 32º - 33º API, while sulfur content had risen above 2 percent. Figure 2-I2 shows the development of Iraqi oil production during the last two decades. Historically, Iraqi production peaked in December 1979 at 3.7 million bbl/d, and then in July 1990, just prior to its invasion of Kuwait, at 3.5 million bbl/d. From 1991, when production crashed due to war, Iraqi oil output increased slowly, to 600,000 bbl/d in 1996. With Iraq's acceptance in late 1996 of U.N. Resolution 986, which allowed limited Iraqi oil exports in exchange for food and other supplies ("oil-for-food"), the country's oil output began increasing more rapidly, to 1.2 million bbl/d in 1997, 2.2 million bbl/d in 1998, and around 2.5 million bbl/d during 1999-2001. Iraqi monthly oil output increased in the last few months of 2002 and into early 2003, peaking at around 2.58 million bbl/d in January 2003, just before the war.

29

Figure 2-I2: Development of Iraqi oil production and consumption for the period 1980-2004 Prior to the recent war, experts of oil industry assessed Iraq's sustainable production capacity at no higher than about 2.8-3.0 million bbl/d with net export potential of around 2.3-2.5 million bbl/d (including smuggled oil). Approximately 2 million bbl/d of Iraq's production pre-war capacity came from southern oil fields and 1 million bbl/d from northern oil fields. Table 2-I1 shows the geographic distribution of Iraqi oil production. Table 2-I1: Distribution of Iraqi oil production by geographic site.

Southern Iraq Northern/Central Iraq

South Rumaila (0.8 million bbl/d) Kirkuk (around 550,000-700,000 bbl/d)

North Rumaila (0.5 million bbl/d) Bay Hassan (100,000-150,000 bbl/d)

West Qurnah (250,000 bbl/d) Jambur (75,000-100,000 bbl/d)

Az Zubair (200,000-240,000 bbl/d) Khabbaz (30,000 bbl/d)

Misan/Buzurgan (100,000 bbl/d) Ajil (25,000 bbl/d)

Majnoon (50,000 bbl/d) East Baghdad (20,000 bbl/d)

Jabal Fauqi (50,000 bbl/d) 'Ayn Zalah/Batmah (17,000-20,000 bbl/d)

Abu Ghurab (40,000 bbl/d)

Luhais (30,000-50,000 bbl/d)

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Crude oil exports during May 2006 averaged 1.5 million bbl/d. Increased production impact on exports will be partially moderated by a fire that destroyed 70 percent of the Khor al-Amaya port facility at the end of May. The facility handled about 5 percent of oil exports, but with the northern export route frequently threatened by attack and the Basra terminal near capacity, this will hurt the prospect of increased oil exports from the country. Repair work will probably take up to four months, according to Iraqi oil officials. Under optimal conditions, and including routes through both Syria and Saudi Arabia that are now closed or being utilized for other purposes, Iraq's oil export infrastructure could handle throughput of more than 6 million bbl/d (2.8 via the Gulf, 1.65 via Saudi Arabia, 1.6 via Turkey, and perhaps 300,000 bbl/d or so via Jordan and Syria). However, Iraq's export facilities (pipelines, ports, pumping stations, etc.) were seriously disrupted by the Iran-Iraq war (1980-1988), the 1990/1991 Gulf war, the most recent war in March/April 2003, and periodic looting and sabotage since then. Refining Iraq's refining capacity was 597,500 bbl/d as of January 1, 2006, compared to a nameplate capacity of 700,000 bbl/d. Overall, Iraq has eight refineries, none of which were damaged during the March-April 2003 war itself. The three largest refineries are the 310,000-bbl/d Baiji, 150,000-bbl/d Basra, and 110,000-bbl/d Daura plants. In May 2005 Iraq, signed contracts to upgrade Daura Capacity to 170,000 bbl/d. Also, on April 1, 2005, Iraq also announced plans to build a new oil refinery in Basra, with a capacity of 250,000-300,000 bbl/d. Iraqi refineries currently are operating at only 50 percent-75 percent of capacity, forcing the country to import around 200,000 bbl/d of refined products, at a cost of $200-$250 million per month. In early December 2005, construction began on two new refineries – a 140,000-bbl/d facility in Karbala province and a 30,000-bbl/d plant at Diwaniya (south of Baghdad). The two plants are expected to be completed within three years . Natural Gas Iraq contains 110 trillion cubic feet (Tcf) of proven natural gas reserves, along with roughly 150 Tcf in probable reserves. About 70 percent of Iraq's natural gas reserves are associated (i.e., natural gas produced in conjunction with oil), with the rest made up of non-associated gas (20 percent) and dome gas (10 percent). Until 1990, all of Iraq's natural gas production was from associated fields. In 2004, Iraq produced 62 billion cubic feet (Bcf) of natural gas, down sharply from 215 Bcf in 1989. Since most of Iraq's natural gas is associated with oil, progress on increasing the country's oil output will directly affect the gas sector as well. Most associated gas is flared off due to a lack of sufficient infrastructure to utilize it; according to Iraq’s oil ministry, 60 percent of all natural gas production is flared off. Significant volumes of gas also are used for power generation and re-injection for enhanced oil recovery efforts. So owns only fossil resources of oil and natural gas. Oil is the main energy resource in Iraq, The main sources of Iraqi associated natural gas production are the Kirkuk, Ain Zalah, Butma, and Bay Hassan oil fields in northern Iraq, as well as the North and South Rumaila and Zubair fields in the south. The Southern Area Gas Project was completed in

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1985, but was not brought online until February 1990. It has nine gathering stations and a larger processing capacity of 1.5 billion cubic feet per day (Bcf/d). Prior to the war, natural gas gathered from the North and South Rumaila and Zubair fields was carried via pipeline to a 575-million-cubic-foot-per-day (Mmcf/d) natural gas liquids (NGL) fractionation plant in Zubair and a 100-Mmcf/d processing plant in Basra. At Khor al-Jubair, a 17.5-million-cubic-foot LPG storage tank farm and loading terminals were added to the southern gas system in 1990. After the 2003 war, gas gathering and treatment facilities in southern Iraq reportedly deteriorated to the point that most gas produced in the area was simply flared off. Iraq is looking at plans for increasing associated natural gas processing capability in Zubair and West Qurna and to reduce gas flaring. Iraq’s only non-associated natural gas production is from the al-Anfal field (200 Mmcf/d of output) in northern Iraq. Al-Anfal production, which began May 1990, is piped to the Jambur gas processing station near the Kirkuk field, located 20 miles away. Al-Anfal’s gas resources are estimated at 4.5 Tcf, of which 1.8 Tcf is proven. In November 2001, a large non- associated natural gas field reportedly was discovered in the Akas region of western Iraq, near the border with Syria, and containing an estimated 2.1 Tcf of natural gas reserves. It is not clear weather the field is associated or non-associated. Besides Al-Anfal, Iraq has four large non-associated natural gas fields (Chemchamal, Jaria Pika, Khashm al Ahmar, Mansuriya) located in Kirkuk and Diyala provinces. Iraq has a major natural gas pipeline with the capacity to supply around 240 MMcf/d to Baghdad from the West Qurna field. The 48-inch line was commissioned in November 1988, with phases II and III of the project never completed due to war and sanctions. The last two phases of the pipeline project were meant to supply Turkey, which now has little need for the gas due to an oversupply in that country. Iraq's Northern Gas System, which came online in 1983, was damaged during the Gulf War as well as by the Kurdish rebellion of March 1991. The system supplied LPG to Baghdad and other Iraqi cities, as well as dry gas and sulfur to power stations and industrial plants. Iraq also has a Southern Gas System, which came online in 1985. Iraq plans to increase its natural gas output in order to reduce dependence on oil consumption, to use for petrochemicals production, and possibly for export at some point. Prior to the 1990/1991 Gulf War, Iraq exported significant volumes of natural gas to Kuwait. The gas came from Iraq's southern Rumaila field through a 40-inch, 100-mile, 300 Mmcf/d pipeline to Kuwait's central manifold at Ahmadi. The gas was used in Kuwaiti electric power stations and liquefied petroleum gas (LPG) plants. Currently, Kuwait and Iraq are making plans to restart the pipeline. A memorandum of understanding between the two governments was concluded in December 2004. The first phase of the project is modest, involving only 35 Mmcf/d, which would be transported through the existing pipeline. The second phase would involve an $800 million investment in refurbishment of the pipeline and associated pumping stations, which would allow the volume to increase to 200 Mmcf/d. For the time being, though, the security situation in Iraq has prevented even the first phase of the plan from being implemented. In addition, Iraq and Kuwait have discussed joint development of the Siba natural gas field which straddles the two countries border near Iran. Prior to the war, Iraq had even been developing plans to build a liquefied natural gas (LNG) terminal. In late September

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2004, Iraq reportedly agreed to join the Arab Gas Pipeline project linking Egypt, Jordan, Syria and Lebanon.

2-1-5 Structure of Iraqi Power Sector During the period 2000-2005 the peak load demand grew steadily from 6120 MW to about 8845 MW in the year 2005, which refers to an annual average growth rate of about 7.6%. In the year 2005, the total generated electricity arrived 33.5 TWh. However, the generated power is significantly below the actual demand due to the lack on installed capacity and the technical condition of available power plants. The total installed capacity for the year 2005 arrived 12937 MW distributed to 22% for hydro, 38% for gas fired power plants and 40% fuel fired power plants. The electricity consumption by sector is shown in Figure I-3. The house hold sector had the highest share with 58%, followed by industry (14%), service sector (24%) and agriculture 4%.

Load DistributionCommercial 8%

Agricultural 4%

Governmental 16%

Industrial 14%

Houseeholds 58%

Figure I-3: Distribution of Iraqi electricity consumption by sectors (2005)

2-1-6 Iraqi Energy policy After long years of war the development of energy infrastructure with the ultimate purpose of expanding the oil production is main goal of Iraqi energy policy. The oil revenues are essential to supporting the rebuilding process in all economy sector including providing energy services to all segments of society at cost effective and affordable price.

The policy of electric power system in Iraq has been developed by ministry of electricity (MOE) as platform for building a new and robust power system. The official policy of power sector faces allot of challenges that comprise aging of electrical system, spare parts availability, fuel supply and capacity building, in addition to many other logical and infrastructure problems. The ultimate goals of MOE are:

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o Develop and increase existing power stations capacity to cover incremental power demand in iraq.

o Stop further deterioration of power system by executing efficient maintenance programs and commencing comprehensive rehabilitation of power plants as well as transmission and distribution networks.

o Improve performance and efficiency of the power system achieve greater stability and reliability of power supply to consumers implement the measures to maintain the sustainability of the power system.

o Develop and expand transmission and distribution network throughout the country by projects for electrification new residential areas.

o Provide best possible services to all classification of consumers ( household , commercial , industrial , agricultural and governmental ).

o Interconnect Iraq’s power system network with the neighboring countries and beyond to operate as apart of the seven countries interconnection in the region.

o Develop human resources and train them to provide high level professional services.

o The policy also intended to allow outside investors participation in building new electricity infrastructure for strengthening the generation , transmission , distribution sectors under BOO (build , own , operate ) contracts and BOOT ( build , own , operate , transfer ) or under PPAs (power purchase agreements ) or under IPP ( independent power producers ) .

o Coordinate with ministry of oil to available the quantities of fuel for existing power stations and for new projects of power plants by increase the oil production and develop anew gases fields and develop pipe line to transfer the gas to plants.

o In future also intended to increase the share of renewable energy specially the solar electric generating station.

o At last we would like to talk about the challenges which are the ministry of electricity faced.

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2-2 JORDAN

2-2-1 Geography and Climate of Jordan The Hashemite Kingdom of Jordan is located in the west part of Asia between 35°-39° eastern longitude and 29°-33° northern latitude, its situated in the great land bridge between Europe, Africa and Asia. Its bounded on the north by Syria, on the north east by Iraq, on the east and south by Saudi Arabia, and on the west by the Palestinian National authority. The total area of Jordan is 90,000 Km2, seven percent of the land is arable. The Kingdom's terrain provides a range of landscapes. The Badia plains lie to the east with mountains in the center, in the west the Jordan River flows through its fertile valley into the Dead Sea, the lowest point on earth. The port of Aqaba in the south gives Jordan a narrow out let to the Red Sea. The climate of Jordan is flounced by the Mediterranean Sea and continental landmass of central Asia, therefore, the climate of Jordan varies from cold-wet winter and sunny–dry summer in north western area (Amman and hilly areas), to the desert conditions in the east and south eastern area.

2-2-2 Demography of Jordan Because of the returnees due to the Gulf crisis, Jordan faced an unbalance in the population increment. Growth rate was estimated at 10.5% due to the flow of about 200,000 returnees from the Gulf. Jordan's population in 2003 (Base year of the study) was 5.3 million inhabitants. Amman, the capital of the country is the most populated city in Jordan with about 2 million inhabitants.

2-2-3 Macro economy and National Accounts of Jordan Within the Kingdom, remarkable progress has been made toward entrenching the democratization process and toward effecting a through structural adjustment of the economy. In order to ensure that the full benefits of the reform program have been complemented by sector – specific reforms and investment in human and physical capital, emphasis has been placed on enhancing the role of the private sector. This role has been clearly reflected in the country's five-year Economic and Social Development plan for 1999-2003, which, among other things, calls for an unhampered private sector growth in the productive fields. The new economic strategy underscores the role of Government as a regulatory and supportive body. Attention was subsequently directed at reforming the relevant legislative framework, modernizing the financial institutions, and fostering a transparent institutional policy environment that would allow a greater role for private investors, both domestic and foreign. Jordan's economy would thus be able to emerge, adapt to, and compete in the world market. Some of the early yields of Jordan's strategy are already obvious. All economic indicators in Jordan have consistently improved over the last five years, inflation has been contained

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at below 2.3%, and the current account deficit brought down to about 1.3 percent of GDP. The first phase of the economic reform program, which has started few years ago, has resulted in a strong positive turnaround in the country's economic performance. The second phase has been designed with a view to deepening and expediting the reform process to reach the goal of a self-sustaining economy before the next decade. Jordan's Economic and Social Development plan for 1999-2003 stipulated a range of broad principles, which are intended to guide the future course of the national economy. The first principle is the "liberalization of the economy and its institutions, elimination of distortions obstructing sound economic performance, and development of an appropriate investment climate.

2-2-4 Main Features of Jordan’s Energy System Energy is of vital importance for the processes of production and manufacturing and, as such, a key element of sustainable development. During the last two decades, the rising cost of energy has posed a difficult challenge for Jordan due to country's meager local resources of economic energy and its reliance on imports. Over the last decades, the cost of imported oil constituted about 6-12% of the gross domestic product (GDP), 32-129% of exported goods, and 12-19% of imports. The demand for primary energy in 2003 was 5.77 million toe which represents an annual growth of 8%. This growth was mainly due to the economic growth witnessed in the Kingdom. The average energy consumption per capita in 2003 was 1064 kg oil equivalent (kgoe) compared to 994 kgoe in 1996. In recent years, Jordan has been undergoing a momentous transformation process, based on a major restructuring of country's economy. This includes reduction in governmental expenditures, new regulations for monetary stability and tax reform and Jordan does not have significant crude oil resources. Limited finds of natural gas have been made in the eastern desert, indicating the availability of some hydrocarbon resources. Oil shale locations have been identified containing more than 40 billion tons of oil shale that can be exploited by open pt methods. The energy and electricity sectors in Jordan are under the supervision of the Ministry of Energy and Mineral Resources (MEMR), which was established in 1984. The principal role of MEMR is to define and assist in implementing national energy policy and has responsibility of securing the country's energy needs from different foreign sources. The policy of MEMR is aimed at attracting private sector (International or local) involvement, in the form of either direct investment or through the implementation of projects on a build-own-operate (BOO) or build-own-transfer (BOT) basis. The schemes include energy projects covering power generation, refining capacity expansion, oil and gas exploration and production, and investment in renewable energy such as solar energy and biomes.

2-2-5 Structure of Electric Power Sector of Jordan In order to improve the functioning and standards of Jordan's electricity sector, the MEMR is creating the enabling environment for private sector investment in power

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generation and distribution by establishing a general policy to deal with private power producer's(IPP's), including the percentage share of private power procedures in total electricity generation in the country, in addition to the energy purchase through short or long term agreement, and is willing in principle to consider the concept of (BOO) scheme. Almost the whole country, 99.9% of total population is supplied with electricity. The total electricity consumption amounted in 2003 to 7.34 TWh whereas the total generation arrived about 8 TWh. The peak load was 1428 MW in 2003. The growth rate of Jordan's peak load is expected to be 5% for the period 2003-2020 and the growth rate of its generated electricity energy is expected to be 5% for the same period. The latest generation expansion plan for Jordan shows that the amount of generating capacity needed annually for local consumption is almost 100 MW starting from the year 2003. These next power generation projects are expected to be as Independent Power Producers (IPP's). In regards to oil and gas exploration, Jordan is favourably situated between the Precambrian outcrop belt and rich oil-producing areas of the Gulf Cost Geosynclines, making it a prime prospective frontier area. The country is offering production-sharing agreement to investors interested in oil and has exploration in the country.

2-2-5-1 Renewable Current Government targets for renewals are very ambitious. Thus, Increased focus is required on research in renewable energy resources in Jordan. In this regard Jordan is trying to maximise the use of solar energy through strengthening the solar thermal market and related industry. The offers for constructing two wind power stations of 30 MW for each were evaluated. The project will be built on the basis of BOO by the private sector. The estimated total investment cost is about 70 million US$. The CEGCO was established to utilize methane gas (biogas) extracted from the organic wastes for electricity generation. It is a joint sharing company owned by CEGCO and Greater Amman Municipality. CEGCO operates a power station of 1 MW in Rusaifa. There are plans to increase this capacity to 6 MW.

2-2-5-2 Existing Generation System : The existing power plants of Jordan generation system are listed below..

Aqaba Thermal Power Station Aqaba Thermal Power Station (ATPS) located at the southern part of Aqaba Gulf. The power station consists of five steam units with installed capacity of 5x130MW, in addition to two hydraulic units with 6 MW installed capacity. Imported Natural Gas is the primary fuel used to fire the power station and Heavy Fuel Oil is used as secondary fuel. Open cooling system by sea water is used. The first , and the second units were put in service in 1986, while the third and fourth units in 1996 and the fifth was installed in 1999.

Hussein Thermal Power Station

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Hussein Thermal Power Station (HTPS) located in the middle of Jordan, 9km to the north of Zarqa city. The installed capacity is 396MW, with 3x33 MW and 4x66MW steam units in addition to 19MW and 14MW gas turbine units. The steam units are air cooled units fired with Heavy Fuel Oil while the gas turbines are fired with Diesel Oil. The power station was installed between 1977 and 1983.

Al Risha Power Station Al Risha power station located at the eastern borders of the kingdom 350km east of Amman, the installed capacity is 150MW comprises of 5x30MW Gas Turbines fired by Natural Gas extracted from the local field of Risha. The secondary fuel is Diesel Oil. The quantities of Natural Gas is limited to fire three Gas Turbines, the other two Gas turbines are fired with Diesel Oil. The power station was constructed in 1989 with two Gas Turbines, the other three Gas Turbines were added on stages up to the year 2005.

Rehab Power Station Rehab power station is located 70 km north of Amman. The installed capacity is 360 MW comprises of 2x30MW Gas Turbines and 1x300MW Combined Cycle unit. It is fired by Natural Gas as a primary fuel and Diesel Oil as a secondary fuel. The units were added to the power station during the years 1994 up to year 2005. Samra Power Station: Samra Power Station located near Hussein Thermal Power Station with installed capacity of 1x300MW Combined Cycle unit. Natural Gas is used as a primary fuel and the Diesel Oil is the secondary fuel. It is built during the years 2005-2006.

Small Gas Turbines The generation system contains many other Gas Turbines units at Marka Power Station (4x20MW), Karak Power Station (1x20MW) and at Amman South Power Station (2x30MW). These Gas Turbines are fired with Diesel Oil.

King Talal Dam The generation system contains two small Hydro units (2x3MW), these units are used to generate electrical power during the flow of water from the dam for irrigation purposes.

Biogas Energy The Biogas energy is used to generate electrical power from the Biogas project located at Russifa near Zarqa with 4MW capacity.

Wind Energy The total installed capacity of wind turbines is about 1.5 MW at Hofa and Alibrahemih locations in the north of Jordan. Figure (2.1) shows the geographical locations for all power stations in the Jordanian electrical system.

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Figure(2.1): Existing power plant locations

Due to temperature effect on generation units at time of peak load, the available generation capacity in the Jordanian electrical system up to the end of year 2006 is about 2000 MW.

2-2-6 Energy Policy of Jordan The significant national aims in energy sector in Jordan are to perform adequate energy provision for sustainable development, with the least cost. To reduce heavy burden on Jordan's economy, future strategy is based on exploitation of all available local energy

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sources in attempt to minimize reliance on imported energy as far as it is feasible. The concerned strategy features are:

- Ensure security of supply of all energy forms and strengthening regional interconnections (electricity and gas).

- Diversification of energy sources, such as using natural gas to gradually replace fuel oil in the different industries and in generating electric power in the regard.

- Increasing the share of renewable energy in the total mix of primary energy, to realize the objective of meeting 3% of the Kingdom's needs of energy using these sources in the foreseen future up to the year 2020.

- Adopting the principle of privatization in order to alleviate the administrative and procedural restrictions, so that the private sector would be free to invest and produce according to the market's forces, in a competitive environment, where privileges are abolished, monopoly is outlawed, and the standard of services is improved and their efficiency are increased.

- Pursuing the efforts aiming at exploiting the oil shale which exists abundantly in Jordan.

- Marketing the exploration regions in Jordan, attracting the international oil companies to explore for oil and gas, and signing with them agreements of partnership for production.

- Formulate pricing policies and improve pricing levels and structures. - Reform of the petroleum sector by starting work to gradually liberalize petroleum,

rationalize pricing and tax structure and dismantle monopoly. - Promotion of energy efficiency to reduce energy intensity and curb demand

growth.

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2-3 KINGDOM OF SAUDI ARABIA (KSA)

2-3-1 Geography and Climate of KSA KSA is located between the Arabian Gulf and the Red Sea with a total area of 865,000 square miles. The Major Cities are Riyadh (royal capital), Jeddah (administrative capital), Mecca, Medina, Dammam, Jubayl,Abha, Buraydah.

2-3-2 Demography of KSA The total Population according to the statistic of 2005 amount to 26.4 million, including 5.6 million foreign nationals. With present average annual population growth rate of 2.3% the population for the year 2003 is estimated to 25.2 million. The country ethnic groups are Arab (90%), Afro-Asian (10%). Macro economy and National Accounts of KSA

With oil export revenues making up around 90-95 percent of total Saudi export earnings, 70-80 percent of state revenues, and around 40 percent of the country's gross domestic product (GDP), Saudi Arabia's economy remains, despite attempts at diversification, heavily dependent on oil (although investments in petrochemicals have increased the relative importance of the downstream petroleum sector in recent years).

The combination of relatively high oil prices and exports led to a revenues windfall for Saudi Arabia during 2004 and early 2005. For 2004 as a whole, Saudi Arabia earned about $116 billion in net oil export revenues, up 35 percent from 2003 revenue levels. Saudi net oil export revenues are forecast to increase in 2005 and 2006, to $150 billion and $154 billion, respectively, mainly due to higher oil prices. Increased oil prices and revenues since the price collapse of 1998 have significantly improved Saudi Arabia's economic situation, with real GDP growth of 5.3 percent in 2004, and forecasts of 5.7 percent and 4.8 percent growth for 2005 and 2006, respectively.

For fiscal year 2004, Saudi Arabia originally had been expecting a budget deficit. However, this was based on an extremely conservative price assumption of $19 per barrel for Saudi oil -- and assumed production of 7.7 million bbl/d. Both of these estimates turned out to be far below actual levels. As a result, as of mid-December 2004, the Saudi Finance Ministry was expecting a huge budget surplus of $26.1 billion, on budget revenues of $104.8 billion (nearly double the country's original estimate) and expenditures of $78.6 billion (28 percent above the approved budget levels). This surplus is being used for several purposes, including: paying down the Kingdom's public debt (to $164 billion from $176 billion at the start of 2004); extra spending on education and development projects; increased security expenditures (possibly an additional $2.5 billion dollars in 2004; see below) due to threats from terrorists; and higher payments to Saudi citizens through subsidies (for housing, education, health care, etc.). For 2005, Saudi Arabia is assuming a balanced budget, with revenues and expenditures of $74.6 billion each.

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In spite of the recent surge in its oil income, Saudi Arabia continues to face serious long-term economic challenges, including high rates of unemployment (around 13 percent of Saudi nationals, possibly higher), one of the world's fastest population growth rates, and the consequent need for increased government spending. These entire place pressures on Saudi oil revenues. The Kingdom also is facing serious security threats, including a number of terrorist attacks (on foreign workers, primarily) in 2003 and 2004. In response, the Saudis reportedly have ramped up spending in the security area (reportedly by 50 percent in 2004, from $5.5 billion in 2003). Saudi Arabia's per capita oil export revenues remain far below high levels reached during the 1970s and early 1980s. In 2004, Saudi Arabia earned around $4,564 per person, versus $22,589 in 1980. This 80 percent decline in real per capita oil export revenues since 1980 is in large part due to the fact that Saudi Arabia's young population has nearly tripled since 1980, while oil export revenues in real terms have fallen by over 40 percent (despite recent increases). Meanwhile, Saudi Arabia has faced nearly two decades of heavy budget and trade deficits, the expensive 1990/1991 war with Iraq, and total public debt of around $175 billion. On the other hand, Saudi Arabia does have extensive foreign assets -- around $110 billion -- which provide a substantial fiscal "cushion."

Movement towards economic reform (e.g., reducing subsidies) in Saudi Arabia remains uneven at best. In addition, the countryalso made only slow progress on another of its main domestic goals -- attracting foreign direct investment (FDI). In January 2004, the Saudi cabinet approved a reduction in taxes on foreign direct investment (to 20 percent in most sectors; 30 percent in the natural gas sector) as part of an effort to speed up the economic reform and privatization process in the country.

Currently, large state corporations, like oil firm Saudi Aramco (which has a monopoly on Saudi upstream oil development, workforce of 54,000, and controls 98 percent of the country's oil reserves) and the Saudi Basic Industries Corporation (SABIC; the world's 11th largest petrochemical producer) dominate the Saudi economy. To date, there has not been a single sale of state assets to private control, and privatization largely has been limited to allowing private firms to take on certain service functions. In May 2002, Saudi Oil Minister Ali Naimi (reappointed in May 2003 for a third, four-year term) stated that the country was considering privatizing some operations of Saudi Aramco. One impetus for Saudi privatization is its desire to join the World Trade Organization (WTO), but progress has been slow towards achieving this goal, and there were no signs of an imminent breakthrough as of December 2004.

In general, Saudi Arabia also has moved cautiously and slowly towards government subsidy cuts, tax increases, or financial sector reforms. Saudi leadership (King Abdullah, in particular) has indicated that it sees privatization -- although controversial -- as a "strategic choice," and has created (in August 1999) a "Supreme Economic Council" charged with boosting investment, creating jobs for Saudi nationals, and promoting privatization. In May 2000, a new law aimed at attracting foreign investment to the Saudi energy sector came into effect. The law permits full foreign ownership of Saudi property and licensed projects, sets up the General Investment Authority (SAGIA) as a "one-stop shop" for foreign investors, and reduces taxes on company profits from 45 percent to 30 percent. Previously, foreign companies were limited to a 49 percent share of joint ventures with Saudi domestic partners. Several important sectors, however, remain closed

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to 100 percent foreign ownership, including (as of July 2005): upstream oil, pipelines, media and publishing, insurance, telecommunications, defense and security, and more. Thus, the foreign investment law is far less attractive than it appears at first glance.

2-3-3 Main Features of Saudi Energy System Oil

Saudi Arabia contains 261.9 billion barrels of proven oil reserves (including 2.5 billion barrels in the Saudi-Kuwaiti Divided, aka "Neutral" Zone), around one-fourth of proven, conventional world oil reserves. Around two-thirds of Saudi reserves are considered "light" or "extra light" grades of oil, with the rest either "medium" or "heavy." Although Saudi Arabia has around 80 oil and gas fields (and over 1,000 wells), more than half of its oil reserves are contained in only eight fields, including Ghawar (the world's largest oil field, with estimated remaining reserves of 70 billion barrels) and Safaniya (the world's largest offshore oilfield, with estimated reserves of 35 billion barrels). Ghawar's main producing structures are, from north to south: Ain Dar, Shedgum, Uthmaniyah, Hawiyah, and Haradh. Ghawar alone accounts for about half of Saudi Arabia's total oil production capacity.

Aramco estimates that the average total depletion for Saudi oil fields is 28 percent, with the giant Ghawar field having produced 48 percent of its proved reserves. Aramco also claims that, if anything, Saudi oil reserves are underestimated, not overestimated. Some outside analysts, notably Matthew Simmons of Houston-based Simmons and Company International, have disputed Aramco's optimistic assessments of Saudi oil reserves and future production, pointing to -- among other things -- more rapid depletion rates and a higher "water cut" than the Saudis report.

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Figure 2-4: Development of Saudi oil production and consumption.

Saudi Arabia is the world's leading oil producer and exporter. For January-July 2005. EIA estimates that Saudi Arabia produced around 10.9 million bbl/d of total oil including crude oil, natural gas liquids and other liquids oil (Figure 2-4). This was up sharply from Saudi Arabia's 8.5 million bbl/d of total oil production in 2002 (see graph). Currently, Saudi Arabia is estimated to be producing around 9.6 million bbl/d of crude oil, well in excess of its current quota level of 9.099 million bbl/d (effective July 1, 2005). In addition to crude oil, Saudi Arabia produces around 1.3 million bbl/d of natural gas liquids (NGLs) and "other liquids," not subject to OPEC quotas.

Saudi Arabia produces a range of crude oils, from heavy to super light. Of Saudi Arabia's total oil production capacity, about 65 percent-70 percent is considered light gravity, with the rest either medium or heavy; the country is moving to reduce the share of the latter two grades. Lighter grades generally are produced onshore, while medium and heavy grades come mainly from offshore fields. The Ghawar field is the main producer of 34o API Arabian Light crude, while Abqaiq (a super-giant field with 17 billion barrels of proven reserves) produces 37o API Arab Extra Light crude. Since 1994, the Hawtah Trend (also called the Najd fields), which includes the Hawtah field and smaller satellites (Nuayyim, Hazmiyah) south of Riyadh, has been producing around 200,000 bbl/d of 45o-50o API, 0.06 percent sulphur, Arab Super Light. Offshore production includes Arab Medium crude from the Zuluf (over 500,000 bbl/d capacity) and Marjan (270,000 bbl/d capacity) fields and Arab Heavy crude from the Safaniya field. Most Saudi oil production, except for "extra light" and "super light," is considered "sour," containing relatively high levels of sulfur.

Saudi Arabia's long-term goal is to further develop its lighter crude reserves, including the Shaybah field, located in the remote Empty Quarter area bordering the United Arab Emirates. (In June 2005, the UAE said it wanted to amend a 1974 border pact which gave the Saudis rights to Shaybah, which lies 80 percent in Saudi territory and 20 percent in UAE). Shaybah contains an estimated 15.7 billion barrels (or higher) of premium grade 41.6

o API sweet (nearly sulfur-free) Arab Extra Light crude oil, with

production as of May 2005 at around 500,000 bbl/d. Overall, the Shaybah project cost around $2.5 billion, with production starting in July 1998. According to Oil Minister Naimi (October 1999), the development of Shaybah showed that "the cost of adding...capacity - that is, all the infrastructure, producing and transportation facilities - necessary to produce one additional barrel of oil per day in Saudi Arabia is, at most, $5,000 compared to between $10,000 and $20,000 in most areas of the world." Plans are to increase Shaybah output by as much as 300,000 bbl/d in the next few years.

The Shaybah complex includes three gas/oil separation plants (GOSPs) and a 395-mile pipeline to connect the field to Abqaiq, Saudi Arabia's closest gathering center, for blending with Arab Light crude (Berri and Abqaiq streams). In addition to oil, Shaybah has a large natural gas "cap" (associated gas), with estimated reserves of 25 trillion cubic feet (Tcf). Gas production of 880 million cubic feet per day (Mmcf/d) is reinjected, along with natural gas liquids (NGLs). A possible gas recovery project could be implemented within 5 or 6 years, potentially for use in petrochemical production.

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In March 2002, Aramco awarded major turnkey contracts to Italy's Snamprogetti ($630 million) and Technip-Coflexip ($360 million) aimed at increasing total Saudi oil production capacity by 800,000 bbl/d (500,000 bbl/d of Arabian light and 300,000 bbl/d of Arabian medium). The $1.3 billion project, known as the Qatif producing facilities development program (QPFDP), involved construction of two gas-oil separation plants (GOSPs), as well as gas treatment and oil stabilization facilities, for the Qatif and Abu Saafa oilfields. Additional Qatif and Abu Saafa production had been slated to replace production elsewhere in Saudi Arabia, not to boost overall capacity, although recently this issue has been thrown into some question as the Saudis attempt to maintain a spare capacity cushion in the face of rapidly growing world oil demand. As of December 2004, Saudi Arabia reportedly had brought production from Qatif and Abu Saafa online.

Another project, at the Khurais field west of Ghawar, could increase Saudi production capacity (of Arab Light) by 1.3 million bbl/d at a cost of $3 billion. This is to involve installation of four GOSPs, with a capacity of 200,000 bbl/d each, at Khurais, which first came online in the 1960s but was mothballed by Aramco.

Several other fields -- Abu Hadriya (1.8-2.0 billion barrels in reserves), Fadhili (1-1.4 billion barrels), Harmaliyah, Khursaniyah (3.5 billion barrels), and Manifa -- were mothballed by the Saudis during the the 1990s, but could be brought back online given high world oil demand and the desire to maintain Saudi spare production capacity. In particular, Saudi Aramco appears to be pushing ahead with development of the Abu Hadriya, Fadhili and Khursaniya (AFK) onshore fields. In March 2005, the Saudis awarded eight contracts for work at Khursaniya and also at Hawiya (see below). The Saudis reportedly have "fast tracked" development at AFK. Production of 500,000 bbl/d (medium, 35

o API) of Arab Light from the AFK fields could begin in late 2007. Besides

AFK, the Saudis are planning to increase Arab Light production from the 1-billion-barrel Nuayyim onshore field by 100,000 bbl/d in 2009.

The $280 million Haradh-3 project aims to increase production capacity at the Haradh oil field to 900,000 bbl/d by February 2006. This will involve adding a third, 300,000-bbl/d GOSP to Haradh (in addition to two other 300,000-bbl/d GOSPs, one of which was inaugurated in January 2004). Haradh also will produce significant volumes of non-associated natural gas, natural gas condensates (perhaps 170,000 bbl/d), and sulfur. The project is being carried out by Aramco, along with private companies like Foster-Wheeler.

Refining/Downstream Saudi Arabia has eight refineries, with combined crude throughput capacity of around 1.75 million bbl/d, plus around 1.6 million bbl/d of refining capacity overseas. The Rabigh refinery on the Red Sea coast is slated for upgrade, with plans to shift the refinery's product slate away from low-value heavy products towards gasoline and kerosene. In addition, there is talk of building a $4 billion, 400,000-bbl/d heavy conversion export refinery in Yanbu. In July 2004, Aramco signed an agreement with Shell to purchase a 9.96 percent share in Showa Shell Group, a refining and marketing company based in Japan. Under the deal, Aramco will supply Showa Shell with 300,000 bbl/d of crude oil. In March 2005, Saudi

45

Arabia and India signed an agreement on oil cooperation, with the Saudis reportedly interested in acquiring a stake in the 300,000-bbl/d Paradip refinery and the 152,000-bbl/d Vizakh refinery in India. Saudi Aramco also is reported to be considering a forward oil stockpile and a 400,000-bbl/d, $3 billion refinery in India. In July 2005, a new, $3.6 billion refinery and petrochemical plant complex was inaugurated in Fujian, China. The facility is a joint venture between Sinopec (50 percent), ExxonMobil (25 percent), and Saudi Aramco (25 percent). Crude oil for the plant is to be supplied by Saudi Arabia. Aramco reportedly is in talks with Sinopec on building a second major Chinese refinery, in the northern province of Shandong. Both plants will be able to handle high sulphur ("sour") oils, which is important because there is a dearth of such capacity worldwide. Exports, Ports, Pipelines, Shipping

Saudi Arabia is a key oil supplier to the United States and Europe. Asia (e.g., China, Japan, South Korea, India) now takes around 60 percent of Saudi Arabia's crude oil exports, as well as the majority of its refined petroleum product exports. During the first five months of 2005, Saudi Arabia exported 1.57 million bbl/d of oil (of which 1.51 million bbl/d was crude) to the United States. For this time period, Saudi Arabia ranked fourth (after Canada, Mexico, and Venezuela) as a source of total (crude plus refined products) U.S. oil imports, and third for crude only. Saudi Arabia is eager to maintain and even expand its market share in the United States for a variety of economic and strategic reasons. During the first five months of 2005, Saudi Arabia's share of U.S. crude oil imports was 14.9 percent, up from 13.9 percent during the first five months of 2004.

Most of Saudi Arabia's crude oil is exported from the Persian Gulf via the huge Abqaiq processing facility, which handles around two-thirds or so of the country's oil output. Saudi Arabia's primary oil export terminals are located at Ras Tanura (6 million bbl/d capacity; the world's largest offshore oil loading facility) and Ras al-Ju'aymah (3 million bbl/d) on the Persian Gulf, plus Yanbu (as high as 5 million bbl/d) on the Red Sea. Combined, these terminals appear capable of handling around 14 million bbl/d, around 3.0-3.5 million bbl/d higher than Saudi crude oil production capacity (10.5-11.0 million bbl/d), and about 4 million bbl/d in excess of Saudi crude oil production during the first half of 2005. Despite this excess capacity, there have been reports that the Saudis are planning to conduct a feasibility study on construction of an oil pipeline from the Empty Quarter of southeastern Saudi Arabia through the Hadramaut in Yemen to the Arabian Sea.

Saudi Arabia operates two major oil pipelines. The 5-million-bbl/d East-West Crude Oil Pipeline (Petroline), operated by Aramco since 1984 (when it took over from Mobil), is used mainly to transport Arabian Light and Super Light to refineries in the Western Province and to Red Sea terminals for export to European markets. The Petroline was constructed in 1981, with initial capacity of 1.85 million bbl/d on a single, 48-inch line (AY-1). The Petroline was expanded in 1987, during the height of the Iran-Iraq war (and specifically the so-called "tanker war" in the Gulf), to 3.3 million bbl/d, with the addition of a parallel ("looped") , 56-inch line (AY-1L). Finally, in 1993, Petroline capacity was increased to 5.0 million bbl/d by adding significant pumping capability on the line. Reportedly, the Saudis expanded the Petroline in part to maintain

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Yanbu as a strategic option to Gulf port facilities in the event that exports were blocked at that end.

In purely economic terms, Yanbu remains a far less economical option for Saudi oil exports than Ras Tanura. Among other factors, shipments from Yanbu add about 5 days roundtrip travel time for tankers through the Bab al-Mandab strait to major customers in Asia compared to Ras Tanura (via the Strait of Hormuz). In addition, according to Oil Minister Naimi, the Petroline is only utilized at half capacity.

Running parallel to the Petroline is the 290,000-bbl/d Abqaiq-Yanbu natural gas liquids pipeline, which serves Yanbu's petrochemical plants. The Trans-Arabian Pipeline (Tapline) to Lebanon is mothballed, and the 1.65-million-bbl/d, 48-inch Iraqi Pipeline across Saudi Arabia (IPSA), which runs parallel to the Petroline from pump station #3 (there are 11 pumping stations along the Petroline, all utilizing on-site gas turbine electric generators) to the port of Mu'ajjiz, just south of Yanbu, was closed indefinitely following the August 1990 Iraqi invasion of Kuwait. In June 2001, Saudi Arabia seized ownership of IPSA "in light of the Iraqi government's persistence in its stands." Theoretically, IPSA could be used for Saudi oil transport to the Red Sea, although the Saudis have stated that "there are no plans" to do so. According to Oil Minister Naimi, Saudi Arabia has "surplus oil export and pipelines capacity...[including the] East-West oil pipeline system [which] can carry and deliver 5 million bbl/d" but is being run at "only half capacity."

Aramco's shipping subsidiary Vela has around 20 VLCC's (very large crude carriers) and 4 ULCC's (ultra large crude carriers), carrying a significant proportion of Saudi oil exports. In September 2004, the Saudis placed a $200 million for two VLCCs from Hyundai Heavy Industry, with delivery expected in 2007. In addition to tankers, Aramco owns or leases oil storage facilities around the world, in places like Rotterdam, Sidi Kerir (the Sumed pipeline terminal on Egypt's Mediterranean coast), South Korea, the Philippines, the Caribbean, and the United States. Natural Gas Saudi Arabia's proven natural gas reserves are estimated at 235.0 trillion cubic feet (Tcf), ranking fourth in the world (after Russia, Iran, and Qatar). Most (around 60 percent) of Saudi Arabia's currently proven natural gas reserves consist of associated gas, mainly from the onshore Ghawar field and the offshore Safaniya and Zuluf fields. The Ghawar oil field alone accounts for one-third of the country's proven natural gas reserves. However, it is important to note that only 15 percent of Saudi Arabia has been "adequately explored for gas," according to Aramco. The Natural Gas Production in 2003 amounted at 2.1 Tcf. Most new associated natural gas reserves discovered in the 1990s have been in fields which contain light crude oil, especially in the Najd region south of Riyadh. Most of Saudi Arabia's non-associated gas reserves (Mazalij, Al-Manjoura, Shaden, Niban, Tinat, Al-Waar, etc.) are located in the deep Khuff reservoir, which underlies the Ghawar oil field. Natural gas also is located in the countries extreme northwest, at Midyan, and in the Empty Quarter (Rub al Khali) in the country's southeastern desert. The Rub al Khali alone is believed to contain natural gas reserves as high as 300 Tcf. In June 2004, gas was discovered at the Fazran 23 well located near Dhahran.

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Another large natural gas field, called Dorra, is located offshore near the Khafji oil field in the Saudi-Kuwaiti Divided Zone and may be developed by Japan's AOC. Dorra development is controversial, however, because part of it is also claimed by Iran (which calls the field Arash). The maritime border between Kuwait and Iran remains undemarcated, but Saudi Arabia reached an agreement with Kuwait in July 2000 to share Dorra equally. Currently, Iran is resisting any moves by Kuwait and Saudi Arabia to develop the field on their own.

In June 2003, Saudi Oil Minister Naimi officially announced termination of negotiations with foreign energy companies on the $15-$20 billion "Saudi Gas Initiative" (SGI), which had promised to be the first major reopening of Saudi Arabia's upstream hydrocarbons sector to foreign investment since nationalization in the 1970s. Companies which had been selected (in 2001) for the three "core ventures" under the SGI were: 1) South Ghawar -- ExxonMobil (35 percent), Shell (25 percent), BP (25 percent), Phillips (15 percent); 2) Red Sea -- ExxonMobil (60 percent), plus Marathon (20 percent) and Occidental (20 percent); and 3) Shaybah -- Shell (40 percent), Total (30 percent), and Conoco (30 percent). The SGI had aimed to increase foreign investment and natural gas development in the country, while integrating upstream gas development with downstream petrochemicals, power generation, and water desalination. SGI had been seen as the key to Saudi Arabia's entire foreign investment strategy. However, negotiations broke down over two major stumbling blocks: the extent of gas reserves to be opened to upstream development and whether or not this should include gas from the Saudi Aramco Reserve Area (SARA); and the rates of return to participating companies (the companies wanted a significantly higher rate than the Saudis were offering).

Core Venture 1, in South Ghawar, would have been one of the world's largest ($15 billion) integrated natural gas projects, including exploration, pipelines, two gas-fired power plants, two petrochemical plants, two desalination units, and more. Core Venture 2 was to involve exploration in the Red Sea, development of the Barqan and Midyan fields on the Red Sea coast in northwestern Saudi Arabia, as well as construction of a petrochemical plant, a power station, desalination capacity, etc., at a cost of $4 billion. Core Venture 3 would have involved exploration near Shaybah in the Empty Quarter, development of the Kidan gas field, laying of pipelines from Shaybah to the Haradh and Hawiyah natural gas treatment plants east of Riyadh, and construction of a petrochemical plant in Jubail, at a cost of $4 billion.

Following cancellation of the SGI, Saudi Arabia repackaged the project as a series of smaller, more focused contracts, with better rates of return than previously offered. At the same time, the Saudis moved away from the integrated upstream/downstream gas, water, power, and petrochemical nature of the SGI, and instead specifically targeted upstream natural gas development in the area that had comprised Core Venture 3. Downstream and "midstream" elements of the SGI will now be handled separately, in large part by SABIC and Aramco. In July 2003, Saudi Arabia reached a tentative deal (officially signed on November 15) with Royal Dutch/Shell and Total on Blocks 5-9 and 82-85 in the Shaybah and Kidan areas of the Empty Quarter region. Besides the major European companies, Saudi Aramco -- replacing ConocoPhillips -- will have a 30 percent share in the $2 billion project. Shell will maintain a 40 percent share and Total the

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remaining 30 percent, in a consortium known as the South Rub al-Khali Company (SRAK). The deal covers an area of 81,000 square miles.

In January 2004, Russia's Lukoil won a tender to explore for and produce non-associated natural gas in the Saudi Empty Quarter. Lukoil will operate in Block A, near Ghawar, as part of an 80/20 joint venture (called "Luksar") with Saudi Aramco. Also in January 2004, China's Sinopec won a tender for gas exploration and production in Block B, while an Eni-Repsol consortium was granted a license to operate in Block C. Under terms of the agreements, Aramco will take "sales quality gas" on a take-or-pay basis for $0.75 per million Btu, while condensates and natural gas liquids will be sold at international market rates (note: Saudi accession to the WTO will most likely require it to give up the dual pricing system for natural gas, and also to set up a comprehensive, transparent regulatory framework for the natural gas sector). In addition, the Saudi government will fund a pipeline connection from the country's Master Gas System (MGS) to contract delivery points.

In October 2002, construction was completed on a $4 billion, 1.4-billion-cubic-feet (Bcf)-per-day, non-associated gas processing plant at Hawiyah, located south of Dhahran and east of Riyadh near the giant Ghawar oil field. Hawiyah represents the largest Saudi natural gas project in more than 10 years, and the first to process only non-associated gas (from the deep Khuff and Jauf reservoirs). Hawiyah was officially inaugurated in October 2002, and reportedly is producing enough natural gas to free up around 260,000 bbl/d of Arabian Light crude oil for export. Aramco also has invited bids to expand Hawiyah to recover "hundreds of thousands of barrels daily of additional petrochemical feedstock," primarily NGLs from the treatment of 4 billion cubic feet (Bcf) per day of natural gas. In March 2005, Japan's JGC was awarded a contract for Hawiya that involves building the world's largest NGL processing plant.

Besides Hawiyah, Foster Wheeler has been managing a $2 billion project to build a new natural gas processing plant at Haradh, 120 miles southwest of Dhahran at the southern tip of Ghawar. The Haradh plant was completed in the summer of 2004, increasing total Saudi natural gas processing capability by 1.6 Bcf/day, to around 9.5 Bcf/day. Haradh processes non-associated natural gas (both sweet and sour) from four fields in the Khuff formation. In addition, a $1.3 billion, 3,800-Mmcf/d "straddle plant" -- a natural gas reprocessing plant located adjacent to a gas transmission line for the purpose of extracting light hydrocarbon liquids newly formed due to recurring compression and decompression of gas during transmission -- is slated to be built. When complete, the straddle plant will service both Haradh and Hawiyah and increase Saudi NGL production.

In other natural gas-related developments, a key pipeline project was completed in June 2000 to extend the MGS from the Eastern Province (which contains large potential gas and condensate reserves) to the capital, Riyadh, in the Central Province. This is part of a broader expansion of the existing gas transmission system in Saudi Arabia, reportedly to include the construction of around 1,200 miles of additional natural gas pipeline capacity (on top of 10,500 miles of oil, gas, condensate, products, and natural gas liquid pipelines currently in operation) by 2006. Domestic demand is driving expansion of the MGS, which was completed in 1984. The MGS feeds gas to the industrial cities of Yanbu on the Red Sea and Jubail, which combined account for 10

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percent of the world's petrochemical production. Prior to the MGS, all of Saudi Arabia's natural gas output was flared.

2-3-4 Structure of Electric Power Sector of KSA Saudi Arabia's rapidly growing population and artificially low power prices (as a result of low, government mandated tariffs and consumer subsidies) are increasing demand on electric utilities, as power demand grows by 7 percent or more each year (Figure 2-4).

Figure 2-4: Development of Saudi electric power consumption.

Saudi Arabia's Industry and Electricity Ministry estimates that the country will require up to 20 gigawatts (GW) of additional power generating capacity by 2019 nearly the same amount as today's 26.6 GW at a cost of $4.5-$6 billion per year. Most of this money is slated to come from the private sector, possibly including foreign investors. Also, the vast majority of this capacity will either be natural gas-fired or combined cycle, as part of the government's plans to expand gas utilization in the power sector (and elsewhere) significantly. On February 16, 2000, Electricity Minister Dr. Hashem Ibn Abdullah Yamani signed a merger agreement between Saudi Arabia's 10 existing regional power companies (SCECOs), and on April 5, 2000, the long-anticipated SEC, a joint-stock company owned 50 percent by the Saudi government, was established. Creation of the SEC could open the door to private sector construction of new power plants on BOO (Build-Own-Operate) and BOT (Build-Own-Transfer) bases. The future of IPP's (Independent Power Producers) in Saudi Arabia remains uncertain, however, with major challenges including tariffs, the legal and operating framework, taxation, and fuel supply. In January 2003, the Electricity Services Regulatory Authority (ESRA) was set up as an independent "watchdog" in charge of the country's power sector, IPPs, and IWPPs (independent water and power projects). In early July 2005, Saudi Arabia's first IPP came online at Jubail, with a capacity of 250 MW. The cogeneration facility was built by Siemens, and the operator is the Jubail Energy Company joint venture.

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Several recent projects have employed financing mechanisms that are new to Saudi Arabia's electric power sector. For example, the $1.7 billion, Ghazlan II power project was financed by an internationally syndicated, $500 million, commercial loan (the first such loan in Saudi history), and was built by a consortium led by Mitsubishi and Bechtel. Ghazlan II consists of four, 600-MW steam turbine units, the first of which came online in the summer of 2001. Combined with the existing 1,600-MW Ghazlan I facility located on the Gulf coast north of Dammam, the entire complex has a power generating capacity of 4,000 MW and supplies Saudi Arabia's Eastern Province. In July 2002, the Supreme Economic Council passed a resolution setting out a framework for private sector involvement in developing IWPPs. Saudi Arabia reportedly is hoping to attract private sector investment for up to 60 percent equity in IWPP projects. Initial IWPP projects identified for development include a $1 billion, 900-MW, 176-million-gallons-per-day (mmg/d) oil-fired plant at Shuaiba on the Red Sea coast 70 miles southeast of Jiddah; a 700-MW, 23-mmg/d plant at Shuqaiq in the country's southwest; an 850-MW, 212-mmg/d plant at Shaqiq; and a 2,500-MW, 176-mmg/d plant at Ras Az Zour in the Eastern Province. Saudi Arabia's Saline Water Conversion Corp. (SWCC) has estimated that the country will need to spend $50 billion on water projects through 2020 in order to meet the Kingdom's rapidly growing water demand. In March 2004, Gulf News reported that Saudi Arabia planned to establish 10 IWPPs by 2016, at a total cost of $16 billion. In March 2005, the SEC selected Alstom and Saudi Archirodon Construction to build three new 400-MW oil-fired generators at Shuaiba. This should bring generating capacity at the plant to 4,400 MW by 2008. On October 9, 2000, Saudi Arabia approved plans for setting up a new utility company in the twin industrial cities of Yanbu and Jubail. The company, named Marafiq, was founded by the Royal Commission, the Public Investments Fund, Saudi ARAMCO, and SABIC, with local investors also holding a stake. UCO may be privatized when it becomes profitable. In the meantime, UCO has begun several water and power projects in Yanbu and Jubail. In July 2004, Marafiq issued a request for proposals (RFP) for a $2.5 billion, 2,400-MW, 79-mmg/d (of water), gas-fired IWPP in Jubail. Besides generation, Saudi Arabia also requires additional investment in power transmission. At present, around 20 percent of Saudis are not connected to the national power grid (Isolated area with their own generation units). Creating a unified national grid could require over 20,000 miles of additional power transmission lines. Currently, Saudi Arabia has around 150,000 miles of transmission lines. Table 2-7: Structure of Saudi electric power system.

INSTALLED CAPACITY BY TYPE OF GENERATION (MW) STEAM TURBINE

GAS TURBINE DIESEL HYDRO OTHERS TOTAL

10,165 13,684 685 - 3,073 30,091

PEAK DEMAND (MW)

2002 2003 GROWTH (%) RESERVE 2003

23,938 26,272 9.8 14.54%

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2-4 LEBANON

2-4-1 Geography and climate of Lebanon Lebanon is a small Middle Eastern country, bordering the Eastern Mediterranean Sea, between Palestine and Syria. The total area of Lebanon is 10,452 square km. The total Land boundaries is 454 km, border countries are Palestine 79 km, Syria 375 km, The Coastline border is 225 km. The topography is narrow coastal plain; The Bekaa Valley separates Lebanon and Anti-Lebanon Mountains. The Elevation extremes vary between lowest point 0m at Mediterranean Sea and highest point 3,087 m at Jabal al Makmal. The Land use is distributed as following: 21% arable land, 9% permanent crops, 1% permanent pastures, 8% forests and woodland (according to 1993 estimation). The Irrigated land: 860 square km (according to 1993 estimation.) Lebanon climate is Mediterranean: mild to cool, wet winters with hot, dry summers. Lebanon Mountains experience heavy winter snows.

2-4-2 Demography of Lebanon The Central Administration of Statistics (CAS) has estimated Lebanon’s population at 4 million people in 1997 (included the Palestinians, estimated to be around 300,00). Population size is increasing at the rate of 1.65 percent yearly about 66,000 net births in 1999 (CAS Bulletin/No.1, 2000). Thus, the population for the year 2003 can be estimated to 4.4 million. The estimated population distribution by Mohafaza is presented in Table 2-? Table 2-?: Distribution of Lebanon population by Mohafaza

2-4-3 Lebanese Economy The 1975-1991 war had seriously damaged Lebanon's economic infrastructure. Peace has enabled the central government to restore control in Beirut, begin collecting taxes, and regain access to key port and government facilities. Economic recovery has been helped by a financially sound banking system and resilient small- and medium-scale manufacturers, with family remittances, banking services, manufactured and farm exports, and international aid as the main sources of foreign exchange. Lebanon's

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economy has made impressive gains since former Prime Minister HARIRI launched his $18 billion "Horizon 2000" reconstruction program in 1993. Real GDP grew 8% in 1994 and 7% in 1995 before Israel's Operation Grapes of Wrath in April 1996 stunted economic activity. During 1992-1996, annual inflation fell from more than 170% to 10%, and foreign exchange reserves jumped to more than $4 billion from $1.4 billion. Progress also has been made in rebuilding Lebanon's war-torn physical and financial infrastructure. After that, the year 1997 was selected as a base year to compile the 5-year time-series accounts of 1998-2002 for two main reasons: firstly, the data for the year 1997 is sufficient to allow the compilation of the main accounts describing all aspects of the economic life of the country; and secondly, the year 1997 can be described as a "normal" year. The distribution of GDP by the type of economic activity and its evolution for the period 1997-2002 is given in Table 2-!. Figure 2-! presents the GDP distribution by activity for the year 2005. One can see the dominance of service sector on the economy of the country. The stagnation of value added in value, in the sectors of agriculture and industries, results from a fall of prices and a weak real growth. On the other hand, the fall in volume of construction was compensated by a rise in price attenuating the fall in value. The progression of values added in the services, were almost entirely due to the rise in prices. On the other hand, growth of the transport and communication sector was real, since prices in this sector were stable.

Table 2-!: Evolution of Lebanese GDP for the period 1997-2002 by type of activity5.

5 Economics accounts of Lebanon 1997-2002 published on the Ministry of finance website.

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Services 72%

Agriculture 7% Industy

21%

Figure 2-!: Distribution of Lebanese GDP by sector for the year 2005.

2-4-4 Lebanese Energy Sector All energy in Lebanon derived from imported petroleum products and some coal. A modest amount of hydropower and traditional energy (wood and charcoal), representing less than 2 % of energy consumption, is produced locally. Table 2-!! shows the development of energy consumption by fuel type for the period 1995-1999.

Table 2-!!: Development of Lebanese energy consumption by fuel type for the period 1995-1999.

Promoting Renewable Energy Use of solar energy to heat water continues to be very limited in Lebanon! In comparison, neighboring countries such as Cyprus, Jordan etc. have for years relied heavily on solar water heating panels for domestic uses (almost all buildings have solar heaters on the roof). According to ALMEE estimates, the installation of 400,000 solar heaters in Lebanon, over a 10-year period, would entail electric energy savings of about 8 percent, with the following associated positive impacts (ALMEE, 2000): • Avoiding the need to expand the power production capacity by 100 MW (Avoid

capital cost of over US$100 million); • An energy bill lower by about US$30 million over 10 years; and • Sharp reductions in atmospheric pollution from thermal power plants.

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2-4-5 Structure of Electric Power Sector of Lebanon Electricity is supplied through EDL a public establishment working under the jurisdiction of the Ministry of Energy and Water. Generation power plants operate on H.F.O. (Zouk, Hreiche and Jieh as well as Tyr and Baalbeck), Diesel (Zahrani and Beddawi) and some hydro power plants like Litani, Kadisha Safa and Bared. At least two developments will affect the energy sector in Lebanon in the coming years: the substitution of diesel oil with natural gas for operating the Beddawi and Zahrani thermal plants and the privatization of the power generation and distribution sectors. The GoL has signed an agreement with the Syrian government to supply natural gas from Syria to operate the Beddawi (north Lebanon, nominal capacity 435 MW) and Zahrani (center region, nominal capacity 435 MW) power plants. Preliminary designs indicate that the project will be implemented in two phases. During the first phase of the project, a coastal pipeline will extend 40 km from across the Syrian border to Beddawi and will be executed in 2002 at a cost of US$ 12 million. Second pipeline will be constructed extending 132 km from Beddawi to Zahrani. Completion of both pipelines will entail US$ 100 million in annual savings, thus significantly alleviating Lebanon’s energy bill. In addition, using natural gas will reduce air emission loads.

2-4-6 Lebanese Energy policy Current proposals suggest that power generation as well as electricity distribution (and collection of fees) will be privatized while electricity transmission (medium and high voltage network) will remain state owned and operated.

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2-5 SYRIA

2-5-1 Geography and Climate of Syria The Syrian Arab Republic lies on the eastern coast of the Mediterranean Sea, bounded by Turkey to the north, Iraq to the east, Palestine and Jordan from the south and by Lebanon and the Mediterranean Sea to the west. The total area of SAR is about 185.18 thousand km2, from which ca. 32% are cultivated land and the remained is desert and Rocky Mountains. The Syrian Desert is suitable for grass growing and is used as pastures during sufficient rainfall. The climate of the Mediterranean Sea generally prevails in Syria; this climate may be characterised by rainy winter and dry hot summer separated by two short transitional seasons. The coastal region is characterised by heavy rainfall in winter and moderate temperature and high relative humidity in summer. The interior is characterised by a rainy winter season and a hot dry season during summer, the area in the mountains with an altitude of 1000 m or more characterized by rainy winter where rainfall may exceed 1000 mm and moderate climate in summer. The desert region is characterized by small amount of rainfall in winter and hot dry summer.

2-5-2 Demography of Syria The population of Syria was 4.565 million in 1960, but during the following two decades the number doubled to 9 million, and has kept an increasing trend reaching 13.782 million according to the census in 1994. According to the last population census in 2003 the total population reached 17.765. According to the population censuses in 1981 and 1994 the Central Bureau for Statistic (CBS) estimated for the time 1981-1994 an average population growth rate of about 3.3%, which was one of the highest growth rate in the world. Considering the last population censuses in 1994 and 2003 the CBS found out that the growth rate has been decreased rapidly in the last 5 years arriving a recent growth rate of about 2.7% [4]. This decreasing is the result of different factors influencing the demographical situation in Syria. Like changing the life style, increasing of marrying age from 26 to 29 years by male and from 20 years to 25 years by female, increasing the women share in the labour force and other factors6. The population share in rural was significantly higher in the sixties and seventies but in the following years and during the last two decades the population in urban has increased rapidly as results of immigration from rural to urban. The population distribution is now nearly equal in urban and rural. The trend of immigration from country to city - and from all zones to the Damascus and rural Damascus - was a significant demographical phenomenon with saturation tendency in the last 10 years. The effect of this demographic movement was the coming up of many satellite small cities around the big cities like the situation around Damascus.

6 According to Human Development Report 2000 (Table 19, page 225), population growth rate in Syrian Arab Republic (SAR) was 3.2% per annum during the period 1975-1998. This report predicts 2.3% p.a. population growth rate during the period 1998-2015 for the Syria. Total population of SAR will be 22.6 million by the year 2015 of which 62.1% will be in urban areas and 3.5% above the age of 65 years.

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According to the official estimations of the central bureau for statistic It is assumed that the annual growth rate would decrease gradually from the present value of 2.7% to 2% in the next 30% years. The other parameters describing the future development of population distribution indicates the shift to more urbanisation resulting from the fact that big villages will growth more and more to form small cities. On the other side the population share outside large cities will decrease, while the population inside large cities will increase. As result of the expected life style improvement, changing in the social structure and decreasing of children per family the number of capita per household (Cap/hh) will gradually decrease from the actual 6.68 to about 5 persons in the year 2030. This is reflected in the enlarging of household number from the present of 2.38 to about 6.17 million in 2030.

2-5-3 Macro economy and National Accounts of Syria The evolution of GDP by economic sectors at the constant price of 1995 is shown in Table 2-3 for the last 30 years. During this past period the Syrian economy has recorded an average annual growth rate of 5.5%. Beginning with a period of high economic growth rate of 12.6% (1970-1975), a continuous decreasing is recorded in the next 10 years with 7.6% in 1980, 2.4% in 1985 and arriving a negative rate of –1.5% in 1990. The high economic growth in the first period is a result of economy restructuring and political stability coupled with more engagement from the government. In addition to that high financial support was received from the Golf states after the war in 1973. The following decrease of economic growth in the period (1975-1985) may be shown as a trend of recession after a period of high economy as result of economical difficulties ending in economic cries in 1985. The effects of this period are still affecting the Syrian economy, which is largely state-owned economy. After this economic crisis during the period (1985-1990) a high economic growth rate of 8% has been achieved as result of dramatically increase in oil production between 1990-1996, foreigner support after the second Golf ware and new investment law. In 1991, Syria passed Investment Law No. 10, encouraging foreign and Syrian private investment through a combination of tax and custom exemptions, the right to repatriate profits and relaxation of foreign exchange controls. Private investors, with financial backing from the Gulf States, have been expanding into various sectors of industry. This has encouraged the development of textiles, pharmaceuticals, food processing (Non-durable) and other light industries, many built by wealthy Syrians from abroad. Tourism appears to be growing as well. Up 1990 the structure of economy that based until that time mainly on agriculture, foreign aid and remittances from Syrian workers abroad, has changed to more dependency on the oil sector. The new situation has made the Syrian economy very sensitive to oil price fluctuation on the world market. In addition to that roughly 80% of agricultural land is still dependent on rain-fed sources, which makes the dominant agriculture sector climate dependant. This effect can be clearly observed in the low agriculture share in 1997 and 1999 comparing with 1998. The decreasing of agriculture share together with low oil prices caused the fall of the economic growth rate from 7.4% in 1996 to 2.5% in 1997 and from 7.6% in 1998 to even –1.8% in 1999. During the last 5 years a moderate growth rate of almost 2% was resisted. The influence of the already mentioned high population growth rate on the economic growth is still the most important factor. Consequently the GDP/cap has fluctuated between 9% (1975-1970) and about –4% (1990-1985 and 1999-1998) arriving an average

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increase of only 2% during the last 30 years. This means effectively, by considering the inflation rate, a large decrease in the net income of population, which indicates that the economic development of the country was not at the adequate level with the demographic growth. The development of the different economic sectors during the last decades shows an increasing share of service sector which arrived about 50% in 2003 (including transportation & communications), followed from the agriculture sector that has been fluctuated around 30% of the total GDP in all past years. Its share declined from 33% in 1970 to 27% in 1985, which was the lowest, then grew during the following years to 32% and fell again to 27% in 2003 (Figure 2-2). The share of industry (Manufacturing + Mining + Energy sectors) was rather very small with even falling tendency from 10% to 8% in the period (1970-1985). After a relatively large increasing to 13% in the period (1985-1990) a moderate and continues increase to 18.5% is observed in the period (1990-2003). The recorded progressive growth was a direct result of oil production increase starting by 1986 and the passed Investment Law No. 10 in 1991, encouraging foreign and Syrian private investment through a combination of tax and custom exemptions, the right to repatriate profits and relaxation of foreign exchange controls. The share of building & construction sector has increased from 5% to 10% in the period (1970-1985) and then decreased during the following years to stabilize at the lowest value of 4% in 2003. The observed trend in this sector is a direct consequent of the large demand of private dwelling and governmental building in the period 1970-1985. The declining to about 4% in the following period resulted from the lack in construction material, the prices rising as result of economical difficulties up 1986 and the organized constraints on the building progress from the government side. However, the stabilisation of this sector at the level of 4% of the GDP in the last 10 years indicates a saturation tendency. Thus it is expected that this trend will continue with decreasing tendency expected in the next 10 years since the actual dwelling supply is significantly higher than the real demand, especially in big cities. Figure 1.3 presents the GDP distribution by sector in the base year 2003 at the constant price of 2000.

In d u s try& M in in g1 9 %

S e rv ic e5 0 %

C o n s tru c tio n4 % A g ric u ltu r

2 7 %

Figure 2-2: Distribution of the Syrian GDP by type of activity for 2003.

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The future development of economy and its structure represents the main driven mechanism of future energy demand projection. Accordingly the accomplished analysis of future final energy and electricity demand projection of Syria up to the year 2030 relied upon selected economic development scenarios of the country [4]. The reference scenario, being considered to estimate the energy and electricity demand data for this supply study, proposed high annual GDP growth rate of 7% during the whole study period except the first time interval (1999-2005), which should be increased by only 4.5% reflecting the possible lower economic development during the start phase of the proposed economic growth (transient economy). The main driving force to this growth will be the manufacturing sector reflecting the governmental policy in the support of the non-energy intensive industry sectors like manufacturing.

2-5-4 Main Features of Syrian Energy Sector Syrian indigenous energy resources rely on oil, natural gas and limited hydro resources. Oil sector Figure 2-3 shows the development of Syrian oil production during the recent years. Syria's oil industry faces many challenges in the years to come. Oil output and production continues to decline due to technological problems, depletion of oil reserves and low oil prices. Starting in the mid-1980s and into the 1990s, oil production increased dramatically, peaking at about 600,000 barrels per day (bbl/d) in 1996. After this peak the Syria's average oil production decrease continuously to about 561,000 bbl/d in 1997, 553,000 bbl/d in 1998, 530,000 bbl/d in 2000 and about 500, 000 bbl/d in 2004. The proven reserves of oil were estimated to about 2.6 billion barrel in 2002.

Figure 2-3: Development of Syrian oil production and consumption for the period 1990-2006

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Oil output now appears to have begun a steady decline since the production is expected to fall steadily over the next several years. Oil is critical to Syria's economy, accounting for 55%-60% of Syria's total export earnings and more than one-third of its GDP. Syria currently exports Syrian Light, a blend of light and sweet crudes produced primarily from the Deir ez-Zour and Ash Sham fields, and heavy Suwaidiyah crude produced from the Soudie and Jebisseh fields. Syria is a member of OAPEC (the Organization of Arab Petroleum Exporting Countries), although not of OPEC. Syria's main oil producer is al-Furat Petroleum Co (AFPC) a joint venture established in May 1985 between state-owned Syrian Petroleum Company, or SPC (50% share), Pecten Syria Petroleum (15.625%), plus foreign partners Royal Dutch/Shell (15.625%) and Germany's Deminex (18.75%). AFPC's fields are located in the north-eastern Syria -- particularly the Deir ez-Zour region, where commercial quantities of oil were discovered in the late 1980s -- and are producing about 350,000 bbl/d of high quality light crude, a significant decline from 405,000 bbl/d in 1994. In early 1997, Shell and Deminex signed a new oil contract with SPC for exploration in north-eastern Syria. Besides conventional oil reserves, Syria also has major shale oil deposits in several locations, mainly the Yarmouk Valley stretching into Jordan. The reserves amount to 488 million-barrel (65 Mtoe). Exploitation of this oil is not economic below a crud oil price of 30-35 $/bbl. With oil supplies expected to deplete in the next ten years, Syria is concentrating on development and exploration initiatives. Oil exploration activity in Syria has been slow in recent years due to unattractive contract terms by SPC, and poor exploration results. For these reasons, only four companies (Elf, Shell, Deminex, and Marathon) out of 14 operating in the country in 1991 remain in Syria at present. However, under pressure from Shell and Elf Aquitaine, Syria has begun to take a more flexible approach to foreign oil contracts, demonstrated by the publication of a favourable consortium agreement, which is likely to attract other foreign companies [4]. Despite a recent increase in exploration activity, only about 36% of Syria's estimated 800 potential oil and gas structures have been drilled. No major new oil reserves have been discovered since around 1992. With the recent estimation of proven reserves of about 2.5 billion barrel and without significant new discoveries in the next few years, and in view of increasing demand and declining production, Syrian and foreign oil company officials (including Shell, the main foreign operator) believe that the country could become a net oil importer around 2015. The last time Syria was a net oil importer was in 1987; Syria bought from Iraq until April 1982, when it switched to Iran as an ally and oil supplier and closed the 1.1-1.4 million-bbl/d-capacity IPC pipeline from Kirkuk to Banias [4]. Refining/Downstream Syria's two refineries are located at Homs and Banias. Total current production from these refineries is around 240,000 bbl/d (120,000 bbl/d each). Syria is planning to construct a third refinery, with an initial capacity of 60,000 bbl/d (possibly increasing to 120,000 bbl/d), at Deirez-Zour to supply products to the eastern part of the country. A feasibility study on this project reportedly was completed in January 1998. In addition, Syria plans to upgrade its two current refineries, both of which are in urgent need of overhauling, to replace output of fuel oil with light products.

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Syria markets all of its crude oil, including that produced by foreign companies, solely through state marketing company Sytrol. Prices for Syrian Light and Suwaidiyah blends are tied to the price of dated Brent and are adjusted monthly. At present, Sytrol has term contracts with more than 20 companies, including Agip, Bay Oil, Chevron, Conoco, Marc Rich, OeMV, Total, Veba. In January 1999, Royal Dutch/Shell decided to drop its 21,000 bbl/d contract for Syrian Light. Gulf Interstate has also given up its 10,000 bbl/d contract, leaving Sytrol with a restructured contract list of 200,000 bbl/d of Syrian Light. The 65,000-bbl/d slate of customers for Syrian Heavy is unchanged. Since January 1994, Sytrol has had a clause in its term contracts prohibiting customers from re-selling Syrian crude without written permission from Sytrol. Syria's major oil export terminals are at Banias and Tartous on the Mediterranean, with a small tanker terminal at Latakia. Banias can accommodate tankers up to 210,000 dead weight tons (dwt), and has a storage capacity of 437,000 tons of oil in 19 tanks. Tartous can take tankers up to 100,000 dwt, and is connected via a pipeline to the Banias terminal. Latakia can handle oil tankers up to 50,000 dwt. The Syrian Company operates all three terminals for Oil Transport (SCOT), a sister of SPC. SCOT also is in charge of Syria's pipelines, including:

1) a 250,000-bbl/d export line from SPC's north-eastern fields to the Tartous terminal, with a connection to the Homs refinery;

2) a 500,000-tons/year refined products pipeline system linking Homs refinery to Damascus, Aleppo, and Latakia;

3) a 100,000-bbl/d spur line from al-Thayyem and other fields to the T-2 pumping station on the old Iraqi Petroleum Company (IPC) pipeline;

4) a spur line from the al-Ashara and al-Ward fields to the T-2 pumping station. On July 14, 1998, Syria and Iraq signed a memorandum of understanding on reopening the IPC pipeline. The 552-mile, 1.1-1.4 million-bbl/d pipeline was closed in 1982 after a break in diplomatic ties, then severely damaged during the 1991 Gulf War, and now is estimated to require $80 million in repairs. Besides IPC, the Syrian-Iraqi memorandum provided for construction of a new pipeline through Syrian territory to transport Syrian Light crude from the Deir ez-Zour field to Banias. Iraq and Syria also agreed to build a joint 140,000-bbl/d refinery at Banias to handle the blend of Iraqi and Syrian crude being pumped through the pipeline. As of February 1999, Iraq's section of the joint pipeline was close to operation, although the Syrian section was not quite ready, as Damascus was using parts of it to transport its own crude oil. In December 1998, Gazprom of Russia expressed interest in renovating the section of the pipeline, which runs from the Syrian-Iraqi border to Banias.

Natural Gas Syria's proven natural gas reserves for 2002 are estimated at 311 billion cubic metres (equal to about 11 Tcf). Most of these reserves (73%) are owned by SPC, including about 42% in the Palmyra area, 19% at the al-Furat fields, 14% at Suwaidiyah, 9% at Jibeissah, 8% at Deir ez-Zour, and the remainder at al-Hol, al-Ghona, and Marqada. About 54% of Syria's gas is non-associated, with the rest either associated (with oil) or "cap" gas. In 2003, Syria produced about 6.0 billion cubic meters of natural gas, an approximately five-fold increase over the past decade. Syria plans to increase this production even further in coming years, as part of a strategy to substitute natural gas for

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oil in power generation in order to free up as much oil as possible for export. A number of new gas-fired power projects are currently under construction or being planned. About 70% of total gas consumption is used by power plants for electricity production. The remain is going to the fertiliser industry. As increased volumes of natural gas feedstock become available, and given abundant phosphate reserves, Syria is adding capacity to produce fertiliser. At present, Syria has two nitrogenous fertiliser plants and one phosphate-based unit, both located at Homs. Syria also has plans for significant further expansion in fertiliser production, including a 450,000-ton-per-year nitrogenous complex near the northeastern town of Hasaka. This plant would utilise gas from the Omar field. In addition, Bechtel and Makad International are constructing a 500,000-ton-per-year triple-super-phosphate plant near Palmyra [4].

A key challenge for the Syrian natural gas industry is logistical, with gas reserves located mainly in northeastern Syria, while population is centred in western and southern Syria. SPC currently is working to increase Syria's gas production through several projects. The Palmyra area in central Syria is the site of much of this activity, including development of the Al Arak gas field, which came on stream at the end of 1995. Two other "sweet gas" fields in Palmyra include Al Hail and Al Dubayat, both of which came on line in 1996, while two "sour gas" fields -- Najib and Sokhne -- are began production during 1999.

In October 1997, Syria announced discovery of a large new gas field in the Abi Rabah area of the Palmyra region. In addition to supplying a new (completed in 1997), 375-megawatt, power plant at Zaisoun in central Syria, the Palmyra fields also are to be linked with a new pipeline to Aleppo, as well as to the Tishreen power plant in Damascus and the Mhardeh power plant in Homs. As of October 1998, SPC had received several bids for the estimated $80 million contract for the pipeline from Palmyra fields to Aleppo. SPC selected Italy's Tentini to supply and install gas production facilities for the Najib field in the Palmyra region. Najib, the fourth and final field developed in this region, started production in late 1999 at a capacity of 100 milllion cubic feet per day (mmcf/d). In August 1998, the Arab Petroleum Investments Corporation announced that it would lend $50 million to the development of a new gas field in the north Palmya area, as well as partial financing of a new gas plant at Najib and Zara. The loan will be allocated to finance gas projects being executed by SPC.

Syria's Jibeissah gas treatment plant, which came online in 1988, accounts for more than one-quarter of the country's total gas processing capacity. Jibeissah's capacity was increased 88% in a project completed during the first half of 1997. Other gas processing plants include: Deir ez-Zour Gas Treatment Plant (since 1991); Jafra Gas Separation Plant (late 1996) and the Palmyra Gas Processing Plant (late 1996).

Renewable It is planned that renewable energy will participate in supplying not less than 6% of the energy demand in 2020. An industry of solar heaters is under development. It is expected to produce about 20,000 m2 of solar panels. Solar heating passive systems are constructed in 2000 household apartments located south east of Damascus. There is a possibility to construct 500 MW of wind turbines up to the year 2010. These turbines would supply about 1.1% of the total demand of power energy by this year.

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The potential of geothermal energy is rather limited. The potential of biogas has been evaluated at 285 Mm3/year. The public Syrian Solar Company (SOLCO) had started the first countrywide commercial use of modern utilisation of solar energy. SOLCO’s products were passive elements for hot water.

2-5-5 Structure of Syrian Power Sector The peak load demand grew steadily from 3878 MW in 2000 to about 6000 MW in the year 2005, which refers to an annual average growth rate of about 9%.

As a motive force in the development process, electricity sector achieved a huge jump during the same period 2000-2005, resulting in increasing the total generated electricity from 25.2 TWh to 35 TWh. This corresponds to an average annual growth rate of about 7 % [AER, 2006]. The secondary electricity production per capita grew from a 1545 kWh in 2000 to around 2000 kWh in 2005 (Figure 4, 5).

0

5

10

15

20

25

30

35

2000 2001 2002 2003 2004 2005

TW

h

peak load

0 2000 4000 6000

2000

2001

2002

2003

2004

2005

MW

Figure 4: Development of electricity production in the period 2000-2005 (TWh) [AER, 2006]

Figure 5: Peak Load Development 2000-2005 [AER, 2006]

Figure 6 presents the structure of the Syrian electricity generation system by generation type in the year 2005. The total installed capacity amounted to 7160 MW whereas the available installed capacity was 6008 MW distributed to 24% for Hydropower and 76% for fossil fired power plants. The total gross electricity generation in 2005 amounted to 34.9 TWh, whereas the total final electricity consumption amounted to 26.81 TWh that's about 76.82 % of the total generated electricity. The sectoral electricity consumption is shown in figure 6. The house hold sector had the highest share with 47%, followed by industry (31%), service sector and agriculture with 14 % and less than 6% respectively, while the remaining 3% went to mining, construction, and pipeline transporting with less than 1 % for each.

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Electricity Consumption by Sectors (Total = 26.811 TWh)

Transportation0%

Manufacturing31%

Mining1%

Construction1%

Agricultur

e6%

Service14%

Houshold47%

Figure 6: Total Installed capacity by Generation Type

Figure 7: Electricity Consumption By Sectors

2-5-6 Syrian Energy policy The overall target of Syrian energy policy aims at ensuring supply security by providing energy services to all segments of society at cost effective and affordable prices appropriate to Syrian economic conditions. To accomplish this goal Syrian energy policy is faced with three challenges, namely expanding the gas market, sustaining the oil production and developing country’s power capacity [Hainoun, 2004]. To manage these challenges following general implementation measures are considered: o Reducing the technical losses and illegal consumption, o Improvement of energy efficiency, o Encouraging the use of renewables, o Establishing costing oriented price policy, o Saving oil and substituting it by gas, o Attracting foreign investment in oil, gas and power sectors.

A key challenge for the Syrian natural gas (NG) industry is logistical, with gas reserves located mainly in north-eastern Syria, while population is centred in western and southern Syria. SPC currently is working to increase Syria's gas production through several projects aiming at expanding and developing the NG network. The electricity production policy consists in substituting gas by oil in the existing stations and building new stations suitable for gas alone (in 2005 about 90% of generated electricity is thermal origin, from which 40% is gas origin). The Government is in process to relax state monopoly over power sector. There are many efforts to reinforce the transmission and distribution networks, and to improve the quality of customer services.

Total Installed Capacity Distributed by Generation Type in 2005

MW 328051%

1040 MW 16%

MW 1585

24.4%

600 MW 9%

Steam Gas Fiered CC Hydro

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2-6 UNITED ARAB EMIRATES (UAE)

2-6-1 Geography and Climate The United Arab Emirates is a Federation of Seven Emirates (Abu Dhabi, Dubai, Sharjah, Ras Al Khaimah, Fujairah, Ajman and Umm Al Quwain). It is located at Southern tip of the Arabian Gulf. It has borders with the Arabian Gulf from the north and northwest, Saudi Arabia and Qatar from the west, Sultanate of Oman and Saudi Arabia from the south and Gulf of Oman and Sultanate of Oman from the East. It lies between latitudes 22° and 26°. 5 North and longitudes 51° and 56.5° East. The total area of the country is 83,600 km². This includes an archipelago with an area of about 5900 km2. The geographical information of each Emirate is summarized as follow:

1) ABU DHABI It is situated the Arabian Gulf, between latitudes 22.5°, 25° North, and longitudes 51°, 55° East. It is the biggest of all seven Emirates, with an area of 67,340 sq. km., which is equivalent to 86.7% of the country’s total area, excluding the islands. The city of Abu Dhabi is the capital of the Emirate, a number of islands are part of Abu Dhabi Emirate, the most important of which are Das island, Mubraz Island, Zirku Island and Arzana Island, which constitute the main offshore oil fields. Other islands include Delma, Al Sadiyat and Abu El – Abyaadh.

2) DUBAI It stretches along the coast of Arabian Gulf, over a distance of about 72 KM. The area of Dubai Emirate is about 3885 sq. km., which is equivalent to 5% of the country’s total area, excluding the islands. Jebel Ali area is considered one of the most significant industrial and commercial areas in the whole country; it has the biggest free trade zone in the whole Gulf. It comprises the Dry dock, Jabel Ali Port and Dubai Aluminium Factory. The most important tourism landmarks in Dubai are Hatta district, Al Aweer district and Al Khawaneej.

3) SHARJAH: The Emirate of Sharjah is located along the coast of the Arabian Gulf extending over a distance of approximately 16 KM and extending into the interior for distance exceeding 80 KM. The three parts of Sharjah lying on the Gulf of Oman are: Kalba, Khor Fakkan and Dibba El-Husn. The Emirate has an area of 2590 SQ.KM, which is equivalent to 3.3° of the country’s total area, excluding the islands. Sharjah Emirate also encompasses some oasis, that are scattered in the interior, the best known of which is Dhayd area with very rich fertile soil, which produces large quantities of the city of Khor Fakkan, having the main port for the eastern region. The two islands that belong to Sharjah Emirate are Abu Mousa and Sayeer Bou Naa’eer.

4) AJMAN The Emirate of Ajman is located along the coast of the Arabian Gulf extending over a distance of about 16 KM and between the Emirates of Umm al Quwain and Sharjah. The

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area of Emirate is about 259 SQ.KM, which is equivalent to 0.3% of the country’s total area, excluding the islands. The city of Ajman is the capital of the Emirate; it comprises the Ruler’s office, companies, banks and commercial markets. The port of Ajman is located along a natural creek (Khor), which penetrates the town.

5) UMM AL QUWAIN The Emirate of Umm Al Quwain is located on the coast of the Arabian Gulf, stretching over a distance of 24 KM between Sharjah to the West, and Ras Al Khaimah to the East. Its land spreads towards the interior for a distance of 32 KM approximately. The total area of the Emirate is about 777 sq. km, which is equivalent to 1% of the country’s total area, excluding the islands.

6) RAS AL KHAIMAH The Emirate of Ras Al Khaimah is located on the farthest borders of the Arab world, on the Arabian Gulf. Its stretching for a distance of about 64 KM. It extends towards the interior for a distance of 128 KM. It has an extremely mountainous borderline with the Sultanate of Oman to the south and Northeast. A number of islands in the Gulf’s water belong to the emirate, the best known of which are the Bigger Tunb and Lesser Tunb. The area of emirate is 1684 sq. km., which is equivalent to 2.3% of the country’s total area, excluding islands.

7) FUJAIRAH The Emirate of Fujairah is the only emirate situated along the Gulf of Oman, away from Hurmouz Strait. Its coasts extend along the Gulf of Oman over a distance 90 KM. This location gives the emirate a very special strategic importance. The area of the emirate is 1165 sq km, which is equivalent to 1.5% of the country’s total area, excluding islands.

The physical features of UAE are characterized by a chain of rough mountains, containing in between them and the Gulf of Oman, the eastern coastal plain, which is very fertile, Other important areas include Dibba Al Fujairah, which includes the most important agricultural and livestock projects. It is also well known for fishing. The UAE lie in the arid tropical zone, extending across Asia and North Africa. The Indian Ocean affects the climatic conditions in the area, as the country lies on the coastal zone of both the Arabian Gulf and the Gulf of Oman. This also explains why high temperature in summer is always accompanied by humidity. Some noticeable differences in the climatic conditions could be observed among coastal areas, the desert interior areas and mountainous areas. The country is considered one of the world best winter resorts. Between the months of November and March, a moderate warm climate prevails during the day, with an average temperature of 26 C and a lightly cool climate prevails throughout the night, with an average temperature of 15 C. The humidity tends to get higher between the months of June and August. The prevailing winds tend to change between southern or south easterly, western or northern and northwesterly. Rainfall is relatively little, as the average rainfall does not exceed 6.5 cm, annually, and takes place during the months of November to April. More than half of the rainfall is experienced during the months of December and January.

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2-6-2 Demography of UAE The total population of the UAE has increased rapidly from about 0.558 million in 1975 to 3.75 million in 2002 with an average annual growth rate of about 7%. This very high rate is a direct consequent of the immigration policy of the country. Thus, the population in 2003 can be estimated to 4.036 million. However, the Ministry of Planning proposed an annual growth rate of about 2.9% in 2005.

2-6-3 Macro economy and National Accounts of UAE Table 2-4 summarizes the major economic activities of the UAE. Table 2-4: Major Economic Activities of the UAE (2003)7. GDP (US$ MN) 49205 Growth Rate in G.D.P. (%) 2.8 Inflation Rate (%) 2.0 GDP Per Capita (US $ TH) 18.7 Per Capita Manufacturing Product (US$ MN)

2092

Final Consumption Expenditure Per Capita (US $ TH)

12.0

Percentage of Labour Force to Population (%)

50

Per Capita Agriculture Product (US$) 576 Per Capita Agriculture Imports (US$) 835 Fish production (Th.Ton) 114.3 Commodity Imports 55.3 Commodity Exports 67.7 Trade Balance 12.5 Gross Investments (Gross Capital Formation)

27.5

Final Consumption Expenditure 64.3 Deficit in Government Budget 3.8 Distribution of GDP (%) Mining & Quarrying Sector 30.0 Manufacturing Sector 11.3 Construction Sector 8.6 Trade, Restaurants & Hotels Sector 12.5 Transport, Storage & Communication Sector

6.4

Government Services Sector 10.3

7 Source: Ministry of Planning of the UAE.

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2-6-4 Main Features of UAE’s Energy System Oil and Natural Gas UAE belongs to the oil rich countries with significant reserves of about 98 billion barrel. At the recent daily production of about 2.35 million brl/d the life range of oil is very long. The natural gas reserves amount to 6243 billion m3 with the current annual production of about 6.5 billion m3 (Table 2-5 presents). The capacity of oil refinery amounts to 282,000 bbl/d. The primary energy consumption per capita arrived in 2003 about 35 toe, which is one of the highest in ARASIA and world wide; the average annual growth rate of primary energy consumption amounted to about 9%. Table 2-5: General Features of UAE’s Energy System (2003) Crude Oil Production (Th.B/d) 2240 Crude Oil Reserves (Bill.B) 98.1 Natural Gas Reserves (Bill.CU.M) 6243 Natural Gas Production (Bill. CM /Year)

6.4960

Refinery Capacity (TH.B/d) 282 Per Capita Energy Consumption (Equivalent to Oil B/Year)

260

2-6-5 Structure of Electric Power Sector of UAE Table 2-6 gives an overview on the development of electricity consumption, peak load and total installed capacity for the last five years. To meet the increasing electricity demand the electricity generation has increased rapidly with an average annual growth rate of about 7.7% (2000-2004) arriving 53.74 TWh in 2004. The peak load increased during this period from 7336 MW in 2000 to about 10000 in 2004 with an average annual growth rate of about 8%. To meet this peak demand the total installed capacity has enlarged from 9474 MW in 2000 to 14508 MW in 2004 with a present system reserve margin of about 40% that indicates a high level of electricity supply security in the country. Table 2-6: Development of electricity system of UAE 2000 2001 2002 2003 2004 Generation (GWh) 39944 43176 46857 50277 53738 Consumption (GWh) 38110.5 41215.3 45072 48064.1 51292.6 Peak Load (MW) 7336 8128 8743 9268 9956 Installed Capacity (MW) 9474 9462 10659 12917 14508

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2-7 YEMEN

2-7-1 Geographic and climate of Yemen Yemen is in the Middle East, in the south of the Arabian Peninsula in southwest Asia, at 15°N 48°E / 15, 48, bordered by Saudi Arabia to the North, the red Sea to the west, the Arabian Sea and Gulf of Aden to the South, and Oman to the east. Yemen territory includes over than 200 islands. At 527,970 km², Yemen is the world's 49th-largest country (after France). It is comparable in size to Thailand, and somewhat larger than the U.S. state of California. The country can be divided geographically into four main regions: the coastal plains in the west, the western highlands, the eastern highlands, and the Rub al khali in the east. The Tihamah (hot lands) form a very arid and flat coastal plain. Despite the aridity, the presence of many lagoons makes this region very marshy and a suitable breeding ground for malaria mosquitoes. There are also extensive crescent-shaped sand dunes. The evaporation in the Tihamah is so great that streams from the highlands never reach the sea, but they do contribute to extensive groundwater reserves. Today, these are heavily exploited for agricultural use. Near the village of Madar about 48km North of Sanaa dinosaur footprints have been found, indicating that the area was once a mud flat. The Tihamah ends abruptly at the escarpment of the western highlands. This area, now heavily terraced to meet the demand for food, receives the highest rainfall in Arabia, rapidly increasing from 100 mm per year to about 760 mm in tai'zz and over 1,000 mm in Ibb. Agriculture here is very diverse, with such crops as sorghum dominating. Cotton and many fruit trees are also grown, with mangoes being the most valuable. Temperatures are hot in the day but fall dramatically at night. There are perennial streams in the highlands but these never reach the sea because of high evaporation in the Tihama. The central highlands are an extensive high plateau over 2,000 metres in elevation. This area is drier than the western highlands because of rain-shadow influences, but still receives sufficient rain in wet years for extensive cropping. Diurnal temperature ranges are among the highest in the world: ranges from 30 °C in the day to 0 °C at night are normal. Water storage allows for irrigation and the growing of wheat and barley. Sana'a is located in this region. The highest point in Yemen is Jabal an Nabi Shuayb, at 3,666 meters. The Rub ak Khali in the east is much lower generally below 1000 meters, and receives almost no rain. It is populated only by Bedouin herders of camels.

2-7-2 Demography of Yemen The Population of Yemen was estimated to 20.2 million in 2003, with 46% of the population being under 15 years old and 2.7% above 65 years. Yemen has one of the world's highest birth rates; the average Yemeni woman bears seven children. Although this is similar to the rate in Somalia to the south, it is roughly twice as high as that of Saudi Arabia and nearly three times as high as those in the more modernized Arab states of the Arabian Gulf.

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2-7-3 Macro economy and National Accounts: Yemen has experienced economic improvement following several years of internal efforts specially after1990 unification of North and South of Yemen. As a condition for a 1995 loan from the International Monetary Fund (IMF), Yemen's government continues to implement an economic reform program that includes banking reform, privatization of state-run industries, major infrastructure investment, and reduction or elimination of government subsidies, including wheat, flour, diesel/gasoline, and utilities. Oil income makes up an estimated 70% of total Yemeni government revenue. Over the last two years, Yemen's economy has benefited from relatively high oil prices, which have increased the country's hard currency receipts and remittances from Yemeni workers in the Gulf countries. Yemen's real gross domestic product increased 4.0% in 2003 and it is projected to grow 4.2% in 2004.

2-7-4 Main Features of Yemeni Energy Sector The primary energy supply in Yemen is covered by following alternatives: • Wood (as typical energy used in some villages), • Oil and Gas, • Renewable Energy (very rare under and limited to some urban areas). • Solar Energy (limited use in the costal and desert areas).

Oil Yemen is a small, non-OPEC oil producer. According to Oil and Gas Company, the country contains proven crude oil reserves of more than 7.2 billion barrels. Taking the expected offshore reserves the Yemeni government estimates that the country holds around 9 billion barrels of oil reserves, and that as remaining blocks are explored, production will increase in the near future particularly from offshore fields. The oil is concentrated in five areas: Marib-Jawf - Block 18 (estimated 800 million barrels) in the north; Masila -Block 14 (estimated 800+ million barrels) in the south; East Shabwa- Block 10A (estimated 180 million barrels); Jannah- Block 5 (estimated 345 million barrels) and Iyad- Block 4 (estimated 135 million barrels) in central Yemen. Figure1 shows the historical development of oil production between the year 1995 and 2006, it points that the production increased from 348000 bbl/d in 1995 to come to climax in 2001 with daily production of 438000 bbl/d. The production stagnated at this level for the years 2002 and 2003 to decline continuously to 406000 bbl/d, 400000 bbl/d and 380,000 bbl/d in 2004, 2005 and 2006 respectively. In part, according to Yemen's Petroleum Exploration and Production Authority (PEPA), this is due to declining production in Masila and Marib, the country's two largest fields. EIA’s Short-Term Energy Outlook currently projects oil production to be 360,000 bbl/d for 2007 and 350,000 bbl/d in 2008. The government hopes to boost output to 500,000 bbl/d in the next few years and to this end is carrying out an offshore licensing (source: http://www.eia.doe.gov).

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Daily oil pruduction (in Thousand barells)

0

50

100

150

200

250

300

350

400

450

1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 Figure1: Development of oil production during the period 1995-20068 Natural Gas Yemeni Government has estimated its proven gas reserves at about 11 Trillion Cubic Feet (Tcf) and 16.3 Trillion Cubic Feet (Tcf) as estimated reserve.9. The bulk of Yemen's natural gas reserves are concentrated in the (Marib & Masila) Blocks, with 14.5 trillion cubic feet (Tcf), while Damis's Block contributes much less than the other two (Table1). Table1: Estimated gas quantities in (Tcf)

Block Company Operated Estimated reserve 18 _Marib Hunt Oil Company (HOC) 14.5 5_Jannah Hunt Oil Company (HOC) 1.3 S1_Damis Vintage Company 0.5 Total 16.3

Add to that the Government has allocated 5.3 Tcf from the total current reserves for Electricity sector. Furthermore, with reserves of 16.3 trillion cubic feet (Tcf), Yemen has the potential to become a commercial producer and exporter of natural gas. In 2003, there was no production of natural gas in Yemen, despite longstanding plans to develop an export-based liquidated natural gas (LNG) industry. Currently, 30% of the extracted gas as by-product of oil production is reinjected. From the other side and to utilize Yemen's large reserves of associated gas and earn foreign revenues, the Government of Yemen is trying to export natural gas through the construction of the LNG facility. Recently Yemen LNG has been biding for a contract to

8 Source: the sixth annual reports for oil, gas, and minerals statistics 9 According to OGJ, Yemen had 16.9 trillion cubic feet (Tcf) of proven natural gas reserves in 2007

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supply South Korea and USA by LNG by the end of 2008. And if Yemen wins a LNG contract in the near future that would have major effects on the Yemeni budget, which traditionally depends on revenues from oil. On the other side it could also help to develop the domestic gas market. The sector has lagged due to weak investment and marketing prospects, but the push to develop the liquefied natural gas (LNG) sector is likely to increase opportunities for exploration and production. Liquefied Natural Gas Of the 16.3 Tcf of proved natural gas reserves in Yemen, 9 Tcf have been earmarked for the Total-led Yemen LNG (YLNG) project. Despite problems negotiating with the government-owned Safer Exploration and Production for the supply of natural gas from its Marib fields and other delays, work is currently underway at YLNG’s gas liquefaction plant, located at the port of Balhaf near Aden on Yemen’s southern coast. The facility is expected to produce 6.7 million tons per year (900 million cubic feet per day) of LNG. YLNG is also building a 20-mile pipeline connecting the gas processing facilities in Marib’s Block 18 to the liquefaction facilities. Train 1 was expected to come online by December 2008, but delays have pushed back the start up into early 2009. Train 2 is expected to come online by May 2009. The plant plans to export approximately two-thirds of its production to the U.S. and the remainder to Asia. The Yemen Gas Company holds a 23 percent share in the YLNG project and the sector is regulated by the MOMR. The government also has plans to develop the gas resources for domestic industry and 1 Tcf of the country’s proved reserves have been allocated for domestic usage but the downstream sector is limited and there is no established legal framework in place (Source: http://www.eia.doe.gov). Downstream and Refineries Yemen has a limited integrated network of pipelines to transport crude oil and natural gas produced in three central areas. This 560-mile network connects with four longer pipelines that transport oil to several major export terminals. The 260-mile Marib-Ras Isa pipeline is the longest of the domestic pipelines, transporting oil from the Marib basin to the Ra's Isa offshore export terminal on the Red Sea. The pipeline has a capacity of 225,000 bbl/d. The Masila-Shahir pipeline, capable of transporting 300,000 bbl/d, has the largest capacity of pipelines in Yemen. It runs approximately 90 miles from Masila to the export terminal at Ash Shahir. The Shabwa-Rudhum pipeline carries up to 135,000 bbl/d from the Eyad-Shabwa block to the Rudhum terminal on the Gulf of Aden. Jannah-Safir, built in 1996, carries 120,000 bbl/d to production facilities in the Marib region (OGJ). Yemen currently has a crude refining capacity of 130 thousand barrels/day from two refineries. The refinery in Aden, which has been commissioned in 1956, operated by Aden Refinery Company (ARC), has a capacity of 120 thousand barrels/day, while capacity at the Marib refinery, which has been commissioned in 1986, operated by Yemen Hunt Oil Company, is 10 thousand barrels/day. The present domestic demand is estimated to almost 129 thousand barrels/day. The government signed an agreement in December 2002 with the Hadramawt Refinery Company, the country's only private refining company, to construct a 50 thousand barrels/day (rising to 100 thousand barrels/day) capacity at Al Mukalla. The facility is scheduled to be completed by 2008.

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2-7-5 Structure of Electric Power Sector of Yemen According to Yemen's Public Corporation for Electricity (PCE) the total electricity generation in 2003 amounted at about 4096 GWh distributed to 1.465 GWh for diesel power plants and 2.631 GWh steam power plants. The total installed capacity in 2003 was about 997 MW, and the electricity distribution network is inadequate. The estimated peak demand is about 766 MW. It is noticeable that the public grid covers less than 50% of total country load. Additional capacities come from private operators according to annual supply contracts with the government, refineries, and mobile power plants as well . Currently, it is estimated that less than one-third of households in Yemen have access to electricity from the national power grid. In other words about 42% of the population has access to electricity in urban areas and about 20% in rural. Even for those connected to the network, electricity supply is intermittent, with rolling blackout schedules maintained in most cities. According to the PCE, Yemen's generation capacity must be increased by double of its installed capacity by 2010, in order to meet growing demand (up to 4.8% over 2004) and to avert an energy crisis in the medium term. Yemen's state-owned PEC, under the Ministry of Electricity and Water, operates about 80% of the country's generating capacity as well as the national power grid. The remainder of Yemen's electricity is generated by small, off-grid suppliers and privately-owned generators in rural areas. Over the past decade, the government has taken steps toward alleviating Yemen's electricity shortage, including reform, expansion and integration of the country's power sector through the privatization of all domestic generators (in the range of 5-20 MW) small-scale privatization and independent (private) power projects (IPPs). Plans to privatize the power stations have been slow in implementation. Currently, Yemen's two largest power plants are the 165-MW power station at Ra's Kanatib, near Al Hodeidah, and the 160-MW station in Al Mukha, south of Al Hodeidah. Table 6 presents a list of in base year 2003 installed power plants by fuel type. Table 6: Existing power plants in Yemen for the base year 2003.

Fuel Type Station name

Installed capacity

(MW)

Available capacity

(MW) Year of

construction

RAS KATIB 150 136 1984 MUKHA 160 153 1987 HISWA 125 95 1991

MANSOURA2 70 75 1984 HIZIAZ2 70 67 2005 HIZIAZ3 30 31.2 2005 D

iese

l-Maz

ot

RAYAN 70 44 1986 MANSOURA1 64 45.5 1980

KHOR-MAKSER 13.5 18 1970 TAWAHI 6.6 5 1975

DHABAN1 21 9.9 1980

Die

sel

DHABAN2 25 20.2 1980

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HIZIAZ1 30 30.3 2003 TAIZ-

OSSEFRA 15 13 1976 AL-HALI 25.75 18 1981

KHORNISH 7.5 6 1977 SANA'A 19 11.3 1977 GA'AR 9.5 10.4 1975

MANAWARAH 16 9.6 1992 KHALF 11.6 9.1 1980 SHEHR 13 2.8 1999 SAYAN1 28 17 1985 SAYAN2 21 20.9 1989 Branches 322 120 1975 Industrial 93 90

Rular 100 70 Rental P. COMPANIES 270 269

Total Gen 1786.45 1397.2 References

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33.. OOPPTTIIMMAALL EENNEERRGGYY SSUUPPPPLLYY SSTTRRAATTEEGGIIEESS The major objective of comprehensive energy system analysis aims at formulation of medium- to long-term optimal energy supply strategies that ensure meeting the expected demand in respect to supply security and requirements of sustainable development of the energy sector. The realization of this goal requires the analysis of both demand and supply sides of the energy system. The demand side deals with the assessment of future energy and electricity needs of various consumption sectors, whereas the supply side is devoted to the technical, economic and environmental evaluations of all energy supply options taking into account national specific needs and constraints. Future final energy and electricity demands of ARASIA countries have been estimated in previous analyses using different approaches. Thus, to formulate adequate national supply strategies that ensure meeting the projected future demand in standalone setting of ARASIA energy systems, comprehensive analysis of national energy supply options have been performed using MESSAGE model. For every country the analysis relies upon detailed reconstruction of national energy chains including domestic resources, primary secondary and final levels. The different levels are linked by intermediate activities and its technologies of extraction, generation, refining, transportation and distribution. In addition to the available present conversion technologies, the most favourable future supply options represented by fuel type and conversion technology have been also considered as future candidates. To increase supply security the energy supply mix is diversified by selecting more efficient and cost-effective energy technologies, like improved fossil fired technologies, renewables and nuclear technologies (IEA, 2006). Taking into account the variety of national conditions of ARASIA countries, national needs in social and economic dimensions have been reflect by imposing constraints on new investments, fuel availability, energy import and export, market penetration rates and time entering for new technologies. This is essential for realistic appraisal in case of introducing renewables connected with problems of availability or nuclear option associated to huge investment and preparation of national infra structure. The so constructed national energy systems have been evaluated to formulate optimal national energy supply strategies based on minimizing the total system costs for the entire study period 2003-2030. The optimal solution selects the most appropriate supply option based on discounted cost of delivered energy unit that consists of whole technology cost of investment operation and maintenance (O&M) and fuel cost at constant price of the base year. This approach enables the realistic evaluation of the long term role of an energy supply option under competitive conditions.

Structure of National Supply Networks Every national energy system is structured in a supply network including final, secondary and primary energy level and the domestic energy resources (oil, gas, uranium, coal mines etc.). in this network the energy levels are linked by so called energy conversion technologies.

o Domestic Energy Resources

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It's the first stage in the energy system chain and refers to available domestic energy resources like fossil (oil, gas, and Oil shale), nuclear (Uranium and Thorium) and traditional (wood) resources. By modelling the resources in MESSAGE a subdivision into three cost categories called grades is available, which enable the user to represent three types of reserves:

− Grade (a): extractable reserve that can be extracted profitably using the available extracting and techniques;

− Grade (b): technological reserve which exists actually in the reservoirs but needs advanced technologies (like recovery techniques) and extra cost to be extracted;

− Grade (c): estimated geological reserve that refers to the theoretical resource amount that may be estimated depending on geological studies & seismic surveys for country soils structure and the main tectonic elements.

It should be mentioned that according to the continuous improvements in the exploration and extraction technologies the amount of extractable and proven reserves could increase on the cost of geological reserve. However, this will be coupled with additional investments and extra costs. According to this principle and for economical reason, the model will exploit resources gradually starting from the cheapest, so that grade (a) wouldn't be overstepped unless it is used up.

o Energy Conversion Technologies The linking of energy levels is realized using conversion technologies –like extraction, treatments, generation, transportation, distribution....- that cover both available and future candidates. Imports and exports of different energy carriers are considered mostly at the secondary and final energy levels. Technologies are defined by Activity & Capacity. The Activity specifies input and output energy, efficiency, variable O&M cost and the user imposed limits and bounds on activity. Capacity describes the installed capacity, investment cost, fixed O&M cost, plant factor, construction period, and economic life time, in addition to the imposed limits on the installed capacity, investment cost and penetration factor.

o Time frame Following MESSAGE modelling framework the representation of the energy system consists of time frame, load region, electric load curve, energy levels, energy forms, technologies, resources, demand and constraints. As in the last stage of this analysis the developed national energy models will be linked in a regional grid interconnection, some general data must be identical for all national models. These data include the study period, discretization of time horizon, year distribution in seasons, days and hours, so called load regions. The application of identical load regions is necessary for the simulation of electricity exchange in the regional electric grid interconnection. The study period cover the time horizon of 2003-2030 with the time step of 2 years for the period 2003-2007, 3 years for the period 2007-2010 and 5 years for the period 2010-2030. Figure 3-1 shows the representatively the reference years of the study. Change of any system variable is specified at these reference years.

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The base year 2003 represents the starting year in optimization process that has to be described in detailed to specify the initial condition.

Figure 2-7-1: Dicretization of time horizon for the study period 2003-2030

o Load Regions Demand variation of certain energy forms, e.g. electricity, has to be specified by load variation during a year which is represented by so-called load regions and load curves. This enables the definition of annual load curves taking into account the peak load. For this purpose the year is divided into seasons which are divided into day types includes working days, holly days, and week end days. Each day type contains different parts with a given length reflecting daily demand variation. Table 3-1 shows the definition of load regions applied in all national cases. After evaluation the variation characters of the most national load curves observed during the last years, each year is divided into 4 seasons of different length corresponding to the expected weather conditions. Every season is divided into 3 day types (working days, holly days, and week end days) and every day is again divided into 4 time zones of different lengths. Following this scheme each year is totally divided into 48 load regions. The length of every load region corresponds to its time share during the year which is considered to be the same for all modelling years.

Table 3-1: Seasonal, daily, and hourly divisions for defining the electric load curve.

Relative length of day Day Types

Season Duration

0.25 0.125 0.458 0.167 Work day 0.25 0.125 0.458 0.167 Friday 0.25 0.125 0.458 0.167 Sunday

Spring 01/03- 14/6


Summer 15/6-14/10


Autumn 15/10-30/11

0.458 0.125 0.25 0.167 Work day 0.458 0.125 0.25 0.167 Friday

0.458 0.125 0.25 0.167 Sunday

Winter 1/12-28/02

o Load Curves Due to the nature of electricity as an non-storable energy form, implicit coupling between electricity generation and consumption has to be considered where the electricity

2002

03

04

05

20 25 30 3515 10

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generation has to follow the required variable demand hour by hour. Thus, for modelling the power system, the hourly load variation over the year has to be specified. The hourly load curves have been adopted from official estimation or studies of future electricity demand if available (Hainoun et al, 2006). Otherwise the shape of load curve for the base year 2003 has been considered for the future years too. The annual energy demand is distributed according to the specified time regions. The module calculates the peaks values and their duration as an average of all values in a certain period which doesn’t enable the exact capturing of the peaks load. For this reason some manual adjustment can be necessary. Unified time's division of seasons and day types is adopted for all countries, while the electricity consumption behaviours during the used days and seasons were described by particular load curve for each country. The following paragraphs present the developed MESSAGE models and the achieved results of the formulated national energy supply strategies of Iraq (IRQ), Jordan (JOR), Kingdom of Saudi Arabia (KSA), Lebanon (LEB), Syria (SYR), United Arab Emirates (UAE) and Yemen (YEM).

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3-1 OPTIMAL SUPPLY STRATEGY FOR IRAQ

2-1-1 MESSAGE Model of Iraqi Energy System

3-1-1-1 Levels and Forms of Iraqi Energy System The structure of Iraqi energy network is presented in Figure 1. Four different energy levels are considered consisting of domestic resources, primary energy, secondary energy and final energy which is identical to the final energy demand. To link the different energy levels various energy conversion technologies like extraction, treatments, generation, transporting and distribution are used. Import and export of energy are modelled either at primary or secondary level reflecting the real situation of the considered fuel type.

Resources: Iraqi resources comprise oil and natural gas. With about 115 billion barrels of proven oil reserves Iraq owns the third largest oil reserves in the world (behind Saudi Arabia and Canada), concentrated overwhelmingly (65% or more) in southern Iraq. Estimates of Iraq's oil reserves and resources vary widely, however, given that only about 10% of the country has been explored. Some analysts believe, for instance, that deep oil-bearing formations located mainly in the vast Western Desert region could yield large additional oil resources (possibly another 100 billion barrels or more), but have not been explored.

Iraq contains 110 trillion cubic feet (Tcf) of proven natural gas reserves, along with roughly 150 Tcf in probable reserves. About 70% of Iraq's natural gas reserves are associated (i.e., natural gas produced in conjunction with oil), with the rest made up of non-associated gas (20%) and dome gas (10%).

Following the official data the expected development in oil and natural gas production for coming three decades are presented in Table 1. Table 1: Expected Future Daily Production of Crude Oil and Natural Gas.

Year 2003 2004 2005 2007 2010 2015 2020 2025 2030 2035

Crude Oil (kboe/d)

1536

1995

1853

2000

3587

6235

6235

6235 6235 6235

Natural Gas (Mm3/d)

15.2 19.8 19.4 19.5 37 50 81 131 131 131

Primary Energy Level: At this level (4 of energy levels) are defined consisting of natural gas , crude oil, natural gas export and crude oil export.

Secondary Energy Level:

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At this level (7of energy levels) are defined consisting of (Electricity, Heavy fuel oil, Gas oil, Benzene, Kerosene and Natural gas & Export Oil Products ).

Final Energy Level: At this level (4 of energy levels) are defined consisting of (Electricity, Heat, Motor and Non-energy). Figure (3) presents the schematic network of national energy system including energy forms for the specified energy levels. Table 2 summarizes levels and forms of energies of the developed MESSAGE model. Table 2: Energy forms & levels that used in Iraqi energy system description

Crude Oil Resources

Natural Gas Natural Gas Crude Oil Natural Gas Export Primary Energy Level

Crude Oil Export Electricity Heavy Fuel Oil Gas Oil Benzene Kerosene Natural Gas

Secondary Energy Level

Export Oil Products Electricity demand Heat Motor Final Energy Level

Non-Energy

3-1-1-2 Final Energy Demand As already mentioned MESSAGE methodology starts in formulating the future supply strategy from a given demand that has to be specified externally depending on additional analysis on the demand side. Table 3 presents the future final energy demand projected for the reference case by type of final consumption consisting of electricity, heat use, motor fuel and non-energy consumption (petrochemical, fertilizer, ..)

Table 3: Projected Iraqi reference final energy demand by type of consumption [Mtoe]. Electricity

Year GWh Mtoe

Heat Uses

Motor Fuel

Non-energy uses

Total Mtoe

2003 41438.30 3.56 6.78 12.75 0.75 23.84 2004 42392.27 3.64 6.98 13.13 0.78 24.53

80

2005 50102.82 4.31 7.19 13.52 0.81 25.83 2007 57064.39 4.90 7.63 13.93 0.88 27.34 2010 77846.62 6.69 8.33 14.35 0.99 30.36 2015 110202.55 9.47 9.66 14.78 1.21 35.12 2020 143331.12 12.3 11.20 15.22 1.47 40.19 2025 176065.49 15.13 12.99 15.68 1.78 45.58 2030 206087.76 17.71 15.05 16.16 2.17 51.09

3-1-1-3 Import, Export and Energy Exchange The model offers a possibility of modelling the energy exchange between the national

system and other external system at primary or secondary level. This feature enables the comparative assessment between internal consumption or exporting of an energy carrier and importing another alternative to comply with the demand taking into account the energy system structure and availability of national resources. Hence, the developed Iraqi energy model considers the possibilities of import and export of oil derivatives (liquid gas, natural gas and electricity) at secondary level and crude oil and natural gas at primary level. As already mentioned in previous chapter, Iraq faces in the short-term technical and infrastructure problems in refinery sector. Thus, the considered supply scenario compensates the deficit through importing oil derivatives, whereas as it will continue in exporting crude oil. This situation will sustain until the introduction of first new refinery that is committed to the year 2010. Regarding the electricity import possibilities, there are five tie lines with neighboring countries:

- Millad Abadan from Iran: 200 MW; - Karmanshah from Iran: 300 MW; - Sarbilzahab from Iran: 200 MW; - Slowbi from Turkey: 200 MW; - Tal Abo Taher from Syria: 350) MW.

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Figure 3-1-1: Flow chart of national energy system (Iraqi example)

Crude

Oil

Crude O

il Export

Elec. Trans + Dist

Heating Trans +

Dist.

Motor Trans +

Dist.

Import Pro. Ben.

Import_Pro. G.Oil

Renewable Eng.

Natural G

as Export

Crude

OilField

Resources Final

Natural G

as

Natural G

as

Kerosene

Benzene

Gas O

il

Heavy Fuel

Electricity

ProcessingN

aturalGas

Free NG +Ass Ext

New_ST_PP1

Exst_ST_PP1

Elect Import

Crude Export

Refinery

Motor

Heat

Non Energy

Electricity

New Refinery

Exst_ST_PP2

Exst_ST_PP3

Exst GTP1

Exst GTP3

Exst GTP2

Exst_HPP

New HPP

New Diesel

New_GT_PP1

Secondary

New_CCGT_PP1

Import Pro. Ker.

Non-Energy Trans + Dist.

Primary

Crude oil Ext-Trans

NG_Export

Export G Oil

Export Ben

Export . Ker.

Export

82

3-1-1-4 Iraqi Energy Conversion Technologies Technologies are used for connecting two energy levels which results either in conversion the energy form (e.g. producing electricity from gas) or just energy transforming or distributing. In the defined system network both existing and future candidate technologies are included. Each technology is defined by activity and capacity variables. Capacity definition deals with technical factors like capacity unit, annual operation time, plant factor, economic life time, construction time, maximum and minimum operation level, fixed operation cost and overnight cost. Activity definition describes the operation of technology and includes definition of input and output of energy forms, efficiency and variable operation & maintenance cost. The user can define more than one activity of a technology for alternative mode of operation. The user can impose limits or bound on technology such as maximum capacity that can be built on a technology, or maximum and minimum levels of output from a technology. There is a variety of limits and bounds that can be defined on capacity building of technologies. Moreover, there is a set of limits/bounds that can be defined for variables related to activity of a technology, i.e. its input, output and fuel inventory. If a technology has more than one activity, limits and bounds can be defined on technology variables of each activity. Besides, a global limit on all activities of a technology can also be defined. Table 4a, 4b, 4c present the specification of existing and new candidate technologies.

Table (4)a: Categories of existing and new introduced technologies. Technology Name Description Exst_ST_PP Existing Steam Power Plant New_ST_PP New Steam Power Plant Exst_GTP Existing Gas Turbine plant Exst_HPP Existing Hydro Power Plant New_CCGT_PP New Combine Cycle Gas Turbine Power Plant Extr_Tra Extraction & Transmission of crude oil Free NG+Ass Ext Extraction & Transmission of Natural gas N_G Export Natural Gas Export C_O Export Crude oil Export Processing Natural Gas processing technique Export Product Export crude oil product such as Kerosene ,Gas

Oil &Benzene Elec Imp Electricity Import Trans. + Dist. Transmission and Distribution of Electricity,

Motor, Heating & Non_Energy.

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Table (11a) Capacity and Activity of Existing Plants Plant Capacity Activity

Inv-cost [$/kW]

Cons-cost [$/kW/y]

Unit Size [MW]

Economic life [y]

Const-time [y]

Operation time [%]

Historical -capacity

[MW] Input Efficiency

[%]

Var O&M cost

[$/kWy] Installed Plants

THERMAL PP1 1000 16 - 40 4 60 2160 H-F, C-O, N-G

35 15

THERMAL PP2 1000 16 - 40 4 60 2195 H-F, C-O 35 15 THERMAL PP3 1000 16 - 40 4 60 600 C-O, N-

G/P,N-G/S

35 15

GAS_GTP1 600 16 - 35 4 60 2500 N-G 37 15 GAS_GTP2 600 16 - 35 4 60 882 H-F, G-O,

N-G 37 15

GAS_GTP3 600 16 - 35 4 60 664 C-O,G-O, N-G

37 15

HYDRPO_HPP 1300 6 - 40 4 70 2513 - 90 5 REFINARY 1100 8 - 40 4 75 9916 C-O 40 5 IMPORT_ELEC - - - - - - - 99 1752 IMPORT_BENZ - - - - - - - 99 441 IMPORT_GAS_OIL - - - - - - - 99 331 IMPORT_KERS - - - - - - - 99 331

Table (11b) Capacity and Activity of New Installed Plants

Plant Capacity Activity

Inv-cost [$/kW]

Cons-cost [$/kW/y]

Unit Size

[MW]

Economic life [y]

Const-time [y]

Operation time [%]

Historical -capacity

[MW] Input Efficiency

[%]

Var O&M cost

[$/kWy]

Candidate plants NEW CCGT_PP 600 16 600 35 4 90 - N.Gas 45 15 NEW GT_PP 600 16 100 30 4 90 - H-F, C-

O,G-O, N-G

39 15

NEW_ST_PP 1000 16 200 40 4 70 - H-F, C-O, N-G

37 15

NEW_DEISEL 500 16 100 35 4 70 - H-F, G-O

39 15

NEW_HPP 1300 6 100 50 4 70 - - 95 5 NEW RFEINARY 1250 8 8264 40 4 85 - C-Oil 95 5 NEW NUK 1950 45 1000 45 10 80 - UR 33 20 WIND 1000 27 30 50 4 80 - 2 5 SOLAR 3155 48 30 30 4 60 - - - 0

The future power plant candidates include : • NEW CCGT-PP: Seeba 400MW, Akaaz 900MW, Mansouriea 900 MW,

Chamchamal 900 MW, Oumara 300 MW, Expansion gas turbine power station 500 MW (expected capacity 12000 MW)..

• NEW GT-PP : Mossaib 500 MW, Baghdad south 400 MW, Qudos expansion 246 MW, Dibis 320 MW, Diewaniya 246 MW, Karbala 300 MW, Sader 300 MW, Arbeel 500 MW, Bazergan 80 MW, Nassriya 40 MW, Najaf 246 MW.

• NEW-ST-PP : Uosofiya 840 MW, Shimal 1400 MW, Salah Aldeen 1200 MW, Waset 1320, Anbar 200 MW, Expansion Hartha 660 MW, Expansion Nasseriya 420 MW, Expansion Najiebiya 150 MW, Expansion Zab 150 MW, and Khairat 600 MW.

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• NEW-DEISEL PP: North Baghdad PP, Hurriea PP , Samawa PP, Hadetha PP, Samurra PP (expected capacity 1500 MW).

• NEW-HPP: Al-ethaim, Badosh, Albaghdady power stations (expected capacity 1000 MW).

3-1-1-5 Reference Supply Scenario Assumptions for Iraq

Following assumptions, constraints and simplification were adopted for the reference scenario analysis:

o Adopting official oil and natural gas reserves described previously; o Imposing limits and bounds on the annual extractions of oil and natural gas

according to Table 1; o No limit on annual crude oil export; o Considering new refinery candidate with maximum capacity of 500 kboe/day; o Limiting the minimum reserve margin of generation system to 10%; o Limiting import & export according to the available installed capacity of electric

grid interconnection with the neighbouring countries; o Considering renewable options for electricity generation (wind and PV).

2-1-2 Results of Reference Energy Supply Strategy for Iraq To meet the projected future final energy demand, the following supply scenario has been developed to realize optimal national supply strategy characterized by minimal total costs of the energy system over the study period. The national resources and available energy conversion technologies have been exploited wisely as well import and export options.

3-1-2-1 Trend Results of Energy Supply for Iraq According to the above mentioned assumptions the developed MESSAGE’S

model of Iraqi energy system has been used to formulate the optimal long-term energy supply strategy that assures covering the given future demand at a minimum of total system costs over the entire study period of (2003-2030). Thus, the achieved results regarding the distribution of energy forms at primary and secondary levels, import and export possibilities and the selected future technologies from the proposed candidates characterize the best combination that can be achieved by minimizing the objective function, i.e. total system costs, under the set of specified constraints that define the feasible region. Figure 3.2.3 presents the secondary and primary energy required to cover the future final demand. It is important to mention that the average system efficiency, i.e. the ratio between final and primary energy, will decrease from 68% to about 58% during the study period. This is - as it will be seen later- a direct consequent of the steadily increased share of electricity in the final demand. To cover the final demand that will grow at annual rate of about 3%, both total secondary energy before electricity generation and primary energy will grow by 4%.

85

0102030405060708090

100

2005 2006 2007 2008 2010 2015 2020 2025 2030

Mto

eFinalSecondaryPrimary

Figure 3-1-2: Development of Iraqi energy system at various energy level (Sec2: secondary energy before electricity generation, Sec1: secondary energy after electricity generation).

Secondary Energy Supply This level considers all energy carriers allocated for internal consumption consisting of oil derivatives, natural gas and renewable. These carriers are either consumed directly by the end consumers or used partially in the power sector for electricity generation where the new energy carrier "electricity" appears. Thus, as mentioned above, at the secondary level one has to distinguish between secondary energy before and after electricity generation. Table (5) shows the distribution of secondary energy by fuel types before electricity generation. Subsequently the contribution of NG shows the highest growth, as the share of NG will increase from 10.3% to 62% during the period 2003-2030, whereas the HFO share will decrease from around 24% to 13.5%. The crude oil being used in few existing power plants will vanish in 2025 without phasing of these power plants. The increased share of NG is a direct result of its enlarged contribution in electricity generation. Table (12): Distribution of secondary energy before &after electricity generation (Mot)

2003 2004 2005 2007 2010 2015 2020 2025 2030

Sec. Energy after Elec. Gen 26.42 27.20 28.63 30.30 33.65 38.91 44.54 50.48 56.57

Sec Energy before Elec. Gen 34.17 35.13 37.75 40.52 46.52 56.05 65.95 76.17 86.88

Total Energy on Sec. Level before Elec. Gen (Mtoe) consists of domestic oil products, imported oil products, imported electricity, renewables, and hydro power. Table 15 and Figure 9 show the distribution of fuel consumption at secondary level. One can see the dominance of gas oil in the first period. However, after 2010 the share of NG will increase gradually arriving more than 40% in 2030. Due to the deficit in the power

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generation sector, high amounts of electricity import were required. However, due to the limited available capacity of transmission lines (of about 250 MW) the power sector faced high shortage that is represented as ENS (energy not served). Thus, electricity import and ENS amounted at 15% in 2003 and 8% in 2007 of total secondary demand. Table (15): Fuel consumption at secondary level before electricity generation (ktoe)

Gas oil Gasoline Fuel oil

KEROSIEN NG Crude Hydro

Renewable

Ele imp+ENS

Total (Ktoe)

2003 8638 5667 3322 3766 4141 335 3212 0 5086 34168 2004 8894 5838 3379 3879 4228 335 2811 0 5764 35128 2005 9280 6012 5079 3995 5856 538 2811 0 4183 37754 2007 9698 6192 6438 4239 5955 2394 2409 0 3193 40517 2010 9977 6378 9423 4632 11050 1016 2008 0 2040 46524 2015 9854 6569 12698 5369 15049 3104 2008 0 1402 56053 2020 10348 6766 13533 6225 24070 1065 3286 144 512 65948 2025 12172 6970 13939 7216 30799 1314 3286 144 327 76167 2030 13299 7184 14367 8366 37635 1359 3286 1082 303 86880

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

2003 2004 2005 2007 2010 2015 2020 2025 2030

ENS

Ele-imp

Renew able

Hydro

Crude

NG

Fuel oil

Gasoline

Gasoil

Figure 3-1-3: Distribution of secondary energy by fuel types before electricity generation

(Including electricity import &ENS &Hydro).

Table (17): Distribution of Secondary Energy (after electricity generation) by type of consumptions (%)

Electricity Motor Fuel Heat Use Non-Energy

Consumption Total

(Mtoe) 2003 14.98 53.63 28.51 2.88 26.42 2004 14.89 53.67 28.53 2.91 27.20 2005 16.72 52.50 27.91 2.87 28.63 2007 17.99 51.09 27.98 2.94 30.30

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2010 22.10 47.39 27.53 2.98 33.65 2015 27.06 42.21 27.60 3.13 38.91 2020 30.74 37.98 27.95 3.33 44.54 2025 33.32 34.52 28.59 3.57 50.48 2030 34.80 31.74 29.57 3.88 56.57

Table 17 shows the distribution of secondary energy –after electricity generation-

by energy form. It can be seen that over the study period the share of electricity will increase from about 15% to 35%, the fuel consumption for thermal application will remain almost the same at about 28%, whereas the share of motor fuel will decrease from 54% to about 32%. Figure 10 depicts the trend development for oil products, NG and electricity consumption at secondary level.

0

10000

20000

30000

40000

50000

60000

2003 2004 2005 2007 2010 2015 2020 2025 2030

ktoe

GAS_OIL BENZEN Fuel oil

NG KEROSIEN Electricity

Figure 3-1-4: Distribution of secondary energy by energy form (after electricity generation).

3-1-2-2 Power Sector and Electricity Supply of Iraq The results of future development of Iraqi electricity generation depicts that the secondary electricity (total generation) will grow steadily from 46 TWh in 2003 (more than 17 TWh was not served) to 229 TWh in 2030 with an average annual growth rate of 6% The growing electricity generation and peak load demand entail adequate continuous capacity addition of different power plant types during the study period. The optimal expansion plan refers to the least cost plan over the whole study period in respect to national constraints in term of economic, technological and fuel availability. Thus, a suitable list of power plant candidates has been considered that consists of combined cycle (CC), gas turbines, NG and heavy fuel fired steam pp.

3.1.2.2 Capacity Expansion

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The total installed capacity will be optimally expand from 11500 to 42000 MW during the study period (Figure 9). Due to exploitation of water resources only one new hydro power plant of 1000 MW will be added to the already existing hydro capacity of 2500 MW. During the study period the system need to install about 40000 MW new capacities of which around 50% is CC (Figure 8).

New instaled capacity (MW)

0

1000

2000

3000

4000

5000

6000

2004 2005 2007 2010 2015 2020 2025 2030

MW

NEW_CC NEW_DISEL_PPNEW_GAS_PP NEW_HYDRO_PPNEW_THERMAL_TPP RENEWABLE_PP

Figure 3-1-5: New capacity addition of future electric generation system by period and power plant type

Total instaled capacity and peak load(MW)

0

5000

10000

15000

20000

25000

30000

35000

40000

2003 2004 2005 2007 2010 2015 2020 2025 2030

MW

Existing_thermal Existing_hydro

NEW_CC NEW_DISEL_PP

NEW_GAS_PP NEW_HYDRO_PP

NEW_THERMAL_TPP RENEWABLE_PP

Peak Load(Mw )

89

Figure 3-1-6: Peak Load and optimal expansion of installed capacity for Iraqi future generation system by power plant type.

3.1.2.2 Electricity Generation and Fuel Consumption Table 8 presents the development of electricity generation by type of fuel consumption. As already mentioned the generated secondary electricity will grow with an average annual rate of 6% from 46 TWh in 2003 to 229 TWh in 2030. The high increase in electricity generation required augmented fuel amounts. The total fuel consumption will grow up five times from about 3.4 Mtoe in 2003 to about 45 Mtoe in 2030. Figure presents the development of fuel consumption for electricity generation. One can see the increased contribution of NG Table (8): Distribution of electricity generation and fuel consumption by fuel type (NG: natural gas, FO: fuel oil, (-) means electricity export)

HFO Crude NG Gas oil hydro Renewab

le IMPOR

T ENS Total Gen (TWh) 5.86 1.36 6.41 0.56 12.33 0.00 2.23 17.29 46.04 2003 Fuel (Mtoe) 1.44 0.33 1.50 0.14 - - - 0.00 3.41 Gen (TWh) 5.86 1.36 6.41 0.56 10.79 0.00 2.53 19.60 47.10 2004 Fuel (Mtoe) 1.44 0.33 1.50 0.14 - - - 0.00 3.41 Gen (TWh) 12.54 2.20 13.02 1.07 10.79 0.00 1.83 14.22 55.67 2005 Fuel (Mtoe) 3.08 0.54 3.04 0.26 - - - 0.00 6.92 Gen (TWh) 17.58 10.07 12.59 1.67 9.25 0.00 1.40 10.85 63.40 2007 Fuel (Mtoe) 4.32 2.39 2.95 0.41 - - - 0.00 10.07 Gen (TWh) 28.93 4.14 36.22 1.67 7.70 0.00 0.49 7.34 86.50 2010 Fuel (Mtoe) 7.11 1.02 7.73 0.41 - - - 0.00 16.27 Gen (TWh) 40.76 13.12 55.48 0.00 7.70 0.00 0.61 4.77 122.45 2015 Fuel (Mtoe) 10.01 3.10 11.15 0.00 - - - 0.00 24.26 Gen (TWh) 42.14 4.37 96.34 1.28 12.61 0.55 0.25 1.72 159.26 2020 Fuel (Mtoe) 10.42 1.07 19.48 0.20 - - - 0.00 31.16 Gen (TWh) 39.23 5.63 124.82 11.54 12.61 0.55 0.14 1.11 195.63 2025 Fuel (Mtoe) 10.33 1.31 25.39 1.72 - - - 0.00 38.75 Gen (TWh) 37.20 5.93 154.46 17.06 12.61 0.55 0.13 1.03 228.99 2030 Fuel (Mtoe) 10.18 1.36 31.26 2.52 - - - 45.33

90

Fuel Consumption for Electricity Generation (ktoe)

05000

100001500020000250003000035000400004500050000

2003 2004 2005 2007 2010 2015 2020 2025 2030

Ngas Fuel crude GAS_OIL

Figure 3-1-7: Development of future fuel consumption in the electricity generation

3-1-2-3 Primary Energy Supply of Iraq The optimal supply strategy indicates that Iraqi energy system will continue to rely mainly upon oil and natural gas to cover its primary energy supply. Figure 13 and Table 22 show that the primary energy will grow from almost 35 Mtoe in 2003 to 91 Mtoe in 2030 with an average annual growth rate of about 4%. Table (22) Development of primary energy supply structure (%)

Oil NG Hydro Renewable

Ele-imp ENS

Total (Mtoe)

2003 63.0% 13.0% 9.3% 0.0% 1.7% 13.0% 34.59 2004 62.9% 13.0% 7.9% 0.0% 1.9% 14.4% 35.50 2005 65.2% 16.5% 7.4% 0.0% 1.3% 9.7% 38.20 2007 72.2% 14.7% 5.6% 0.0% 0.8% 6.6% 42.92 2010 66.3% 25.2% 4.2% 0.0% 0.3% 4.0% 47.53 2015 66.0% 28.1% 3.4% 0.0% 0.3% 2.1% 58.40 2020 55.5% 38.7% 4.8% 0.2% 0.1% 0.7% 68.32 2025 52.5% 42.8% 4.1% 0.2% 0.1% 0.4% 79.28 2030 49.0% 45.9% 3.6% 1.2% 0.0% 0.3% 90.96

91

Primeray energy [Mtoe]

01020

3040506070

8090

100

2003 2004 2005 2007 2010 2015 2020 2025 2030

Mto

eOil NG

Hydro Renewable

Ele-imp ENS

Figure 3-1-8: Development of Iraqi primary energy by fuel type. In covering the primary demand it is necessary to analyse the primary energy balance in view of import and export of crude oil, natural gas and oil derivatives over the study period. Table 23 shows the balance of oil and NG. In 2003 the Crude Oil production amounted at about 76.247 Mtoe with an export of about 67 Mtoe. The official plan is to increase the production to 310 Mtoe with in 2030. Over the study period more than 80% of Iraqi oil will be exported. NG production amounted to 4.5 Mtoe in 2003, and the plan is to increase the production to 42.6 Mtoe in 2030. Negligible amount of about 7.5 and 0.9 Mtoe could be exported in 2025 and 2030 respectively. Table (9): Development of crude oil and natural gas supply (Mtoe)

Crude Oil Natural Gas

Year Local Production Import Export Local

Production Import Export

2003 76.48 0 67.68 4.50 0 0.00 2004 99.34 0 90.54 4.60 0 0.00 2005 92.27 0 79.03 6.30 0 0.00 2007 99.59 0 76.03 6.33 0 0.00 2010 185.50 0 160.93 11.97 0 0.00 2015 310.46 0 275.62 16.42 0 0.00 2020 310.46 0 275.57 26.44 0 0.00 2025 310.46 0 274.30 41.45 0 7.53 2030 310.46 0 273.19 42.58 0 0.87

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Table 24 presents again the development of primary energy compared with import and export possibilities of Iraq. The few amounts of energy import –compared to the oil export- refer to the oil derivatives and electricity. During the first period relatively high share of primary energy was imported due to technical problems in refineries and power plants. Nevertheless, the imported oil derivatives represented small share of oil export. Table (23): Development of primary energy supply in view of export and import possibilities (Mtoe)

Year Primary Energy Energy Export Energy Import 2003 34.6 67.683 13.57 2004 35.5 90.539 14.19 2005 38.2 79.033 12.15 2007 42.9 76.031 7.80 2010 47.5 160.929 7.06 2015 58.4 275.615 3.89 2020 68.3 275.567 3.10 2025 79.3 281.833 5.49 2030 91.0 274.052 7.33

2-1-3 Conclusion The results of presented reference optimal energy supply strategy indicate that to

ensure security concern, the energy supply will still really mainly upon oil and natural gas with limited share of hydropower. The base year primary energy consumption amounted at 34.6 Mtoe distributed to 63% crude oil, 13% NG and 9% hydro power. It will grow annually at average rate of 4% to reach at the end of the study period about 91 Mtoe distributed to 49% crude oil, 46% NG and about 5% hydro and renewables. This trend denotes the increased role of NG that will steadily substitute crude oil. It is a direct consequence of the increased electricity generation which will grow annually at 6% and progressively rely upon NG fired power plants. This can be dedicated from the fact that the share of primary energy consumed for electricity generation will triplicate from 10% in 2003 to 50% in 2030.

The fuel supply for electricity generation in 2003 was covered by 42% fuel oil, 44% NG, 10% crude and 4% gas oil. In 2030 the NG will dominate the generation sector as its share will arrive 69% compared to 22% for HFO, 6% gas oil and 3% crud oil. Thus, the power sector will face major challenge in restructuring the future expansion plan. The total installed capacity will be optimally expand from 11500 to 38500 MW during the period 2003-2030. The total new capacity addition will arrive about 29 MW of which about 40% is CC.

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3-2 OPTIMAL SUPPLY STRATEGY FOR JORDAN

2-2-1 MESSAGE Model of Jordanian Energy System

3-2-1-1 Energy Levels and Energy Forms The structure of Jordanian energy network is presented in Figure 2. Five different energy levels are considered consisting of domestic resources, primary energy, secondary energy and final energy which is identical to the final energy demand. To link the different energy levels various energy conversion technologies like extraction, treatments, generation, transporting and distribution are used. Import and export of energy are modelled either at primary or secondary level reflecting the real situation of the considered fuel type.

Jordanian Energy Resources Jordan is a poor energy resource country. It owns only limited quantities of oil shale and natural gas. Oil shale is expected to be the main energy resource in Jordan in the future, but it hasn’t yet be proved as a feasible energy resource. Otherwise, natural gas still very lake and can not be used as the main energy resource in Jordan, so, the Jordanian Energy sector still depends on the Imported Natural Gas either than other crude oil and other petroleum products to cope with the local demand.

• Natural Gas Local natural gas is produced from AL Risha field. The gas production started in 1988. Currently, the daily production is about 25-30 Million Cubic Feet (MCF), which is only enough to operate generation capacity between 70-85 MW. The extracted gas is soled to the Central Electricity Generation Company (CEGCO) at price of 7 US Cents/CM. This price is adopted over the period of this study for the present quantities.

• Oil Shale In the light of fluctuation of oil prices, the lake of local oil resources and limited natural gas quantities produced from Al Risha field; utilizing the oil shale reserves was made a strategic choice to encounter the increasing energy demand in Jordan. The existing oil shale reserve in different areas in Jordan from Ma’an in the south up to Yarmouk River in the north is estimated to be around 40 billion ton. The heat value of Jordanian oil shale is about 1530-1650 Kcal/kg. Oil shale can be used for electricity generation by using direct burning mechanism, or by retorting. Thus, to utilize oil shale in power generation, MEMR and NEPCO signed a Head of Terms Agreement with EESTI ENERGIA to build an Oil Shale Power Plant (OSPP) using direct burning technology with a proposed capacity between 600 MW and 900 MW, the first phase of this project -if feasible- is expected to be in operation by the year 2015. The estimated cost of utilizing oil shale for power generation purpose assumed 15 US $/ton.

• Uranium Jordan is estimated to have 80000 tones of uranium deposits plus 100000 tones in its phosphate reserves. Jordan has taken practical steps to start extraction of uranium

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deposits. Jordan Atomic Energy Commission currently owns Jordan Energy Resources Incorporation (JERI), a Jordanian company with a mandate to explore uranium, thorium and other heavy metals, mining of uranium ore, extraction of uranium from phosphates, milling and processing of yellow cake and other special nuclear heavy metals and provision of nuclear material needed for the civilian nuclear fuel cycle. In this context, Jordan has signed in September 2008 an agreement with AREVA (a French company) to start extraction of uranium in a specified location in central Jordan. Later agreements were singed with Rio Tinto and the Chinese government for reconnaissance in other parts of Jordan. Subsequently, the utilization of the peaceful nuclear energy option requires a long preparation period and a well-established infrastructure that includes human resource development. Hence, it is assumed that the introduction of first NPP will take place in 2018.

Primary Energy Level: At this level, seven types of energy were defined, that are (Oil shale, Local natural gas, Imported natural gas, Imported crude oil, Imported H.F.O, Imported Diesel, Imported light products).

Secondary Energy Level: The secondary energy level was defined by main four types of energy that are (H.F.O, Diesel, Imported Natural gas at Amman, and the Uranium).

Final Energy Level: This energy level was defined by the main and the most effective energy type which is the electricity sent out from the power plants and from the interconnected tie-line with Syria and Egypt.

Demand Energy Level: The demand is the final energy level and it is the consumer side, so it includes all the customers’ requirements that include (Electricity consumption, Gas consumption, H.F.O consumption, Diesel Consumption and the light products consumption). Figure 1 presents the schematic network of national energy system including energy forms for the specified energy levels. Table 1 summarizes levels and forms of energies of the developed MESSAGE model. Table 2: Energy forms & levels that used in Jordanian energy system description

Oil Shale Resources

Natural Gas Oil shale

Local natural gas Imported natural gas Imported crude oil Imported H.F.O Imported Diesel

Primary Energy Level

Imported light products

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H.F.O

Diesel Imported Natural gas at Amman

Imported Natural gas at Amman Uranium


Uranium Final Energy Level Electricity sent out

Electricity consumption Gas consumption H.F.O consumption Diesel Consumption

Demand Energy Level

light products consumption As already mentioned MESSAGE methodology starts in formulating the future supply strategy from a given demand that has to be specified externally depending on additional analysis on the demand side. Future national final energy demand has been projected according to NEPCO’s annual report. Table3: Projected final energy demand by type of consumption [Mtoe]

Year Electricity consumption Gas HFO Diesel Light

Products Total

2003 0.606 0.000 0.346 1.273 1.372 3.598

2004 0.661 0.000 0.357 1.311 1.414 3.743

2005 0.704 0.000 0.368 1.351 1.456 3.879

2007 0.871 0.008 0.390 1.433 1.545 4.247

2010 1.079 0.056 0.420 1.565 1.663 4.784

2015 1.377 0.075 0.475 1.815 1.882 5.625

2020 1.657 0.090 0.538 2.104 2.129 6.518

2025 1.931 0.090 0.608 2.439 2.409 7.477

2030 2.153 0.090 0.688 2.828 2.726 8.485

3-2-1-2 Import, Export and Energy Exchange The model offers a possibility of modelling the energy exchange between the national system and other external system at primary or secondary level. This feature enables the comparative assessment between internal consumption or exporting of an energy carrier

96

and importing another alternative to comply with the demand taking into account the energy system structure and availability of national resources. The developed nation energy model offers the possibilities of import and export. Crude oil, oil derivatives and natural gas are imported at primary level, whereas electricity exchange is modeled in the Jordanian case at final level.

• Natural Gas Import In 2001, the Governments of Egypt, Jordan, Syria, and Lebanon signed a Memorandum of Understanding (MoU) to establish the Arab Gas Pipeline network. The parties agreed to start the routing of the pipeline from Alarish – Taba - Aqaba – Amman-Rehab-Der Ali- Damascus-Homos- Turkey, and on a later stage to Europe. The maximum capacity of the 36 inch pipeline is 10 billion cubic meter per year. The length of the first stage from Alarish in Egypt to Aqaba in Jordan is 268 km was completed in 2003. The second stage was completed in 2006, which took place within the Jordanian borders, from the city of Aqaba to the northern border with Syria with a length of 393 km. The Government of Jordan endorsing the National Electric Power Company (NEPCO) the (Buyer) to sign 30 years Gas Sales Agreement (GSA) with Jordanian – Egyptian Fajr Company for natural gas transmission and distribution (seller). According to the agreement, NEPCO will buy the natural gas from Fajr Company and sell it to generation companies. Currently, Aqaba, Rehab, Samra and Amman East power stations are using imported natural gas as a primary fuel. According to the Gas Sales Agreement (GSA), the available gas quantities for Jordan are as in Table 21. The GSA allows the buyer (NEPCO) to increase the annual contract quantities mentioned in Table 21 by 15%. In the beginning of 2008, an additional 1000 MMSCM of gas quantities were allocated to Jordan by amending the GSA. The imported natural gas average price according to the GSA and its amendment is 3.5 US $/MMBTU. However, the contracted quantities in Table 21 and the additional quantities of natural gas are not enough for the future expansion of the power generation system in Jordan. Thus, the third IPP project will be the last power using burning imported natural gas in the power system. Table 3-2: Contracted Gas Quantities

Annual Contarct

Quantities

Daily Contarct

Quantities

Maximuam Daily

Contarct Quantities

MMSCM MMSCF MMSCF2004 1025 105 1252005 1250 120 1402006 1300 125 1452007 1500 145 1652008 1600 155 1802009 2000 195 2202010 2200 210 2452011 2300 220 255

2012 and up to end of the agreement

2300 or as agreed btween parties but not less than 2300

220 or as agreed btween parties but not less than 220

225 or 115 % which is greater

year

• Crude Oil and Oil Products Import

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All crude oil needed to produce HFO is imported to Jordan through the Aqaba port, and is trucked to the Jordan Petroleum Refinery where the HFO is produced for power generation purposes. For the purpose of this study, the international HFO price was assumed to be 350 US $/ton [source: MEMR] over the study period. Jordan’s needs of light oil are also totally imported at international prices. For the purposes of conduct this study, we assume that the price of Diesel Oil is 550 US $/ton [source: MEMR] over the study period.

3-2-1-3 Energy Conversion Technologies Technologies are used for connecting two energy levels which results either in conversion the energy form (e.g. producing electricity from gas) or just energy transforming or distributing. In the defined system network both existing and future candidate technologies are included. Each technology is defined by activity and capacity variables. Capacity definition deals with technical factors like capacity unit, annual operation time, plant factor, economic life time, construction time, maximum and minimum operation level, fixed operation cost and overnight cost. Activity definition describes the operation of technology and includes define input and output of energy form, efficiency, and variable operation & maintenance cost. The user can define more than one activity of a technology for alternative mode of operation. The user can impose limits or bound on technology such as maximum capacity that can be built on a technology, or maximum and minimum levels of output from a technology. There is variety of limits and bounds that can be defined on capacity building of technologies. Moreover, there is a set of limits/bounds that can be defined for variables related to activity of a technology i.e. its input, output and fuel inventory. If a technology has more than one activity, limits and bounds can be defined on technology variables of each activity. Besides, a global limit on all activities of a technology can also be defined.

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Figure 3-2-1: Flow chart of national energy system (Jordanian example)

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Table (4): description of electric power plants of Jordan.

Plant Capacity Activity

Inv-cost [$/kW]

Cons-cost [$/kW/y]

Unit Size [MW]

Economic life [y]

Const-time [y]

Operation time [%]

Historical -capacity [MW]

Input Efficiency [%]

Var O&M cost [$/kWy]

Existing Plants ATPS 800 6.25 130 30 - 88 650 NG (P)

H.F.O (S) 35(NG) 37

5.2(NG) 6 (H.F.O)

HTPS33 400 8.3 33 30 - 85 99 H.F.O 30 8.5 HTPS66 400 8.3 66 30 - 90 264 H.F.O 31 8.5 RISHA 350 5.2 25 - 85 120 L_NG 30 5 SAMRA 550 2.65 300 30 3 95 300 Imp_NG 46 5.7 Gas_T 350 5.56 - 25 - 85 100 Diesel 28 1.3 REHAB 200 2.65 300 25 - 95 300 Imp_NG 45 5.7 SOLAR 2000 4 - 50 - 60 - 100 1 BIO_Gas 2500 4 - 50 - 85 - 100 2 Hydro_ pp

2500 4 - 50 5 60 12 100 3

OS_PP 1200 6.6 150 30 4 - - Oil Shale 32 7 Nu_pp 2300 600 40 7 - - Uranium 40 New_CC 550 2.6 300 30 3 - - NG 46 5.5 New_GT 400 4 100 25 2 - - NG_Amn 33 5.25 New_ST 800 6.6 100 30 3 - - H.F.O 35 7 Power Plants Candidates CC_PP 550 12 300 25 3 87.6 - N.Gas 55 10 GT_PP 400 12 100 25 2 92.1 - N.Gas 33 26.3 Gst_PP 770 12 200 30 4 82.8 - N.Gas 38 17.52 Fst_PP 770 12 200 30 4 80.8 - Fuel Oil 38 17.5 Nu-PP 1400 40 1000 45 6 79 - Uranium 1 20 Nu-PP 1600 45 600 45 6 79 - Uranium 1 20 Wind_PP 1045 266 25 20 4 25 - - - 5 Solar_PP 3155 47 100 30 2 32 - - - 0 Photovoltaic_PP

4804 10 5 30 2 32 - - - 5

3-2-1-4 Reference Supply Scenario Assumptions for Jordan Following assumptions, constraints and simplification were adopted for the reference supply scenario analysis:

o Adopting the rarely local natural gas resources extraction, and taken consideration the local oil shale resources as an option;

o Imposing limits on annual imported NG amounts from Egypt according to the contracted quantities as mentioned before.

o Oil shale for power generation will be introduced after 2015. o Nuclear option: it is assumed that nuclear option will be available in the

power sector beginning with 2020 and limited to a total installed capacity of 2000 MW.

o Limiting the minimum reserve margin of generation system to 15%; − Limiting import & export according to the available

installed capacity of electric grid interconnection with the neighbouring countries and the capacity of Arab Gas.

SENSITIVITY ANALYSIS TO THE BASE CASE

Based on the above general assumptions a reference supply scenario (Base Case) has been formulated. However, to cope with the expected uncertainty in certain main supply

100

assumptions, variations to the reference case have been evaluated in term of sensitivity analysis as follow.

1) ENHANCED NG-IMPORT (NG CASE) Keeping all reference scenario assumptions unchanged, it is assumed in this case that – in addition to NG import from Egypt- Jordan can import additional NG quantities from Iraq or KSA with an upper annual quantity of 5000 Mcm.

2) UNLIMITED NUCLEAR OPTION (NPP CASE) Keeping all reference scenario assumptions unchanged, it is assumed that no capacity limitation is applied for the introduction of nuclear power option.

3) UNAVAILABILITY OF NUCLEAR POWER SCENARIO (NO-NPP CASE) Given the assumptions for reference case scenario, this case assumes that no nuclear power can be introduced over the whole study period.

2-2-2 Results of Reference Energy Supply Strategy for Jordan To meet the projected future final energy demand, the following supply scenario has been developed to realize optimal national supply strategy characterized by minimal total costs of the energy system over the study period. The national resources and available energy conversion technologies have be exploited wisely, and import & export options as well.

3-2-2-1 Trend Results of Energy Supply for Jordan Figure 2 presents the total amount of secondary and primary energy required at the supply side to cover the future final demand. To cover the final demand that will grow at annual rate of 3.8% from 3.6 Mtoe to 9.9 Mtoe during the study period 2003-2030, the energy supply at secondary level (after electricity generation) will grow from 3.8 Mtoe to 10.6 Mtoe (the difference of Sec-el to final level results mainly from transmission and distribution losses of electricity). Whereas the total secondary energy before electricity generation will grow from 5 Mtoe to 17.8 Mtoe (the difference of Sec-tot to Sec_el refers to generation losses of power plants and refining losses of oil refineries). At the top of energy chain the required primary energy supply will grow from 6.2 Mtoe to 20 Mtoe. The total system efficiency –related to energy conversion technologies in the system- shows that the relative share of final to primary level will decrease from about 58% to 49% during the study period as consequent of the increased share of less efficient in the power generation sector given by oil shale and nuclear power plants.

101

02468

101214161820

2003 2004 2005 2007 2010 2015 2020 2025 2030

Mto

e

FinalSec-elSec-totPrimary

Figure 3-2-2: Development of energy flow in the Jordanian energy system (Sec-tot: secondary energy before electricity generation, Sec-el: secondary energy after that).

3-2-2-2 Secondary Energy Supply of Jordan This level considers all energy carriers allocated for internal consumption consisting of oil derivatives, natural gas, oil shale, renewables and nuclear. These carriers are either consumed directly by the end consumers or used partially in the power sector for electricity generation where the new energy carrier "electricity" appears. Table 3 shows the distribution of secondary energy by fuel types before electricity generation (total secondary fuel including thus allocated for electricity generation). The secondary energy supply during the study period will be covered mainly by oil derivatives, and natural gas and small amounts of renewables, nuclear and oil shale. The share of diesel and light products is almost the same with about 25% each. HFO and NG that are mainly used in the generation sector; Over the study period HFO share will decline from 37% to 26% whereas NG share will increase from 12% to 24% in 2015 and then decline to 15% in 2030. Nuclear option will appear first in 2020 with a share of 14% and will increase to 18% in 2030. Oil shale will enter the system in 2015 with a share of 2.6% that will increase to 4% in 2030. Due to their limited potential, renewable energies will have a small share of about 0.5% over the study period. Compared to the first study period the secondary energy supply structure shows more diversification during the period 2015-2030.

Table 3: Shares of secondary energy by fuel type (before electricity generation). HFO Diesel Light

prod. NG Nuc. Oil Shale

Renew-ables

Elec-Imp Total

2003 37.2% 26.1% 27.0% 9.4% 0.0% 0.0% 0.3% 0.0% 5.132004 36.5% 25.5% 26.4% 11.2% 0.0% 0.0% 0.3% 0.0% 5.402005 34.8% 25.4% 26.2% 13.3% 0.0% 0.0% 0.3% 0.0% 5.612007 31.9% 24.4% 25.3% 17.9% 0.0% 0.0% 0.5% 0.0% 6.182010 28.2% 23.5% 24.0% 23.9% 0.0% 0.0% 0.4% 0.0% 7.012015 29.0% 21.8% 21.7% 24.4% 0.0% 2.6% 0.5% 0.0% 8.782020 22.1% 19.9% 19.3% 19.3% 14.4% 4.1% 0.6% 0.3% 11.132025 20.9% 18.2% 17.2% 15.2% 22.6% 5.3% 0.6% 0.0% 14.14

102

2030 26.1% 18.0% 15.4% 12.0% 17.9% 4.2% 0.5% 5.8% 17.83

3-2-2-3 Power Sector and Electricity Supply of Jordan

Results of Base-Case The base case generation expansion plan consists of installing 1200 MW combined cycle units burning imported natural gas (300 MW per unit), 1500 MW steam units (300 MW per unit) burning HFO, 600 MW oil shale power plants (300 MW per unit) and 2000 MW nuclear power plants (1000 MW per unit), in addition to 1260 MW gas turbines burning natural gas and diesel oil. The contribution renewable will be 170 for wind and 10 MW for PV (Figure 24).

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Existing CCGT GTSteam NPP OSPPSolar Wind Peak Load

Figure 3-2-3: Optimal Expansion Plan of Electricity Generation System (Base Case)

The total fuel consumption for electricity generation, in the base case scenario is expected to reach 10166 ktoe by year 2030 as shown in Figure 28.

103

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ktoe

Local Gas Imported GasHFO DOOil Shale Uranium

Figure 3-2-4: Fuel Consumption for Electricity Generation (Base Case) Heavy fuel oil and nuclear fuel will be the main fuel used for future power generation, the heavy fuel oil share will reach 39% of the total fuel mix, the nuclear fuel share will reach 31%. Other fuel types share will be around 30% as represented in Figure 29.

0%

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100%

2003 2004 2005 2007 2010 2015 2020 2025 2030

Local Gas Imported Gas HFO DO Oil Shale Uranium

Figure 3-2-5: Fuel Shares for Electricity Generation (Base Case)

The amount of total generated electricity and the corresponding consumed fuel over the study period is presented in Table 23. Table (23): Electricity generation and fuel consumption by fuel type (Base Case)

Year Imported Gas Local Gas HFO DO Oil

Shale Uranium Total

104

Gen [GWH] 5301 759 2077 0 0 0 8138 2003 Fuel [ktoe] 1229 218 581 0 0 0 2028

Gen [GWH] 6326 759 1931 0 0 0 9016 2004 Fuel [ktoe] 1445 218 539 0 0 0 2202

Gen [GWH] 7050 788 1819 0 0 0 9657 2005 Fuel [ktoe] 1580 226 507 0 0 0 2313

Gen [GWH] 8918 788 1992 0 0 0 11699 2007 Fuel [ktoe] 1930 226 504 0 0 0 2660

Gen [GWH] 11669 788 1868 6 0 0 14331 2010 Fuel [ktoe] 2445 226 473 2 0 0 3145

Gen [GWH] 12037 788 6064 0 841 0 19730 2015 Fuel [ktoe] 2389 226 1498 0 226 0 4340

Gen [GWH] 9706 788 7710 0 1682 6329 26216 2020 Fuel [ktoe] 1823 226 1900 0 452 1601 6001

Gen [GWH] 9725 788 9320 0 2803 12658 35295 2025 Fuel [ktoe] 1823 226 2313 0 753 3201 8316

Gen [GWH] 9750 788 15695 914 2803 12658 42609 2030 Fuel [ktoe] 1823 226 3925 238 753 3201 10166

Results of NG-Case The optimal electricity generation expansion plan for the NG Gas consists of installing 3600 MW combined cycle units burning imported natural gas (300 MW per unit), 600 MW steam units (300 MW per unit) burning HFO, 300 MW oil shale power plants and 2000 MW nuclear power plants (1000 MW per unit), in addition to 600 MW gas turbines burning natural gas and diesel oil as shown in Figure 25.

105

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Figure 3-2-6: Optimal Expansion Plan of Electricity Generation System (NG Case)

The total fuel consumption for electricity generation for NG-Case is expected to reach 9798 ktoe by year 2030 as shown in Figure 30. The main contributing fuels in this case will be natural gas and nuclear by 59% and 33% respectively. Other fuels shares will constitute 8% as shown in Figure 31.

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Uranium Oil Shale DO HFO Imported Gas Local Gas

Figure 3-2-7: Fuel Consumption for Electricity Generation (NG Case)

106

0%

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80%

90%

100%

2003 2004 2005 2007 2010 2015 2020 2025 2030


Figure 3-2-8: Fuel Shares for Electricity Generation (NG Case)

The amount of total generated electricity and the corresponding consumed fuel over the study period is presented in Table 24. Table (24): Electricity generation and fuel consumption by fuel type (NG Case)


Shale Uranium Total

Gen [GWH] 5300 759 2077 0 0 0 8136 2003 Fuel [ktoe] 1229 218 581 0 0 0 2028

Gen [GWH] 6325 759 1931 0 0 0 9015 2004 Fuel [ktoe] 1445 218 539 0 0 0 2202

Gen [GWH] 7048 788 1819 0 0 0 9656 2005 Fuel [ktoe] 1580 226 507 0 0 0 2313

Gen [GWH] 8916 788 1992 0 0 0 11697 2007 Fuel [ktoe] 1930 226 504 0 0 0 2660

Gen [GWH] 11667 788 1868 6 0 0 14329 2010 Fuel [ktoe] 2445 226 473 2 0 0 3145

Gen [GWH] 16861 788 2016 0 0 0 19665 2015 Fuel [ktoe] 3416 226 510 0 0 0 4152

Gen [GWH] 17464 788 43 0 1682 6329 26306 2020 Fuel [ktoe] 3287 226 10 0 452 1601 5576

Gen [GWH] 25924 788 34 0 2234 6329 35309 2025 Fuel [ktoe] 4849 226 8 0 600 1601 7284

2030 Gen [GWH] 30765 788 34 0 2234 12658 46479

107

Fuel [ktoe] 5763 226 8 0 600 3201 9798

Results of NPP-Case The expansion plan for NPP-Case consists of installing 600 MW combined cycle units burning imported natural gas (300 MW per unit), 900 MW steam units (300 MW per unit) burning HFO, 600 MW oil shale power plants (300 MW per unit) and 5000 MW nuclear power plants (1000 MW per unit), in addition to 480 MW gas turbines burning natural gas and diesel oil as shown in Figure 26.

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Wind Solar OSPPNPP Steam GTCCGT Existing Peak Load

Figure 3-2-9: Optimal Expansion Plan of Electricity Generation System (NPP Case)

The total fuel consumption for electricity generation in NPP-Case is expected to reach 11128 ktoe by year 2030 as shown in Figure 32.The nuclear fuel will be the main input fuel used for future power generation by 72%. However, other fuels share will be limited to 28% as illustrated in Figure 33.

108

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ktoe


Figure 3-2-10: Fuel Consumption for Electricity Generation (NPP Case)

0%10%20%30%40%50%60%70%80%90%

100%

2003 2004 2005 2007 2010 2015 2020 2025 2030


Figure 3-2-11: Fuel Shares for Electricity Generation (NPP Case)

The amount of total generated electricity and the corresponding consumed fuel over the study period is presented in Table 25. Table (25): Electricity generation and fuel consumption by fuel type (NPP Case)


Shale Uranium Total

Gen [GWH] 5300 759 2077 0 0 0 8136 2003 Fuel [ktoe] 1229 218 581 0 0 0 2028

109

Gen [GWH] 6325 759 1931 0 0 0 9015 2004 Fuel [ktoe] 1445 218 539 0 0 0 2202

Gen [GWH] 7048 788 1819 0 0 0 9656 2005 Fuel [ktoe] 1580 226 507 0 0 0 2313

Gen [GWH] 8916 788 1992 0 0 0 11697 2007 Fuel [ktoe] 1930 226 504 0 0 0 2660

Gen [GWH] 11667 788 1868 6 0 0 14329 2010 Fuel [ktoe] 2445 226 473 2 0 0 3145

Gen [GWH] 13444 788 3251 0 841 0 18325 2015 Fuel [ktoe] 2742 226 811 0 226 0 4005

Gen [GWH] 9737 788 1343 0 1682 12658 26208 2020 Fuel [ktoe] 1823 226 317 0 452 3201 6018

Gen [GWH] 6797 788 32 0 2234 25316 35167 2025 Fuel [ktoe] 1282 226 8 0 600 6402 8518

Gen [GWH] 9729 788 1367 0 2803 31646 46333 2030 Fuel [ktoe] 1823 226 323 0 753 8003 11128

Results of No-NPP-Case The optimal electricity expansion plan under the constraints of unavailable nuclear option (No-NPP Case) consists of installing 1200 MW combined cycle units burning imported natural gas (300 MW per unit), 3600 MW steam units (300 MW per unit) burning HFO and 600 MW oil shale power plants (300 MW per unit), in addition to 1440 MW gas turbines burning natural gas and diesel oil as shown in Figure 27.

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110

Figure 3-2-12: Optimal Expansion Plan of Electricity Generation System (NO-NPP CASE)

For the case that no nuclear power will be considered in the future power expansion plan the total fuel consumption for electricity generation is expected to reach 11113 ktoe by year 2030 as shown in Figure 34. In this case, the heavy fuel oil will be the main fuel used for future power generation, the heavy fuel oil share will be about 75% of total fuel consumption for electricity generation by year 2030, the imported natural gas share will be around 16% and other fuel types will comprise 9% as shown in Figure 34.

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ktoe


Figure 3-2-13: Fuel Consumption for Electricity Generation (NO-NPP CASE)

0%10%20%30%40%50%60%70%80%90%

100%

2003 2004 2005 2007 2010 2015 2020 2025 2030Local Gas Imported Gas HFO DO Oil Shale Uranium

Figure 3-2-14: Fuel Shares for Electricity Generation (NO-NPP CASE)

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The amount of total generated electricity and the corresponding consumed fuel over the study period is presented in Table 26. Table (26): Electricity generation and fuel consumption by fuel type (No-NPP Case)


Shale Uranium Total

Gen [GWH] 5300 759 2077 0 0 0 8136 2003 Fuel [ktoe] 1229 218 581 0 0 0 2028

Gen [GWH] 6325 759 1931 0 0 0 9015 2004 Fuel [ktoe] 1445 218 539 0 0 0 2202

Gen [GWH] 7048 788 1819 0 0 0 9656 2005 Fuel [ktoe] 1580 226 507 0 0 0 2313

Gen [GWH] 8916 788 1992 0 0 0 11697 2007 Fuel [ktoe] 1930 226 504 0 0 0 2660

Gen [GWH] 11667 788 1868 6 0 0 14329 2010 Fuel [ktoe] 2445 226 473 2 0 0 3145

Gen [GWH] 12100 788 5936 0 841 0 19666 2015 Fuel [ktoe] 2405 226 1467 0 226 0 4324

Gen [GWH] 9714 788 13408 0 1682 0 25592 2020 Fuel [ktoe] 1823 226 3341 0 452 0 5841

Gen [GWH] 9725 788 21850 0 2803 0 35167 2025 Fuel [ktoe] 1823 226 5482 0 753 0 8283

Gen [GWH] 9702 788 33040 0 2803 0 46334 2030 Fuel [ktoe] 1823 226 8312 0 753 0 11113

3-2-2-4 Primary Energy Supply of Jordan Figure 13 and Table 22 present the development of primary energy supply. The primary energy will grow from almost 6.2 Mtoe in 2003 to 20 Mtoe in 2030 with an average annual growth rate of about 4.4%. The optimal supply strategy indicates that Jordanian energy system will continue to rely mainly upon oil and natural gas to cover its primary energy supply. During the first period (2003-2015) where oil and NG dominate with increased share of NG up to 35%, the following period shows some diversity in primary supply due to the increased role of nuclear, oil shale and renewables. In 2030 nuclear share will amount at 16%, oil shale 3.8%, renewables about 0.5% and the remaining shares for oil and NG with 54.5% and 20% respectively. Table (22) Development of Jordanian primary energy supply structure (%)

NG Oil Oil Shale Nuclear Renewables

Elec-Imp

Total (Mtoe)

2003 12.10% 87.66% 0.00% 0.00% 0.24% 0.00% 6.2172004 15.16% 84.59% 0.00% 0.00% 0.23% 0.02% 6.5412005 18.39% 81.39% 0.00% 0.00% 0.22% 0.00% 6.903

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2007 25.40% 74.21% 0.00% 0.00% 0.38% 0.01% 7.8142010 33.83% 65.82% 0.00% 0.00% 0.33% 0.02% 9.2152015 35.32% 62.31% 1.97% 0.00% 0.39% 0.02% 11.4982020 30.61% 53.13% 3.41% 12.06% 0.54% 0.25% 13.2692025 24.90% 50.34% 4.62% 19.63% 0.48% 0.04% 16.3102030 20.23% 54.50% 3.75% 15.94% 0.46% 5.12% 20.077

Primary Energy (Mtoe)

0.02.04.06.08.0

10.012.014.016.018.020.0

2003 2004 2005 2007 2010 2015 2020 2025 2030

Mto

e

Elec-ImpReneablesNuclear Oil ShaleOilNG

Figure 3-2-15: Development of Jordanian primary energy by fuel type. As already mentioned the lack of domestic energy resources in Jordan makes rthe country completely depended on energy import. During the first period 2003-2015 over 96% of primary is imported and 4% is local NG production. After 2015 the increased participation of oil shale and nuclear will help to improve the national energy balance. Thus, in 2030 about 20% of primary energy will be domestic origin.

2-2-3 Conclusion The results of reference energy supply scenario show that the future Jordanian energy system will still depend mainly on imported oil and natural gas. With an average annual growth rate of about 4.4% the primary energy will grow from about 6.2 Mtoe in 2003 to 20 Mtoe in 2030. The primary energy in 2003 was covered by oil and NG with 87% and 12% respectively. At the end of the study period some diversity in energy supply is observed due to the increased role of nuclear, oil shale and renewables. In 2030 nuclear share will amount at 16%, oil shale 3.8%, renewables about 0.5% and the remaining shares for oil and NG with 54.5% and 20% respectively. The structural change denotes the steadily substitution of crude oil with the consequent of less import dependency. Hence, the share of import primary energy will decline to 80% in 2030 compared to 96% in 2003.

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To cover the expected future demand the total electricity generation will increase from about 14 TWh in 2010 to 43 TWh in 2030 showing an average annual growth rate of about 5.6%. For the base case of reference supply scenario the electricity generation by fuel type shows that fuel consumption will increase from 3 Mtoe in 2010 to about 10 Mtoe in 2030. The NG will be the main contributor in the electricity generation; its share will increase to arrive a maximum of about 85% of total fuel consumption in 2010 and then decrease continuously to about 20% at the end of study period. The share of local NG will amount at 7% in 2010 and decrease to a negligible 2% in 2030. The retreat of natural gas for electricity generation will be compensated by fuel oil nuclear. The share of HFO will increase from 15% in 2010 to about 40% in 2030. Nuclear option will inter the system in 2020 making a share of about 30% of fuel consumption for electricity generation. Besides, the domestic oil shale use in the power sector is expected to begin after 2015 making about 8% of fuel consumption. The total installed capacity will be optimally expand from 2000 MW to about 8000 MW during the study period. To face the increase demand on generation capacity and replace the out phasing of old power plants the system will need to add a total capacity of about 7000 MW over the study period. For the base case, the expansion plan will consist of 1200 MW combined cycle (300 MW per unit), 1500 MW steam turbines (300 MW per unit) burning HFO, 600 MW oil shale power plants (300 MW per unit) and 2000 MW nuclear power plants (1000 MW per unit), 1260 MW gas turbines burning natural gas and diesel oil, 170 MW wind and 10 MW PV. The considered sensitivity analysis shows the dependency of the power sector on NG import. Due to the fact that both nuclear option and local oil shale are vulnerable alternatives, the decrease of NG availability will force the system to depend more on HFO. However, in view of the attractive CC generation technology with its high efficiency – in addition to further economic and environmental reasons-, it would be the first priority for the development of power sector to guarantee adequate NG import sources making benefit from the high regional NG availability.

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3-3 OPTIMAL SUPPLY STRATEGY FOR LEBANON

2-3-1 MESSAGE Model of Lebanese Energy System

3-3-1-1 Energy Levels and Energy Forms The Lebanese electrical system is very simple; It can be divided into 3 different levels:

Electricity Demands The energy demands specify the existing demand at the base year and the projection of Demand in the upcoming years of the study period. For the national Lebanese model, the growth was considered as "Constant Growth" of a value = 3% (According to the latest study of Hydrocarbone strategy… ) The table and graph below represent the Expected future growth of energy demand in Lebanon

Demands MWyr Year Electricity 2003 1400 2004 1442 2005 1485.26 2006 1529.82 2010 1721.82 2015 1996.07 2020 2313.99 2025 2682.54 2030 3109.8

Primary Level: Lebanon has no energy resources such as fossil fuel or nuclear resources or any other sources. The Demand is satisfied by either importing these resources from other countries or importing electricity directly from Syria.

Secondary Level: The secondary level of Lebanese energy system can be simply described by the existing power plants and representing each one as a separate technology. For future optimization new technologies are also added. Table 2.3-2 summarizes the type and total installed capacity of each existing technology: Table 2.3-2: Existing power plants of Lebanese power system Power Plant MW Year of start Running on Technology named

in MESSAGE Zouk1.2.3 3 * 145 1984 H.F.O. Zouk_F_PP

Zouk4 1 * 172 1987 H.F.O. Zouk_F_PP

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Hreicheh 70 1983 H.F.O. Hreicheh_F_PP

Jieh 1,2 2*65 1970 H.F.O. Jiah_F_PP

Jieh 3,4 and 5 3*72 1984 H.F.O. Jiah_F_PP

Deir Amar 435 1998 Diesel/NG Deir_Amar_D_PP

Zahrani 435 1998 Diesel/NG Zahrani_D_PP

Tyr 2*35 1996 Diesel Sour_D_PP

Baalbeck 2*35 1996 Diesel Baalbeck_D_PP

Litani 190 1945….1962 Hydro Litani_H_PP

Kadicha, Safa, Bared

30 1935……1957 hydro Kadisha_H_PP Bared1_H_PP Bared2_H_PP

Final Level:

The final energy level includes the electricity demand for all sectors (Industry, HouseHolds, services etc..). Figure 2.3-2 represents the existing Lebanese electricity supply system. While figure 2.3-3 represents the proposed technologies.

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Figure 3-3-1: Network of electricity chains of the Lebanese national model

3-3-1-2 Energy Conversion Technologies The next step, after defining the levels in the energy chain is to connect these levels through what so called "Technologies". Technologies are defined by their inputs and outputs, their efficiency and degree of variability if more than one input (output) is used (produced) for defining the possible production pattern for some technologies. As previously explained each power plant is represented as a separate technology to simulate the existing electricity supply system (refer to figure 2.3-2). To optimize and fulfill the future growth in the Lebanese electricity sector, new technologies were introduced:

1- New Fuel Power plants. 2- New Diesel Power Plants. 3- New Hydro Power Plants. 4- New NG Power Plants. 5- Solar/Wind power plants.

In Technology user must define some critical values such as: Unite capacity, Investment cost, Life time, Construction time, Efficiency etc.. The MESSAGE computes all these inputs (as well as existing technologies) to create the best scenario. It can also assess the effects of the energy sector’s development on the economy and environment by adding the appropriate bounds or limitations.

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To build the Lebanese best case scenario, the following assumption, bounds and constraints were adopted:

o In some technologies a lower bound on the annual activity was added in order to force these technologies to Work on peak load time, and therefore a load curve system related to this technology was created (as shown in figure below).

o An upper bound on capacity was also introduced in order to forbid MESSAGE

from creating new similar technologies after the expiring of the existing ones, in order to allow the implementation of new technologies.

o Also a limit on importing electricity from Syria was defined (According to

agreement between the Lebanese and Syrian government only 200MWyr of imported electricity is allowed.)

o Importing NG was banned before year 2010. o New power plants implementation start after year 2010.

3-3-1-3 Main Assumptions and Trend Results The result shows that in the future it's more economic to implement new NG, Hydro power plant than implementing Fuel or Diesel power plants or even importing electricity from Syria. In details, the total electricity generation will doubled by 2.2 times during the study period jumping from about 1555 MWyr in 2003 to more than 3455 MWyr in 2030 achieving an annual growth rate of 3% approximately.

3.3.1.3 Capacity Expansion Figure below presents the future development of the installed capacity. Starting from a total installed capacity of around 2275 MW in 2003 the future generation system will be optimally expanded arriving around 4870 MW in 2030. in spite of the fact that the national electricity system suffer from a shortage in electricity supply by 5.4 % of the total demand in 2003, no new addition will suggested during the first seven years (between 2003 and 2010) owing to the bounds and conditions that is forced by the Lebanese team, while the installed capacity is supposed to reduce to 2006 MW during the same period. in 2010 only a rehabilitation for Zouk_PP with capacity of 100 MW is made and be in work for the next time period when it will retired by 2020 . However, results show that during the period between 2010 and 2015 a new capacities of 1680 MW will be added comprises of 900 MW of Combined cycle, 700MW of coal Power plant and 80MW of wind energy, in addition to the 107 MW rehabilitation of Zouk that must be done by 2010.

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Development of Installed Capacity Over the Study Period

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Coal_pp CC_PP NG_PP F.O_PP Hyd_PP Wind_PP Existing

Figure 3-3-2: Existing and New Capacity Addition of Lebanese Generation System.

In 2020 more than 520 MW of the existing capacities are supposed to be faced off, therefore the new additions must replace this losses in capacity and cover the growth in internal demand, which will not be possible in the situation of Lebanese system without importing. So that, the total installed capacity in 2020 will amount about 3085 MW and the new capacities equals to almost 553 of them 250 MW comes from Hydro energy, while the remaining is from HFO power plants. The electricity generation system will change dramatically starting from 2015 with entering new technologies of hydro and coal power plants as well as the addition of reciprocated Engines. Hydro power plants can be promising from the year of 2020 when the first capacities of 250 MW to be added, a new addition of 250 MW is added and double to 500 during the next two periods resulting that the total new hydro capacities will achieve 750 MW by the end of study period . Coal power plant may have a potential role by 2015, but since coal is cheap we had to limit the installed capacity to 700 MW. Because of the adopted bound on the total installed capacities of the companied cycle power plants, the new additions of gas power plants that’s to be built during the last two periods will be gas-fired, this kind will take it's advantage in 2025 with building about 1800MW jumps to 2550 MW in 2030.

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Total Installed Capacity 2030 (4870 MW)

Coal_PP14%

Wind2%Hydro_PP

19%

NG_PP65%

Total Installed Capacity 2003 (2275 MW)

Diesel_PP44%

Hydro_PP10%

F.O_PP46%

Figure 3-3-3: structure of total installed capacity at the first and last year of the study period

Figure 3-3-4 shows a comparison of the structure of the total installed capacity at begin and end of the study period. By the end of the study period, the structure of the electricity system will consists of 14.4% coal power plants, 64.7% NG power plants, while the remaining goes for hydro and wind by 19.3%, 1.6% respectively. One can see that the system became more efficient since there is no contribution of diesel power plants that is very expensive and has a low efficiency, in addition to the fact that the security in the generation system will be higher because of the diversity of the electricity generation resources.

3.3.1.3 Electricity Generation and Fuel Consumption Results indicate that the total electricity generation will doubled by 2.2 times during the study period jumping from about 1556 MWyr in 2003 to more than 3455 MWyr in 2030 achieving an annual growth rate of 2.2% approximately. Table & figure below present the development of total electricity generation during the study periods distributed by types of fuel Up to 2007 the generation system will rely mainly on both diesel and fuel oil due to fact that the natural gas supply are not available before 2010. Share of electricity generated by Diesel fired power plants power plants will increase from 52.5% in 2003 to arrive its maximum of more than 54.4% in the period 2007-2010, after 2010 it will decrease dramatically and eliminate by the year of 2025. While the share of electricity generated by fuel oil decreased continuously from about 35.4% in 2003 to be stopped by the period 20020-2025. This trend will be compensated from gas fired PP starting from 2010 when the first amount of the imported natural gas is supposed to be delivered to DeirAmmar_PP the plant of 230 MW installed capacity and whom can burn two kind of fuel to generate electricity, as a result it switched to use natural gas instead of diesel to generate about 392 MWyr in 2010. After that natural gas share in the electricity generation will arrive about 64% at the end of the study supported by the new combined cycle to be build in 2015 and other gas fired to be build during the last two periods..

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Starting form 2015 coal will enter the system sharing by almost 23% during the first period of entering to the service, but this share declains almost 15% in during the next two periods. Hydro power plants contribution will maintain the share of 7 % till the year of 2015 when jumps to 11.3%, 16.4% and 20% during the next three periods respectively. Wind turbines will have less than 0.7% starting from the year 2020. Table3.2.1: Electricity generation by fuel types (MWy)

0

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MW

yr

coal Diesel F.O NG CC_NG hydro&wind Import

Figure 3-3-5: Development of total electricity generation distributed by power plants type between 2003-2030

coal Diesel F.O NG CC_NG hydro&wind Import

Shortage Total Generation

2003 0 817 551 0 0 113 75 0.0 1556 2004 0 827 588 0 0 113 75 0.0 1602 2005 0 837 526 0 0 113 75 100 1551 2007 0 847 522 0 0 113 75 194 1557 2010 0 69 605 783 0 113 75 269 1644 2015 504 60 0 714 729 129 82 0.0 2218 2020 504 60 303 470 729 305 200 0.0 2571 2025 504 0 0 1209 729 505 33 0.0 2981 2030 504 0 0 1484 729 705 33 0.0 3455

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3.3.1.3 Shortage in electricity supply: As presented in the table above, the system will suffer from an apparent shortage of electricity generation, this shortage rounded between 5 to 6% of the total demand in 2003.This lack will reflect in two pictures: the first one is importing electricity from our neighbours by an average annual amount of 75 MWyr till 2015 when it may jump to more than 125 MWyr. But as a result of the limitation in the available imported energy and the growing in electricity demand, about 100 MWyr demand will not covered in 2007 (about 6.4% of the total demand in the same year) growing to 194 and 269 MWyr in the next two periods . However by 2020 and as a result of building a new natural gas power plants that are consumed an Egyptian imported gas across n Oriental pipelines, the system will totally depend on the existing capacity to satisfy the demand. According to the last results, table below presents the required fuel as secondary energy to comply with the electricity generation needs to meet the internal demand. Results indicates that the total consumed fuel for electricity generation grows to more than 5.4 Mtoe in 2030 comparing with 2.4 Mtoe in the first year that's equal to an average growth rate of 2.9 % annually. Table 3.2.2 :Electricity generation and corresponding fuel consumption distributed by fuel types (NG: natural gas, FO: fuel oil) during the study periods

coal Diesel F.O NG hydro&wind Import Total Gen (GWh) 0.0 7156.8 4824.8 0.0 988.1 657.0 13626.7

2003 Fuel (Mtoe) 0.0 1.3 1.1 0.0 0.0 0.0 2.4Gen (GWh) 0.0 7242.4 5148.0 0.0 988.1 657.0 14035.5

2004 Fuel (Mtoe) 0.0 1.3 1.2 0.0 0.0 0.0 2.5Gen (GWh) 0.0 7330.1 4608.1 0.0 988.1 657.0 13583.2

2005 Fuel (Mtoe) 0.0 1.3 1.1 0.0 0.0 0.0 2.4Gen (GWh) 0.0 7420.8 4570.7 0.0 988.1 657.0 13636.5

2007 Fuel (Mtoe) 0.0 1.3 1.1 0.0 0.0 0.0 2.4Gen (GWh) 0.0 601.9 5297.5 6859.1 988.1 657.0 14403.6

2010 Fuel (Mtoe) 0.0 0.2 1.2 1.2 0.0 0.0 2.6Gen (GWh) 4415.0 521.6 0.0 12644.9 1128.2 718.7 19428.4

2015 Fuel (Mtoe) 1.1 0.1 0.0 2.1 0.0 0.0 3.3Gen (GWh) 4415.0 521.6 2658.3 10501.5 2674.4 1752.0 22522.8

2020 Fuel (Mtoe) 1.1 0.1 0.6 1.7 0.0 0.0 3.5Gen (GWh) 4415.0 0.0 0.0 16980.2 4426.4 288.3 26110.1

2025 Fuel (Mtoe) 1.1 0.0 0.0 3.7 0.0 0.0 4.8Gen (GWh) 4415.0 0.0 0.0 19383.6 6178.4 291.7 30268.7

2030 Fuel (Mtoe) 1.1 0.0 0.0 4.3 0.0 0.0 5.4 Figure () shows the development trend of fuel consumption for electricity generation by type of fuel. The comparison between the first and last study period shows a significant change in the fuel mix. At the begin diesel and HFO dominate with 42%, 58% respectively, while those two fuel disappears by 2030 when natural gas will became the dominant fuel with about 80% of the total required fossil fuel. Further more, starting from 2015 where the first coal power plant is expected to enter the system, the contribution of coal fuel consumption is expected to drop from almost 32.7% to about 20% at the end of the study period.

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Fuel Consumption for Electricity Generation (ktoe)

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4000.0

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6000.0

2003 2004 2005 2007 2010 2015 2020 2025 2030

ktoe

Coal Diesel

HFO NG

El-Impt

Figure 3-3-6: development of fuel consumption mix for electricity generation

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3-4 OPTIMAL SUPPLY STRATEGY FOR KSA

2-4-1 MESSAGE Model of Saudi Energy System

3-4-1-1 Energy Levels and Energy Forms Energy levels classify the different stages that the any energy form passes through during the conversion processes to arrive the final demand. 4 energy levels are considered consisting of domestic resources, primary energy, secondary energy and final energy. Final level is identical to the energy demand. The energy levels are linked with each other by energy conversion technologies like extraction, treatments, generation, transporting and distribution. Import and export of energy forms are modelled either at primary or secondary level reflecting the real situation of the considered fuel type.

Resources: It's the first stage in the energy system chain and refers to available domestic energy resources like fossil (oil, gas, and coal), nuclear (Uranium and Thorium) and traditional (wood) resources. By modelling the resources in MESSAGE a subdivision into three cost categories called grades is available, which enable the user to represent three types of reserves:




It should be mentioned that according to the continuous improvements in the exploration and extraction technologies the amount of extractable and proven reserves could increase on the cost of geological reserve. However, this will be coupled with additional investments and extra costs. According to this principle and for economical reason, the model will exploit resources gradually starting from the cheapest, so that grade (a) wouldn't be overstepped unless it is used up. Saudi Arabia owns only fossil resources of oil and natural gas. KSA owns the highest oil reserves worldwide. Its proven reserves are estimated to about 264 Billion barrels making about 23% of total world oil reserves. Besides, the proven natural gas reserves are estimated to 7153 Billion cubic meters (AOAPEC, 2008). Following the official data the expected development in oil and natural gas production for coming three decades are presented in Table 1. Table 1: Expected Future Daily Production of Crude Oil and Natural Gas.

Year 2003 2004 2005 2007 2010 2015 2020 2025 2030 Crude Oil (Mboe/d) 8.2 8.3 8.4 8.6 8.8 9.3 9.7 10.2 10.8

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Natural Gas (Mcm/d) 167.3 179.9 195.0 203.7 232.8 273.8 410.7 508.4 547.7

Primary Energy Level: Three energy forms are defined in this level as following: Crude oil, gas, and gas-central.

Secondary1 Crude Level: This level include: diesel, gasoline, LPG, HFO, and kerosene.

Secondary Energy Level: This level including: central electricity, east electricity, west electricity, and south electricity.

Final Energy Level: This level including: central, east, west, and south electricity also include diesel, gasoline, LPG, HFO, kerosene, and natural gas.

Figure 1 presents the schematic network of national energy system including energy forms for the specified energy levels. Table 1 summarizes levels and forms of energies of the developed MESSAGE model. Table 1: Structure of energy forms and energy levels describing KSA energy system

Crude Oil Resources

Gas Crude Oil Gas Primary Energy Level Gas-Central Diesel Gasoline LPG HFO

Secondary Energy Level-1 (Oil products)

Kerosene Central Electricity

East Electricity West Electricity

Secondary Energy Level (Electricity)

South Electricity Central Electricity East Electricity West Electricity South Electricity Diesel

Final Energy Level

Gasoline

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LPG HFO Kerosene NG

3-4-1-2 Forms of Final Energy Demand As already mentioned MESSAGE methodology starts in formulating the future supply strategy from a given demand that has to be specified externally depending on additional analysis on the demand side. Future national final energy demand has been projected according to the Ministry of Water and Electricity long term plan [Add reference: Demand forecast Report]. Final energy demand distributed by form of consumptions is presented in Table 2.

Table 2-a: Projected final electricity demand [GWh]. year elect_central elect_eastern elect_south elect_west Total 2003 39,789 50,902 9,857 41,646 142194 2004 41,327 50,187 10,113 42,758 144385 2005 44100 53350 11010 44824 153284 2007 52096 52751 13020 51914 169780 2010 56925 70454 13870 57863 199112 2015 71440 92856 17297 72803 254396 2020 90191 127046 21576 92141 330954 2025 114984 178752 27053 117752 438541 2030 139221 229485 32393 142837 543936

Table 2-b: Projected final energy demand by fuel type [Mtoe].

Year Diesel Gasoline HFO Kerosene LPG NG Total

2003 12.06 12.56 8.33 0.28 1.32 15.77 50.342004 12.66 13.00 8.75 0.29 1.39 16.56 52.662005 13.30 13.46 9.18 0.30 1.46 17.39 55.092007 14.66 14.42 10.13 0.31 1.61 19.17 60.292010 16.97 15.98 11.72 0.33 1.86 22.20 69.062015 21.66 18.98 14.96 0.36 2.38 28.33 86.672020 27.64 22.55 19.09 0.40 3.04 36.15 108.872025 35.28 26.78 24.37 0.44 3.88 46.14 136.892030 45.03 31.80 31.10 0.48 4.95 58.89 172.26

3-4-1-3 Import, Export and Energy Exchange The model offers a possibility of modelling the energy exchange between the national system and other external system at primary or secondary level. This feature enables the comparative assessment between internal consumption or exporting of an energy carrier

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and importing another alternative to comply with the demand taking into account the energy system structure and availability of national resources. Hence, the developed nation energy model offers the possibilities of import and export of oil derivatives, liquid gas, natural gas and electricity at secondary level; crude oil and natural gas at primary level.

DieselSupply

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GT-E

GT-WCC-W

ST-W

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INTER TIE

GT-C

INTER TIE

Figure 3-4-1: Flow chart of Saudi energy system

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3-4-1-4 Energy Conversion Technologies Technologies are used for connecting two energy levels which results either in conversion the energy form (e.g. producing electricity from gas) or just energy transforming or distributing. In the defined system network both existing and future candidate technologies are included. Each technology is defined by activity and capacity variables. Capacity definition deals with technical factors like capacity unit, annual operation time, plant factor, economic life time, construction time, maximum and minimum operation level, fixed operation cost and overnight cost. Activity definition describes the operation of technology and includes define input and output of energy form, efficiency, and variable operation & maintenance cost. The user can define more than one activity of a technology for alternative mode of operation. The user can impose limits or bound on technology such as maximum capacity that can be built on a technology, or maximum and minimum levels of output from a technology. There is variety of limits and bounds that can be defined on capacity building of technologies. Moreover, there is a set of limits/bounds that can be defined for variables related to activity of a technology i.e. its input, output and fuel inventory. If a technology has more than one activity, limits and bounds can be defined on technology variables of each activity. Besides, a global limit on all activities of a technology can also be defined.

2-4-2 Optimal Saudi Energy Supply Strategy To meet the projected future final energy demand, the following supply scenario has been developed to realize optimal national supply strategy characterized by minimal total costs of the energy system over the study period. The national resources and available energy conversion technologies have be exploited wisely, and import & export options as well.

3-4-2-1 Main Assumptions and Trend Results Scenario Assumptions Following assumptions, constraints and simplification were adopted for the reference scenario analysis:

o Adopting official oil and natural gas reserves described previously; o Maximum annual extractions of oil is 3000 Mboe (about 8.22 Mboe/day) during

2003, and it will increase for 1% yearly after that, o Maximum annual extractions of gas is 81660 Mcm (about 223.7 Mcm/day) during

2003, and it will increase for 2% yearly after that, o No nuclear option, o 5% minimum electricity Reserve margin, o Availability of expanding the capacity for the electricity liens transportation

between the Kingdom four areas, o Availability of Importing NG from Yemen to the South area after 2010

(maximum 1 billion cubic meter per year), o After 2015 additional capacity for gas pipeline from Eastern area to the Central

(the NG pipeline capacity to the central region will increase from about 800 million cubic feet/day in 2003 to about 1600 million cubic feet/day in 2015,

o Limite on the NG amount which is available for the eastern region (1500 million cubic feet/day).

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3-4-2-2 Secondary Energy Supply This level considers all energy carriers allocated for internal consumption consisting of oil derivatives, natural gas, renewables and nuclear. These carriers are either consumed directly by the end consumers or used partially in the power sector for electricity generation where the new energy carrier "electricity" appears. Thus, as mentioned above, at the secondary level one has to distinguish between secondary energy before and after electricity generation.

0%

10%

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80%

90%

100%

2003 2004 2005 2007 2010 2015 2020 2025 2030

West_ele_gen East_ele_gen Central_ele_genSouth_ele_gen Diesel GasolineHFO Kerosene LPGNG

Figure 3-4-2: Distribution of secondary energy by type of consumption

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0

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2003 2004 2005 2007 2010 2015 2020 2025 2030

Mto

eelect_west electr_esaternelectr_central elect_southDiesel GasolineHFO KeroseneLPG NG

Figure 3-4-3: Development of future secondary energy supply structure by type of energy carrier (after electricity generation).

3-4-2-3 Primary Energy Supply The optimal supply strategy indicates that Saudi energy system will still rely mainly upon oil products and natural gas to cover its primary energy supply. Figure 7 shows the development trend of primary energy supply. The primary energy demand will grow from around 113 Mtoe to 364 Mtoe during the study period corresponding to annual average growth rate of 5.2%.

Primery Energy Supply (Mtoe)

050

100150200250300350400

2003 2004 2005 2007 2010 2015 2020 2025 2030Year

Mto

e

Crude+Oil products NG+LNG NG_imp

Figure 3-4-4: Development of future primary energy by fuel type.

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In covering the primary demand it is necessary to analyse the primary energy balance in view of import and export of crude oil, natural gas and oil derivatives over the study period Table >>>: Future development of import and export of crude oil and NG

Crude Oil (Mtoe)

Natural Gas (Mtoe)



2003 409.3 0.0 -309 54 0.0 0.0 2004 413.4 0.0 -313 58 0.0 0.0 2005 417.5 0.0 -316 63 0.0 0.0 2007 425.9 0.0 -324 66 0.0 0.0 2010 438.8 0.0 -332 76 0.0 0.0 2015 461.2 0.0 -350 89 0.9 0.0 2020 484.7 0.0 -337 133 0.9 0.0 2025 509.4 0.0 -304 165 0.9 0.0 2030 535.4 0.0 -259 178 0.9 0.0

3-4-2-4 Power Sector and Electricity Supply To cover the electricity demand the electricity generation will increase from 165 TWh in 2003 to about 600 TWh in 2030. The growing electricity generation and peak load demand entail adequate continuous capacity addition of different power plant types during the study period. The optimal expansion plan refers to the least cost plan over the whole study period in respect to national constraints in term of economic, technological and fuel availability. Thus, a suitable list of power plant candidates has been considered that consists of combined cycle (CC), steam turbines, gas turbines, and diesel turbine.

3.4.2.4 Capacity Expansion The total existing and committed power plants capacity amounted about 32000 MW in 2003. It will be optimally expanded to around 107000 MW in 2030. The new capacity addition by geographic region of KSA is presented in the following figures. The East region shows the highest new installed capacity with around 44% of total country capacity addition (Figure 6a and Figure 6e).

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New capacity Addition (East)

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MW

Crude_GT Diesel_GT

Gas_Steam NG_GTNewDiesel_GT New_CC

New_NG_GT New_Steam

Figure 3-4-5: New capacity addition of future electric generation system by period and power plant type of East Region.

New Capacity Addition (Central)

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CrudeGAS_GT Crude_GTCOOLERCrude_GT Diesel_GTGas_CC NG_GTNG_Gtcooler NewDiesel_GTNew_CC New_Gas_GT

Figure 3-4-6: New capacity addition of future electric generation system by period and power plant type (GT: gas turbine, CC: combined cycle)central.

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New Capacity Addition (West)

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Crude_GT Crude_CC Diesel_GTHFO_Steam NewDiesel_GT New_CCNew_Crude_GT New_Steam

Figure 3-4-7: New capacity addition of future electric generation system by period and power plant type (GT: gas turbine, CC: combined cycle)West.

New Capacity Addition (South)

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Crude_GT Diesel_GT

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New_Crude_GT New_NG_GT

Figure 3-4-8: New capacity addition of future electric generation system by period and power plant type (GT: gas turbine, CC: combined cycle) South.

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New Capacity Addition of KSA by Generation Type (MW)

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OtherCC

GTSteam

Figure 3-4-9: Total new capacity addition for the entire KSA electric generation system by power plant type

New Capacity Addition of KSA by Region (MW)

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Figure 3-4-10: Distribution of total new capacity addition for the entire KSA electric generation system by country region.

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Total Installed Capacity (East)

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Crude_GT Diesel_GTGas_Steam NG_GTNewDiesel_GT New_CCNew_NG_GT New_SteamAramco- Des TielinePeak-east

Figure 3-4-11: Development of Peak Load and optimally expanded installed capacity of future generation system by power plant type (East).

Total instaled capacity (central)

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New_CC_Cen New_Gas_GT_CenImp_others_Central TielinePeak

Figure 3-4-12: Development of Peak Load and optimally expanded installed capacity of future generation system by power plant type (Central).

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Total instaled capacity (West)

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Crude_GT Crude_CCDiesel_GT HFO_SteamNewDiesel_GT New_CCNew_Crude_GT New_SteamImp_Des Tielinepeak load

Figure 3-4-13: Development of Peak Load and optimally expanded installed capacity of future generation system by power plant type (West).

Total instaled capacity (South)

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Crude_GT Diesel_GTNewDiesel_GT New_CCNew_Crude_GT New_NG_GTOthers (during Peak) TielinePeak (MW)

Figure 3-4-14: Development of Peak Load and optimally expanded installed capacity of future generation system by power plant type (South).

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Total Installed Capacity (MW)

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Imp_others_Central

New_Gas_GT_Cen

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NewDiesel_GT_Cen

Figure 3-4-15: Development of Peak Load and optimally expanded installed capacity of future generation system by power plant type (for the whole system).

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Total Instaled Capacity of KSA (MW)

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Figure 3-4-16: Development of Peak Load and optimally expanded installed capacity of future generation system by power plant type (for the whole system).

3.4.2.4 Electricity Generation and Fuel Consumption Table 4 presents the development of electricity generation and fuel consumption by type of fuel. The total electricity generation will increase from about 164 TWh to 600 TWh over the study period corresponding to an average annual growth rate of about 5%. The required fuel consumption will increase from about 33 Mtoe in 2003 to about 133 Mtoe in 2030. One can see that Crude and NG dominate the electricity generation followed by HFO and Diesel

Table 4: Distribution of electricity generation and fuel consumption by fuel type (NG: natural gas, HFO: Have fuel oil,)

Diesel HFO Crude oil NG Others Total

Gen (TWh) 27.4 15.9 19.9 66.5 33.8 163.6 2003 Fuel (Mtoe) 8.4 3.8 5.7 15.2 33.1 Gen (TWh) 24.8 20.2 20.2 78.2 25.9 168.3 2004 Fuel (Mtoe) 7.7 4.8 5.8 17.3 35.7 Gen (TWh) 24.1 20.7 23.2 85.4 25.5 178.7 2005 Fuel (Mtoe) 7.4 5.0 6.6 19.5 38.4 Gen (TWh) 19.0 22.8 24.6 96.9 33.5 196.8 2007 Fuel (Mtoe) 6.1 5.4 7.1 21.8 40.4 Gen (TWh) 10.5 29.1 22.1 123.5 47.4 232.3 2010 Fuel (Mtoe) 3.5 6.9 6.3 27.9 44.7 Gen (TWh) 10.1 44.0 11.7 181.0 47.9 293.8 2015 Fuel (Mtoe) 3.4 10.5 3.0 38.4 55.3

2020 Gen (TWh) 3.8 43.3 91.0 197.2 48.8 382.6

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Fuel (Mtoe) 1.1 10.1 22.9 40.6 74.7 Gen (TWh) 9.2 48.5 191.9 197.8 48.8 494.7 2025 Fuel (Mtoe) 2.8 11.6 49.8 40.6 104.8 Gen (TWh) 18.9 67.2 268.0 197.9 48.8 599.2 2030 Fuel (Mtoe) 5.8 16.1 70.5 40.6 132.9

*Imp-El: electricity import from independent producer (Aramco and others..)

3-4-2-1 Conclusion The results of reference optimal energy supply strategy indicate that to assure supply security the KSA energy system will continue to rely mainly upon oil and natural gas. The primary energy demand will increase from about 113 Mtoe to 164 Mtoe over the study period showing an average annual growth rate of about 4.4%. Starting from an initial primary energy distribution of 67% and 33% for oil and NG respectively, the contribution of NG will increase to arrive its maximum of 40% in 2015; thereafter it wil decrease again to arrive 33% in 2030. This result is a direct consequent of the applied assumption that local NG production is limited and still no official plans are known for NG import. On the other hand, KSA will remain the biggest oil producer worldwide with crude oil production increase from about 8 Mbrl/day 2003 to an expect amount of 11 Mbrl/day in 2030. However, the high growth rate of primary demand on crude oil indicate that the share of internal oil consumption in the total oil and oil products of KSA will increase from 19% in 2003 to arrive about 45% in 2030. Nevertheless, the expected production increase of oil and oil derivatives will guarantee a nearly constant export quantity of more than 6 Mbrl/day over the study period. The total electricity generation will increase from about 164 TWh to 600 TWh over the study period corresponding to an average annual growth rate of about 5%. The required fuel consumption will increase from about 33 Mtoe in 2003 to about 133 Mtoe in 2030. Herewith, the share of fuel consumption in the total primary energy of KSA will increase from 30% to about 36% over the study period, indicating the increased dominance of power sector in the whole energy system. The consumed fuel in the generation sector in 2030 will be distributed to 53%, 31%, 12% and 4% for crude oil, NG, HFO and diesel respectively. To cope with the high electricity demand the installed capacity will be optimally expanded from about 32 GW in 2003 to about 107 GW in 2030. The capacity distribution by region will be 28 GW in the central, 26 GW in the west, 45 GW in the east and about 5.4 GW in the south region. The share of CC in the total installed capacity will increase firstly from 10% to 30% over the period 2003-2015 to decrease again to 10% in 2030.

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3-5 OPTIMAL SUPPLY STRATEGY FOR SYRIA In a previous study the future final energy and electricity demand of the country has been projected for the next three decades according to various scenarios representing the possible future socio-economic and technological development trends of the country (Hainoun et al, 2006), (NEC, 2009). It has been found that for the reference demand scenario the final energy demand will grow annually at average rates of 5.5%.

2-5-1 MESSAGE Model of Syrian Energy System

3-5-1-1 Levels and Forms of Syrian Energy System Energy levels classify the different stages that any energy form passes through during the conversion processes to arrive the final demand. 4 energy levels are considered consisting of domestic resources, primary energy, secondary energy and final energy. Final level is identical to the energy demand. The energy levels are linked with each other by energy conversion technologies like extraction, treatments, generation, transporting and distribution. Import and export of energy forms are modelled either at primary or secondary level reflecting the real situation of the considered fuel type (Figure 1).

Resources: It's the first stage in the energy system chain and refers to available domestic energy resources like fossil (oil, gas, and coal), nuclear (Uranium and Thorium) and traditional (wood) resources. By modelling the resources in MESSAGE a subdivision into three cost categories called grades is available, which enable the user to represent three types of reserves:




It should be mentioned that according to the continuous improvements in the exploration and extraction technologies the amount of extractable and proven reserves could increase on the cost of geological reserve. However, this will be coupled with additional investments and extra costs. According to this principle and for economical reason, the model will exploit resources gradually starting from the cheapest, so that grade (a) wouldn't be overstepped unless it is used up.

Syrian fossil resources are limited to oil and natural gas. The proven geological oil reserves are estimated to almost 24 billion barrel of oil equivalent (Bboe) of which 7.15 Bboe are extractable. Almost 4.75 Bboe have been already extracted up to 2008 and the recently remaining oil reserves are estimated to about 2.4 Bboe (MOM, 2009), (WOG,

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2009), (CPA, 2005), (Mashfij, 2004). The proven geological reserve of natural gas in Syria is estimated to 699 billion cubic meter (10) (Bm3) of which 410 Bm3 are extractable. 125 Bm3 have been produced up to 2008 and the remaining reserve is about 285 Bm3 (MOM, 2009), (WOG, 2009), (MOM, 2004), (CG, 2004). Following the official data the expected development in oil and natural gas production for coming three decades are presented in Table 1. Table 1: Expected future daily production of crude oil and natural gas.

Year 2003 2004 2006 2008 2010 2012 2014 2016 2018 2020 2030Crude Oil (kboe/d) 510 460 430 380 245 300 355 375 245 510 460

Natural Gas (Mm3/d)

25 23 22 21 24 35.5 29 26 26 25 23

Primary Energy Level: At this level four energy forms are defined consisting of natural gas, crude oil at the oil field, crude oil at refinery gate and imported nuclear fuel for the nuclear power plants.

Secondary Energy Level: Seven energy forms are included; natural gas (after treatment in the gas factories), liquefied gas (produced from gas factories oil refineries and direct import), gasoline and kerosene, diesel, fuel oil, asphalt, heavy derivatives ( Coke and Sulphur) and electricity at the gate of power plants.

Final Energy Level: Four energy forms are included representing motor fuel (refers to energy consumption in the transportation sector), heat uses (in industry, service and household sector), electricity demand in all consumption sectors and non-energy demand (for fertilizer, petrochemical industry, and asphalt).

Figure 1 presents the schematic network of Syrian energy system including energy chains, technologies and forms for the specified energy levels.

10 1 boe= 154 m3 (NG)

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Cru

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Figure 3-5-1: Flow chart of Syrian energy system including energy chains, levels and technologies.

3-5-1-2 Syrian Final Energy Demand As already mentioned MESSAGE methodology starts in formulating the future supply strategy from a given demand that has to be specified externally depending on additional analysis on the demand side. In a previous study the future final energy and electricity demand of the country has been projected for the next three decades using the end-use approach. In this projection the future demand is estimated according to various scenarios representing the possible future socio-economic and technological development trends of the country (Hainoun et al, 2006), (NEC, 2009). It has been found that for the reference demand scenario the final energy demand will grow annually at average rates of 5.5% and the final electricity demand at rates of 6.5%. The resulted final energy demand distributed by form of consumptions is presented in Table 2.

Table 2: Projected final energy demand by type of consumption [Mtoe]. Non-energy uses

Year Electricity Thermal Uses

Motor Fuel 11Asphalt 12Feedstock

Total

2003 1.998 5.574 4.820 0.260 0.672 13.3242004 2.153 5.988 5.206 0.260 0.677 14.2842005 2.636 7.118 6.230 0.725 0.324 17.0342007 2.817 7.553 6.511 0.747 0.324 17.9522010 3.184 8.439 7.027 0.792 0.324 19.7672015 4.441 11.350 8.758 0.919 0.649 26.1172020 6.155 15.260 11.025 1.065 0.649 34.1542025 8.187 19.753 13.731 1.235 0.649 43.5542030 10.844 25.364 17.276 1.431 0.649 55.564

3-5-1-3 Import, Export and Energy Exchange The model offers a possibility of modelling the energy exchange between the national system and other external system at primary or secondary level. This feature enables the comparative assessment between internal consumption or exporting of an energy carrier and importing another alternative to comply with the demand taking into account the energy system structure and availability of national resources. Hence, the developed nation energy model offers the possibilities of import and export of oil derivatives, liquid gas, natural gas and electricity at secondary level; crude oil and natural gas at primary level. Furthermore there is a possibility for importing nuclear fuel elements at secondary level to for supplying the proposed nuclear power plant candidates. Import and export technique, which enables the user to impose limits and bounds on the activities and capacities of input and output, is used for modelling the electric grid interconnection between Syria and the neighbouring countries (Turkey, Jordan and

11 Asphalt data are not included in MAED results. The data up to the year 2010 refer to official estimation, for the following years an annual growth rate of 3% has been assumed. 12 For fertilizer and petrochemical industry

Lebanon). This possibility helps in improving the electricity supply security using peaks shifting between the countries. Furthermore, the interconnection reflects positively on reducing the total installed capacities by lowering the reserve margin, which means less investment for the power sector.

3-5-1-4 Syrian Energy Conversion Technologies Technologies are used for connecting two energy levels which results either in conversion the energy form (e.g. producing electricity from gas) or just energy transforming or distributing. In the defined system network both existing and future candidate technologies are included. Each technology is defined by activity and capacity variables. Capacity definition deals with technical factors like capacity unit, annual operation time, plant factor, economic life time, construction time, maximum and minimum operation level, fixed operation cost and overnight cost. Activity definition describes the operation of technology and includes define input and output of energy form, efficiency, and variable operation & maintenance cost. The user can define more than one activity of a technology for alternative mode of operation. The user can impose limits or bound on technology such as maximum capacity that can be built on a technology, or maximum and minimum levels of output from a technology. There is variety of limits and bounds that can be defined on capacity building of technologies. Moreover, there is a set of limits/bounds that can be defined for variables related to activity of a technology i.e. its input, output and fuel inventory. If a technology has more than one activity, limits and bounds can be defined on technology variables of each activity. Besides, a global limit on all activities of a technology can also be defined. The Syrian energy system has been modelled using 38 technologies of following categories:

Oil & Gas extraction; Oil & Gas transportation; Oil Refineries; Electric power plants; Transmission & distribution of oil, oil derivatives, natural and liquid gas,

and electricity; Export & import.

3-5-1-5 Reference Supply Scenario Assumptions for Syria

The following assumptions and constraints have been adopted for the reference scenario analysis:

o Adopting official oil and natural gas reserves described previously; o Imposing limits and bounds on the annual extractions of oil and natural gas

according to Table 1; o No limit on annual crude oil export; o Considering tow new refiners candidate with capacity of 220 boe/day; o Covering final energy demand for motor fuel by gasoline 25% in the base year,

and in 2030 the gasoline share will be in range 28%-30%, CNG share will be about 4.2%, the rest is covering by diesel.

o Covering final energy demand for heat applications by HFO, NG, liquefied gas, traditional fuel and solar energy, with maximum share of 23.5% for HFO and

share of 16% for liquefied gas (according to base year shares). The NG maximum share on covering the heat demand will grow from 18% to 31% in 2015 because of the new available resources for importing NG, then it will decrease again to18% at the end of the study period, while traditional fuel quantities and solar energy share are equal to the results of final demand projection (RS on the demand side);

o Renewable energies: − Wind turbines: installation of a total capacity not less than 700MW during

the period 2010-2030. Seasonal and daily wind variation is adopted from wind atlas in the south region. (Atlas,20??).

− PV: total installed capacity of 300 MW minimum. It should be mentioned that for realistic representation of renewable options the time variation of the production pattern of all renewable power plants (hydro, wind, PV and CSP) are modeled as outputs variation following the adopted load regions for seasonal and daily variation.

o Successive reduction of technical losses for transmission and distribution (T&D) of electric grid reducing to arrive 15% of total electricity production in 2030.

o Nuclear option: due to basic infrastructure requirements and financial limitation first entering of nuclear option is after 2020. Besides, no more than one power plant per five years is allowed;

o Limiting the minimum reserve margin of electricity generation system to 10% after 2020;

o Electricity exchange (import & export) with neighbouring countries: − Electricity exchange (Import and export) with Jordan is limited to the

available existing tie-line capacity of 300 MW (in two directions); − Export to Lebanon is limited to the available capacity of 80 MW during

the period 2005-2010; after that maximum capacity addition of 100 MW is allowed;

o NG import via Arab Gas Pipe Line (AGPL) and from neighbouring countries as follow:

− Operation begin of AGPL is 2009. The initial import capacity is about 4 million cubic meter per day in 2010, and it will increase to 6 million cubic meter in 2015;

− NG import of 3 Mcm per day from Turkey during the period 2012-2017; For all considered energy carriers the import prices are higher than export price. Thus, for crude oil the import and export prices are 55 and 50 US$/boe, for NG 100 and 73 US$/km3, for Gasoline 693 and 630 US$/toe, for Diesel 698 and 634 US$/toe, for HFO 398 and 362 US$/toe, for electricity 70 and 60 US$/MWh and import price for nuclear fuel is estimated to 3 US$/MWh. Note that all data are in constant price of the 2000.

2-5-2 Results of Reference Energy Supply Strategy of Syria To meet the projected future final energy demand (Table 2), the following supply scenario has been developed to optimize national supply strategy characterized by

minimal total costs of the energy system over the study period. The national resources and available energy conversion technologies have be exploited wisely, and import & export options as well. Thus, the achieved results regarding the distribution of energy forms at primary and secondary levels, import and export possibilities and the selected future technologies from the proposed candidates characterize the best combination that can be achieved by minimizing the total system costs, under the set of predefined constraints.

3-5-2-1 Trend Results of Energy Supply for Syria Figure 2 presents the total amount of secondary and primary energy required at the supply side to cover the future final demand. To cover the final demand that will grow at annual rate of 5.5% from 13.3 Mtoe to 56 Mtoe during the study period 2003-2030, the energy supply at secondary level (after electricity generation) will grow from 14.3 Mtoe to 58.3 Mtoe (the difference of Sec-el to final level refers to transmission and distribution losses of end energy carriers, mostly from electricity and oil derivatives). Whereas the total secondary energy before electricity generation will grow from 18.4 Mtoe to 76.6 Mtoe (the difference of Sec-tot to Sec_el refers to generation losses of power plants and refining losses of oil refineries). At the top of energy chain the required primary energy supply will grow from 20.2 Mtoe to 79 Mtoe (the difference to Sec-tot refers to extraction and transportation losses of primary energy carriers) marking an average growth rate of 5.17% over the study period. The comparison of required energies at the different levels indicates an improvement in the efficiency of energy conversion technologies due to the increased share of modern equipments. Thus, the relative share of final to primary level will increase from about 66% to 71% and that of secondary to primary from about 91% to 97%, during the study period.

0

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3040

5060

7080

90

2003 2004 2005 2007 2010 2015 2020 2025 2030

Mto

e

FinalSec-elSec-totPrimary

Figure 3-5-2: Development of energy flow in the Syrian energy system (Sec-tot: secondary energy before electricity generation, Sec-el: secondary energy after that).

3-5-2-2 Secondary Energy Supply of Syria This level considers all energy carriers allocated for internal consumption consisting of oil derivatives, natural gas, renewables and nuclear. These carriers are either consumed directly by the end consumers or used partially in the power sector for electricity generation where the new energy carrier "electricity" appears. Thus, as mentioned above, at the secondary level one has to distinguish between secondary energy before and after electricity generation. able 3 shows the distribution of secondary energy by fuel types before electricity generation (total secondary fuel including thus allocated for electricity generation). Subsequently the secondary energy supply during the study period will be covered mainly by oil derivatives, and natural gas and small amounts of renewables and nuclear. It is apparent that the share of diesel will remain the main over the study period followed by fuel oil and natural gas that are mainly applied in the electricity generation. The share of hydro energy in the total secondary supply will go down from 3.8% to almost 1.1% at the end of the study as consequent of exploiting national water resources for hydro projects. While the share of other renewable resources in electricity generation will grow from 0% to 0.8%. However, the share of solar energy (used in thermal use) will stay less than 0.02%. The nuclear energy will take place after 2020 with a share of around 4%.

Table 3: Shares of secondary energy by fuel type (before electricity generation).

2003 2004 2005 2007 2010 2015 2020 2025 2030

Diesel 31.9% 32.0% 32.0% 31.4% 33.6% 32.5% 34.2% 33.7% 34.1%Gasoline 6.8% 6.8% 6.9% 7.3% 7.9% 8.1% 7.5% 7.0% 6.9% Fuel 22.9% 23.4% 25.2% 27.1% 16.1% 9.0% 20.7% 25.5% 31.4%LPG+LNG 4.9% 4.9% 4.8% 4.7% 5.1% 5.5% 5.4% 5.4% 5.3% NG 22.0% 20.5% 20.8% 18.5% 26.3% 39.2% 22.2% 16.8% 12.9%Asphalt 3.7% 3.4% 3.2% 3.1% 3.0% 2.8% 2.3% 2.1% 1.9% Heavy products 2.3% 2.1% 2.0% 1.8% 1.6% 1.3% 0.9% 0.7% 0.6% Hydro 3.8% 5.5% 4.2% 3.8% 3.2% 2.6% 1.9% 1.5% 1.1% Wind + PV 0.0% 0.0% 0.0% 0.0% 0.0% 0.1% 0.4% 0.8% 0.8% Traditional 2.0% 2.0% 2.0% 1.9% 1.7% 1.5% 1.2% 1.0% 0.8% Solar 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% Nuclear 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 2.4% 4.9% 3.8% Electricity exchange -0.4% -0.7% -1.0% 0.4% 1.4% -2.5% 0.8% 0.6% 0.5%

Total Annual (Mtoe) 18.40 19.77 21.17 23.62 26.55 33.16 45.35 59.03 76.60

According to the type of application the secondary energy will be devoted to cover thermal, motive and non-energy application in addition to electricity generation (Figure 3). During the study period the share of thermal application in the total secondary supply will be vary between 30% to 34%, for electricity generation between 36% and 41%, for motive energy between 23% and 27% and for non-energy application (including Asphalt and heavy products like coke) between 3.3% and 7.4%. Figure 3 depicts that in average around 35% of secondary energy is devoted to electricity generation. Thus, the total secondary energy decreases mainly due to the conversion

factors (efficiency) of various power plants as part of secondary fuels is converted to electricity. At this stage the secondary energy amounts to around 80% of the total secondary energy before electricity generation. Figure 4 shows the distribution of secondary energy after electricity generation. The total secondary energy by form of energy delivered to the end user will increase from 14.2 Mtoe to 58.3 Mtoe representing an average annul growth rate of 5.35%. The development trend of the energy forms at the secondary level shows that the share of electricity in the secondary energy supply will swing around 19% of total secondary energy over the study period. However, Diesel will still dominating the secondary energy; its share will vary between 38.5% in 2015 and 44.6%in 2030. The decreasing trend of Diesel contribution in 2015 arises from the fact that diesel application will be substituted partially by natural gas for heating purposes and motor fuel. Hence, natural gas (NG) share will increase from 8.7% in 2003 to around 16.3% in 2015. However, NG contribution will decrease again during the last decade of the study marking its limited availability proposed in the previously adopted scenario assumptions. Additionally, diesel for heat application will be substituted partially to limited amounts by solar where its share will stay less than 0. 1% of secondary energy at the end of study period. Shares of Fuel oil, Gasoline and liquid gas will keep nearly constant over the study period with around 8%, 9% and 6% respectively.

0%10%20%30%40%50%60%70%80%90%

100%

2003 2004 2005 2007 2010 2015 2020 2025 2030

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Thermal Application Motive EnergyNon-Energy Use Electricity Generation

Figure 3-5-3: Distribution of secondary energy by type of consumption.

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ktoe

ElectricityTraditionalSolarHeavyprod.AsphaltNGLPG+LNGFuel oilGasolineDiesel

Figure 3-5-4: Development of future secondary energy supply structure by type of energy carrier (after electricity generation).

3-5-2-3 Power Sector and Electricity Supply The results indicate that the almost constant share of 19% of the produced electricity in the secondary energy supply refer to an increase in the produced amount from 29.3 TWh (equal to 2.5 Mtoe) in 2003 to 147.6 TWh (12.7 Mtoe). The growing electricity generation and peak load demand require adequate capacity addition of different power plant types during the study period. In view of high total cost (investment, O&M and fuel) of power sector, finding the optimal future expansion plan of electricity generation system characterizes a significant part in formulating the optimal energy supply strategy. The optimal expansion plan refers to the least cost plan over the whole study period in respect to national constraints in term of economic, technological and fuel availability. Thus, a suitable list of power plant candidates has been considered that consists of combined cycle (CC), fuel fired steam turbines, gas turbines, nuclear power plants, wind turbine, photo voltaic and hydro power plants. Possibilities of electricity import and export to and from neighbouring countries have been also considered through modelling the existing tie-lines capacities.

3.5.2.3 Capacity Expansion The total existing power plants capacity is 6230 MW in 2003. It consists of around 1150 MW hydro power plants and about 5000 fossil fired power plants of which 640 MW CC and the remain are fuel or gas (or duel) fired power plants.

After 2010 and mainly during the period 2015-2020 a considerable number of old power plants will face out, so that from the existing capacity of 6230 MW only 1400 will remain till the year 2030. Thus, to face this situation significant capacity addition is required to cover the increased peak demand and restore the outage of obsolete power plants. The resulting new capacity additions of the optimal expansion plan are presented in figure 5. Accordingly, the total new installed capacity over the study period will amount to 29800 MW. The addition consist of 10800 MW CC (unit size 300 MW) in addition to 3350 MW as committed plant during the period 2007-2015, 700 gas turbine (unit size 100 MW) and 260 MW as committed plant, 12000 MW fuel fired steam turbine (unit size 200 MW), 1600 MW nuclear (600 MW in 2020, 1000 MW in 2025) and 790 MW wind turbines (starting with 10MW in 2010).and 300 MW Photo voltaic. Figure 6 presents the resulting future development of total installed capacity compared to the projected future peak load (Hainoun, 2006). Starting from a total installed capacity of around 6230 MW in 2003 the future generation system will be optimally expanded to arrive a total capacity of about 30300 MW in 2030 (in addition to 480 MW for the tie-lines of electricity exchange). The committed new capacity addition amounts to 1800 MW during the period 2005-2010 that comprises of 300 MW CC during the period 2005-2007 (replacing two existing gas fired power plants of 600 MW capacity with two 900 MW CC).new CC power plant with 450 MW in 2010, three additional CC of 750 MW each have been committed to enter the system during the period 2007-2015 (Deir ali in 2010 and deir ali expansion and deir alzoor during 2012-2015), 260 MW as gas turbin in 2009. In addition to the base year capacity of 380 MW for the tie-lines connecting Syria with Jordan and Lebanon, the optimal expansion considers adding 100 MW after in 2010. The structure of the total installed capacity to the end of the study period shows that the nuclear and wind will contribute in the generation mix in 2030 with 8% and 0.2% respectively.

New capacity addition

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2004 2005 2007 2010 2015 2020 2025 2030

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CC FsteamN1000 N600GT Renewablecommited CC

Figure 3-5-5: New capacity addition of future electric generation system by period and power plant type (FSteam: fuel oil steam turbine, NU: nuclear, GT: gas turbine, CC: combined cycle, renewable: wind and PV).

0

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CC (Existing & Committed ) GT (Existing & Committed )Fsteam (Existing) Hydro_PPCC_PP GT_PPGSteam_PP FSteam_PPNU600_PP NU1000_PPWind_PP Ele_exchgPeak Load

Figure 3-5-6: Development of Peak Load and optimally expanded installed capacity of future generation system by power plant type.

3.5.2.3 Electricity Generation and Fuel Consumption The total annual electricity generation will increase from 29.3 TWh 2003 to 148.4 TWh in 2030 marking an average annual growth rate of ca. 6.2%. Table 4 presents the development of electricity generation and fuel consumption by type of fuel. The total fuel consumed for electricity generation will increase from about 6 Mtoe in 2003 (45% natural gas, 55% fuel oil) to 29.3 Mtoe in 2030 (25% natural gas, 65% fuel oil, 10 % nuclear). Up to 2015 the generation system will rely mainly on natural gas. However, due to the proposed limitation of natural gas –following the official data- the system will shift toward more dependency on fuel oil. Share of electricity generated by NG fired power plants (mainly CC) will increase from 43% in 2003 to arrive its maximum of 83% in 2015, after 2015 it will decrease continuously arriving about 32% at the end of the study. The fall down of NG availability is expected to be compensated mainly by fuel oil; its share will increase form 15.5% in 2015 to arrive 55.4% at the end of the study. After 2020 the nuclear will enter the system making an average share of 7.5% during the last decade of the study. No fuel is consumed for Hydro and wind and PV power plants. However, their share in the total electricity generation will decrease steadily from 9.2% in 2003 to almost 2.2% in 2030.

Table 4: Distribution of electricity generation and fuel consumption by fuel type (NG: natural gas, FO: fuel oil, (-) means electricity export)

NG FO Hydro Wind& PV Nuclear Diesel Ele-

Exch Total

Gen (TWh) 12.61 14.23 2.71 0.00 0.00 0.00 -0.25 29.30 2003 Fuel (Mtoe) 2.80 3.21 0.00 0.00 6.01 Gen (TWh) 12.62 15.32 4.16 0.00 0.00 0.00 -0.53 31.57 2004 Fuel (Mtoe) 2.73 3.54 0.00 0.00 6.27 Gen (TWh) 13.75 17.86 3.37 0.00 0.00 0.00 -0.84 34.14 2005 Fuel (Mtoe) 3.01 4.18 0.00 0.00 7.19 Gen (TWh) 13.46 21.68 3.47 0.00 0.00 0.00 0.40 39.01 2007 Fuel (Mtoe) 2.80 5.02 0.00 0.00 7.82 Gen (TWh) 32.01 9.58 3.30 0.02 0.00 0.00 1.43 46.33 2010 Fuel (Mtoe) 6.18 2.18 0.00 0.00 8.36 Gen (TWh) 52.40 9.80 3.30 0.18 0.00 0.70 -3.21 63.16 2015 Fuel (Mtoe) 8.49 2.22 0.00 0.14 10.85 Gen (TWh) 49.31 26.26 3.30 0.84 4.15 1.01 1.43 86.29 2020 Fuel (Mtoe) 7.62 6.35 1.08 0.15 15.20 Gen (TWh) 47.49 47.86 3.30 1.31 11.07 0.94 1.43 113.402025 Fuel (Mtoe) 7.30 11.11 2.88 0.14 21.44 Gen (TWh) 47.33 82.27 3.30 2.09 11.07 0.93 1.43 148.422030 Fuel (Mtoe) 7.29 18.96 2.88 0.14 29.27

3-5-2-4 Primary Energy Supply of Syria The optimal supply strategy indicates that Syria will still rely mainly upon oil products and natural gas to cover its primary energy supply. Figure 7 shows the development trend of primary energy supply.

Primary energy supply

01020304050607080

2003 2004 2005 2007 2010 2015 2020 2025 2030

Mto

e

Oil NGNuclear HydroWind+PV Solar-HeatTraditional Fuel

Figure 3-5-7: Development of future primary energy by fuel type..

The primary energy will grow from almost 20 Mtoe to 79 Mtoe during the study period. Oil share will decrease firstly form 67.9% in 2003 to almost 55.2% in 2015 to increase after that gradually up to 76% in 2030. Natural gas share (including liquid gas) will vary between 25.4% in 2004 and 41.8% in 2015 during 2003-2015 to decrease after that to 17.6% in 2030. Hydro will decrease gradually from 3.5% in 2003 to about 1.1% in 2030. wind and PV will increase from 0% to 0.7% in 2030. Solar and traditional fuel (consumed for heat application in residential sector) will decrease slowly to arrive about 0.8% at the end of study period. Nuclear will enter the system in 2020 and arrive in 2030 a share of about 3.7% of total primary supply. Table 5: Development of crud oil and natural gas supply (Mtoe)

Crude Oil Natural Gas



2003 25.7 0.0 -14.3 5.2 0.0 0.0 2004 25.1 0.0 -13.7 5.2 0.0 0.0 2005 18.9 0.0 -7.5 7.3 0.0 0.0 2007 18.9 0.0 -7.5 7.0 0.0 0.0 2010 18.7 0.0 -7.2 7.8 1.3 0.0 2015 17.7 3.5 0.0 11.5 2.9 0.0 2020 14.9 6.2 0.0 9.4 1.9 0.0 2025 12.2 8.9 0.0 8.4 1.9 0.0 2030 12.2 8.9 0.0 8.4 1.9 0.0

In covering the primary demand it is necessary to analyse the primary energy balance in view of import and export of crude oil, natural gas and oil derivatives over the study period (Table 5 and Figure 8). As already mentioned, according to official estimations, Syrian oil production will face many challenges in the years to come, as production continues to decline due to technological problems, depletion of the existing wells and lack in new exploration activity; at the same time local demand on oil will increase massively as presented above. Table 5 shows the development of crud oil and natural gas supply in view of import and export possibilities. It refers to that from 25.7 Mtoe in 2003 the oil production will decrease to 18.7 Mtoe in 2010. Production decline and continues increase of internal consumption will be reflected in sharp failing of oil export from 14.3 to 7.2 Mtoe during the same period. his scenario will continue steadily leading the country to become oil importer by the year 2020 with total crud import of 6.2 Mtoe. Furthermore, Syria will become net oil importer after 2025 with ca. 8.9 Mtoe.

-20-10

0102030

405060708090

2003 2004 2005 2007 2010 2015 2020 2025 2030

Mto

ePrimery supplyImportExport

Figure 3-5-8: Comparison of primary energy consumption, energy import and export over the study period.

The natural gas shows more optimistic trend than oil as the production capacity will increase gradually from 5.2 in 2003 and reach its highest level 11.5 Mtoe in 2015. Between 2015and 2030, the production decreases and fixed at 8.4 Mtoe till the end of the study. the system will start to import NG in 2010 to cover the internal demand mostly arising from the increasing share of combined cycle in the future power expansion as already illustrated. The imported NG amount of 1.3 Mtoe, then in 2015 it will increase to 2.9 Mtoe because of increasing the share of Egyptian NG and the availability of importing NG from Turkey (2012-2017), after that the importing will confine on AGPL and the quantity will be 1.9 Mtoe. Furthermore, as the refining capacity is expected remain under the internal demand the energy import is not limited to NG and crude oil. The energy system will import relatively high amounts of diesel and fuel oil after the year 2015. Figure 8 demonstrates the development of the primary energy balance in view of imported and exported shares. One can see that comparing to a positive energy balance of the period 2003-2012 the system will shift to increased dependency on energy import. Consequently, the energy import will increase from about 22% of primary consumption in 2015 to more than 70% in 2030.

2-5-3 Conclusion The results of reference energy supply scenario show that the future Syrian energy system will depend mainly on oil and natural gas. The share of natural gas in the primary energy supply will increase gradually up to the year 2015 and then retreat following the limited national production and import capacity. Besides, with the continuous decrease of national oil production, the oil export is expected to vanish in 2015-2020 and the country would become a net oil importer in 2025. In this year the energy import will amount at around 62% of total primary energy consumption. Thus, the expected costs of energy

import for the second half of study period represent a hard challenge for the Syrian economy and its future development. During the last decade of the study period increased contribution of wind, PV and nuclear energy are observed. The Syrian base year primary energy consumption of 20 Mtoe -distributed to 68% for oil, 27% for natural gas, 3.5% for hydro power and 1.8% for traditional fuel- will grow annually at average rates of 5.17% to reach at the end of the study period about 79 Mtoe -distributed to 76% for oil, 17.6% for natural gas, 1.8% for wind PV and hydro, 0.8% for solar and traditional (heat application) and 3.7% for nuclear-. The electricity generation by fuel type shows that the share of natural gas in the power sector will arrive almost 83% in 2015 and then decrease continuously to about 32% at the end of study period. The retreat of natural gas for electricity generation will be compensate by fuel oil and nuclear of the shares 55.4% and 7.5% respectively. The total installed capacity will be optimally expand from 6230 MW to 30300 MW during the study period. The new capacities addition will amount to 29800 MW distributed to fuel fired steam turbine, combined cycle, gas turbine, PV and wind power plants and two nuclear power plants that are expected to enter the system after 2020. References Hainoun A., Seif-Eldin M. K., Almoustafa S., 2006. Analysis of the Syrian Long-Term

Energy and Electricity Demand Projection Using End-Use Methodology, Energy Policy 34

Hainoun, A., Seif-Eldin M. K., Almoustafa S., 2007. Integrated Role of Energy Options in Elaborating Sustainable Energy Supply Strategy, 4th Middle East and North Africa Renewable Energy Conference (MENAREC4), Damascus

Hainoun, A., 2007. Developing an Optimal Energy Supply Strategy for Syria in View of GHG Reduction with Least-Cost Climate Protection, Research Coordination Meeting on GHG Mitigation Strategies and Energy Options, IAEA, Vienna.

IEA, 2006. Energy Technology Perspectives, Scenarios and Strategies to 2050, IEA, Paris

GC, 2004. Report of Gas Committee, Nr. 1285, Ministry of Electricity, Damascus (in Arabic).

CPA, 2005. Report of Committee for Price Analysis of Energy Carriers, State Planning Commission, Damascus (in Arabic)

Mashfij, H. 2004. Energy in Syria –Problems and Solutions up to 2020- Research Project Nr. 99, National Defence Faculty, Damascus (in Arabic)

MESSAGE, 2004. Model for Energy Supply Strategy Alternative and their General Environmental Impacts), User Manual, IAEA, Vienna.

MOM, 2004. Ministry of Oil and Mineral Resources, official message to the AECS, Damascus (in Arabic)

MOM, 2009. Ministry of Oil and Mineral Resources, official Data, Damascus (in Arabic)

WOG, 2009.Workshop on future strategic plane for oil and gas production in Syria, Damascus, December 2009.

Atlas,2006. Syrian Wind Atlas. Damascus NEC, 2009. Projection of Syrian Final Energy demand up to 2030. National Energy

Committee, prime ministry council, Damascus (in Arabic).

3-6 OPTIMAL SUPPLY STRATEGY FOR UAE

2-6-1 MESSAGE Model of Emirate Energy System

3-6-1-1 Levels and Forms of Emirate Energy System Energy levels classify the different stages that any energy form passes through during the conversion processes to arrive the final demand. 4 energy levels are considered consisting of domestic resources, primary energy, secondary energy and final energy. The energy levels are linked with each other by energy conversion technologies like extraction, treatments, generation, transporting and distribution. Table 1 presents the structure of UAE energy system which focuses only on the power sector. Table 1 :Energy forms & levels used in national energy system

Crude Oil Resources

Natural Gas Natural Gas Primary Energy Level Oil

Secondary Energy Level Electricity Final Energy Level Electricity Demand

Resources: UAE fossil resources are limited to oil and natural gas. The UAE holds the fifth largest proven oil in the Middle East , and the fifth largest proven Natural Gas reserves in the world . The United Arab Emirates (UAE) is an important oil producer with the fifth largest proven oil reserves in the Middle East. The UAE is a member of the Organization of the Petroleum Exporting Countries (OPEC) since joining in 1967. The emirate of Abu Dhabi is the center of the oil and gas industry, followed by Dubai, Sharjah, and Ras al Khaimah. In 2008, natural gas supplied 64 percent of the country’s total energy consumption, and oil supplied the remaining 36 percent. The UAE plans to increase production capacity future over the next seven years .In 2008, EIA estimates that the United Arab Emirates (UAE) produced 2.9 million barrels per day of total oil liquids, of which 2.5 million was crude oil. The UAE’s proven oil reserves is estimated to 97.6 billion bringing UAEA to the fifth rank in the region. UAE crude streams are expensive due to their light and sweet composite compared to other Middle Eastern producers. The UAE’s proven natural gas reserves is estimated to 214 trillion cubic feet (Tcf) as of January 1, 2007. UAE holds the fourth largest proven natural gas reserves in the Middle East after Iran, Qatar, and Saudi Arabia. The expected future production of oil and NG are given in Table 1. Table 1: Expected future daily production of crude oil and natural gas.

Year 2003 2004 2005 2007 2010 2015 2020 2025 2030 Crude Oil (kboe/d) 2400 2400 2500 2500 2800 4600 5100 5800 6900 Natural Gas (BCf/d) 4.33 4.48 4.55 4.72 5.34 7.48 10.44 10.55 10.55

Primary Energy Level: At this level four energy forms are defined consisting of natural gas, crude oil at the oil field, crude oil at refinery gate and imported nuclear fuel for the nuclear power plants.

Secondary Energy Level: Seven energy forms are included; natural gas (after treatment in the gas factories), liquefied gas (produced from gas factories oil refineries and direct import), gasoline and kerosene, diesel, fuel oil, asphalt, heavy derivatives ( Coke and Sulphur) and electricity at the gate of power plants.

Final Energy Level: Four energy forms are included representing motor fuel (refers to energy consumption in the transportation sector), heat uses (in industry, service and household sector), electricity demand in all consumption sectors and non-energy demand (for fertilizer, petrochemical industry, and asphalt).

Figure 1 presents the schematic network of Syrian energy system including energy chains, technologies and forms for the specified energy levels.

3-6-1-2 UAE Final Energy Demand As already mentioned UAE case is limited to the analysis of power sector. The expected future final electricity demand and peak load at final level are adopted from BMI LTD, Report Q 2008 , and EIA Energy overview 2009 (Table 2). According to Table 2 the electricity demand will grow at annual growth rate of 8.2% arriving about 377 TWh in 2030. Table 2: Projected final electricity demand and peak load of UAE.

Year 2003 2004 2005 2007 2010 2015 2020 2025 2030

Final Electricity

(TWh) 44.42 47.09 53.87 67.57 96.8 148.2 198.6 294.35 376.94

Peak Load (MW) 9963 9570 10907 13438 16928 24873 34885 48929 68625

.

3-6-1-3 UAE Energy Conversion Technologies Technologies are used for connecting two energy levels which results either in conversion the energy form (e.g. producing electricity from gas) or just energy

transforming or distributing. In the defined system network both existing and future candidate technologies are included. Each technology is defined by activity and capacity variables. Capacity definition deals with technical factors like capacity unit, annual operation time, plant factor, economic life time, construction time, maximum and minimum operation level, fixed operation cost and overnight cost. Activity definition describes the operation of technology and includes define input and output of energy form, efficiency, and variable operation & maintenance cost. The user can define more than one activity of a technology for alternative mode of operation. The user can impose limits or bound on technology such as maximum capacity that can be built on a technology, or maximum and minimum levels of output from a technology. There is variety of limits and bounds that can be defined on capacity building of technologies. Moreover, there is a set of limits/bounds that can be defined for variables related to activity of a technology i.e. its input, output and fuel inventory. If a technology has more than one activity, limits and bounds can be defined on technology variables of each activity. Besides, a global limit on all activities of a technology can also be defined. The Syrian energy system has been modelled using 38 technologies of following categories:

Oil & Gas extraction; Oil & Gas transportation; Oil Refineries; Electric power plants; Transmission & distribution of oil, oil derivatives, natural and liquid gas,

and electricity; Export & import.

Table 3 presents a list of the future power plant candidates in the UAE power system. Table 3: Future power plant candidates of UAE power system. Unit

Size [MW]

Overnight cost [$/kW]

Economic life [y]

Const-time [y]

Plant factor [%]

Fuel Efficiency[%]

CC_PP 600 900 25 3 87.6 NG 55 GT_PP 150 650 25 2 91.1 NG 35 FST_PP 400 900 30 4 80.8 HF 38 GST _PP2 300 800 30 3 82.8 NG 38 Wind_PP - 1800 25 2 28 - - Solar_PP - 3155 25 30 PV_PP 10 4481 25 2 30 - - Nuc_PP 1000 2200 50 6 85 - 1

3-6-1-4 Reference Supply Scenario Assumptions for UAE The following bounds and limits are adopted during study simulation, to reflect as much as possible the actual situation and conditions:

Regarding to oil and Gas reserves and annual productions: the official numbers that are mentioned before are adopted;

Nuclear and wind power plants aren’t available before 2015, and the recent governmental policy to implement the nuclear power for electricity generation was

considered starting from 2015 with 1000 MW and new capacity of 1000MW during each periods beyond 2015.

Electricity exchanging is available for both import and export with limits of 1000MW

All produced NG quantities are available to be used in electricity generation.

2-6-2 Results of Reference Energy Supply Strategy of UAE To meet the projected future final energy demand (Table 2), the following supply scenario has been developed to realize optimal national supply strategy characterized by minimal total costs of the energy system over the study period.

3-6-2-1 Trend Results of Energy Supply for UAE

3-6-2-2 Power Sector and Electricity Supply The result of the optimal electric expansion plan show that the generation system will rely more upon combined cycle power plants. Moreover, Nuclear and Wind power plant will have a considerable role in UAE electricity supply system beyond the year 2015 when many existing capacities will turn off. The total electricity generation will doubled by more than 8.7 times during the study period jumping from about 5635 MWyr in 2003 to more than 48898 MWyr in 2030 achieving an annual growth rate of more than 8%.

3.6.2.2 Capacity Expansion comparing to the present situation, results indicates that future power plants mixture will have more diversity, containing new types of electricity power plants that ensure the security supply and comply with the environmental affaires. Figures 3.1 and Table 4 present the development of capacity addition during the study period. By the year of 2007 an additional capacity of almost 4200 MW is to be added (according to the official numbers that is adopted from the UAE report).However, by 2015 about 20% of the existing capacities are supposed to phase out for technical reasons related to the economic life time, which create a big challenge for electricity supply system. Regarding to it’s technical advantages, CC_PP will be the favourable option for system expansion, going with this facts this type will be the unique fossil fuel choice during the periods two periods after 2007, and results suggest to add 8400 MW in 2010 and 6600 MW in 2015, to cover the growing demand and replacing the shift off power plants, by 2030the total new addition of CC_PP will amount about 37800 MW. Owing to the insufficient natural gas quantities (according to projected production quantities) in 2025 the additional capacities of CC_PP will not be enough to cover the demand and Fsteam_PP will has it’s role with total installed capacity of 25000 MW in 2030. For technical reasons related to start up time and loading flexibility, a very limited capacities of new NG_PP will be needed to serve mainly in the peak load region in the load curve ( only 750 MW will be installed by 2030). Following the official policy in encouraging new electricity generation options to serve in the electricity system, wind & nuclear _PP will enter by 2015 starting from 600, 1000 MW respectively in 2015, to 4000 MW each in 2030 (Table 4).

Total Installed Capacity in 2030 distributed by plants types

24884MW 35%

750MW1%

37800MW 52%

4000MW6%

4000MW 6%

CC GT Steam Wind Nuclaer

Total Installed Capacity in 2003 distributed by plants types

4342 MW 35%

8064MW 65%

GT Steam

Figure 3-6-1: Structure of total installed capacity in 2003 and 2030

Table 4: development of new capacity addition by power plant type (MW). Exis &com CC GT Fsteam Wind Nuclear

2003 12406 0 0 0 0 0 2004 13617 0 0 0 0 0 2005 15998 0 0 0 0 0 2007 17086 0 0 0 0 0 2010 15116 8400 0 0 0 0 2015 14113 15000 0 0 600 1000 2020 12409 22800 450 0 1600 2000 2025 20747 28800 750 12000 3000 3000 2030 4884 37800 750 20000 4000 4000

Figure 6 presents the development of installed capacity over the study period. Starting from a total installed capacity of around 12400 MW in 2003 (distributed by almost 35% for steam fired power plants and 655 for NG_PP), future generation system will be optimally expanded arriving around 71450 MW in 2030 distributed by 52% for CC_PP, 35% Fsteam_PP, while the remaining 13% will distributed between wind_PP, nuclear_PP, and GT_PP with shares of 6%,6%, and 1% respectively. Figure below presents the future development of the installed capacity comparing to the expected peak load development over the study period.

0

10000

20000

30000

40000

50000

60000

70000

80000

2003 2004 2005 2007 2010 2015 2020 2025 2030

MW

Exis &com CC Fsteam Nuclear Wind GT Peak Figure 3-6-2: Development of Peak Load and optimally expanded installed capacity of future generation system by power plant type.

3.6.2.2 Electricity Generation and Fuel Consumption Results indicate that the total electricity generation will doubled by 8.7 times during the study period jumping from about 5635 MWyr in 2003 to more than 48898 MWyr in 2030 achieving an annual growth rate of 8.3% approximately.

Table & figure below present the development of total electricity generation during the study periods distributed by fuel types.

Results show that fossil fuel will remains the dominated consumed fuel in the electricity generation system during the next three decades, in spite of the exerted efforts to diversify the fuel baskets.

Figure 7 shows the expected development of generated electricity by type of fuel. Up to 2010 the generation system will rely mainly on both heavy fuel oil (HF) and NG that are produced locally. Share of electricity generated by NG fired power plants will increase from almost 75% in 2003 to arrive its maximum of more than 91% in 2015, after 2015 it will decrease gradually taking the space for the new fuels( wind and nuclear) and finishing the study periods at the level of 71%. From the other side, the raising trend of NG share during the first periods will lay its shadow on the electricity generation from HF resulting on a dramatic declining from about 25% in 2003 to almost 18% in 2007 and about 8% in 2010. This trend will continue till 2020 when the lowest share will be achieved by almost 3% of the total electricity generation, after this year it will raise up forced by the building new addition Fsteam power plants (as a result of the fact that the local NG quantities will not sufficient to stimulate building more CC_PP) and finishing the study with share of almost 20%.

Nuclear and wind electricity generation will be available by 2015, when about 850 and 168 MWyr respectively will be produced, the expected contributions from wind and nuclear electricity at the end of the study will amount to 2.3% and 6.9% respectively.

Figure 3-6-3: Development of total electricity generation distributed by fuel types between 2003-2030

To cope with the high growth rate of electricity generation the fuel requirement will grew by 6.3% annually arriving about 76.3 Mtoe in 2030 compared to 14.62 Mtoe in 2003.

Table 3.22.2 summarizes the results of future electricity generation by type of fuel consumption. The results indicate that the total consumed HF for electricity generation will decline from 26% (from the total consumed fuel for electricity generation) in 2003 to 6.5% in 2015 achieving the lowest contribution in 2020 with 5.3%, after that it will increase during the next two periods and finishing the study at level of 25%. The picture of natural gas requirements will be reversed and it\s contribution will show strong grow between 2003 and 2015 jumping from about 74% to 88% respectively, beyond this year it’s expected to go down to 65% in 2030, after 2015 the nuclear power will take place and the nuclear fuel contribution will increase from 6% in 2015 to 10% in 2030. Figure 3.22. depicts the development structure of fuel mix required for electricity generation for the years 2003 and 2030.

Table 3.2.2: Electricity generation and corresponding fuel consumption distributed by fuel types (NG: natural gas, FO: fuel oil) during the study periods

NG Fuel Wind Nuclear Total Fuel (Mtoe) 10.8 3.8 14.6

2003 Gen (TWh) 37.0 12.4 0.0 0.0 49.4 Fuel (Mtoe) 11.6 3.8 15.3

2004 Gen (TWh) 40.0 12.4 0.0 0.0 52.3 2005 Fuel (Mtoe) 13.3 4.1 17.4

Gen (TWh) 46.5 13.4 0.0 0.0 59.9 Fuel (Mtoe) 18.2 4.1 22.3

2007 Gen (TWh) 63.4 13.4 0.0 0.0 76.8 Fuel (Mtoe) 20.7 2.7 23.3

2010 Gen (TWh) 101.3 8.7 0.0 0.0 110.0 Fuel (Mtoe) 28.8 2.0 1.9 30.8

2015 Gen (TWh) 152.9 6.6 1.5 7.4 168.4 Fuel (Mtoe) 35.8 2.0 2.9 40.6

2020 Gen (TWh) 204.2 6.6 3.9 10.9 225.7 Fuel (Mtoe) 40.9 14.0 5.8 60.8

2025 Gen (TWh) 243.4 61.4 7.4 22.3 334.5 Fuel (Mtoe) 49.2 19.3 7.8 76.3

2030 Gen (TWh) 303.7 85.0 9.8 29.8 428.3

Fuel consumption in 2003 by Fuel Types (14.62 Mtoe)

74%

26%

NG fuel

Fuel consumption in 2030 by Fuel Types (76.3Mtoe)

65%

25%

10%

NG fuel Nuc

Figure 3-6-4: Comparison of fuel mix requirement for electricity generation for 2003 and 2030.

3-6-2-3 Primary Energy Supply of UAE The optimal supply strategy indicates that UAE will still rely mainly upon oil products and natural gas to cover its primary energy supply. ..... [add more to primary supply..]

2-6-3 Conclusion The electricity generation by fuel type shows that the share of natural gas in the power sector will arrive almost 83% in 2015 and then decrease continuously to about 32% at the end of study period. The retreat of natural gas for electricity generation will be compensate by fuel oil and nuclear of the shares 55.4% and 7.5% respectively. The total installed capacity will be optimally expand from 6230 MW to 30300 MW during the study period. The new capacities addition will amount to 29800 MW distributed to fuel fired steam turbine, combined cycle, gas turbine, PV and wind power plants and two nuclear power plants that are expected to enter the system after 2020.

3-7 OPTIMAL SUPPLY STRATEGY FOR YEMEN

2-7-1 MESSAGE Model of Yemeni Energy System

3-7-1-1 Levels and Forms of Yemeni Energy System Energy levels classify the different stages that the any energy form passes through during the conversion processes to arrive the final demand. 4 energy levels are considered consisting of domestic resources, primary energy, secondary energy and final energy. Final level is identical to the energy demand. The energy levels are linked with each other by energy conversion technologies like extraction, treatments, generation, transporting and distribution. Import and export of energy forms are modelled either at primary or secondary level reflecting the real situation of the considered fuel type. According to the modern classification of Yemen energy form Levels and the Massage's program we classified the energy form levels to five levels and summarizes levels and forms of energies to developed in MESSAGE model. Energy forms & levels that used in Yemen energy system :

Crude Oil Resources

Natural Gas Crude oil

Crude refinery NG

Primary Energy Level

Export Electricity

Fuel oil (Mazot) NG

LPG Kerosene Gasoline

Diesel


Export Final Energy Level Electricity

Electricity Motors Demand

Heat

Resources: It's the first stage in the energy system chain and refers to available domestic energy resources like fossil (oil, gas, and coal),. By modelling the resources in MESSAGE a subdivision into three cost categories called grades is available, which enable the user to represent three types of reserves:


It should be mentioned that according to the continuous improvements in the exploration and extraction technologies the amount of extractable and proven reserves could increase on the cost of geological reserve. However, this will be coupled with additional investments and extra costs. According to this principle and for economical reason, the model will exploit resources gradually starting from the cheapest, so that grade (a) wouldn't be overstepped unless it is used up (detailed description of Yemeni energy resources are presented in Chapter 2).

Following the official data the expected development in oil and natural gas production for coming three decades is presented in Table 1. Table 1: Expected Future Daily Production of Crude Oil and Natural Gas.

Primary Energy Level: At this level 4 energy forms are defined consisting of NG, Crude Oil, Crude for refinery and export.

Secondary Energy Level: At this level 8 energy forms are defined consisting of Electricity, Diesel, Gasoline, Fuel, oil, Kerosene, NG, LPG and Export.

Final Energy Level: At this level 3 energy forms are defined consisting of Electricity, Heat and Motor Fuel.

3-7-1-2 Final Energy Demand The demand comprised the required country energy consumption at final level comprising electricity, heat and motor fuel. As already mentioned MESSAGE methodology starts in formulating the future supply strategy from a given demand that has to be specified externally depending on additional analysis on the demand side (Table 2). Future Yemeni final electricity demand has been projected according to official estimation that covers the period 2006-2012 [Ministry of Electricity, Annual report, 2005]. For the later period 2012-2030 an average annual growth rate of 13% has been assumed reflecting the expected demand increase in all consumption sectors. This high growth rate should reflect the ambition to cover the most service and household consumers. Furthermore, as the independent electricity producer participate up to now at almost 18% in covering the total electricity demand; it has been assumed that this share

Year 2003 2004 2006 2007 2010 2012 2014 2016 2018 2020 2030 Crude Oil (kBbls/day) 431 402 365 319 259 200 200 180 180 170 150

LPG (K tone Metric)

714

746

720

733

912

930

947

415

484

734

2,012

LNG(Million CF/day) - - - - 900 920 950 970 990 1100 1500

will be kept for the future study period. Thus, electricity demand will grow from 507 MWy (4.4 TWh) in 2003 to 8294 MWy (72.6 TWh) in 2030 which mean that it will double by more than 16 times during the study periods. These huge steppes in electricity supply are essential to bridge the gap between the actual and potential current demand; inview of the fact that less than 40% of the population has access to public electricity grid. Expected thermal and motor fuel demand has been projected based on official projection for the development of oil derivatives demand in the period between 2000 and 2035 in the ministry of oil, and the contribution of every fuel in thermal (heat) and transportation (Motor fuel) uses are estimated as well. According to these sources the thermal and motor fuel demand are projected in respect to following:

o The future demand for oil derivatives will grow by 5% for benzene , 11% for diesel, and 10% for fuel oil, in addition to 2%, 6% for kerosene and jet kerosene,

o diesel contributions for heat and motor fuel uses shares 38% and 25% respectively,

o 19% of the total heavy fuel oil consumption goes to satisfy the thermal uses in industry sector,

o 98% of the total LPG consumption is for thermal uses in household, the remaining 2% is for transportation purposes taking to account the future official plans to use CNG for transportation reaching the level of 30% of the total transport consumption in 2025.

Depending on the previous assumptions the projected thermal and motor fuel demands will mount to about 26.5 and 14.53 Mtoe in 2030 starting from3.22 and 3.7 Mtoe in the base year and reflecting annual growth rates of 8% and 5% respectively.

Table 2: Projected final energy demand by type of consumption [Mtoe].

Electricity Thermal Uses

Motor Fuel

Total Year

MWyr Mtoe Mtoe Mtoe Mtoe 2003 872.4 0.66 3.22 3.70 7.57 2004 905.4 0.68 3.35 3.49 7.51 2005 955.7 0.72 3.58 3.53 7.83 2007 1419 1.07 3.85 3.80 8.73 2010 1682 1.27 4.52 4.16 9.95 2015 2322 1.75 6.65 6.44 14.84 2020 2924 2.20 10.53 8.57 21.31 2025 3650 2.75 16.69 9.01 28.44 2030 4467 3.36 26.51 14.53 44.40

3-7-1-3 Import, Export and Energy Exchange The model offers a possibility of modelling the energy exchange between the national system and other external system at primary or secondary level. This feature enables the comparative assessment between internal consumption or exporting of an energy carrier and importing another alternative to comply with the demand taking into account the energy system structure and availability of national resources.

Hence, the developed nation energy model offers the possibilities of import and export of oil derivatives, liquid gas, natural gas, electricity and rest prediction of oil derivatives of at secondary level; crude oil,crude refinery, natural gas and export at primary level. Electrical demand was based on fixed growing because of growing in numinous offer 2012 according for official plans. Gas export would start in 2010 according to official plan, and first electrical gas station would be start operated in the end of 2008 and the second in meddle of 2009. Because of 2007 and 2009 hadn't been involved in the MESSAGE model program.

3-7-1-4 Energy Conversion Technologies Technologies are used for connecting two energy levels which results either in conversion the energy form (e.g. producing electricity from gas) or just energy transforming or distributing. In the defined system network both existing and future candidate technologies are included. Each technology is defined by activity and capacity variables. Capacity definition deals with technical factors like capacity unit, annual operation time, plant factor, economic life time, construction time, maximum and minimum operation level, fixed operation cost and overnight cost. Activity definition describes the operation of technology and includes define input and output of energy form, efficiency, and variable operation & maintenance cost. We can define more than one activity of a technology for alternative mode of operation. The user can impose limits or bound on technology such as maximum capacity that can be built on a technology, or maximum and minimum levels of output from a technology. There is variety of limits and bounds that can be defined on capacity building of technologies. Moreover, there is a set of limits/bounds that can be defined for variables related to activity of a technology i.e. its input, output and fuel inventory. If a technology has more than one activity, limits and bounds can be defined on technology variables of each activity. Besides, a global limit on all activities of a technology can also be defined. Table 2 description of electric power plants of Yemen

Plant Capacity Activity Overnight

cost [$/kW]

Fixed O&M [$/kW/y]

Unit Size [MW]

Economic life [y]

Const-time [y]

Operation time [%]

Historical -capacity [MW]

Input Efficiency [%]

Var O&M cost [$/kWy]

Installed and Committed Power Plants Total Diesel _PP

- 15 327 30 - 82.8 1983-1995

N. Gas 38 17.52

ExtSteam_PP

- 15 435 30 6 90 1984-1991

Fuel oil 30 12

Rayan/mansora_PP

- - 140 35 - 70 1984-1986

diesel 30 17

branches _PP

- 15 320 35 - 70 1985 diesel 30 17

Rural_pp 15 100 32 70 1985 diesel 29 17 Rental_pp - - 377 - - - 2006 - 30 - industrial _PP

- 15 93 35 2 70 1985 diesel 28 17

Hiziaz_PP 600 15 100 30 4 70 2005 Fuel oil 32 12 Future Candidates Mareb_PP 400 12 750 30 2 88 2008 N. Gas 33 26.3 Ma'abr_PP 400 12 450 30 2 90.0 - N. Gas 33 26.3

Steam_pp 525 12 200 30 3 82.8 - N. Gas 38 17 CC_PP 550 12 100 25 3 87.6 - N. Gas 55 10 Wind_PP 1736 20 100 25 1 0.35 - - - 5 PV 4000 40 10 30 1 0.2 - - - 0

Figure 3-7-1: Flow chart of Yemeni energy system.

3-7-1-5 Reference Supply Scenario Assumptions for Yemen Following assumptions, constraints and simplification were adopted for the reference scenario analysis:

- By adopting the official oil and natural gas reserves as described previously Resources' Level;

- Make some limits and boundaries on the annual extractions of oil and natural gas also on the annual crude oil export;

- Considering new refinery candidate with capacity of 230000 boe/day; - Considering the recent established gas station in Marib (Committed Simple Cycle

Gas P.P ) as one of the candidates Stations with capacity of 400 MW in 2009;

- Considering (Future Combined Cycle Gas P.P ) representing by Ma'abar gas station as one of the candidates Stations with capacity of 200 MW in 2018;

- Imposing of entering the Coal Power Plant in 2016 with Capacity of 100MW. - Sharing the above Power Plants with Renewable Power Plants ( Wind-

Geothermal –Solar-Pv) with total Capacity of (210)MW gradually starting from 2012- 2015.

- Include Nuclear Power Plant in 2025 with out any limits. - The overall goal of the Yemen government is to achieve 80% electrification

coverage in grid-quality electricity to rural households by the year 2015 from the current level of 20%.

- Widely expand the access for electricity services to the rural population through development of appropriate programs and action plans to promote the Renewable Energy Technologies.

- Limiting import & export according to the available installed capacity of electric grid interconnection with the neighboring countries and the capacity of Arab Gas.

- Provide access to reliable, safe and environmentally clean electricity services to cover main cities and rural areas, at an affordable cost to the national community.

- No Consideration on the Environmental Effects at this Scenario.

2-7-2 Results of Reference Energy Supply Strategy for Yemen To meet the projected future final energy demand, the following supply scenario has been developed to realize optimal national supply strategy characterized by minimal total costs of the energy system over the study period. The national resources and available energy conversion technologies have be exploited wisely, and import & export options as well.

3-7-2-1 Trend Results of Energy Supply for Yemen According to the above mentioned assumptions the developed MESSAGE’s model of Yemen energy system has been used to formulate the optimal long-term energy supply strategy that assures covering the given future demand at a minimum of total system costs over the entire study period of (2003-2030). Thus, the achieved results regarding the distribution of energy forms at primary and Demand levels, and the selected future technologies from the proposed candidates characterize the best combination that can be achieved by minimizing the objective function, i.e. total system costs, under the set of specified constraints that define the feasible region. Figure (10) presents the total amount of Final Demand and primary energy required at the supply side to cover the future final demand. To cover the final demand that will grow at annual rate of 6.8%, primary demand must grow at 4.4 % annually mounting to 48.6 Mtoe in 2030 comparing with 15.3 Mtoe in 2003.

0

5

10

15

20

25

30

35

40

45

50

2003 2004 2005 2007 2010 2015 2020 2025 2030

Mto

ePrimary Secondary Demand

Figure 3-7-2: Development of Yemeni energy system at various energy levels.

Figure 2 presents the development of secondary and primary energy required at the supply side to cover the future final demand. The total secondary energy before electricity generation will grow from almost 8 Mtoe to 47.6Mtoe during the study period, while the secondary after electricity will grow from 7.8 Mtoe to 45 Mtoe. The average energy system efficiency (ratio of final to primary energy) will be improved from 50% to 90% during the study period reflecting the expected efficiency improvement in the electricity generation system due to the increased contribution of combined cycle power plants.

3-7-2-2 Secondary Energy Supply This level considers all energy carriers allocated for internal consumption consisting of oil derivatives, natural gas, renewables and nuclear. These carriers are either consumed directly by the end consumers or used partially in the power sector for electricity generation where the new energy carrier "electricity" appears. Thus, as mentioned above, at the secondary level one has to distinguish between secondary energy before and after electricity generation. Table (20) and Figure (11) show the distribution of secondary energy by fuel types before electricity generation (total secondary fuel including thus allocated for electricity generation). Subsequently the secondary energy supply during the study period will be covered mainly by diesel, fuel oil, gasoline, kerosene, LPG, natural gas, and coal.

Table 3: Distribution of secondary energy by fuel type (before electricity generation) (Mtoe) Diesel Gasoline Kerosene Mazot LPG Coal Nuclear NG Renewable 2003 3.456 1.770 1.811 0.641 0.353 0.000 0.000 0.000 0.000 8.0302004 3.521 1.787 1.765 0.641 0.376 0.000 0.000 0.000 0.000 8.090

2005 3.672 1.900 1.822 0.641 0.393 0.000 0.000 0.000 0.000 8.4282007 4.487 1.970 2.313 0.633 0.412 0.000 0.000 0.000 0.000 9.8142010 3.470 2.150 1.152 1.674 0.581 0.000 0.000 2.767 0.000 11.7962015 4.657 2.780 1.964 1.902 0.852 0.000 0.000 4.526 0.026 16.7062020 7.036 3.812 3.203 1.761 1.377 0.374 0.000 5.915 0.249 23.7262025 10.141 5.139 5.336 1.884 2.197 0.562 0.000 5.835 0.300 31.3952030 16.039 6.839 8.938 1.451 3.538 0.436 0.768 9.199 0.344 47.552

Shares % 2003 43.0 22.0 22.5 8.0 4.4 0.0 0.0 0.0 0.0 1002004 43.5 22.1 21.8 7.9 4.6 0.0 0.0 0.0 0.0 100 2005 43.6 22.5 21.6 7.6 4.7 0.0 0.0 0.0 0.0 100 2007 45.7 20.1 23.6 6.4 4.2 0.0 0.0 0.0 0.0 100 2010 29.4 18.2 9.8 14.2 4.9 0.0 0.0 23.5 0.0 100 2015 27.9 16.6 11.8 11.4 5.1 0.0 0.0 27.1 0.2 100 2020 29.7 16.1 13.5 7.4 5.8 1.6 0.0 24.9 1.1 100 2025 32.3 16.4 17.0 6.0 7.0 1.8 0.0 18.6 1.0 100 2030 33.7 14.4 18.8 3.1 7.4 0.9 1.6 19.3 0.7 100 With 47.6 Mtoe in 2030 the total secondary energy demand doubles by almost 6 times during the study periods, starting from 8 Mtoe in 2003. This demand will cover by Diesel, NG, kerosene, gasoline, LPG, mazot, nuclear, coal, and renewable. As shown in table 20, all the demand will cover by oil derivatives till 2010 when the first commercial amounts of natural gas appear and take its role in fuel mixture especially for electricity generation, when CC_PP will serve as new and efficient candidates in electricity system replacing the old diesel and mazot (fuel oil) power plants. Results refer that diesel will keep on it’s rank as the main energy carriers over the study periods, despite of the declining in it’s share to 33.7% comparing with 43% in the base year. However, and as was mentioned before NG will have a considerable role starting from 2010 when it supposed to contribute by almost 23.5 of the total energy supply at secondary level ranking the second after Diesel, and maintain it’s rank jumping to 27% in 2015, beyond that it will go down finishing the study by 19.3%. Gasoline and kerosene shares will decrease from 22%, 25% in 2005 to 14.4% and 18.8 % respectively in 2030. Moreover, LPG share will grow 4.4 % to 7.4% over the study period, while mazot contribution will decline from 8% in the base year to 3.1 % by 2030 (because of the expected change in the electricity generation fuel mixture for the favor of NG and nuclear ) although of showing an increasing trend between 2003 and 2015 and reaching it’s highest value in 2010 with 14.2% and go down to 7.5%. Renewable energy (wind and PV) will contribute after 2015 with an expected share of about 1% of total secondary energy. The same rend is observed for nuclear and coal that will enter the system in 2020 for coal and 2025 for nuclear with an expected average shares of about 1.6% each.

0.000

5.000

10.000

15.000

20.000

25.000

30.000

35.000

40.000

45.000

50.000

2003 2004 2005 2007 2010 2015 2020 2025 2030

Mto

e

Diesel Gasoline Kerosene Mazot LPG Coal Nuclear NG Renewable

Figure 3-7-3: Distribution of secondary energy by energy form (after electricity generation) Figure (6) present the development trend of the energy forms at the secondary level. This figure shows that the share of Diesel in the secondary energy supply will keep on its very important role because of the fact that it penetrates all demand categories, although of the decreasing trend that is shown over the study periods comparing with the base year. Despite of increasing of Gasoline and kerosene amounts, their shares decrease because of partially replacing of kerosene by LPG in transport sector and kerosene by others in thermal uses. Figures (7) and Figure (8) present the distribution of secondary fuel for covering motor fuel and heat application. The fuel demand for heat use will duplicated 4 times from 3.7Mtoe in 2003 to 14.53 recording an annual growth rate of 5.2%. Figures (7)and (8) present the mixture of fuel with which both motor fuel and heat demand was complied. The 1.98 Mtoe of Motor fuel (transportation mainly) demand covers in the base year by gasoline, LPG, diesel, and kerosene, this mix distributed by 54%, 1%, 40%, and 5 respectively, the ambitious plans of government to support using LPNG in transportation will yields after the year 2015 and it's share will go up to 4% then 8% and 11% in the years 2025, 2030 respectively. This switching reflects dramatically on gasoline share that's dropped to 26% by the end of study period meditative by the previous reason and the steady growing of diesel share from 40% to 59% between 2003 and 2030, as a result of the expected increasing of diesel small and heavy cars.

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

2003 2004 2005 2007 2010 2015 2020 2025 2030

Diesel Kerosene LPG Mazot NG

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

2003 2004 2005 2007 2010 2015 2020 2025 2030

Gasoline LPG Diesel kerosen

Figure 3-7-4: Distribution of Heat demand fuel demand by fuel type.

Figure 3-7-5: Distribution of Transport demand by fuel type.

For heat uses, the main share of the 1.44 Mtoe was covered by LPG (44%) in the base year while the remaining shares come from fuel oil, diesel, kerosene that are shared by (13%,36%, 7.9%) respectively. Till 2007 LPG serves as the main contributor in heat uses then it's share do dawn for diesel favour in 2010 and keep on this trend of declining till the last year when it's share mounts about 19%. In 2010 NG takes it's role as cheap and clean fuel to cover the thermal uses demand ( LPNG in house hold sector and NG for industry and other sectors) by 3% and grows to 30% by the end of the study period. Kerosene share drop dramatically and replaced mainly by Ng specially in household sector where most of this fuel is consumed and it's almost disappear By 2030. However, The remaining amount covers by fuel oil with 11%.

3-7-2-3 Primary Energy Supply The optimal supply strategy indicates that Yemen system Energy will still rely mainly upon oil products and natural gas to cover its primary energy supply until 2010 then it will decrease its dependants' on Oil Products and after 2010 to start to use the Natural Gas and Coal as essentially new resource of the power supply Consumption as its shown in table (21) As mentioned previously, results refer that the primary energy will gradually increase from almost 15.31Mtoe to 48.65Mtoe with 4.4% annual growth rate during the study period. Moreover the table (21) below can show the development oil and natural gas supply in view of import and export possibilities. It refers to that from 22.4 Mtoe in 2003 the production decrease to16Mtoe in 2010, and keep on this trend of declining till 2020 when it reach to 14.2 Mtoe and maintain this level over the last three periods . While the exported activities will limited on crude oil as there is no extra amount of derivatives to be exported. Results refers that the expected exported amounts of Crude oil will follow

up the production trends and fall from 8.9 Mtoe to almost 5.5 Mtoe between 2003 and 2030 respectively. Table (21) Development of crud oil and natural gas supply (Mtoe)

Crude Oil Natural Gas Uranium

Coal

Local Export Total Local Export Total Import Import

2003 22.35 -8.87 13.48 0.00 0.00 0.00 0.00 0.00 2004 20.89 -8.87 12.02 0.00 0.00 0.00 0.00 0.00 2005 20.89 -8.87 12.02 0.00 0.00 0.00 0.00 0.00 2007 18.95 -8.68 10.27 0.00 0.00 0.00 0.00 0.00 2010 15.63 -6.82 8.81 14.84 -11.34 3.50 0.00 0.00 2015 15.63 -5.46 10.17 16.70 -11.34 5.36 0.00 0.00 2020 14.21 -5.46 8.75 18.00 -11.34 6.66 0.00 0.37 2025 14.21 -5.46 8.75 17.91 -11.34 6.57 0.00 0.56 2030 14.21 -5.46 8.75 21.52 -11.34 10.18 0.77 0.44

In Yemen Case the Gas situation will share the Oil as a new resource of energy extract in the period of 2010 to the end of the study, where the production capacity will grow gradually from 14.8 Mtoe to 21.5 Mtoe between 2010 and 2030. This production is encouraged to build several natural gas (combined-cycle) power plants beside the oil-fired plants. A constant amount of this production of about 11.34 Mtoe will be exported following the committed contract with the international gas industry developers. Starting from the year of 2020 0.37, 0.56, 0.44 Mtoe of Coal will be imported for electricity production during the last three periods. While uranium needs will be limited at 0.77 Mtoe and used in the projected unclear power plants during the period between 2025 and 2030.

Table (22) shows the projected future development of oil derivatives supply , and imply that our Yemen energy system will depends on importing some oil Derivatives because of the shortage in local Refining and the continuous rising of oil Derivatives demand in local Consumption, furthermore, some official and international studies and estimations assured that Yemen oil production will faces many challenges in the next years due to Expectation on production declines over the years because of the deplete on of the existing wells and a lack in new exploration while consumption rises. Results show that the Crude oil will be refined from both (Aden and Marib) Refinery by a total Energy of 1488 MWyr until 2010, while the new Refinery Which will be located in Somewhere in the Coastal areas in Yemen will start to enrolled the service by the end of 2012 with a total energy of 5100 Mwy which will support the local oil derivatives production. However, this new capacities will not be sufficient to cover the local demand and a considerable amounts of oil derivatives must be imported .

Table (22): development of oil derivatives balance over the study periods (Mtoe)

Diesel gasoline Kerosene LPG Mazot 2003 Local Import Local Import Local Import Local Import Local Import 2004 2.648 0.808 1.550 0.221 0.741 1.069 5.543 0.000 0.641 0 2005 2.648 0.873 1.550 0.237 0.741 1.024 5.411 0.000 0.641 0 2007 2.648 1.025 1.550 0.350 0.741 1.080 5.411 0.000 0.641 0 2010 2.457 2.030 1.440 0.530 0.741 1.572 4.830 0.000 0.633 0 2015 2.559 0.912 1.353 0.798 1.086 0.067 2.758 0.000 1.403 0 2020 3.207 1.449 1.605 1.175 1.369 0.594 2.477 0.000 2.060 0 2025 2.751 4.285 1.293 2.519 0.837 2.365 2.732 0.000 1.755 0 2030 2.947 7.194 1.310 3.830 0.900 4.435 2.288 0.000 2.128 0 2003 2.566 13.473 1.228 5.612 0.578 8.360 3.538 0.000 1.396 0 Depending on the obtained results, future carry heavy burden for both energy system and economy that can be concluded in the raising of importing energy carriers bill especially during the last three periods when the total imported energy will pass the level of 50% of the total consumed oil derivatives and reaching about 74% in 2030 .

3-7-2-4 Power Sector and Electricity Supply The growing electricity generation and peak load demand Deserved adequate continuous capacity addition of different power plant types during the study period. The optimal expansion plan refers to the least cost plan over the whole study period in respect to national constraints in term of economic, technological and fuel availability. Thus, a suitable list of power plant candidates has been considered that consists of Coal, Combined Cycle Gas (CCG), and some Renewable Power Plants Such as (Wind ,Geothermal, PV) Which has highly Potentials in Yemen as we mentioned before and Limited Nuclear Station as Essential Technology should be applied in Yemen. Results indicates that to follow up the continues growing in electricity demand and to comply with economic development requirements, the total installed capacity in the power sector will double by almost 6.22 times during the next 27 years, achieving mounting about 9560 MW in 2030 comparing with 1535 MW in the base year, which mean an average yearly added capacity of 300MW. As a result The total electricity generation will grow from 805MW to 5255MW between 2003 and 2007, with an average growth of almost 7% annum. Nuclear electricity will not have the role before 2025 where a 1200MW to be added, while renewable energy will have a limited role starting from 2015.

3.7.2.4 Capacity Expansion The total installed capacity will be optimally expand from 1535 to 5255 MW during the study period. It consists of around five power plants as it's shown below in figure (16), where most of them such as (Branches, Rental, Diesel Single Fuel ,Exist Steam ) will be stop working with in 2020 almost , while the others will Continue working to the end of the Study such as (Diesel Duel Fuel , Industrial , Ruler , Committed Single Cycle Gas,) Power Plants. During the Study Period the System will need to install about 1000Mw

with different kinds of Power Plants such as (Coal PP, Combined cycle Gas PP, Geothermal PP, Wind PP, PV PP , Nuclear PP) all of them are represent 50% of the system as its seen in table (23).

New Capacity Addition

0

500

1000

1500

2000

2500

3000

3500

2003 2004 2005 2007 2010 2015 2020 2025 2030

MW

CC_PP G_PPNuclear_PP Coal_PPRenewaple_PP Diesel_PPIndustrial_PP Rural

Figure 3-7-6: Total new capacity addition of future electric generation system

Table (23) the total installed capacity addition of future electric generation system(MW). CC_PP G_PP Nuclear_PP Coal_PP Renewaple_PP Diesel_PP Industrial_PP Rural_2003 0 0 0 0 0 0 02004 0 0 0 0 0 90 32005 0 0 0 0 0 280 72007 0 0 0 0 0 1058 122010 0 620 0 0 0 1740 2192015 900 620 0 0 25 2520 2322020 1500 400 0 500 170 2740 2462025 2100 400 0 1000 225 3080 2622030 2400 400 1200 1500 270 3260 451

Another Configuration of the resulting Program is shown the Development of Future Generation Distributed by type s of power plants during the study Periods as show in figure (17) below.

Total installed capacity by type of generation

0

2000

4000

6000

8000

10000

12000

2003 2004 2005 2007 2010 2015 2020 2025 2030

MW

Existing PP Coal PPCC_NG G_PPRenewable PP Nuclear PP

Figure 3-7-7: Development of Optimally Expanded Installed Capacity of Future Generation System by Power Plant Type.

3.7.2.4 Electricity Generation and Fuel Consumption Table (24) presents the development of electricity generation and fuel consumption by type of fuel. As a result of depending on small and local power plants, diesel forms the main fuel in electricity generation system. The total fuel consumed for electricity generation will increase from about 1.116 Mtoe in 2003 (distributed by 70% diesel and 30% Mazot) to 6.17 Mtoe in 2030 that means more than 5.5 times doubled. By 2010 the system will Enrolled the natural gas for electricity production using tow types of power plant (CSCG & FCCG) in addition to the fossil fuel (Diesel and Mazot), with a very small amount of renewable (Wind) energy in 2015, also Coal Power Plants in 2020 and Nuclear Power Plant by the end of the Study. With share of more than 60%, natural gas is projected to be the main consumed fuel in electricity generation system by the end of the study period while it will generate about 44% of the total electricity in the same year, followed by Mazot, and diesel with shares of 12.7 and 7.7 respectively, while the remaining contributions come from nuclear and coal with 12.5% and 7.1% respectively. Table (24) Distribution of electricity generation and fuel consumption by type of fuel (Diesel, Mazot, NG, Renewable, Coal, Nuclear Fuel).

Diesel Mazot NG Renewable Coal nuclear Total 2003

Gen 472.6 332.0 0.0 0.0 0.0 0.0 804.5

(MWy) Fuel (ktoe) 784.8 331.1 0.0 0.0 0.0 0.0 1115.8 Gen (MWy) 539.9 366.8 0.0 0.0 0.0 0.0 906.7 2004 Fuel (ktoe) 901.3 357.3 0.0 0.0 0.0 0.0 1258.6 Gen (MWy) 567.6 440.2 0.0 0.0 0.0 0.0 1007.9 2005 Fuel (ktoe) 907.0 412.7 0.0 0.0 0.0 0.0 1319.7 Gen (MWy) 960.2 732.6 0.0 0.0 0.0 0.0 1692.9 2007 Fuel(ktoe) 1524.1 632.9 0.0 0.0 0.0 0.0 2157.0 Gen (MWy) 618.8 889.4 594.4 0.0 0.0 0.0 2102.5 2010 Fuel (ktoe) 728.7 799.4 1588.9 0.0 0.0 0.0 3116.9 Gen (MWy) 644.1 1030.4 1145.9 11.3 0.0 0.0 2831.7 2015 Fuel(ktoe) 644.3 848.0 2096.6 0.0 0.0 0.0 3588.9 Gen (MWy) 621.9 1069.4 1558.6 109.2 163.9 0.0 3522.9 2020 Fuel (ktoe) 540.0 824.8 2635.3 0.0 374.0 0.0 4374.1 Gen (MWy) 679.9 1182.2 2054.1 131.5 246.4 0.0 4294.1 2025 Fuel (ktoe) 578.6 906.8 3352.1 0.0 562.4 0.0 5399.9 Gen (MWy) 574.1 1019.0 2300.5 150.6 191.0 1020.0 5255.3 2030 Fuel (ktoe) 474.9 782.8 3707.6 0.0 436.0 768.3 6169.6

Results conclude that to bridge the gab between the demand and generation, which appear during the first three periods in form of supply shortage (about 32% of the total electricity generation), and to reduce the share of independent producers in the total demand, the total generated energy between 2003 and 2030 will jump from 805 MWyr to 5255 MWyr recording an annual growth rate of 5.6%.

Mazot 1116 MWy 21%

Diesel, 626 Mwyr 12%

NG, 2151MWy41%

Nuclear 1020MWy 19%

Coal, 191MWy 4%

Renewable 151MWy

3%

Figure 3-7-8: projected Future Generation in 2030 Distributed by type of power plants (MWyr) .

As presented in figure (18): from the total electricity generation, natural gas power plant (mainly the new combined cycle) will be the main contributor by 41% of the total generation, followed by Mazot ,Nuclear, and Diesel with 21%,19%, and 12% respectively. while the remaining 7% will cover by coal and renewable power plants with 4%, and 3% respectively.

2-7-3 Conclusion

References OAPEC, 2008. Annual Statistical Report. Organization of Arab Petroleum Exporting Countries, Kuwait, http: //www . oapecorg .org

44.. RREEGGIIOONNAALL GGRRIIDD IINNTTEERRCCOONNNNEECCTTIIOONN (this chapter needs to be updated) In MESSAGE, the user has the possibility to simulate the energy exchange between the analyzed system and the ambience at any energy level. This feature is essential for optimizing the cost of the energy system. In MESSAGE there are two ways to realize that. The first possibility is applied for single energy system and being realized by using the simple import and export technologies with the corresponding negative and positive cost flow. In addition to the import of not available or export of excessive energy carriers this possibility enables, according to the cost effectiveness, the selection between consuming a national energy carrier or exporting it and import another more suitable one taking into account the applied energy technologies and the available resources. This feature has been applied by the optimization of the national energy systems in the previous chapter. The other possibility is applied to link different regions (subsystems) in unique global energy framework (Multiregional), e.g. different local subsystems in one national system or different national subsystems in one regional system. The new achieved global energy system has one objective function and the optimal solution is not more related to one subsystem but to the optimal consumption of an energy alternative over the whole system. That means it is not important where an energy carrier is produced or consumed but what the whole energy chain does cost for the system. In this regard the energy flows between the subsystems have to be balanced. Figure 4-1 shows schematically the country linkage network.

Main Region(ARASIA)

Main Region(ARASIA)

YEMYEM KSAKSA JORJOR SYRSYR LEBLEB

Main Region(ARASIA)

Main Region(ARASIA)

YEMYEM KSAKSA JORJOR SYRSYR LEBLEB

UAEUAE IRQIRQUAEUAE IRQIRQ

Figure 4-1: Schematic linking structure of ARASIA countries to one main region.

Using the second feature the national energy systems of ARASIA counties, that have been modeled and simulated in the previous chapter, are linked and integrated in one regional system. The linkage is realized for the electricity grid (El-Grid) and natural gas grid (NG-Grid) with respect to the physical boundaries of the countries. According to figure 4-2 for the electricity grid, Syria is linked to Jordan and Lebanon and can import and export to Turkey. Jordan is linked to Syria and KSA and can import and export to Egypt. KSA is linked to Jordan and Yemen (in addition to the other interconnection to the Golf countries which is not considered at this stage of study). The electricity interconnection is performed using special transfer technologies defined at the physical nodes at the boundaries between the countries with user-defined constraints on capacities and activities. As already mentioned the regional electric grid will contribute in increasing the supply security and reducing the cost. As it helps in reducing the system reserve margins that helps in saving new investments which would have been required at national level. The same technique was adopted for simulating the regional natural gas grid in order to increase the available gas amount for electricity production and other uses. For the first step the gas grid, coming from Egypt, pass through Jordan and Syria with a branch link to Lebanon and ends at the boundary to Turkey. The NG link between Jordan and KSA is defined but not active (Figure 4-3).

Figure 4-2: Schematic presentation of the regional electric grid interconnection of

ARASIA countries..

Figure 4-3: Schematic presentation of the regional gas grid interconnection of ARASIA

countries.

4-1 REFERENCE SUPPLY SCENARIO UNDER REGIONAL GRID INTERCONNECTION

This scenario considers the influence of regional NG and electricity grid interconnection. The assumptions of this scenario are similar to that of isolated cases of the national energy systems.

2-1-1 Scenario's assumptions: In this case Maine region is called ARASIA has been defined. The national energy systems are included as sub region. Depending on the official performed projects for interconnection between the five countries, the following interconnections are considered:

• The electricity interconnection among Egypt, Jordan, Syria, Lebanon, • The orient gas pipeline that connect Egypt with Turkey across the other three

countries (Syria, Lebanon, and Jordan), • The Yemen and Saudi Arabia planes to connect gas and electricity nets as well, • And the possibility of connecting Saudi Arabia and Jordan with electricity line.

The following constraints were imposed on the exchange capacities according to the available electricity network lines and the orient gas pipeline:

− Electric grid line Syria-Jordan with a capacity of 300 MW in tow directions, − Electric grid line Syria-Lebanon with a capacity of 300 MW in tow directions,

− Electric grid line Syria-Turkey with a capacity of 300 MW in tow directions (for export and import),

− Electric grid line Jordan- KSA/ West with a capacity of 300 MW in tow directions,

− Electric grid line Jordan-Egypt with a capacity of 300 MW in tow directions (for export and import),

− Electric grid line KSA/South-Yemen with a capacity of 300 MW in tow directions,

− NG-pipeline (Arab pipeline) will start its operation in 2010. − Syria can pump in and out from this pipe. The amount of out pumping can not

exceed 10 % of the nominal pipeline capacity (10 Billion m3 annually).

2-1-2 General data The main region holds the same data of the isolated systems as to the base (final) year, modeling years, and the approved discount rate. Load Regions: similar to the isolated system. Energy Level: in this case, we considered the borders lines between two countries that sharing the same project as energy levels, in addition to possibility of export (import) choice form (to) the whole region. Depending on the last considerations five levels were defined: 1. Egept_Jordan: contains two energy forms:

• Electricity (elec): presents the quintuple electricity net (according to the recent official data it's possible to be sevenfold),

• Gas (gas): apart of the orient gas pipeline. 2. Saudi_jordan: includes one energy form called electricity (elec). 3. Saudi_Yemen: two energy forms were defined in this level:

• Electricity (elec): the interconnection point on the borders, • Gas (gas): gas pipeline connects between the western region of Saudi Arabia and

Yemen. 4. Jordan_Syria: with two energy forms as following:

• Electricity (elec): presents the quintuple electricity net, • Gas (gas): apart of the orient gas pipeline.

5. Export (Export): presents the energy exchange possibility between the whole region and external ambience and contains two energy forms:

• Electricity (elec): • Gas (gas):

Table 4-1 shows the levels and energy formed used to define the regional electricity and gas grid interconnection.

Table 4-1: Energy forms & levels used in regional linking (see Figure. 4-2, 4-3) Energy level Energy form

Electricity Egept_Jordan

Gas

Saudi_jordan Electricity

Electricity Saudi_Yemen Gas Electricity Jordan_Syrian

Gas Electricity Jordan_Syrian Gas

4-2 ENERGY TRANSFORMING TECHNOLOGIES Table 4-2 shows the specification of transforming technologies applied to model the grid interconnection. In the main region three technologies are defined representing the activities of gas import and export and Syrian gas pipeline. An additional technology is defined in the Syrian sub region representing gas transportation across Syrian territory in relation with the orient gas pipeline that start from Jordan borders and end at the Turkey boundary. The gas export technology flows out at the export level in the main region, and the gas import technology fills in at the Jordan- Syrian energy level in the main region as well. Table 4-2: Technical and economical features of transforming technologies.

Technology Capacity Activity

Investment

cost [$/kW]

Const_cost [$/kW/y]

Economical life [y]

His_capacity

[MW] Input Output Eff

[%]

Var- Cost

[$/kWy]

NG_exp* - - - - NGas/Secondary

gas/export/M_Arasia

1 5

NG_imp* - - - -

gas/jordan_syrian/M_Arasi

a

NGas/Secondar

y 1 25

TiLine_jordan** 300 50 300

ele/Jordan_syria/M_Arasi

a

Electricity/Secondary

98 350

gas_pip_syria*** - - - - - 1

gas_exp*** - - - -

Gas/ Jordan_s

yria

Gas/Export 1 5

gas_imp*** - - - - -

Gas/Egypt_Jor

dan 1 65

*modified in Syrian sub region . **: added to the Syrian sub region *** defined in the main region M_ARASIA

4-3 OPTIMIZATION OF SYRIAN SUPPLY STRATEGY UNDER REGIONAL INTERCONNECTION

Depending on the previous assumptions an analysis to identify the effect of for regional linking has been carried out. The results could reflect the influence on the future energy supply structure and provide an alternative approach for the optimal supply strategies in regional term. However, the results should demonstrate the oscillation of electricity exchange between the sub regions as results of load variation during the same time.

2-3-1 Structure of Syrian Energy Carriers and Energy Supply Levels

Table 4-3 and figure 4-4 presents the development of energy supply at all levels. Comparing with isolated system, the final energy supply (given by type of consumption) will remain the same as it is imposed by external consumption behavior which will not change. Some changes are observed at the secondary and primary levels as consequent of shifting in the shares of energy carriers needed for satisfying the final supply. Table 4-3: Development of Syrian energy supply under regional grid.

Absolute Values (Mtoe) Relative to the primary (%)

Year Final Secondary Primary Final Secondary Primary 2003 12.6 18.4 20.3 62.02 90.74 100.002004 13.1 19.3 21.1 62.13 91.13 100.002005 13.7 19.7 21.6 63.69 91.31 100.002007 15.1 20.6 22.8 66.31 90.45 100.002010 17.4 24.0 27.1 64.38 88.60 100.002015 22.3 30.3 32.9 67.69 91.83 100.002020 28.6 39.4 42.0 68.11 93.89 100.002025 36.6 51.0 54.1 67.65 94.31 100.002030 46.9 65.5 68.9 67.99 95.05 100.00

Energy flow in Syrian energy system

0

20000

40000

60000

80000

100000

120000

140000

2003 2004 2005 2007 2010 2015 2020 2025 2030

Mto

e

PrimarySec-totalFinal

Figure 4-4: Development of Syrian energy supply under regional grid (Mtoe) Final Level According to Table 4-3 and figure 4-4 final energy demand will grow from 12.6 Mtoe in the base year to 46.9 Mtoe in 2030 achieving an average annual growth rate of 5%. The highest demand appears in the last three periods, when it jumps from 22.3 to 28.6 Mtoe

between 2015 and 2020, and to 36.6 and to 46.9 Mtoe in 2025 and 2030 that equal to 30.3, 39.4, 51, 65.5 Mtoe consequently as a primary energy. For the secondary and primary energy demand they will grow from (18.4, 20.3) Mtoe in the base year to (65.5, 68.9) Mtoe in the last year 2030 with average annual growth rat of 4.7%, and 4.5% consequently. Secondary Level The distribution of secondary energy by consumption type (Table 4-4, Figure 4-5) shows that the king shares in the base year still goes to thermal uses and electricity production, with 34.5% and 34% (corresponding to 6.33 and 6.32 Mtoe) respectively. This aspect will be sustained all over the study period, as the thermal uses reach it's highest share in 2015 with (37.5%) and shows a little decrease after that to 35.5% (23.3) Mtoe in 2030, electricity share vacillates up and dawn, decreasing from (35%) in 2004 to the lowest value in 2007 (30.9% about 6.4 Mtoe) then it will increase and keep on for the coming three periods reaching the highest value at 35.1% (23 Mtoe) in 2030. For the other fuel types, the motor fuel share differs between (23.3 to 24.7) %, but the non-energy use (including heavy refineries products and coke coal) share decreases from 7.7% in 2003 to 4.7% in the last year.

Table 4-4: Secondary energy distribution by type of consumption.

Absolute Values (Mtoe) Secondary energy shares (%)

Year Total Heat

use Motor

fuel

Non- Energy+ heavy

prod. Electricity Heat use

Motor fuel

Non- Energy+ heavy

prod. Electri

city 2003 18.4 6.3 4.3 1.4 6.3 34.5 23.4 7.7 34.52004 19.3 6.6 4.5 1.4 6.7 34.4 23.3 7.4 35.02005 19.7 6.9 4.6 1.5 6.6 35.3 23.5 7.4 33.72007 20.6 7.6 5.1 1.5 6.4 37.1 24.7 7.3 30.92010 24.0 8.8 5.8 1.8 7.5 36.8 24.3 7.6 31.32015 30.3 11.3 7.5 1.9 9.5 37.5 24.7 6.3 31.62020 39.4 14.5 9.7 2.1 13.3 36.8 24.5 5.3 33.42025 51.0 18.4 12.5 2.6 17.5 36.1 24.5 5.0 34.32030 65.5 23.3 16.3 3.1 23.0 35.5 24.7 4.7 35.1

Energy Distribution by Uses at Secondary

0.0

5.0

10.0

15.0

20.0

25.020

0320

0420

0520

0720

1020

1520

2020

2520

30

Mto

e

HeatMFNon_Eng+HeavyproductsElectricity

Figure 4-5: Secondary energy distribution by consumption types.

A detailed picture for energy distribution (absolute values and shares) by fuel types is demonstrated in table 4-5. Diesel shows the biggest share of the total consumed fuel in the base year with 32.9% (6.055 Mtoe), and keep on this domination till 2010 when it will decrease to 28.1% (6.749 Mtoe) leaving his position for natural gas favor as a result of the official expansion policy of using NG in electricity generation. By the year 2020 diesel's share will fall to the lowest value (26.8%,10.549 Mtoe) but this once for fuel oil favor that will be widely used in electricity generation, but returns to raising again After that to 30.5% in 2030. This behavior is similar to the isolated case with some changes in values especially for fuel oil as its share raise from 20% to 33% in the isolated case against 30% in case of interconnection. Fore natural gas, the changing line will start from 23.1% in the base year decreasing in the following two year to 21.6% as the absolute vale remains fixed at 4.247 Mtoe, but as a result of the official policy about NG expansion uses that previously mentioned it will raise sharply in the next five years reaching the highest value with (8.173 Mtoe) in 2010, and as the gas amount will not be enough to sustain this high share it will decline dramatically during the remains periods to its lowest value in 2030 with 12.1% (7.897 Mtoe) and as we see the decrease will be in the value and the share. For the nuclear option no difference to the single case is observed as this option is constrained to be participating after 2020. Due to building two nuclear power plants with a total capacity of 1600 MW possessing a share of 4.6 % (1.803 Mtoe) raising to 5.7 % in 2025 and 4.4% in 2030 (2.885 Mtoe). In this scenario Hydro & wind will play the same role of the isolated one, as its share in the base year is the highest with 5.3 % (968 Mtoe) and fluctuated between 5% and 3.5% between 2005 and 2020 corresponding to about 0.968 and 1.369 Mtoe. As can be seen the shares decreasing doesn't reflect an absolute value decrease, and there is a chance to build 500 MW wind farm in 2015 while it was 400 MW in the isolated one. Heavy products and traditional will play the same role in the two scenarios.

Table 4-5: Development of Syrian secondary energy distribution by fuel type under regional grid (ktoe). Year

diesel Gasoline Fuel oil LPNG Ngas Asphalt

Heavy Products Hyd&Wind Treditional Solar Nuclear Exchange

TILine Exch Total

2003 6055 1290 3713 825 4247 672 424 968 185 0 0 0 0 18378 2004 6309 1338 4230 864 4247 692 424 968 191 0 0 0 0 19264 2005 6612 1389 4232 905 4247 713 424 968 197 0 0 0 0 19686 2007 6983 1524 3144 996 6445 756 394 968 208 42 0 -183 -685 20593 2010 6749 1752 5058 1151 7560 826 618 968 225 96 0 -183 -828 23992 2015 8545 2246 5579 1474 8173 958 501 1369 255 247 0 0 878 30224 2020 10549 2906 9006 1883 7897 1111 471 1369 285 789 1803 20 1344 39432 2025 14741 3761 12821 2389 7897 1288 692 1369 314 1001 2885 20 1831 51009 2030 20003 4858 19689 3011 7897 1493 811 1369 344 1261 2885 20 1871 65513

Shares (%) 2003 32.9 7.0 20.3 4.5 23.1 3.7 2.3 5.3 1.0 0 0 0 0 100% 2004 32.8 6.9 22.0 4.5 22.0 3.6 2.3 5.0 1.0 0 0 0 0 100% 2005 33.6 7.1 21.5 4.6 21.6 3.6 2.3 4.9 1.0 0 0 0 0 100% 2007 33.9 7.4 15.3 4.8 31.3 3.7 1.9 4.7 1.0 0.3 0.0 -0.9 -3.3 100% 2010 28.1 7.3 21.1 4.8 31.5 3.4 2.6 4.0 0.9 0.4 0.0 -0.8 -3.5 100% 2015 28.3 7.4 18.5 4.9 27.0 3.3 1.7 4.5 0.8 0.8 0.0 0.0 2.9 100% 2020 26.8 7.4 22.8 4.8 20.0 2.8 1.3 3.5 0.7 2.0 4.6 0.1 3.4 100% 2025 28.9 7.4 25.1 4.7 15.5 2.5 1.4 2.7 0.6 2.0 5.7 0.0 3.6 100% 2030 30.5 7.4 30.1 4.6 12.1 2.3 1.3 2.1 0.5 1.9 4.4 0.0 2.9 100%

Oil and Gas: As the oil & gas production are motivated by the official plans and some technical conditions that remain the same in the isolated and linking case, so that the oil & NG production picture doesn't change significantly. Table 4-6 depicts the development of oil and NG balance. Due to its direct impact on oil and gas the balance of electricity generation is also presented. In the years 2010 and 2020 the oil production in the multi case will be (17.9, 6.3) instead of (18.6, 5.6) Mtoe for the single case. Table 4-6 depicts that oil production will decrease from 25.7 Mtoe in 2003 to 18.6 in 2010, which will be associated with a sharp declining in the exported amount from 14.3 to 6.3 Mtoe during the same period. This scenario will continue steadily (similar to isolated case) leading the country to become oil importer by the year 2020 with amount of 8.9 (while it is 9.5 in the isolated one) Mtoe and a net oil importer in 2025 with 21.1 Mtoe of imported oil and 24.4 Mtoe by the end of the study period. From 2003 to 2020 the exported oil amounts present more than 50% of the production and declines from 14.3 Mtoe to 11 Mtoe. Gas production doesn't change but the available capacity is sufficient till 2015, which means disappearing the paradox that shown in isolated case that while our production is at highest level, we have to import 0.5 Mtoe in 2010, that because of allowing to import electricity across the TiLine and others instead of building some combined-cycle power plants as we will explain later. so gas production will increase from 5.3 to 8.3 Mtoe between 2003 and 2007, and reach it's highest level in 2010 (9.1Mtoe) as it's shown in table 4-7. Between 2010 and 2015, the production decreases and fixed at 8.4 Mtoe till the end of the study. On the other side, the imported gas amount reach the maximum level allowed for Syria according to the operation agreement of orient pipeline staring from the year 2015 that is 0.9 Mtoe. The electricity production increases from 2.4 Mtoe on 2003 to 8.9 Mtoe in 2030 that means about 3.7 times doubled as same as it in isolated case. Table 4-7 shows that the exported electric energy may be (0.39, 0.33) Mtoe during the period between 2007 and 2010, while there is no chance to export any amount during the next periods but we have to import electricity starting from 2015 using mainly the TiLine between Syria, Jordan, and Egypt, which is cheaper than building new capacities. as a result the imported electricity increases from 0.39 Mtoe in 2015 to 0.45 Mtoe in 2020 reaching the highest level in 2030 with 0.62 Mtoe. Table 4-6: Balance of crude oil, NG and electricity under regional grid at Syrian secondary energy level (Mtoe)

Crude Oil NG Electricity

Local Prod. Import Export Local

Prod. Import Export Local Prod. Import Export

2003 25.7 0.0 -14.3 5.3 0.0 0.0 2.4 0.00 0.00 2004 25.1 0.0 -13.7 5.3 0.0 0.0 2.5 0.00 0.00 2005 24.6 0.0 -13.3 5.3 0.0 0.0 2.7 0.00 0.00 2007 21.7 0.0 -11.0 7.8 0.0 0.0 2.9 0.00 -0.39 2010 17.9 0.0 0.0 9.1 0.0 0.0 3.4 0.00 -0.33 2015 14.8 0.0 0.0 8.8 0.9 0.0 4.3 0.39 0.00 2020 6.3 8.9 0.0 8.4 0.9 0.0 5.3 0.45 0.00

2025 0.0 21.1 0.0 8.4 0.9 0.0 6.9 0.61 0.00 2030 0.0 24.4 0.0 8.4 0.9 0.0 8.9 0.62 0.00 Table 4-7 compares fuel oil and NG balance of single and multi case. Due to its influence on both the electricity exchange is also presented. As it can be seen the change is observed for the fuel oil and electricity exchange only. No change is observed on the quantities of NG, since the use of Arab gas pipeline was already considered in the single case using the same limitation on the import capacity for Syria which was chosen to be 10% of the nominal pipe line capacity (the annual capacity is estimated to 10 billion m3). The influence of interconnection can be observed in the quantities of fuel oil being manly used for electricity generation. In the first phase the consumed amount of fuel oil is less than in the single case as there is no electricity exported is observed. In the following period more electricity import is proposed so that the fuel oil requirements are rapidly going down. In this regard the electricity exchange affects mainly the fuel oil requirements. Table 4-7: Balance comparison between single and multi case for fuel oil, NG and

electricity exchange in the Syrian energy system (ktoe).

2-3-2 Electricity Exchange According to Table 4-8 the total consumed fuel for electricity generation will increase from 6.339 Mtoe in 2003 distributed as: 51% (3.345 Mtoe) NG, 34% (2.126 Mtoe) fuel oil, 15. % (986 Mtoe) hydro power and wind, to 23.024 Mtoe in 2030 distributed as: 13% NG, 60% fuel oil, 6 % hydro and wind, and 13 % nuclear. One can see that the dominated fuel for electricity production before 2010 is NG (79 % in 2007), as its production increases during this period, and a limited quantities from fuel oil are available. This trend will reverse for fuel oil sake starting from 2010 when a new refinery will built, that afford extra quantities of fuel oil to be used economically in electricity production especially by considering the limitation of produced and imported NG across the Arab pipeline. The general trends of this scenario are similar to that of isolated case. Table 4-8: Electricity generation by fuel type (ktoe).

Fuel Oil NG Electricity Exchange single Interconnection single Interconnection single Interconnection

2003 3713 3713 4247 4247 0 0 2004 5067 4230 4247 4247 -913 0 2005 5069 4232 4247 4247 -913 0 2007 3144 3144 6484 6445 -913 -868 2010 5058 5058 7470 7560 -913 -1011 2015 6606 5579 8173 8173 -188 +878 2020 10204 9006 7897 7897 +5 +1364 2025 14326 12821 7897 7897 +120 +1851 2030 21486 19689 7897 7897 -184 +1891

Negative (-) is export Positive (+) is import

Year NG Fuel Oil Hydro& Wind Nuclear Total

2003 3245 2126 968 0 63392004 3198 2569 968 0 67352005 3183 2492 968 0 66442007 5036 1229 968 0 63662010 4700 2847 968 0 75042015 4546 2743 1369 0 95362020 3259 5384 1369 1803 131792025 3173 8227 1369 2885 175052030 2980 13898 1369 2885 23024

Share (%) 2003 51% 34% 15% 0% 100%2004 47% 38% 14% 0% 100%2005 48% 38% 15% 0% 100%2007 79% 19% 15% 0% 100%2010 63% 38% 13% 0% 100%2015 48% 29% 14% 0% 100%2020 25% 41% 10% 14% 100%2025 18% 47% 8% 16% 100%2030 13% 60% 6% 13% 100%

2-3-3 Development of Syrian Installed Capacity under Regional Interconnection The total installed Syrian electric capacity in 2003 was around 6505 MW. The installed capacity will double by 2.7 times over the study period reaching about 17965 MW in 2030. Table 4-9 presents the electricity system distribution by plants types. The table shows that two gas power stations of combined cycle system will add in the years 2005 and 2007 (committed building), the first is called Zayzon – Nasreah (900 MW) that will be converted to work on combined cycle system, and the second is Dier Alzor – Deir Ali (1500MW). Both will insure an adequate generation capacity till 2010. Table 4-9: Development of Syrian installed capacity for multi case (MW)

Existing Capacity

Zezo-Nasr-CC_

DAliZour-CC CC GT FSteam Wind

NU600 &1000

Tieline-Jordan Total

2003 6505 0 0 0 0 0 0 0 300 65052004 6505 0 0 0 0 0 0 0 300 65052005 5905 900 0 0 0 0 0 0 300 68052007 5905 900 1500 0 0 0 0 0 300 83052010 5655 900 1500 0 100 0 0 0 382 81552015 5135 900 1500 2100 200 0 0 0 500 98352020 3310 900 1500 2100 500 3000 180 1000 750 124902025 3310 0 1500 2100 900 5600 180 1600 1000 151902030 1585 0 1500 2100 1000 10000 180 1600 1000 17965

Between 2015 and 2020 a considerable number of plants will face out which will be replaced by new capacity addition. During the study period about 15084 MW generation capacities will be added, comparing to 15600 MW in the isolated case. Fuel and gas fired power plants will remain the main types. However, from the year 2020 nuclear power plants will be economically competitive and two nuclear power plants with total share of 10.6% will be added (1000 MW in 2020 and 600 MW in 2025). Wind turbine may be available economically by 2015 with share of 3.3 % of total installed capacity comparing to 400 MW in the single case. Solar energy will be still not economical for electricity generation and its role will be limited to water heating. The reduction in the total added capacity will cover from the imported electricity that is cheaper and more efficiency. For this purpose the capacity for electricity exchange (TieLine to Jordan) will expand from 300 MW in 2003 to 1000 MW in 2030. In addition to the possibility of reducing the total installed capacity the electric grid interconnection will improve the operation of the regional power system by using the load shifting in the different sub region. This can be recognized through the time variation of the exchanged electricity in both direction of Syrian-Jordan TieLine as presented in Figure 4-6.

Figure 4-6: Electricity exchange in both direction of Syrian Jordan TieLine.

4.4 Optimization of Jordan Supply Strategy under Regional Interconnection

4-4-1 Structure of Jordan Energy Carriers and Energy Supply Levels Table 4-10 and figure 4-7 present the development of energy supply at all levels. Comparing with isolated system, the final energy supply (given by type of consumption) will remain the same as it is imposed by external consumption behavior which will not change. Some changes are observed at the secondary and primary levels as consequent of shifting in the shares of energy carriers needed for satisfying the final supply.

Table 4-10: Development of Jordan energy supply under regional grid.

Absolute Values (Mtoe) Relative to the primary (%)

Year Final Secondary Final Secondary Final Secondary

2003 3.6 5.2 5.4 0.67 0.97 100.00

2004 3.7 5.4 5.6 0.67 0.97 100.00

2005 3.9 5.7 5.9 0.66 0.97 100.00

2007 4.2 6.0 6.2 0.67 0.97 100.00

2010 4.6 6.7 6.8 0.67 0.98 100.00

2015 5.2 7.4 7.6 0.69 0.98 100.00

2020 5.9 8.3 8.5 0.70 0.98 100.00

2025 6.7 9.5 9.7 0.69 0.98 100.00

2030 7.6 10.8 11.1 0.69 0.98 100.00

Energy flow in Jordan energy system

0.0

5.0

10.0

15.0

20.0

25.0

30.0

35.0

2003 2004 2005 2007 2010 2015 2020 2025 2030

Mto

e PrimarySecFinal

Figure 4-7: Development of Jordan energy supply under regional grid (Mtoe)

According to Table 4-3 and figure 4-4 final energy demand will grow from 3.6 Mtoe in the base year to 7.6 Mtoe in 2030 achieving an average annual growth rate of 2.8%.

The secondary energy will increase from 5.2 Mtoe to 10.8 Mtoe during the study period with an average annual growth rate of about 2.8% similar to that of final demand. The primary energy demand will arrive 11.1 Mtoe in 2030 starting from 5.4 Mtoe in 2003.

The distribution of secondary energy by consumption type (Table 4-11, Figure 4-7) shows that the main demand goes to the light oil products with 38% equivalent to 1.4 Mtoe in the base year 2003. This share will decrease to about 35.8% at the end of the

study period. The share of Diesel ranges as second with 35% (about 1.3 Mtoe). This share decrease during the study period to about 32%. The continuous decrease in the share of light and medium oil products during the study period will compensate by the increase of electricity. Its share will increase from 16.8% in 2003 to 20.8% (about 1.6 Mtoe) in 2030 with an average growth rate of 3.6%.

The NG demand at secondary level (except that for electricity production) will increase to 36.7 ktoe in 2010 and arrive 90 ktoe in 2020 and remain at this level (with about 1.5% of total secondary demand).

Table 4-11: Jordan secondary energy distribution by fuel type.

Absolute Values (Mtoe) Secondary energy shares (%)

Year Total Heavy

products

Diesel Electricity NG

(ktoe)

Light products

Heavy

products

Diesel Electricity NG

(ktoe)

Light products

2003 3.6 0.3 1.3 0.6 0.0 1.4 9.6 35.4 16.8 0.0 38.1

2004 3.7 0.4 1.3 0.7 0.0 1.4 9.5 35.0 17.7 0.0 37.8

2005 3.9 0.4 1.4 0.7 0.0 1.5 9.5 34.8 18.2 0.0 37.5

2007 4.2 0.4 1.4 0.8 37.7 1.5 9.3 34.2 18.8 0.9 36.8

2010 4.6 0.4 1.5 0.9 56.5 1.7 9.2 33.7 19.6 1.2 36.3

2015 5.2 0.5 1.7 1.1 75.3 1.9 9.1 33.4 20.1 1.4 36.0

2020 5.9 0.5 2.0 1.2 90.4 2.1 9.1 33.3 20.3 1.5 35.9

2025 6.7 0.6 2.2 1.4 90.4 2.4 9.0 33.2 20.7 1.3 35.7

2030 7.6 0.7 2.5 1.6 90.4 2.7 9.0 33.2 20.8 1.2 35.8

2003 2004 2005 2007 2010 2015 2020 2025 2030

Mto

e

Fuel

Diesel

Electricity

NG

Light Prod.

Total

Figure 4-8: Secondary energy distribution by fuel types.

Table 4-12 shows the secondary energy balance for the different energy carriers.

Table 4-12: Secondary energy balance of Jordan

Import Export

Crude Electricity Electricity

Crude HFO Diesel

Light

Prod NG From Syria

From KSA

From Egypt

To Syria

To Egypt

2003 0.91 0.00 1.18 1.18 1.13 0.00 0.00 0.23 0.00 0.00

2004 0.94 0.00 1.22 1.22 1.25 0.00 0.00 0.23 0.00 0.00

2005 0.97 0.00 1.25 1.25 1.25 0.00 0.00 0.23 0.00 0.00

2007 1.03 0.00 1.33 1.33 1.76 0.00 0.00 0.23 0.00 0.17

2010 2.40 0.21 1.29 0.00 1.78 0.00 0.00 0.23 0.00 0.27

2015 2.72 0.23 1.46 0.00 2.13 0.00 0.00 0.23 0.21 0.19

2020 3.07 0.26 1.65 0.00 2.52 0.00 0.00 0.23 0.54 0.24

2025 3.48 0.30 1.87 0.00 2.71 0.00 0.00 0.23 0.72 0.29

2030 3.93 0.34 2.11 0.00 2.41 0.00 0.00 0.23 0.72 0.37

4-4-2 Development of Jordan Installed Capacity under Regional Interconnection Table 4-13 shows the distribution of installed capacity by fuel type. The total installed capacity in the base year amounted to 1546 which is distributed to by fuel type to 50% NG, 26% Diesel, 23% fuel oil and 1% renewable. This capacity will decrease to 1527 MW in 2005 due to facing out of some fuel oil fired plants. This will lead to increasing the imported electricity to 376 MWyr. In the following years the building of new capacities (mainly NG fired) will compensate the decommissioned plants and increase the installed capacity at the end of study to 1736 MW which will be distributed to 81% NG, 7% Diesel and 12% renewable. However, the Jordan power system will depend more on the imported electricity that will arrive 2171 MWyr indicating the importance of regional electric grid. As it will be shown later, the electricity will be imported mainly from KSA and Egypt.

The future development shows also the increased role of NG in the electricity generation, as its share will increase from 50% in 2003 to 81% in 2030, whereas the fuel oil will be removed completely after 2015. On the other hand the increased share of renewable (wind and photovoltaic) is remarkable, as its share will increased from 1% in 2003 to almost 12% in 2030.

Table 4-13: Electricity generation by fuel type (MW). Share (%) Installed

Capacity Fuel Oil

NG Diesel Renewable Import (MWyr)

Fuel Oil

NG Diesel Renewable

2003 1546 363 770 400 13 311 23 50 26 1

2004 1546 363 770 400 13 337 23 50 26 1

2005 1527 314 800 400 13 376 21 52 26 1

2007 1666 264 800 400 202 298 16 48 24 12

2010 1508 106 800 400 202 588 7 53 27 13

2015 1536 0 1034 300 202 715 0 67 20 13

2020 1774 0 1272 300 202 1203 0 72 17 11

2025 1889 0 1387 300 202 1686 0 73 16 11

2030 1736 0 1414 120 202 2171 0 81 7 12

4.5 Optimization of KSA Supply Strategy under Regional Interconnection The performed analysis of Saudi case is limited to the optimization of electric power system. The development of the whole energy system structure is not considered in this analysis. However, due to the huge amount of oil reserves the KSA energy system will remain depending on oil products with an increased role of NG in the electricity generation. On the other hand the installed capacity of the Saudi system is very high and the generation costs are relatively low compared to other ARASIA countries. Thus the KSA power system will affect significantly the regional electric grid.

4-5-1 Structure of Energy Supply of KSA Power System Table 4-14 and figure 4-9 present the development of energy supply of KSA power system. The final electricity will grow with an annual average of 4.9% forcing the final demand to increase from 11.49 Moe in 2003 to 35 Mtoe. The corresponding secondary energy supply will increase from 27.6 to 65 Mtoe in the same period. It can be seen that after a smooth initial demand increase the required electricity demand will increase rapidly after 2010 with big jumps.

Table 4-14: Energy supply of KSA power system under regional grid.

Absolute Values (Mtoe)

Share

(%)

Year Final Energy

Secondary Energy

Final Energy

Secondary Energy

2003 11.5 27.6 42 100

2004 12.7 32.4 39 100

2005 13.2 34.2 39 100

2007 14.3 20.1 71 100

2010 16.1 24.6 65 100

2015 19.5 32.3 60 100

2020 23.7 40.2 59 100

2025 28.8 51.3 56 100

2030 35.0 65.0 54 100

0

10

20

30

40

50

60

70

2003 2004 2005 2007 2010 2015 2020 2025 2030

Mto

e

Secondary

Final

Figure 4-9: Development of KSA energy supply for the power system under regional

grid (Mtoe)

Table 4-15 and figure 4-10 present the future development of final electricity distributed by geographical zones. It can be seen that the east zone of KSA ranges at first with about 38% of total demand. Its share will decrease slightly to 36% during the study period with an average growth rate of 4%. The share of Middle zone will increase from 23% to 28% during the period 2003-2004 and stagnate at this level indicating the highest growth rate during the study period. The south zone ranges at the last due to the lowest population density. The total final demand of this zone will decrease from 7.4% to 6% during the study period.

Table 4-15: Geographical distribution of Final electricity in KSA

Final Electricity (Mtoe) Share (%)

Middle East South West Total Middle East South West

2003 2.69 4.38 0.85 3.58 11.49 23.4 38.1 7.4 31.2

2004 3.56 4.55 0.88 3.72 12.71 28.0 35.8 6.9 29.3

2005 3.70 4.73 0.91 3.87 13.22 28.0 35.8 6.9 29.3

2007 4.00 5.12 0.97 4.19 14.28 28.0 35.8 6.8 29.3

2010 4.50 5.76 1.08 4.71 16.05 28.0 35.9 6.7 29.4

2015 5.48 7.01 1.28 5.73 19.50 28.1 35.9 6.6 29.4

2020 6.66 8.53 1.52 6.98 23.69 28.1 36.0 6.4 29.4

2025 8.11 10.37 1.81 8.49 28.77 28.2 36.1 6.3 29.5

2030 9.86 12.62 2.15 10.32 34.95 28.2 36.1 6.1 29.5

0.0

5.0

10.0

15.0

20.0

25.0

30.0

35.0

40.0

2003 2004 2005 2007 2010 2015 2020 2025 2030

Mtoe

Middle

East

South

West

Total

Figure 4-10: Development of final electricity distributed by geographical zones (Mtoe)

Table 4-16 shows the development of electricity exchange to Jordan and Yemen. For Jordan only electricity interconnection is simulated due to the actual situation. For Yemen both NG and electricity interconnection are considered.

Table 4-16: Electricity export and energy flow for electricity generation in KSA power system (Mtoe).

Import Electricity Export

NG from Yemen

Diesel for ARAMCO

Diesel for South Zone

Diesel for West Zone

To

Jordan

To Yemen

2003 0 1.88 0.01 0.83 0.00 0.00

2004 0 1.88 0.02 0.86 0.00 0.00

2005 0 1.88 0.05 0.90 0.00 0.00

2007 0 1.88 0.12 0.97 0.00 0.00

2010 0 1.88 0.21 1.09 0.22 0.00

2015 0 1.88 0.30 1.33 0.54 0.29

2020 0 1.88 0.30 1.61 0.91 0.57

2025 0 1.88 0.16 1.96 1.27 1.08

2030 0 1.88 0.13 2.39 1.63 1.45

Table 4-17 and figure 4-11 show the development of installed capacity distributed by geographical zones. Starting from 22.7 GW in 2003 the total installed capacity will increase with an annual average rate of 4.5% arriving a total capacity of 74.5 GW in 2030. The geographical zones range with the following order: east, west, middle, and south. Their share in the total installed capacity will change from 38%, 32%, 20%, and 9% in the base year to 42%, 26%, 25%, and 7% in 2030.

As expected the east zone will keep its first range due to its important economical role in KSA.

Table 4-17: Development of installed capacity distributed by geographical zone.

Installed Capacity (MW) Share (%) Year Total South West Middle East South West Middle East

2003 22728 2135 7328 4641 8624 9 32 20 38

2004 27349 2135 7328 8785 9101 8 27 32 33

2005 28062 2135 7328 9766 8833 8 26 35 31

2007 36166 2135 7692 9766 16572 6 21 27 46

2010 37589 2135 8855 9611 16988 6 24 26 45

2015 40449 2351 10686 9658 17755 6 26 24 44

2020 49580 2963 13372 11867 21377 6 27 24 43

2025 61480 4051 16524 15120 25785 7 27 25 42

2030 74485 5172 19523 18643 31147 7 26 25 42

0

10000

20000

30000

40000

50000

60000

70000

80000

2003 2004 2005 2007 2010 2015 2020 2025 2030

MW

TotalSouthWestMiddleEast

Figure 4-11: Development of installed capacity in KSA (MW).

The distribution of installed capacity by firing type of fuel is presented in table 4-18 and figure 4-12. The KSA generation system includes only thermal plants fired with crude oil, NG and Diesel. In the south zone only Diesel and crude oil are used. During the study period the Diesel fired plants will be replaced by crude oil power plants. The high share of Diesel in 2003 with 72% will decrease to 17% in 2030. The same trend is observed in the west zone where crud oil will completely replace Diesel during the study period.

The situation is more balanced in the middle zone with increased role of Diesel and crude instead of NG. In the east zone the trend will be the complete dominance of Diesel fired plant. In general the role of crude oil will increase continuously and KSA power system will depend more and more on NG and crude oil arriving 45% for NG, 43% for crude and 12% for Diesel in 2030.

0

10000

20000

30000

40000

50000

60000

70000

80000

2003 2004 2005 2007 2010 2015 2020 2025 2030

MW

Crude Oil

Diesel

NG

Total

Figure 4-12: Distribution of installed capacity by fuel type (MW).

Table 4-18: Development of installed capacity in KSA by fuel type (MW)

Installed Capacity (MW) Share (%)

South Zone

Year Crude Oil Diesel NG

Total Crude Oil Diesel NG

2003 590 1545 0 2135 28 72 0

2004 590 1545 0 2135 28 72 0

2005 590 1545 0 2135 28 72 0

2007 590 1545 0 2135 28 72 0

2010 590 1545 0 2135 28 72 0

2015 837 1514 0 2351 36 64 0

2020 1840 1124 0 2963 62 38 0

2025 3229 822 0 4051 80 20 0

2030 4302 870 0 5172 83 17 0

West Zone 2003 5453 1875 0 7328 74 26 0

2004 5453 1875 0 7328 74 26 0

2005 5453 1875 0 7328 74 26 0

2007 5817 1875 0 7692 76 24 0

2010 6992 1863 0 8855 79 21 0

2015 8839 1847 0 10686 83 17 0

2020 11984 1388 0 13372 90 10 0

2025 16079 446 0 16524 97 3 0

2030 19399 124 0 19523 99 1 0

Middle Zone 2003 0 517 4125 4641 0 11 89

2004 1851 2783 4151 8785 21 32 47

2005 1851 3638 4277 9766 19 37 44

2007 1851 3638 4277 9766 19 37 44

2010 1702 3632 4277 9611 18 38 44

2015 1176 5259 3223 9658 12 54 33

2020 2625 6451 2791 11867 22 54 24

2025 5072 7289 2759 15120 34 48 18

2030 8168 8386 2089 18643 44 45 11

East Zone 2003 0 123 8501 8624 1 99 1

2004 0 123 8978 9101 1 99 1

2005 0 123 8710 8833 1 99 1

2007 0 123 16449 16572 1 99 1

2010 0 123 16865 16988 1 99 1

2015 0 113 17642 17755 1 99 1

2020 0 68 21310 21377 0 100 0

2025 0 0 25785 25785 0 100 0

2030 0 0 31147 31147 0 100 0

Whole Power System

2003 6043 4060 12626 22728 27 18 56

2004 7894 6326 13129 27349 29 23 48

2005 7894 7181 12986 28062 28 26 46

2007 8258 7181 20726 36166 23 20 57

2010 9284 7163 21142 37589 25 19 56

2015 10852 8734 20864 40449 27 22 52

2020 16448 9031 24100 49580 33 18 49

2025 24380 8557 28543 61480 40 14 46

2030 31869 9380 33236 74485 43 13 45

4.6 Optimization of Yemeni Supply Strategy under Regional Interconnection

4-6-1 Structure of Energy Supply of Yemeni Energy System Table 4-19 presents the development of energy supply at all levels. The final energy demand will increase from 0.68 Mtoe (corresponding to 1.97 Mtoe secondary and 5.07 Mtoe primary energy) to 3.9 Mtoe (corresponding to 13.37 Mtoe of secondary). This situation indicates the high energy losses during the transformation processes. The total energy transforming efficiency is less than 29%. Table 4-19: Development of Yemeni energy supply under regional grid (Mtoe).

Absolute Values (Mtoe) Share to Primary (%)

Year Final Secondary Primary Final Secondary Primary 2003 0.68 1.97 5.07 13 39 100.00 2004 0.73 2.42 5.12 14 47 100.00 2005 0.79 2.64 5.72 14 46 100.00 2007 0.92 3.19 5.97 15 53 100.00 2010 1.16 4.08 4.08 28 100 100.00

2015 1.63 5.67 5.67 29 100 100.00 2020 2.23 7.74 7.74 29 100 100.00 2025 2.99 10.26 10.26 29 100 100.00 2030 3.90 13.37 13.37 29 100 100.00

Table 4-20 shows the final energy distribution by type of consumption with about 35% for both motor fuel and thermal use and 30% for electricity. Although the final demand will increase from 0.68 to 3.9 Mtoe the share of these shares will remain the same over the whole study period. Table 4-20: final energy distribution by type of consumption (Mtoe).

Share (%) Year Total Motor Fuel

Thermal Use

ElectricityMotor Fuel

Thermal Use

Electricity

2003 0.68 0.25 0.24 0.20 36 35 292004 0.73 0.26 0.25 0.21 36 35 292005 0.79 0.29 0.27 0.23 36 35 292007 0.92 0.33 0.32 0.27 36 35 292010 1.16 0.42 0.40 0.34 36 35 292015 1.63 0.59 0.57 0.47 36 35 292020 2.23 0.81 0.78 0.65 36 35 292025 2.99 1.08 1.04 0.87 36 35 292030 3.90 1.41 1.36 1.13 36 35 29

4-6-2 Development of Yemeni Power System under Regional Interconnection The distribution of installed capacity by firing type of fuel is presented in table 4-21 and figure 4-13. The installed capacity will grow by three times from 714 MW in 2003 to 1972 in 2030. The same is observed for the electricity generation which will increase from 495 to 166 MWyr during the study period.

The present generation system relies on basically on fuel oil with 52%. However, the fuel oil will be continuously substituted by NG so that the NG share will arrive about 70% at the study period.

Due to the high increase of electricity demand the development of national generation capacity will be not at the adequate level so that so deficit is expected in the electricity supply. The electricity interconnection with KSA will be the unique option to avoid the lack in electricity. The system will start to import electricity in the year 2015. The import will increase from 378 MWyr in 2015 to 1900 MWyr in 2030. This means that the imported electricity in 2030 will be almost equal to the generation capacity of Yemeni system.

Table 4-21: Development of installed capacity by fuel type (MW).

Installed Fuel Diesel NG NG Generation Share ( %) Import

Capacity

(MW) Oil &

Fuel(MWyr) Fuel

Oil Diesel NG NG

& Fuel

(MWyr)

2003 714 374 145 0 195 495 52 20 0 27 0

2004 1121 374 145 0 602 669 33 13 0 54 0

2005 1089 342 145 0 602 723 31 13 0 55 0

2007 1371 310 125 274 662 843 23 9 20 48 0

2010 1746 250 100 674 722 1062 14 6 39 41 0

2015 1473 0 60 816 597 1111 0 4 55 41 378

2020 1607 0 0 1052 555 1297 0 0 65 35 744

2025 1663 0 0 1135 527 1316 0 0 68 32 1414

2030 1972 0 0 1371 601 1664 0 0 70 30 1905

Figure 4-13: Development of installed capacity in Yemen (MW).

4-7 Summary of Regional Electricity and NG Interconnection of ARASIA Table 4-22 and table 4-23 summarize again the NG and electricity flows through the regional gas and electricity grids of ARASIA multi region. Figure 4-14 and 4-15 shows the installed capacities for NG and electricity exchange between ARASIA countries. Table 4-22: Summary of the expected NG’s Flows in the regional gas grid (MWyr)

0

500

1000

1500

2000

2500

2003 2004 2005 2007 2010 2015 2020 2025 2030

MW

Fuel OilDieselNGNG & FuelTotal

Jordan Syria KSA Yeman

From Egypt

To ATPS

To Amman

From Jordan

To Syria

From Syria

Export to Turkey

From Yemen

To KSA

2003 1.13 -1.13 0.00 0.00 0.00 0.00 0.00 0.00 0.002004 1.25 -1.25 0.00 0.00 0.00 0.00 0.00 0.00 0.002005 1.25 -1.25 0.00 0.00 0.00 0.00 0.00 0.00 0.002007 8.90 -1.25 -0.52 7.14 0.00 0.00 7.14 0.00 0.002010 8.90 -1.25 -0.54 7.12 0.00 0.13 7.24 0.23 0.232015 8.90 -0.85 -1.28 6.77 -0.89 0.00 5.88 0.38 0.382020 8.90 -0.75 -1.77 6.38 -0.89 0.00 5.49 0.38 0.382025 8.90 -0.75 -1.96 6.19 -0.89 0.00 5.30 0.38 0.382030 8.90 -0.30 -2.11 6.49 -0.89 0.00 5.60 0.38 0.38

Yemen KSA

Syria Jordan

max 300 MWYr (2010) max 500 MWYr (2015)

To ATPS PP

From Egyp MAX 1181

MWYrTo

AmmanMAX 1180 MWYr

To Turkey

MAX 11814 MWYr MAX 11814 MWYr

Figure 4-14: Capacity of NG Pipe Lines in ARASIA

Table 4-23: Summary of the expected Electricity Flows in the regional electric grid.

Jordan Syria KSA Yemen Tieline-through

Syria

Import from

Turkey

Export to

Egypt

Tieline through

KSA

Import from

Turkey

Export to

Turkey

Tieline-through Jordan

Tieline-to

Jordan

Tieline-to

Yemen Tieline-to KSA

2003 0.00 0.23 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.002004 0.00 0.25 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.002005 0.00 0.28 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.002007 0.22 0.00 -0.17 0.00 0.00 -0.06 -0.23 0.00 0.00 0.002010 0.23 0.00 -0.27 0.22 0.00 -0.06 -0.23 -0.22 0.00 0.002015 -0.20 0.00 -0.19 0.54 0.00 0.00 0.20 -0.54 -0.29 0.292020 -0.53 0.00 -0.24 0.91 0.01 0.00 0.53 -0.91 -0.57 0.562025 -0.72 0.00 -0.29 1.27 0.01 0.00 0.71 -1.27 -1.08 1.072030 -0.71 0.00 -0.37 1.63 0.01 0.00 0.70 -1.63 -1.45 1.43

2007 Exchange 0 MWYr

2030 Import 1924 MWYr

2007 Exchange 0 MWYr

2030Export 3988 MWYr

2030 Import 829 MWYr 2030 Import 844 MWYr

Yemen KSA

Turkey Egypt

Syria

2007 Export380 MWYr

Jordan

2007 Import 64 MWYr

20309 MWYr

2007300 MWYr

2030820 MWYr

2007232 MWYr

2030400

MWYr

20302064 MWYr

20070 MWYr

20070 MWYr

20301924 MWYr

200780

MWYr

Figure 4-14: Capacity of Electric Tie Lines in ARASIA

Appendix-1 Grid Interconnection of Gulf Cooperation Council (GCC)

Objectives:

1- To link the electrical power networks in the member states by providing the necessary investments for the exchange of electrical power under to face the inability to generate electricity in emergency situations.

2- To reduce the electrical generation reserve of member states. 3- To improve the economic efficiency of the electricity power system in the

member states. 4- To provide the basis for exchange of electrical power among the member states

in such away as to serve the economic aspect and strengthen the reliability of the electrical supplies.

5- To deal with the exiting companies and authorities in change of the electricity sector in the member states and elsewhere in order to coordinate their operations and strengthen the efficiency of operation with due regard circumstances to each state.

6- To follow up the world technological development in the field at electricity and to seek to apply the best modern technologies.

Projects Studies The Gulf cooperation council sponsored the first project study which was conducted by a local committee from the GCC countries in cooperation with research institute in the state of Kuwait & king Fahad University of Petroleum & Mineral in Saudi Arabia in 1986. This study was updated in year 1990 by local financial organization ( Gulf Investment Bank ) in cooperation with SNC- , on international specialized organization . The 2003 studies update is undertaken as the final preparation for the project tendering. For this study update consultant to cover the following areas:

1- Techno-Economical Analysis. 2- Market Study. 3- Financial Analyses. 4- Interconnection Agreement 5- Implementation strategy.

Grid Interconnection Criteria The main objective of the GCC interconnection is the sharing of reserve between the member states without sacrificing the individual supply reliability. The interconnection allows the reduction of the capacity reserve up to 50% that of the isolated grid. The interconnection size was dimensioned in such a manner that each system can import up to 50% the capacity of its largest plant.

The interconnection size is summarized as follows: MW Member states 1800 Saudi Arabia 1200 Kuwait 600 Bahrain 750 Qatar 900 United Arab Emirates 400 Oman

In any single-event contingency, each member state can import up to value of the interconnection size. Project Implementation The GCC interconnection grid shall be implemented in three stages, namely Phase 1 Interconnection of Kuwait, Saudi Arabia, Bahrain and Qatar. This system is the GCC North Grid. Phase2 Interconnection at the independent systems in UAE as well as in Oman. Phase 3 Interconnection of UAE and Oman (the GCC South Grid) with the GCC North Grid. he GCC north Grid : The system component of phase 1 include the following: 400 kV Main Backbone. Vertical configuration consisting of the following line sections: 212 circuit-Km Al-Zour to Ras Azawr. 210 circuit-Km Ras Azawr to Ghunan. 290 circuit-Km Ghunan to Salwa Area. North-South Grids: The GCC interconnection Phase 3 at the GCC interconnection shall link the networks of Kuwait, Saudi Arabia, Bahrain, Qatar (Noth Grid) and United Arab Emirates and Oman (South Grid). Project Benefit

US$ (Million)

2672 Avoided cost of Reserve saving for 30 years 13485 Interconnection Project Cost 13235 Net Benefits 198 B/C Ratio

Recommendations for Further Interconnections It was found that there are many projects taht should be available inside Saudi

Arabia during the study period, and there are many common projects with Saudi Arabia neighbors counters.

Depend on the scenario assumptions and the used data of the Base Year (2003),

the output results in the end of the study period is Available in the table below: Region 2003 2030 % Center 4936 14745 199 South 1148 2904 153 West 4851 13988 188 East 7747 20631 166 KSA 20685 54298 162

Based on the study results the following projects inside Saudi Arabia are

proposed:

• Increase the capacity of the interconnection line between Central & Eastern Regions of Saudi Arabia from (1800MW) in (2003) to (2500) in (2007), with final capacity of (3500MW) in (2010).

Link the electrical power networks of Saudi Arabia Central & Western Regions in (2010) with capacity of (100MW) and final Capacity of (171MW) in (2030). GCC Interconnection Grid Based on the GCC Long-Term Comprehensive Development Strategy Goals which stands out: "Complete interlinking of the infrastructure network among the GCC states, especially in the field of electricity, transportation, communication and information." Hence, the Authority formed by Royal Decree to:

Link the Power grids of the six member states Operate and maintain the interconnection Grid Eventually become a regional player in the Electricity Trading Market

Geographic Map (GCC Grid Geographic Map)

Interconnection Phases: -

Benefits of GCC IG Reduce generating capacity in each system as a result of sharing power

reserves. Sharing spinning reserves to cover emergency conditions. Provide emergency support to any system during black out situations. Lowering operating costs by using most economic generation unit in the

system. Provide opportunity to engage in regional and international Energy trading.

Total Power Capacity for trading between Gulf Countries:- Country Trading Power (MW) UAE 900 Bahrain 600 Saudi Arabia 1200 Oman 400 Qatar 750 Kuwait 1200

55.. EEXXTTEERRNNAALLIITTIIEESS AANNDD HHEEAALLTTHH DDAAMMAAGGEE CCOOSSTTSS OOFF EELLEECCTTRRIICCIITTYY GGEENNEERRAATTIIOONN

5-1 INTRODUCTION

Economic development relies to the great extent upon security of adequate energy supply to all segments of society. However, in view of the strong interaction between energy sector and other spheres of the society, the applied supply policy has to meet the requirements of sustainable energy development in social, economic and environmental dimensions. While socio-economic issues are typically considered in the advanced energy system analyses – like end-use approach - projecting the future demand according to scenarios reflecting the socio-economic and technological development of the country, environmental factor mostly has not been evaluated explicitly in the considered approaches. Keeping in mind that there is no energy conversion technology without risk, waste or interaction with the environment, environmental issues gained increased importance in view of mounting impacts of energy sector on the environment. Environmental impacts vary depending on types of energy production and consumption, regulatory actions and pricing structures. Gaseous emissions and particulates from burning of fossil fuels pollute the atmosphere, affects local air quality and cause regional acidification. Large hydropower dams flood land and may cause silting of rivers. Fossil and nuclear fuel cycles, as well as geothermal production, emit some radiation and generate wastes of different levels of toxicity. Wind turbines can spoil a pristine countryside. Gathering firewood may lead to deforestation and desertification. Main issues related to the environmental dimension include global climate change, air pollution, water pollution, wastes, land degradation and deforestation (Vera et al, 2005). Thus, environmental impacts affect atmosphere, water and land at national, regional and global levels. Atmospheric effects consist of air quality degradation and emissions of greenhouse gases (GHG). One of the most applied approaches to evaluating the environmental impacts of energy and estimating their damage costs on the society, i.e. quantifying the energy external costs, is known as Impact Pathway Approach (IPA) developed in the ExternE project funded by the European Commission. This approach is a step by step procedure linking a burden to an impact. It consists of firstly measuring the damages to society which are not funded by its main actors; secondly, to translate these damages into a monetary value; and thirdly, to explore how these external costs could be charged to the producers and consumers procedure (Bickel and Friedrich, 2005). Varieties of options can be applied for reducing externalities (internalizing external costs) ranging from promotion/subsidizing of new cleaner technologies to the use of fiscal instrument, like taxing the most damaging technologies, or imposing of emission limits and emission fees. Electricity is a key factor for economic and social development. However, the power generation has also a significant environmental impacts, the most important being human health impact (both, increased mortality – reduction of life expectancy as well increased morbidity – cardio-vascular and pulmonary problems, due to long or short-term

exposure) caused by air pollutants (particulate matter, nitrogen oxides, sulphur dioxide, etc) formed during the normal plant operation. Accordingly, detailed analysis of fuels and technologies of Syrian electric generation system has been performed aiming at estimating the impact of power plants on human health resulting from routine atmospheric emissions of pollutants. The study estimates firstly the environmental damages and the related health impact for existing and committed power plants as well for future power candidates, then deals with monetary valuation of the estimated damages i.e. calculates the external costs. The estimated external costs of the considered power plants can be employed in the comparative assessment of electricity generation options, with the purpose of accounting for the real generation costs that includes environmental impact, when choosing the future optimal expansion plan. This procedure presents a simplified way for partially accounting for environmental damage in the national energy sector.

5-2 IMPACT-PATHWAY APPROACH The SIMPACTS (Simplified approach for estimating environmental impacts of electricity generation) model is based on the Extern_E’s EcoSense methodology but in a simplified form. SIMPACTS consists of separate modules for estimating the impact of energy facilities on human health, agricultural crops and buildings resulting from the pollutants emissions as a result of routine operations of electricity generation plants. It covers fossil-fired electricity generation, nuclear energy as well as hydropower installations. It first estimates physical damages and health impacts, then provides a monetary valuation of these damages and calculates external costs associated with different energy supply strategies (Spadaro, 2002).

For airborne pollution, whether from fossil fuelled or nuclear energy plants, the model utilizes a simplified version of the impact-pathway approach (IPA) (Figure 1). In the IPA approach, the emission source is characterized and an inventory of airborne releases is prepared. The changes in ambient concentrations of various pollutants are estimated using atmospheric dispersion models and in the case of radioactive emissions or deposits, exposure response functions are used to relate the change in pollutant concentration to a physical impact on the relevant receptors. In the case of hydropower, the model offers a simplified approach to estimate the loss of land, population displacement, and emissions during construction from hydro dams as well as the impacts from dam failures. In case of fossil power plants SIMPACTS provides estimates of the impacts from exposure to the following type of pollutants: particulate matter (PM 10), sulphur dioxide (SO2), nitrogen oxides (NOx), carbon monoxide (CO), and secondary species such as nitrate and sulphate aerosols, and estimate the monetary values for the associated health impacts.

Figure 9: The Impacts pathway Approach (Athens,1997)

SIMPACTS is developed by the IAEA for the application in developing countries. It is a simplification of the European Extern-E methodology. By assuming a “uniform world” (uniform population density, wind rose and atmospheric conditions including uniform background pollutant concentrations) at distances outside the local (50 km around the source) area, steady pollutant emission rates, linear with no threshold Exposure-Response functions, and a constant rate of pollutant removal from the air, simplified methodology avoids the need for detailed modelling of pollutants regional dispersion and their chemical transformation in the atmosphere. For primary pollutants, the simplified model allows the user to make a range of external cost estimates ranging from rough to more accurate, depending on availability of data. An approximate estimate can be obtained through input data on average population, plant characteristics and emissions, even if no data are available on local weather conditions. In a typical analysis, the user may start with minimum data to get a rough estimate and then gradually add more information, as it becomes available, to obtain more reliable results. The present study was performed using the most sophisticated module QUERI that requires maximum amount of input information. It assesses the health impacts and their associated damage costs due to primary (PM10, SO2, NOx, CO) and secondary (nitrate and sulphate aerosols) pollutants present in the air. The module uses a semi-empirical approach in which correlations derived from existing IPA studies are used to approximate the impacts. The required data can be classified in five groups including source and stacks data, pollution types, meteorological data, Exposure-Response functions and population data (Table 1).

Table 3: Required data for modelling electric power plants according to QUERI module of SIMPACTS.

Chimney (Stack)

Number Height Diameter Gas Temperature

(K)

Gas Flow (Nm3 /s)

Plant Data Location Rural/Urban Latitude longitude

PM10 SO2

NOx

CO

Others

Emission Rate (Tons/year) Depletion Velocity (cm/s)

N aerosols

Emission Data

S aerosols Depletion Velocity (cm/s)

Regional Population density Population data Local Population distribution

Historical Metrological data

Very detailed data about wind speed, temperature, and the height at which these data are measured

Exposure Response Functions

any available epidemiological studies that may be including: - Long-term Mortality (YOLL) - Recommended; Adults over 30 - Chronic Bronchitis - Recommended; Adults over 18 - Cardiovascular Hospital Admission - Recommended; Adults - Lower Resp. Symptoms - Recommended; Asthmatic Adults; PM10 - Short-term Mortality (YOLL) - Recommended; ALL; SO2

5-3 ESTIMATING THE HEALTH DAMAGE COSTS OF SYRIAN ELECTRICITY GENERATION SYSTEM

2-3-4 Syrian Electricity Generation System The total available installed capacity in 2005 amounts to about 6000 MW (Figure 2). The capacity mix was 10.5% combined cycle, 20% hydro, 19.5% gas turbine, and 50% steam turbine. Except for the combined cycles, the most of the thermal power plants operated with a fuel mix consisting of natural gas and fuel oil depending on fuel availability. The gross electricity generation amounted to ca. 35 TWh of which 10% was generated by hydro, 44% by natural gas and 46% by heavy fuel oil. Around 87% of total generation was produced by the public establishment for generation and transmission (PEEGT). The residual was provided by power plants operated by general establishment of the Euphrates dam (GEED) and Ministry of Petroleum and Mineral Resources (MPMR). GEED operates the three hydroelectric plants which contributed to 10% of the total electricity production (MOE, 2006). In a comprehensive environmental impact analysis of electric generation system, the externalities have to be estimated for all existing and future power plant candidates that have been identified according to the developed optimal expansion plan of future generation system (Hainoun et al, 2008). However, as the site data are not known for the future candidates only the damage costs of committed candidates have been estimated. The pre-analysis of existing power plants shown that the damage costs of such small power plants located in remote area –with low population densities- can be neglected.

Thus, four of the existing power plants (Aleppo_PP, Mohardeh_PP, Tishreen_PP, and Banias_PP) and six committed power plant candidates have been evaluated. The specifications of the committed power plants depend upon official plan of the ministry of electricity. The sites of committed power plants have been selected to comply with the regional demand that requires locating the power plants as near as possible to the main consumption centres. Table 2 summarizes the required characteristic data of the various power plants.

Hydro20.0%

(NG+Fuel) Steam49.9%

GT19.5%

CC10.7%

Total available Instaled Capacity in 2005 (Total Installed 6000 MW)

Figure 10: Distribution of available installed capacity by plant type for the year 2005.

Table 4: Summary of the characteristic power plants data for SIMPACTS analysis.

Stack characteristics Site

Plant Capacit

y (MW)

Fuel Type

Local Density

(person/km2) Nr. Height

(m) Diameter

(m)

Plum Temperatur

e (K)

Flux (m3/s)

Plum velocity

(m/s) Longitude Latitude

Banias 4*170 HFO-NG 224 4 125 5.1 423 361 20 324.6 35,08

Aleppo 5*213 HFO-NG 356 4 125 5.66 425 36.1 322.7 15 ــ

Tishreen 2 * 300 HFO-NG 438 2 125 4.5 443 327 20.5 323.3 33.2

Mharde 4*160 HFO-NG 316 4 125 4 428 138 11 323.5 35.15

Deir Ali (CC) 3*250 NG 453

4 60 6 393 419 14.8 323.7 33.2

Deir Azzour 3*250 NG 119 4 60 6 393 419 14.8 319.4 35.2

(CC)

Deir Ali (steam) 3*200 HFO-NG 453 3 150 5.5 145 418 15 323.7 33.2

Hasakah (steam) 3*200 HFO-NG 3 150 5.5 145 418 15 318.9 36.2

Qatena (steam) 3*200 HFO-NG 218 3 150 5.5 145 418 15 323.6 34.5

Swedeah 3*200 HFO-NG 100 3 150 5.5 145 418 15 319.8 37

2-3-5 Atmospheric Emissions: The quantities of emitted pollutants depend on fuel type, plant efficiency and whether the plant is equipped with pollutants filters or not. In the present study two fuel types (fuel oil and natural gas) are considered. The power plants are assumed to operate without emission reduction technologies. Thus, the quantities of the emitted air pollutants have been estimated by means of emission rates. Table 5: Emission rates for the three pollutants depending on fuel type.

Pollutant

Fuel type SO2** NOx13 PM10

N.Gas (kg/m3) 0 0.00565 0.00005*

Fuel Oil (kg/ton) 70 8 0.64(14)

source: *: energy guys externalities. Hml ** calculated using chemical reaction and S-content of Syrian fuel oil.

The Emissions factors of the three primary pollutants (PM10, SO2, NOx) for the two fuel types (NG, fuel oil) that are required for the analysis are presented in table 3. The SO2 emission rate for fuel oil (70 kg/tone of oil) was calculated using the sulfur content of the current Syrian fuel oil (3.5% in average). The annual emission quantities for every emitted pollutant by each power plant are calculated by multiplying the emission rate value with the consumed fuel quantity (Table 4). The total annual electricity generation of the selected existing power plants refer to the year 2005, whereas for the committed and future power plants an average plant factor of 80% has been assumed.

13 Calculated using Tier1 methodology, taking the IPCC default emissions factor (0.15, 0.02) kg/GJ for natural gas and fuel oil, and the national heat content values, which are 9000, 9600 kcal/kg for fuel oil and natural gas respectively. 14 Calculated using also Tier1 but the emission factor is taken equal to 16 g/GJ depending on GAINS: weighted average over country-specific emission factors (IIASA, 2007a). EMEP/CORINAIR, Guidebook (EMEP/CORINAIR,2007).

Table 6: Estimated average emission rate by type of pollutant for the considered power plants.

Table 5 presents the average specific emission factors per generated MWh. The average annual generation of committed power plants is estimated according to similar existing power plants. It should be mentioned that Banias and Tishreen power plants are designed to operate with duel firing mode using natural gas or fuel oil based on fuel availability. It can be seen that the emissions associated with the Syrian fuel oil are quite high due to high sulphur content (3.5%). Besides, the power plants are not equipped with emission reduction technologies like flue gas desulphurisation. Table 7: Average emission per generated electricity of various Syrian power plants by fuel type.

Dual fired (fuel oil +NG)

fuel oil fired NG fired

SO2 [kg/MWh] 11.5 17.4 0.00 NOx [kg/MWh] 1.8 1.6 0.44 PM10 [kg/MWh] 0.26 0.16 0.01

2-3-6 Exposure Response Functions (ERFs) ERF is a mathematical relationship between a change in pollutant concentration and the increased occurrence of the health damage and illness. It is essential in estimating additional years of life lost or new cases of illnesses / hospital admissions attributable to a given increase in pollutant concentration. In terms of damage costs, the most important health impacts are chronic mortality (CM), followed by chronic bronchitis (CB) and restricted activity days (RAD), (Spadaro, 1999). Thus, the analysis focuses on these impacts.

Consumed fuel Emissions (kton) Plant

Aِverage Annual

Generation (GWh)

NG (Mm3)

Fuel Oil (kton) SO2 NOx PM10

Banias 1948 0 422 29.5 3.38 0.27 Mehardeh 3159 0 816 57.1 6.54 0.522 Tishreen 4200 400.00 690.00 48.30 7.78 0.461

Existing

Aleppo 6000 0 1380.00 96.60 11.04 0.883 Deir Ali (CC) 5755.32 1011.08 0 0.00 5.72 0.05

Committed DeirAzzour (CC) 5755.32 1011.08 0 0.00 5.72 0.05

Deir Ali (steam) 4246.85 0.00 1056.18 73.93 8.45 0.676

Hasakah (steam) 4246.85 0.00 1056.18 73.93 8.45 0.676

Qatena (steam) 4246.85 0.00 1056.18 73.93 8.45 0.676

Future Candidates

Swedeah 4246.85 0.00 1056.18 73.93 8.45 0.676

As already mentioned, SIMPACTS uses the assumption of linear Exposure Response Function with no threshold. Hence, ERF slope (cases/(year.person.μg/m3) is obtained by the following simple relation:

BaselineIRRFIRIRRRF POPslope ⋅=⋅⋅=E

Where:

IRR: Increased Risk Ratio (% change per μg/m3);

IR: Incidence Rate (annual cases per receptor at risk – adult, child, etc.) cases/ (year. receptor);

Fpop (%): the fraction of the population affected (e.g. % adults in the exposed population);

Baseline: the nominal rate of occurrence of a particular disease (case/person. year). For the ERFslope: the default values in the program are adopted which refer to the ExternE values of 1998 with one modification concerning the fraction of the affected population for RAD and CB functions. Only the active labour force and adult age group (more than 18-year age) percentage within the exposed population respectively are considered that are calculated from the country's age table (IAEA, 2002).

Table 8: Exposure Response Functions adopted in this study.

Pollutant Exposure Response Function

Receptor Group

Fpop15

(%)

Slope (cases /year/

person- μg/m3)

Type of Impact

Unit Cost 2000$/case

Chronic Mortality (CM) all 100 2.60E-04

Long-term

mortality 28796

Restricted Activity Days, Adults (RAD)

adult > 18 45.5 4.00E-02 Morbidity 14 PM10

Chronic Bronchitis, Adults (CB)

> 27 35 3.96E-05 Morbidity 19460


Long-term

mortality 28796 Nitrate

Restricted Activity Days, Adults(RAD)

adult > 18 45.5 4.00E-02 Morbidity 14

15 (Statistical, 2005)


> 27 35 3.96E-05 Morbidity 19460


Long-term

mortality 28796

Restricted Activity Days, Adults (RAD)

adult > 18 45.5 6.68E-02 Morbidity 14 Sulfate


> 27 35 6.61E-05 Morbidity 19460

2-3-7 Meteorological and Population Data Besides the regional population density (within a circle of radius of 1000 km surrounding the source), QUERI module of SIMPACTS requires a detailed local population distribution data file (within 50 km around of the emission source, 5 km2 by 5 km2 resolution). For each plant, regional population density is determined separately by considering a radius of 1000 km around the power plant. However, due to lack of information, the local distributions of the population are roughly estimated depending upon specific assumption related to the power plants locations and population areas around them in a circle of 50 km diameter. Figure 3 presents the achieved result for the four selected power plants of Deir Ali in the south region of the country, Aleppo in the north, deir Azzour in the east, and Banias in the west. Figure 3 depicts that the most of power plants are located near to big cities with high population. Thus, the power plants Deir Ali and Tishreen are located at about 22 km from the city of Damascus having population density of 13100 person/km2, whereas the local population density is about 453 and 438 person/km2 respectively. Besides, an Aleppo steam power plant is about 30 km from the city of Aleppo that has 10000 person/km2.

Figure 11: Distribution of Population around the Selected Power Plants. To show the information regarding the distributions of wind speeds and the frequency of wind directions variation, a simple wind rose is drawn using the meteorological data of wind speeds and wind directions derived from the national Wind Atlas. Figure 4 shows the wind roses for six power plants. The compass perimeter was divided into 12 sectors, one for each 30 degrees of the horizon. (A wind rose may also be drawn for 8 or 16 sectors, but 12 sectors tend to be the standard set by the European and Syrian Wind Atlas). The radius of the 12 outermost, wide wedges gives the relative frequency of each of the 12 wind directions, i.e. how many percent of the time is the wind blowing from that direction. The required meteorological files that include detailed data about air temperatures, wind speed and directions were prepared for every power plants region. The year 2005 was considered as a reference year for the metrological data that were extracted from the nearest weather recording stations according to the http://meteo.infospace.ru web site, and prepared according to the data format of QUERI module. This file contains seven spaced separated columns and each one refers to a particular factor: the first column for year of date, second for month, the third for month's days, hours in the fourth, while the remaining columns contains wind direction, wind speed, and ambient temperature respectively.

Figure 12: Wind Roses of various power plants considered in the study.

Depletion velocity: This factor is essential for damage cost assessment. Its value is related closely to the regional characteristics (in view of terrain, meteorological conditions, background pollutant concentrations….etc), besides it is specific for every pollutant type. As no particular calculated values are available for Syria, the calculated values for one of the Mediterranean country (Spain) were considered as reference (Bickel and Friedrich 2005).

Table 9: Depletion velocity values for different pollutants

Pollutant PM10 SO2 NOx Sulfate Nitrate Depletion Velocity (cm/s) 0.67 0.73 1.47 1.73 0.71

2-3-8 Monetary Valuation: SIMPACTS calculates the health cost using the following equation :

)$(ERFDV

QHealthCost j

ctHealthImpaj

reg ∑ ⋅⋅ρ⋅

=

Where: Q: is the pollutant emission rate (ton/year),

regρ : the regional population density; DV: depletion velocity (cm/s); $: economic unit damage cost ($/case), ERFj: Health impact resulting from j exposure response function (cases/year). For health impacts, unit cost is the cost factor for monetization the physical impact and environmental burdens. For example: the cost per asthma attack, or the cost per year life lost (YOLL). It includes three factors: the cost of illness, wage and productivity losses, which are market based factors, as well as non-market costs that take into account an individual's willingness-to-pay (WTP) to avoid the risk of damage (pain and suffering). In view of the fact that the majority of the developing countries have no own WTP studies, SIMPACTS offers the possibility of transferring the values assessed for European countries using so called Benefits Transfer. The unit economic cost is calculated using the transferring value method depending on the unit damage costs from the EXTERNE 1998 study as a reference. In order to apply these external costs to Syria, the following adjustments are made:

(i) to reflect differences in income and accordingly willingness-to-pay, Syrian GDP per capita adjusted for the purchasing power parity PPP is used,

The scaling factors are derived by dividing the magnitude of the parameter for Syria by the corresponding value for EU using the following equation:

EU

Syria

GDPPPPGDPPPP

valueEUvalueSyrian)()(

.. ⋅=

Where: PPP(GDP) is the national gross domestic product GDP per capita adjusted for the purchasing power parity PPP. According the 2006 World Bank and UNDP reports, the Syrian PPP(GDP) counted 4100 US$ in the year 2006, while it was a bout 31181 for the EU (World Bank 2008). Table 8 presents the result of the applied adjustments. Table 10: adjusting of the per case damage costs for Syria.

Health Impact

EU-15 Values(2000$/case)

GDP Adjusting factor (%)

Adjusted values (2000$/case)

CM 219000 13.1 28796 RAD 106 13.1 14 CB 148000 13.1 19460

5-4 DAMAGE COST RESULTS OF SYRIAN POWER SYSTEM

In the following a summary of the externalities assessed for the electricity generation is given. The total damage values show that electricity generation is associated with considerable external costs. The largest damage cost refers to the chronic, and more specifically to the chronic mortality effects (more than 85% of the total cost in average) and the secondary pollutants (more than 97%). However, the obtained cost figures vary according to the plants location and fuel types. As far as the per ton of pollutants damage costs are concerned, it can be seen that these are much lower for the natural gas fired power plants in comparison with fuel oil. While the value attributed to nitrates is the dominated in case of natural gas consumption, the sulphates value dominates in case of fuel oil consumption.

Total Health Damage Cost The summary of the total health cost assessed per power plant are shown in figure 5. The largest costs are observed for fuel-oil fired power plants (Aleppo, Swedeah, Qatena, and Hasakah). The related total damage costs on human health amount to 140, 110, 107 and 107 million US $ respectively (in constant price of the year 2000). The result is a direct consequent of high sulphur continent of fuel oil. It indicates also the advantage of natural gas fired power plants against fuel oil firing. The total health cost assessed for Deir Ali_pp (750 MW combined cycle) which is located about 30 km from the capital Damascus, amounts to 3.4 million $. This amount is less than 4% of the total cost of the for the lowest fuel oil power plant. That is mainly because of the neglected sulphur continent in the natural gas, and the low PM10 and NOx emissions. Tishreen and Banias are dual-fuel fired power plants. Tishreen_PP consumed 62% fuel oil and 38% natural gas; Banias_PP consumes almost 50% for both fuels. The health damage costs depend on the share of each fuel and the site location of the power plants. Figure 5 shows that the health damage costs amount to 46 and 71 million US $ respectively. However, the costs are significantly lower than in case of pure fuel oil fired power plants.

Total health Cost destributed by Powe Plants (M$)

0.020.040.060.080.0

100.0120.0140.0160.0

Aleppo

mohar

dahBan

ias

Tishree

n

Deir A

li

Deir as

sour

Deir A

li Stea

m

Swedeah

Qatena

Hasakah

Figure 13: Total health damage cost by power plant (Million US $). Table 9 present detailed distributions of the external costs by pollutants and type of damage on the human health. The largest external cost share is related to the secondary pollutants. In case of natural gas power plants, the secondary pollutant's shares (nitrates) are 92 % for Deir Alِi CC and 98% for the others. The difference in case of Deir Ali refers to its location near to the large city Damascus, which means that the local damage caused by primary pollutants (PM10) within 50 km radius surrounding the plants has more effective impact (the local population density within this circle for Deir Ali is higher than deir Azzour and Mohardah). Fuel oil fired power plants show that regional damage is distributed between Nitrates and sulphates damages. The sulphates share in the total damage cost is higher with a share ranging between of 87% and 90% compared to (9 to 12) % for nitrates. PM10's share ranges between (1, 2) %. The health damage costs by type of damage indicate that the largest damage cost refers to the chronic mortality effects (more than 85% of the total damage cost). The second is chronic Bronchitis with an average of 9%. The damage cost related to Restricted Activity Days amount to 9%.

Table 11: External costs by type of damage and pollutant Fuel Type NG Fuel Oil

Dual fuel (fuel oil &N.gas)

Plant Deir Ali

(CC)

Deir Azor (CC)

Moharda

Swedeah

Qatena

Haskah

Aleppo

Deir Ali

(steam)

Banias Tishren (62*38)%

Damage cost (M$)

3.4 3.2 95.2 110.4 107.2 106.8 139.6 108.2 43.0 71.1

Health Damage Cost Distribution by the Type of Pollutants (%)

PM10 8 3 13 1 2 1 1 2 1 1

Nitrates 92 97 10 12 9 9 9 9 11 11

Sulfates 0 0 78 87 89 90 90 89 89 87

Health Damage Cost Distribution by the Type Health Effect (%)

CM 85 85 85 85 85 85 85 85 85 85

RAD 6 6 6 6 6 6 6 6 6 6

CB 9 9 9 9 9 9 9 9 9 9

Fuel Type N.gas Fuel Oil Dual fuel

(fuel oil &NG)

Plant Moharda

Deir Ali (CC)

Deir Azor (CC) Swedeah Qatena Haskah Aleppo

Deir Ali (steam) Banias Tishren

Total Damage

Cost (M$) 2.8 3.4 3.2 110.4 107.2 106.8 139.6 108.2 46.1 71.1

Distribution of Health damage cost by type of pollutants (%) PM10 3 8 3 1 2 1 1 2 1 1

Nitrates 97 92 97 12 9 9 9 9 12 11 Sulfates 0 0 0 87 89 90 90 89 87 87

Distribution of Health damage cost by type of health effect (%) CM 85 85 85 85 85 85 85 85 85 85

RAD 6 6 6 6 6 6 6 6 6 6 CB 9 9 9 9 9 9 9 9 9 9

2-3-9 Specific Damage factors per ton of Consumed Fuel Figure 6 shows the distribution of spcific damage cost per ton of pollutants for the differnts Syrian power plants. Table 10 presents a comparision of damage factors per ton of pollutant for Syria and EU. It can be concluded that Syrian damage factors for PM10, Sulfates, and Nitrates are 5.6 , 5.3 and 13.6 times respectively lower than those obtained in Europe

0 .0

1 .0

2 .0

3 .0

4 .0

5 .0

6 .0

PM 10 1.9 2.3 1 .9 1.9 5.2 2.1 3.9 1 .5 2.4 1 .8

N itrates 1 .4 1.4 1 .4 1.4 1.4 1.4 1.4 1 .4 1.4 1 .4

Sulfates 1 .3 0.0 1 .3 1.3 0.0 1.3 1.3 1 .3 1.3 1 .3

A leppo_PPm ohardah_

PPB anias_PP

Tishreen_PP

D eir A li_PPD eir

assour_PPD eir A li

steam _PPSw edeah_P

PQ atena_P P

H asakah_PP

Figure 14: Specific health damage cost by type of pollutants (1000$/ton).

Table 12: Comparison of Syrian and European average damage factors.

2-3-10 Damage Cost per Generated Electricity Unit The per kWh health damage costs are presented in table 11 and figure 7. It can be seen that the average external cost related to health damage amounts to 1.6 US cents per generated kWh. This relatively high value is caused mainly by fuel oil fired power plants. It can be partly justified in view of the fact that all considered power plants are not equipped with any kind of pollutants removing technologies.

16 (Rable and Spadaro, 2004) 17 assuming that 1 EU = 1.2 US $

Pollutant

Syrian Damage factors

$2000/ton

European damage

Factors16 (EU15)

E2000/ton

European Damage factors

(EU15) US $2000/ton17

EU15/Syrian

PM10 2526 11723 14068 5.6 Nitrates resulting

from NOx 1398 5862 7344/ton of

NOx 5.3

Sulfates resulting from SO2

1037 11723 14068/ton of SO2 13.6

Health Damage Cost per kWh per power plant

0 1 2 3 4

Aleppomohardah

BaniasTishreenDeir Ali

Deir assourSwedeahQatena

Hasakah

Cent/kWh

Figure 15: Total health cost by power plants (US cents/ kWh).

Table 13: Average total external health cost distributed by fuel type (in constant price of 2000) Fuel Type NG Fuel Oil Dual

Plant Mohrde (HF)

Deir Ali (CC)

Deir Azor (CC)

Swedeah Qatena

Haskah

Aleppo

Deir Ali

(steam)

Banias FO

Tishren 62*38

%

Toatal Generation

[GWyr] 3159 657 657 485 485 485 685 485 1948 479

Damage Cost [US cent/kWh] 3 0.06 0.06 2.60 2.52 2.52 2.33 2.55 2.22 1.69

Average unit cost per fuel type [US cent/kWh] 0.07 2.5 1.65

The associated health damage cost for producing one kWh using natural gas is about 0.07 US cents in average that seems to be very low compared to 2.5 US cent for fuel oil. The highest health damage cost for using fuel oil in electricity generation is for Swedeah with 2.6 US cents. This results support strongly the choice of replacing fuel oil by natural gas for producing electricity. The calculated external damage costs are very high comparing to the real generation cost per kWh. The official data estimate the average cost with about 8 US cents per kWh for fuel oil fired power plants. Hence, considering external cost causes around 30% extra cost per kWh. However, as already mentioned the resulting high external costs in case of fuel-fired power plants arise from:

• The very high sulfur content in Syrian fuel oil; • Most of considered power plants are located near to big cities with very high

population densities; • The transfer value method gave very high values especially for long-term

mortality; • All installed power plants have no additional technology for air pollutants

reduction before emission.

5-5 CONCLUSION Based on the simplified impact pathway approach (IPA) the health impacts and the resulting external costs due to airborne pollutant emissions have been estimated for the Syrian electricity generation system. The obtained results indicate that the environmental impacts can cause considerable extra cost to the typical generation cost. The estimated externalities vary between 2.5 US cent and 0.07 US cent per generated kWh for fuel oil and natural gas fired power plants respectively. For the fuel oil fired power plants the caused external cost – arisen mainly from Sulphates impact- amounts to 30% of the present generation costs. These results indicate the advantage of natural gas fired power plants as clean generation technology and the necessity of supplying oil fired power plants with SO2 emission reducing technologies. The Impact Path Way Approach applied in simplified form in SIMPACTS presents a reasonable approach for estimating externalities of human health damage related to environmental impact of electricity generation. The analysis results of the Syrian power system show in case of fuel fired power plants relatively high external costs that amount to about 30% of total generation costs. The main reason being the high sulphur content of Syrian fuel oil. Thus, it would be worth performing a cost-benefit analysis, comparing the costs of using sulphur reduction technologies to improve the fuel oil quality to the calculated avoided externalities.

References Hainoun, A. SeifAldin, A. Almoustafa, S. (2008) Formulating an Optimal Long-term

Energy Supply Strategy for Syria using MESSAGE Approach, under publication. MOE, 2006. Technical Statistical Report 2005. Ministry of Electricity, Damascus, Syria

Statistical Abstracts for Syrian Arab Republic (2005). Central Bureau of Statistics, Damascus, Syria

Spadaro J. V. (2002), Airpacts Manual Version (1.01), IAEA, Vienna

Spadaro, J. V. (1999) Quantifying the Damages of Airborne Pollution: Impact Models, Sensitivity Analyses and Applications, Ph.D. Dissertation, Ecole des Mines de Paris, Centre d’Energétique, 60 boul. St. Michel, F75272, Paris, Cedex 06, France.

Rable, A. SpadaroJ. V 2004 Final report for ExternE-Pol: Externalities of Energy, ARMINES/ Ecole des Mines de Paris – 22 November 2004.

Bickel, P., Friedrich, R. 2005. ExternE: Externalities of Energy, Institut für Energiewirtschaft und Rationelle Energieanwendung — IER Universität Stuttgart, Germany.

Athens-1997 External cost of electricity generation in Greece, research prepared by laboratory of Industrial and Energy Economics ,national Technical University of Athens, December 1997.

IAEA, 2002. Reference Database of Concentration-Response Functions for health impacts of Air Pollution. Document prepared for the International Atomic Energy Agency.

World Development Indecators database,World bank, 11 April 2008), www.worldbank.org/data/.

Vera, I. A., Langlois, L. M., Rogner, H. H., Jalal A. I., Toth, F. L., 2005. Indicators for sustainable energy development: An initiative by the International Atomic Energy Agency, Natural Resources Forum 29 (2005) 274–283

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