Table of Contents. Table of Contents... i List of Tables... v List of Figures... vi Acronyms and Abbreviations... ix. 0 Introduction...

Transcription

1 Table of Contents Table of Contents... i List of Tables... v List of Figures... vi Acronyms and Abbreviations... ix 0 Introduction Reporting Definitions and Terms Data Collection Overview on HVDC Cable Interconnection Projects Description of Worldwide Submarine DC Links Submarine DC Links similar to the envisaged Italy-Malta Interconnection Sweden Gotland Italy Corsica Sardinia Moyle (Scotland North Ireland) Cross Sound Cable USA Estlink (Estonia Finland) Technology Screening on Submarine HVDC Cables Introduction HVDC Submarine Cable Installation Configurations: Monopole and Bipole HVDC Submarine Cable Design Study Main Electrical Characteristics Installation Data LI Page i

2 2.3.3 Environmental and Permissible Operating Conditions HVDC Cable Designs General Features Ancillary Equipment Issues Optical Fibre Control Cable Temperature Measurement Summary Technology Screening on Submarine NG Pipeline Interconnections Existing Off-shore Gas Pipelines in the Mediterranean Sea Existing Gas Off-Shore Pipelines in the Mediterranean Sea Planned Gas Off-Shore Pipelines in the Mediterranean Sea General Methodology for Off-Shore Gas Pipelines Design Consideration for Sub Sea Pipelines in the Mediterranean Sea System Design for Sub sea Pipelines Desktop Planning and Routing Meteo Marine Data Collection/Studies Site Investigation (Off-Shore Survey) Pipeline Stress Calculations Geohazards Pipeline Crossings, Free Spans and Sea Bed Rectification Materials and Welding Pipeline Protection Landfall Design and Constructability Corrosion Protection of Sub Sea Pipelines Risk Analysis Matrix LI Page ii

3 4 Power Generation and Supply System on Malta The Existing Power Generation System Historical Development and Current State of Power Generation Installed and Available Capacity Fuel Characteristics and Consumption Outlook The Existing Power Network Geographic and Technological Structure of the Transmission and Distribution System Capacity and Operational Constraints Analysis and Projection of the Electricity Demand Historical Development of the Electricity Demand Electricity Consumption by Sector The Residential Sector (RS) The Commercial Sector (CS) The Industrial Sector (IS) Losses between Final Demand and Demand at Sent-Out level Seasonal Load Characteristics Daily Load Patterns - Working Days Daily Load Patterns - Weekend Days Electricity Demand Forecast Market Analysis on Oil and Gas Prices General Market Forces and Pricing Mechanism General Forecasts for Future Hydrocarbons Process Indicative Market Analysis for Selected Fuels Procurement and Contracting Options for Selected Fuels LI Page iii

4 6.4.1 Procurement and Contracting for Diesel and Fuel Oil Procurement and Contracting for Natural Gas Contracting for LNG Supply Options Procurement Options for LNG Supply Pricing Issues Market Analysis on Electricity Supply from Continental Europe System Adequacy in Central Europe Current and Future Electricity Price Levels LI Page iv

5 List of Tables Table 0-1: Data and Documents Collected Table 2-1: Listing of many of the World s Major DC Submarine Cable Links Table 4-1 : Gross Generation in MWh/a Delimara Power Station ( ) Table 4-2 : Gross Generation in MWh/a Marsa Power Station ( ) Table 4-3 : General Unit Data Delimara Power Station Table 4-4 : General Unit Data Marsa Power Station Table 4-5 : Annual Fuel Consumption in Metric tons Delimara Power Station ( ) Table 4-6: Annual Fuel Consumption in Metric tons Marsa Power Station ( ) Table 5-1 : Annual electricity consumption, average and peak load ( ) Table 5-2 : Development of System s Load Factor in Selected Years ( ) Table 5-3 : (Specific) Electricity consumption in the residential sector ( ) Table 5-4 : Electricity consumption in the commercial sector ( ) Table 5-5 : Electricity consumption in the industrial sector ( ) Table 5-6 : Evaluation of Losses ( ) Table 5-7 : Maximum Demand - Absolute in MW ( ) Table 5-8 : Maximum Demand Adimensional in % ( ) Table 5-9: Peak Load Forecast Enemalta Corporation ( ) Table 5-10: Electrical Energy Demand Forecast Enemalta Corporation ( ) Table 5-11: Updated Electrical Energy Demand and Peak Load Forecast ( ) Table 7-1: UCTE - Generation System Adequacy Forecast in GW ( ) Table 7-2: Italy - Generation System Adequacy Forecast in GW ( ) Table 7-3: Italy Import and Export Balance ( ) LI Page v

6 List of Figures Figure 0-1: Tasks of Work Package I and Link to Work Package II Figure 2-1: Various HVDC Submarine Cable Installation Configurations Figure 2-2: Construction of an HVDC-IRC submarine cable Figure 2-3: Details of the Estlink HVDC Light Project Figure 2-4: Cross Section of a Typical HVDC Submarine Cable Figure 3-1: Overview Map Gas Pipelines in the Mediterranean Sea Figure 3-2: Routing MEDGAZ Pipeline (source Medgaz.com) Figure 3-3: Routing GALSI Pipeline (Source: Petroleum Economist) Figure 3-4: Routing Greece Italy Gas Interconnector (Source: Petroleum Economist) Figure 3-5: Routing Trans Adriatic Pipeline (Source: EGL) Figure 3-6: State of the Art as in 1984 and Figure 3-7: Schematic of S-Lay Methodology with a Horizontal Deck and a Horizontal Reel Figure 3-8: Schematic of J-Lay Methodology l Figure 3-9: Picture of S-Lay Vessel Piper (Owner is Acergy) Figure 3-10: Picture of Reel-Lay Vessel Apache (Owner is Technip) Figure 3-11: Picture of J-Lay Vessel Balder (Owner is Heerema) Figure 3-12: Typical Pipeline Profile (Example for Trans Adria Pipeline) Figure 3-13: Typical Pipeline Schematic Overview (Example for Trans Adria Pipeline) Figure 3-14: Typical routing plan for a sub sea section (Example for Trans Adria Pipeline) Figure 3-15: Typical sea bed contours for a sub sea section (Example for Trans Adria Pipeline) Figure 3-16: Typical Off-Shore Survey Vessel Figure 3-17: Typical Vibro-Coring Figure 3-18: Typical Drop/Gravity/Piston Corers Figure 3-19: Typical Grab Sampling Figure 3-20: Typical Sea Bed Bathymetry (Echo Sounding) Figure 3-21: Typical Rosette Water Sampler Figure 3-22: Typical Sediment Corers Figure 3-23: Typical Methodology for Pipeline Stress Calculations Figure 3-24: Typical Geohazard Analysis and Interpretation of a Sea Bed Figure 3-25: Typical Free Span Section (upper left) and Non Evasive Sea Bed Rectification LI Page vi

7 Figure 3-26: Typical Evasive Sea Bed Rectification using Dredger (left) and Backhoe (right) Figure 3-27: Typical Evasive Sea Bed Rectification using Cutter Suction (left) and Bucket (right) Figure 3-28: Typical evasive Sea Bed Rectification using ROV (Remote Operated Vehicle) Figure 3-29: Typical Semiautomatic Welding Machine on Horizontal Platform for S-Lay Figure 3-30: Typical Concrete Coatings for a Sub Sea Pipeline Figure 3-31: Typical Soil Cover for a Sub Sea Pipeline Figure 3-32: Typical Landfall using a Pull-in on Rollers Figure 3-33: Typical Landfall using a Pull-in Mechanism on Rollers for Prefabricated Pipeline Sections Figure 3-34: Typical Landfall using a Floating Ditch for Pull in Prefabricated Pipeline Sections Figure 3-35: Typical Landfall using Horizontal Drilling for Least Environmental Impact Figure 3-36: Typical Clamp-on Anodes for Sub Sea Application Figure 3-37: Typical Risk Analysis Matrix Figure 4-1: Gross Generation by Technology Delimara Power Station ( ) Figure 4-2: Gross Generation by Technology Marsa Power Station ( ) Figure 4-3: Average Monthly Temperature Profile and Capacity Rating (Example: DPS CCGT) Figure 4-4: Specific Fuel Consumption (Related to Gross Generation) Delimara Power Station ( ) Figure 4-5: Specific Fuel Consumption (Related to Gross Generation) Marsa Power Station ( ) Figure 4-6: Simulated Actual Dispatch of MPS and DPS Generation Units Transition Period (2006) Figure 4-7: Simulated Hypothetical Dispatch of MPS and DPS Generation Units Transition Period (2006) Figure 4-8: Maltese Distribution System Figure 5-1: Historical Development of Annual Demand and Peak Load ( ) Figure 5-2: Sector Break Down of Final (Billed) Electricity Consumption in GWh/a ( ) Figure 5-3: Sectors Proportions of Final (Billed) Electricity Consumption ( ) Figure 5-4: Monthly Patterns of the Maximum Load in Recent Years ( ) Figure 5-5: Typical Load Profiles of Working Days (2005) Figure 5-6: Typical Load Profiles of Weekend Days (2005) Figure 5-7: Trend in Peak Load Development ( ) Figure 5-8: Historical and Projected Development of Peak Load and Energy ( ) Figure 6-1: Crude Oil Prices from in relation to World Events (Source BP Statistical Review) Figure 6-2: Crude Oil Prices from (Source BP Statistical Review) Figure 6-3: Relationship between Crude Oil Prices, Natural Gas Prices in the US (Source Energy Intelligence) Figure 6-4: Natural Gas Prices from (Source BP Statistical Review 2007) LI Page vii

8 Figure 6-5: Global Energy Consumption from (Source EIA) Figure 6-6: Forecast of Crude Oil Prices from (Source EIA) Figure 6-7: Forecast of Natural Gas Prices (Spot at Henry Hub) from (Source EIA) Figure 6-8: Prices for Diesel and 1% Fuel Oil in the Mediterranean Market from Oct to Jun Figure 6-9: Relationship between Crude Oil, Natural Gas and LNG Prices (Source BP Statistical Review) Figure 6-10: Three Stage Tender Process for LNG Purchase Figure 6-11: LNG Sourcing Process as a combination of Tender and Alternative Figure 7-1: Associations of Transmission System Operators in Continental Europe Figure 7-2: UCTE Remaining Capacity and Reference Margin in GW ( ) Figure 7-3: Italy Remaining Capacity and Reference Margin in GW ( ) Figure 7-4: Italy Electricity Import and Export in Recent Years ( ) Figure 7-5: Sicily Current State and Development of the 220 kv and 380 kv Transmission System Figure 7-6: Continental Europe Import & Export Power Balance (January 2007) Figure 7-7: Continental Europe Net Generating Capacity by Country in GW ( ) Figure 7-8: Development of Specific Generation Capital Costs in EUR/kW ( ) Figure 7-9: Development of Raw Materials Costs in % ( ) Figure 7-10: IHS Upstream Capital Costs Index in % ( ) Figure 7-11: Increase of Electricity Wholesale and Retail Prices ( ) Figure 7-12: Historical and Projected Wholesale Prices in EUR/MWh ( ) LI Page viii

9 Acronyms and Abbreviations C Degree Celsius a Year ABB Asea Brown Boveri AC Alternating Current Al Aluminum ARM Adequacy Reference Margin BASF Baden Aniline and Soda Factory, German Chemical Company bbl Blue Barrel BP British Petroleum, British energy company BTU British Thermal Units CAP Chapter CAPEX Capital Expenditures CCGT Combined Cycle Gas Turbine CEPSA Compañía Arrendataria del Monopolio del Petróleo, Spanish Petroleum Company CERA Cambridge Energy Research Associates cm Centimeter CNG Compressed Natural Gas CO 2 Carbon Dioxide CS Commercial Sector CTD Conductivity Temperature Depth Cu Copper DC Direct Current DPS Delimara Power Station DSM Demand Side Management DTS Optical Fibre Sensors EDF Electricité de France EEX European Energy Exchange EGL Elektrizitäts-Gesellschaft Laufenburg, Swiss Utility Company EIA EMC ENDESA ENEL ENI EoI Energy Information Administration Enemalta Corporation, Maltese Utility Company Empresa Nacional de Electricidad. Spanish Utility Company Ente Nazionale per l'energia Elettrica, Italian Utility Company Ente Nazionale Idrocarburi, Italian Oil and Gas Company Expression of Interest LI Page ix

10 EUR EURct FOB FSU GC GDF GDP GPS GSPA GT GW GWh h HFO HoT HPP HV Hz IGBT IPEX IS ITA K ka KESH kg kj km kv kw kwh LCC LI LNGSPA LoI LPX LV m Euro; Currency of the European Monetary Union Monetary Unit; 1/100 EUR Freight on Board Former Soviet Union Generating Capacity Gaz de France, French utility company Gross Domestic Product Global Positioning System Gas Sales & Purchase Agreement Gas Turbine Giga Watt Giga Watt Hour Hour Heavy Fuel Oil Heads of Terms Hydro Power Plant High Voltage Hertz Insulated Gate Bipolar Transistors Italian Power Exchange Industrial Sector Italy Kelvin Kilo Ampere Albanian Power Corporation sh.a, Albanian Utility Company Kilogramme Kilo Joule Kilometer Kilo Volt Kilo Watt Kilo Watt Hour Line Commutated Converters Lahmeyer International LNG Sales & Purchase Agreement Letter of Intend Leipzig Power Exchange Low Voltage Meter LI Page x

11 m² Square Meter m³ Cubic Meter Max Maximum MEG Maghreb-Europe Gas Pipeline MI Mass Impregnated Min Minimum MJ Mega Joule mm Millimeter mm² Square Millimeter mmbtu Millions of BTU MoU Memorandum of Understanding MPS Marsa Power Station MTL Maltese Lire; Currency of the Republic of Malta MV Medium Voltage MVA Mega Volt Ampere MW Mega Watt MWh Mega Watt Hour NBP National balancing point NCV Net Calorific Value NED The Netherlands NGC Net Generating Capacity NOC National Oil Corporation of Libya NOR Norway NOx Nitrogen Oxides NYMEX New York Mercantile Exchange OCGT Open Cycle Gas Turbine OPEC Organization of the Petroleum Exporting Countries OPEX Operational expenditure PE Polyethylene POL Poland PP Polypropylene PSA Production Sharing Agreement PU Polyurethane PWM Pulse Width Modulation RAC Reliable Available Capacity RC Remaining Capacity RL Reference Load RS Residential Sector LI Page xi

12 RWE S SCFF SCP SO 2 SPA ST SVE t T TAP TJ TMPC TPP TransMed TSO U UCTE UK USD VSC w WP XLPE Rheinisch-Westfälisches Elektrizitätswerk AG, German Utility Company Sulphur Self Contained and Fluid Filled South Caucasus pipeline Sulphur Dioxide Sales & Purchase Agreement Steam Turbine Sweden (Metric) Tones Thousand Tans-Adriatic pipeline Terra Joule Trans-Mediterranean Pipeline Corporation Thermal Power Plant Trans-Mediterranean pipeline Transmission System Operator Voltage Union for the Co-ordination of Transmission of Electricity United Kingdom Dollar; Currency of the United States of America Voltage Source Converter Week Work Package Cross-Linked Polyethylene LI Page xii

13 0 Introduction Work Package I Background Analysis and Research focuses on data research tasks to establish a consistent data pool for the subsequent planning tasks. The works aim in particular at providing important background data on the different technological options considered in this energy interconnection study. Furthermore, selected characteristics and data concerning the existing Maltese power generation and supply system are discussed. The work on background analyses and data research comprised the following key issues: Overview on HVDC Cable Interconnection Projects and Lessons Learnt; Technology Screening on Submarine HVDC Cables; Technology Screening on Submarine Natural Gas Pipeline Interconnections; Data on the Existing Power Generation and Supply System on Malta; Demand Analysis and Review; Market Analysis on Oil and Gas Prices; Market Analysis on Electricity Supplies from Continental Europe. 0.1 Reporting The task structure of Work Package I and its link to further topics to be treated within the Work Package IIa Pre-feasibility Study on Interconnection Options is illustrated in Figure 0-1. This report is structured in accordance with the numbering of the individual subtasks. In the following, an insight into the issues treated in the several chapters is provided: Chapter 1 provides an overview on HVDC cable interconnection projects. After a description of world-wide submarine DC links, assignments similar to the envisaged Italy-Malta interconnecttion are selected and described in more detail. Chapter 2 includes a technology screening regarding the application of submarine DC cables. The main cable installation configurations and cable designs are investigated. The exercise places emphasis on main electrical characteristics, environmental and permissible operating conditions as well as on ancillary equipment issues. A technology screening regarding the introduction of a submarine natural gas interconnection to Malta is presented In Chapter 3. Based on an explanation of already existing and planned gas off-shore pipelines in the Mediterranean Sea, the chapter deals with the general methodology for off-shore pipeline assignments. Furthermore the design considerations are presented. Con- LI Page 0-1

14 cerning this matter the main criteria such as the general system design, the desktop planning and routing as well as the pipeline stress calculation and protection are provided. An analysis of the characteristics of power generation and supply in the Republic of Malta is presented in Chapter 4. On the power generating side the chapter deals with the historical development and current state of annual quantities produced, the installed and available system Task I.5 Electricity Demand Analysis / Review Task I.6 Market Analysis on Oil and Gas Prices Task I.3 Technology Screening on Submarine Gas Pipeline Task I.1 Overview on HVDC Cable Interconnection and Lessons Learnt Task I.4 Data on the Existing Power Generation and Supply System Task IIa.1 Estimation of Gas Demand under Alternative Scenarios Tasks IIa.7 & IIa.9 WP I Task I.2 Technology Screening on Submarine HVDC Cables Task I.7 Market Analysis on Electricity Supplies from Continental Europe Task IIa.4 Techno-economic Specification of CNG Infrastructure Task IIa.3 Techno-economic Specification of LNG Infrastructure Task IIa.2 Techno-economic Specification of Gas Pipeline Options Task Iia.11 Techno-economic Specification of HVDC Cable Interconnection Task IIa.5 Dynamic Unit Cost Analysis for Gas Supply Alternatives WP IIa Task IIa.6 Techno-economic Specification of Gasfuelled Supply Options Task IIa.7 Dynamic Unit Cost Analysis for Gas-based Power Generation Task IIa.10 Consideration of Back-up Fuels and Dual Firing Task IIa.8 Techno-economic Specification of Oilfuelled Supply Options Task IIa.9 Dynamic Unit Cost Analysis for Oil-based Power Generation Task IIa.12 Dynamic Unit Cost Analysis for HVDC Electricity Imports Task IIa.13 Specification of Wind Power Characteristics on Malta Task IIa.14 Indicative Environmental Impact Assessments Figure 0-1: Tasks of Work Package I and Link to Work Package II LI Page 0-2

15 capacity and the fuel characteristics and specific consumption of each technology applied in the system. Regarding the transmission and distribution side an overview of the geographic and technological structure is given. Furthermore, the capacity as well as operational constraints are discussed. Chapter 5 presents a detailed assessment of the demand of electric energy in terms of the total annual quantities, the peak and the lowest load levels. In the first step, an analysis of the historical and current conditions is carried out. Besides the annual, seasonal and daily load characteristics, the sectoral demand conditions are investigated. Finally the chapter features the results of the demand forecast. The market analysis on oil and gas prices is the subject of chapter 6. Procurement and contracting options are explained within the first part. The second part of the chapter deals with pricing issues regarding the fuels (potentially) supplied to Malta. Finally, chapter 7 provides a market analysis on electricity supplies from Continental Europe to the islands of Malta. The chapter contains two main elements. Initially a description of the power generation and supply system and its adequacy is assessed. In addition the current and expected future electricity price levels are assessed. 0.2 Definitions and Terms Throughout this report the following definitions and terms apply if not expressly stated otherwise: Fiscal year: The fiscal year n starts in the month October in the year n-1 and ends in the month September in the year n. Calorific value: The energy content of an energy carrier is quantified using the net calorific value (NCV, also denoted as low heating value). Net capacity, net generation: Parameters or indicators are expressed in terms of, or related to, net generating capacity or net generation (at sent-out level) where applicable. Currency: Euro - the official currency of the Euro Zone (banking code: EUR) Exchange rate (2007; source: Olsen and Associates / Oanda): 1 MTL = 2.34 EUR 1 USD = 0.75 EUR Discount rate, interest rate: A rate of 6.5 %/a is applied. LI Page 0-1

16 0.3 Data Collection During the conduction of Work Package I the following data and documents were collected: # Document title Received from Date 1 Map and drawings including details of the existing primary storage facilities P. Borg Enemalta - Annual Report and Financial Statements (year 2001) P. Borg Enemalta - Annual Report and Financial Statements (year 2002) P. Borg Enemalta - Annual Report (year 2002) and Financial Statements (year 2001) P. Borg Enemalta - Annual Report and Financial Statements (year 2003) P. Borg Enemalta - Annual Report (year 2003) and Financial Statements (year 2002) P. Borg Enemalta - Annual Report (year 2004) and Financial Statements (year 2003) P. Borg Enemalta - Annual Report (year 2005) and Financial Statements (year 2004) P. Borg Enemalta - Annual Report (year 2006) and Financial Statements (year 2005) P. Borg Summary of Electricity Tariffs applicable to supply Final Customers by Enemalta Corporation (March to May 2007) P. Borg John Gault SA Report: Natural Gas Pipeline Project. Potential gas acquisition strategies (2004) P. Borg Table 0-1: Data and Documents Collected (1/8) LI Page 0-2

17 # Document title Received from Date 12 Malta Gas Project: Feasibility study evaluation (2003) P. Borg Enemalta - Long-term plan for the High Voltage Network ( ) P. Borg Set of maps and drawings of the existing and proposed Maltese Distribution Grid ( ) P. Borg Overview of fuel types and consumption ( ); Sales Figures for LPG and Propan ( ), Fuel Storage Facilities (2007) P. Borg Compilation of generation and consumption figures including customer break downs ( ) P. Borg Calculation of SO2 and NOX emission figures ( ) P. Borg Set of load characteristics: Load Sent-Out Level (2005), Peak load per month ( ) Set of generation figures: Monthly power generation and fuel consumption by plant ( ), Annual power generation ( ); Annual power generation by unit ( ) P. Borg P. Borg GHG Emissions Report DPS (2005), GHG Emissions Report MPS (2005) P. Borg Enemalta - Electricity Generation Plan ( ) P. Borg Petroleum Storage Legislation (1955) (S.L ) P. Borg Maintenance of Supplies of Essential Commodities Regulations (1957) (S.L ) P. Borg Clean Air Act (1968, 1969) ( (CAP. 200.) P. Borg Table 0-1: Data and Documents Collected (2/8) LI Page 0-3

18 # Document title Received from Date 25 Petroleum (Importation, Storage and Sale) Ordinance (1889) (CAP. 25.) P. Borg Enemalta Act (1977, 1978) (CAP. 272.) P. Borg Development Planning Act (1992) (CAP. 356.) P. Borg Excise Duty Act (1995) (CAP. 382.) P. Borg Malta Resources Authority Act (2001) (CAP. 423.) P. Borg Environment Protection Act (2001, 2002, 2005) (CAP. 435.) P. Borg Utilities and Services (Regulation of Certain Works) Act (1934) (CAP. 81) P. Borg Electricity Supply Regulations and Rules 1939 P. Borg Grant on the Purchase of Household Appliances for Domestic Use Certified as Being Efficient in the Use and Consumption of Energy (2006) (GN 1026) Environment Protection Act, Control of Volatile Organic Compound Emissions (Storage and Distribution of Petrol from Terminals to Service Stations) Regulations (2001) (L.N. 214) Environment Protection Act, National Emission Ceilings for Certain Atmospheric Pollutants Regulations (2002) (L.N. 291) P. Borg P. Borg P. Borg Electricity Supply Amendment (No. 4) Regulations (2006) (L.N. 138) P. Borg Environment Protection Act XX (2001) (L.N. 165) P. Borg Table 0-1: Data and Documents Collected (3/8) LI Page 0-4

19 # Document title Received from Date 38 Petroleum (Importation, Storage and Sale) Legal Notice 53, The Petroleum Ships Regulations (1965) P. Borg Petroleum (Importation, Storage and Sale) Legal Notice 54, Petroleum Ships (Extension) Order (1965) P. Borg Enemalta Act (Act No. XVI) (1977) (L.N. 12) P. Borg Enemalta Act, Electricity Supply (Amendment) Regulations (CAP.272) (1999) (L.N. 27) Malta Resources Authority Act (2000) (Act No. XXV of 2000), Crude Oil and Petroleum Products (Minimum Security Stocks and Crisis Management) Regulations(2002) (L.N. 237) Malta Resources Authority Act (CAP. 423), Promotion of Electricity produced from Renewable Energy Sources Regulations (2004) (L.N. 186) Environment Protection Act (CAP. 435), Integrated Pollution Prevention and Control (Amendment) Regulations (2004) (L.N. 230) P. Borg P. Borg P. Borg P. Borg Environment Protection Act (Act No. XX of 2001), Limit Values for Nitrogen Dioxide, Sulphur Dioxide and Oxides of Nitrogen, Particulated Matter and Lead in Ambient Air (Amendment) Regulations (2004) (L.N. 231) P. Borg Environment Protection Act (Act No. XX of 2001), National Emission Ceilings P. Borg for Certain Atmospheric Pollutants (Amendment) Regulations (2004) (L.N. 232) 47 Environment Protection Act (Act No. XX of 2001), Ambient Air Quality Assessment and Management (Amendment) Regulations (2004) (L.N. 235) P. Borg Malta Resources Authority Act (Act No. XXV of 2000), Electricity Regulation (2004) (L.N. 511) P. Borg Malta Resources Authority Act (CAP. 423), Use of Biofuels or Other Renewable Fuels for Transport Regulations (2004) (L.N. 528) P. Borg Enemalta Act (CAP. 272), Electricity Supply (Amendment) Regulations (2005) (L.N. 132) P. Borg Table 0-1: Data and Documents Collected (4/8) LI Page 0-5

20 # Document title Received from Date 44 Environment Protection Act (CAP 435) Integrated Pollution Prevention and Environment Protection Act (CAP. 435), European Community Greenhouse PBorg Gas Emissions Trading Scheme Regulations (2005) (L.N. 140) P. Borg Enemalta Act (CAP. 272), Electricity Supply (Amendment) (No. 6) Regulations (2006) (L.N. 236) P. Borg Enemalta Act (CAP. 272), Electricity Supply (Amendment) (No. 2) Regulations (2006) (L.N. 37) P. Borg Enemalta Act (CAP. 272), Electricity Supply (Amendment) (No. 3) Regulations (2006) (L.N. 109) P. Borg Enemalta Act (CAP. 272), Electricity Supply (Amendment) Regulations (2007) (L.N. 12) P. Borg Malta Resources Authority Act (CAP. 423), Electricty (Amendment) Regulations, 2007 (L.N. 17) P. Borg Malta Resources Authority Act (CAP. 423), Cogeneration Regulations (2007) (L.N. 2) P. Borg Background Information on the Malta Resources Authority (MRA) (2007) P. Borg Strategy for Renewable Electricity Exploitation in Malta - Volume 1: Renewable Electricity Target - Final Report (Mott MacDonald, 2005) P. Borg Strategy for Renewable Electricity Exploitation in Malta - Volume 2: Policy Options Review - Draft Final Report (Mott MacDonald, 2005) P. Borg Generation Units' utilisation (2006) P. Borg Summary of the existing Primary Storage Facilities P. Borg Compilation of Generation Units' Heat Rates P. Borg Table 0-1: Data and Documents Collected (5/8) LI Page 0-6

21 # Document title Received from Date Environment Protection Act (CAP 435) Integrated European Community Pollution Prevention Greenhouse and P Borg National Allocation Plan for Malta ( ) P. Borg EU Decision - granting Malta a derogation from certain provisions of Directive 2003/54/EC (2006) P. Borg Schematic Diagram of Malta's Transmission and Distribution System (2007) P. Borg Profit and Loss Account schedules ( ) P. Borg Environment Protection Act (Act No. XX of 2001) Pollution Caused by Certain Dangerous Substances Discharged Into the Aquatic Environment Regulations (2001) (L.N. 213) Environment Protection Act (Act No. XX of 2001) Limitations of Emissions of Certain Pollutants into the Air from Large Combustion Plants Regulations (2002) (L.N. 329) Presentation "Large Scale Integration of Wind Energy - Wind Energy and Grid Development: The Italian Case", Terna (2006) P. Borg P. Borg P. Borg Review of Fuel Surcharge Mechanism, Deloitte (2006) P. Borg Self Consumption of generation units (montly ) P. Borg Schematic Diagram of the Marsa Power Station (MPS) Mr. Gauci Actual Data and Explanations of the Operation of the DPS; including: (i) Maximum and Minimum Operating Capacity (taking into account derated capacity during summer months); (ii) Allowance of Units' Start-ups; (iii) Forced Outage Rate; (iv) Scheduled Maintenance; (v) Expected Technical Lifetime and Year of Retirement; (vi) Degradation of Units' Net Efficiency; (vii) Fuel Specifications. Mr. Drago Table 0-1: Data and Documents Collected (6/8) LI Page 0-7

22 # Document title Received from Date Environment Protection Act (CAP 435) Integrated European Community Pollution Prevention Greenhouse and P Borg Net Calorific Values of the Fuels applied in the MPS and DPS (Average for Batches during 2006) Dr. Vassallo Actual Data and Explanations of the Operation of the MPS; including: (i) Maximum and Minimum Operating Capacity (taking into account derated capacity during summer months); (ii) Allowance of Units' Start-ups; (iii) Forced Outage Rate; (iv) Scheduled Maintenance; (v) Expected Technical Lifetime and Year of Retirement; (vi) Degradation of Units' Net Efficiency; (vii) Fuel Specifications. Mr. Gauci Malta - Sicily Interconnection Pre-FS (1995), EDF P. Borg Water Depth Charts for the area around DPS and MPS P. Borg National Greenhouse Gas Emissions Inventory for Malta P. Borg Press Article on "Green Leaders appointed in Ministries" (published on Government of Malta website, date of issue not revealed, (approx. 2005)) P. Borg A Sustainable Development Strategy for the Maltese Islands, , Third Draft, National Commission for Sustainable Development (2006) P. Borg A Draft Renewable Energy Policy for Malta (2006) P. Borg Malta - Renewable Energy Fact Sheet (2007) P. Borg Platts current fuel prices (2007) P. Borg Enemalta's financial and economic data (2006, 2007e) J. Pandolfino Table 0-1: Data and Documents Collected (7/8) LI Page 0-8

23 # Document title Received from Date 44 Environment Protection Act (CAP 435) Integrated Pollution Prevention and PBorg Climate Data: Temperature, Rainfall and Sunshine ( ) P. Borg Fuel price development (platts data) (Oct 2005 to Jun 2007) P. Borg Information on Inverter locations, line routing and possible landing point for the HVDC interconnector P. Borg Individual generation figures ST MPS ( ) and current turbine and boiler efficiencies (2006) P. Borg Table 0-1: Data and Documents Collected (8/8) LI Page 0-9

24 1 Overview on HVDC Cable Interconnection Projects Enemalta, the Maltese power utility and Terna, operator of the power system in Sicily envisage the interconnection of their electricity systems through a submarine DC cable. The link will be connected to the existing 132 kv grid in Malta at Kappara Substation, presently under construction, from where two 132 kv underground cables of about 3 km will be laid to the new Converter Station, which is the terminal point in Malta. Its tentative site will be located about 400 m from the seashore, north of Pembroke. The submarine cable length will amount to approximately 100 km and the distance on land from the sea shore to Ragusa 225 KV Substation, the Terminal Point in Sicily is estimated at 20 km, the exact arrangement and location of the converter station are still to be determined. In Ragusa the converter station will provide the connection to the European interconnected power system. The interconnection shall be designed for a transfer capacity of about 200 MW with one cable or two submarine cables for the DC link. The transfer capacity of 200 MW will be used for the present screening of options, so that different technologies can be compared. At a later stage, the study will evaluate the most feasible transfer capacity. Recently, the submarine fibre-optique cable Italy Malta was laid from St. George Bay in Malta to Catania, Italy. The first 110 km in north-western direction run on the Malta plateau with water depth not exceeding around 110 m. For the more northern direction towards Ragusa, terminal point of the DC link, this depth will probably not be exceeded. In this section mainly sand was encountered at the seabed. Presently, documentation about currents of the sea between Malta and Sicily is not available but preliminary general information showed that remarkable currents do not prevail. Later studies have to confirm the prevailing sea currents. The Malta Gas Report-Feasibility Study, prepared in 2003 indicated that sea water temperature in the coastal region down to 25 m reaches 25 C in summer. At depths between 25 to 150 m, 25 C to 13.7 C are recorded linearly decreasing and below 150 m, constant 13.7 C are measured. 1.1 Description of Worldwide Submarine DC Links Worldwide, various submarine DC links are existing or are under construction that can be compared with the planned Malta Sicily DC submarine cable interconnection. LI Page 1-10

25 The following DC submarine cable projects were commissioned during the past forty years: Domestic links: o 260 kv / 280 kv bipolar link Vancouver Island Canada; o 250 kv mono-polar link Hokkaido Honshu Japan; o 150 kv bi-polar link Sweden Gotland 2 o 150 kv bi-polar link Sweden Gotland 3 o 285 kv bi-polar link Konti Scan 2; o kv bi-polar link New Zealand North South Island; o 350 kv mono-polar link Leyte Luzon Philippines; o 250 kv bi-polar link Kii Channel Japan; o +150 kv bi-polar link Cross Sound Cable USA; o 400 kv mono-polar link Basslink Australia. Bi-national links: o 400 kv mono-polar link Fenno Skan 2 (Finland Sweden); o 200 kv bi-polar link Italy Corsica Sardinia; o 350 kv mono-polar link Skagerak 3 (Norway Denmark); o 450 kv mono-polar link Baltic Cable (Germany Sweden); o 400 kv mono-polar link Kontec (Danmark Germany); o 450 kv mono-polar link Swe Pol Link (Sweden Poland); o kv bi-polar link Cross Channel (England France); o 250 kv mono-polar link Moyle (Scotland North Ireland); o 400 kv mono-polar link Italy Greece; o kv bi-polar link Estlink (Estonia Finland); o kv bi-polar link Nor Ned Cable (Norway The Netherlands). The table shows that the different submarine DC systems vary concerning the mode of operation in mono polar and bipolar systems, in respect of transmitted power reaching up to 2,000 MW and regarding the cable length with a maximum value of 580 km. LI Page 1-11

26 For the Malta Sicily interconnection the experience of various implemented projects having similar size with about 100 km length of the interconnection and around 200 MW of power transfer can be used. 1.2 Submarine DC Links similar to the envisaged Italy-Malta Interconnection Five systems are of particular interest, namely: Sweden Gotland 3 Italy Corsica Sardinia Moyle (Scotland North Ireland Cross Sound Cable USA Estlink (Estonia Finland) Each project was designed according to the specific local requirements. In the following, some key features are extracted for the five links, however the depth of information on the technical parameters varies among the projects. The described projects also provide a review through DC submarine cable technique from the 1954 mercury valves with paper impregnated oil cables to today s tyristor controlled valves and XLPE cables Sweden Gotland 3 The high voltage direct current (HVDC) Gotland, on the Swedish east coast was the first HVDC fully commercial static plant for transmission in the world. The first Gotland link (Gotland 1) went into service in It could transfer 20 MW over a 98 km long submarine cable between Västervik on the mainland and Ygne on the Island of Gotland, with a voltage of 100 kv. As a static inverter, mercury arc valves were used. In 1970 the service was re-engineered to transmission capacity of 30 MW at a voltage of 150 kv by using the first thyristor module for HVDC applications. However, even this capacity was not high enough and in 1983 a new link, HVDC Gotland 2 (transmission capacity: 130 MW, transmission voltage: 150 kv, cable length 92.9 km, 6.6 km overhead line) as well as HVDC Gotland 3 (transmission capacity: 130 MW, transmission voltage: 150 kv, cable length of 98 km) in 1987 were built. The latter made HVDC Gotland 1 redundant and led to its deactivation and disassembly. LI Page 1-12

27 1.2.2 Italy Corsica Sardinia The HVDC Italy-Corsica-Sardinia (also called SACOI; Sardinia-Corsica-Italy) is used for the exchange of electric energy between the static inverter plant Suvereto on the Italian mainland, the static inverter plant Lucciana on Corsica and the static inverter plant Codrongianos on Sardinia. First used in 1965 as mono-polar line, today this takes the form of a bi-polar HVDC line. It consists of three overhead line sections: one on the Italian mainland with a length of 50 km, one on Corsica with a length of 167 km and one on Sardinia with a length of 87 km. In addition to this, there are two submarine cable sections: 103 km (between Italy and Corsica) and 15 km (between Sardinia and Corsica). Static inverters for this line, which can transfer a maximum power of 200 MW at a voltage of 200 kv are in use today. Until the 1990s mercury vapor rectifiers were used, which have now been replaced by thyristors. In 1992 a second pole was taken in service, which can transfer 300 MW at a voltage of 200 kv. In contrast to most other installations for high voltage direct current transmission this system is a multipoint system making thus possible the energy exchange between several static inverter stations. Worldwide only few multipoints exist, since the control and protection system is very complex. Each of the two bi-polar 200 kv cables has a cross-section of 420 mm² cupper for a nominal current of 750 A Moyle (Scotland North Ireland) The Moyle Interconnector links the Northern Irish and Scottish electricity grids, through a submarine cable running from Ballycronan More in Islandmagee, County Antrim, North Ireland to Auchencrosh in Ayrshire, Scotland. The interconnector has a capacity of up to 500 MW, approximately the same as that of modern medium sized power station. The Moyle Interconnector consists of (i) two monopole 250 kv, 1,000 A DC circuits, submarine cable length 55 km, underground cable length 8.5 km and (ii) two converter stations located at Ballycronan More, Co. Antrim and Auchencrosh. Each of the two cable connecting the converter stations is a 250 kv DC mass impregnated cable with integrated return conductor. The main copper conductor is 1000 mm² and can carry 1,000 A. The cable is approximately 114 mm in diameter and also contains a fine stainless steel tube carrying optical fibres which allow control and communication between the converter stations and between the control centres in Northern Ireland and Scotland. The cable system is of the Integrated Return Conductor type (IRC), where the return cable is integrated into the HVDC cable, i.e. a metallic coaxial layer integrated in the cable forms the return path for the current. Applying the return conductor concentrically around the main LI Page 1-13

28 conductor outside the lead sheath, satisfies several major goals: the core is a conventional mass-impregnated cable core, the return conductor insulation may be of different material than the main insulation, there is no external magnetic field, the laying properties are as for a conventional cable and the return conductor is also part of the armouring. The losses of the cable amount to 36 kw/km at full load (1,000 A). The advantages of interconnection are savings of peak demand capacity and of fuel by energy trading, improved security of supply and system reserve management. The interconnector facilities electricity trading and competition over the power system in the UK and Ireland and with a fully rated interconnector capacity of 500 MW, it is of major significance for both transmission systems. Details of the Converter Station: Transformers 12 single phase 3 windings + 1 common spare HVDC valves Light-triggered thyristors AC-filter DC reactor 39 thyristors/valve, 2 redundant All rated 59 Mvar, triple- and single- tuned 200 mh 1000 A Cross Sound Cable USA The Cross Sound Cable is a 40 km long bipolar high-voltage direct current (HVDC) submarine power cable between the 345 kv power system of New Haven, Connecticut, USA and that of the 138 kv of Shoreham, Long Island New York, USA. The Cross Sound Cable is an oil free extruded cable and can transmit a maximum power of 330 MW at a voltage of +150 kv. The maximum current for Cross Sound Cable is 1,175 A. The Cross-Sound Cable consists of two power cables each of 1,300 mm² cupper and one fibre optic cable that are bundled together. The cable consists of steel armour and solid flexible plastic to protect and insulate the copper wire. It measures 10.5 cm in diameter and contains no insulating and/or cooling fluids. Construction of the Cross Sound Cable was started in The cable was first laid on the floor of Long Island Sound; then a jet plow used high-pressure water to fluidize the sea bed directly under the cable. The cable then fell into the liquidized trench. Concern over possible environmental impact of the buried underwater cables caused significant delay in operation. Commercial operation of the cable was delayed until after the August 14 th, 2003 blackout of much of the eastern North American power system. Immediately after the LI Page 1-14

29 blackout, emergency permission was secured to operate the cable. The cable has since then been operating Power can flow in either direction between New Haven and Shoreham terminals and, generally, sells electricity from the New England power grid to the New York power grid Estlink (Estonia Finland) The Estlink is a HVDC submarine cable between Estonia and Finland. The link was taken into service on 4 December It is the first interconnection between the Baltic and Nordic electricity markets. The Estlink is operated by the Nordic Energy Link company, founded by Baltic and Finnish power companies. The main shareholder is Eesti Energia with 39.9% of the shares, Latvenergo and Lietuvos Energija have 25% each, and the remaining 10.1% are divided between Pohjolan Voima and Helsingin Energia.The main purpose of the Estlink connection is to sell electricity produced in the Baltic to the Nordic electricity market, and to secure power supply in both regions. The Estlink cable is connected to the Estonian electrical system at the Harku 330 kv converter station and to the Finnish transmission network at Espoo 400 kv converter station. Estlink is designed as a bidirectional ±150 kv, 350 MW HVDC system, which consists of two voltagesource AC-DC converter (VSC) stations and two 105 km HVDC cross-linked polyethylene (XLPE)-insulated cables, of which 74 km is submarine cable that was buried in the seabed. The 150 kv cable for the land section, 22 km in Finland and 9 km in Estonia, has 2,000 mm² aluminium conductors and the submarine cable section uses 1,000 mm² copper conductors The cable's maximum depth on the seabed of the Gulf of Finland is 100 m. Two identical converter stations are connected to the networks in Harku and Espoo via 400 MVA 3-phase power transformers at each substation. The converter equipment is housed in a building to provide protection from the weather, and serves as an electromagnetic and audible noise shield. The ±150-kV XLPE-insulated cable system connecting the converters is an integral part of the HVDC light technology. The design of each converter station is based on a six-valve converter bridge, equipped with semiconductor valves consisting of several series-connected insulated gate bipolar transistor (IGBT) units. Each unit has 24 IGBT and 12 diode chips connected in parallel. A capacitor bank on the DC side of the converter bridge provides a low-inductance path for the turnoff current and energy storage. The midpoint-grounded capacitor is built up of capacitor units of a dry, selfhealing metallised-film design. The converter's two-level topology means that, by turning the valve transistors on and off, the AC output voltage is switched between +150 kv and -150 kv. Estlink uses pulse width modulation (PWM) with special functions for harmonic cancellation, a LI Page 1-15

30 valve switching method called optimal PWM. Each valve is switched 23 times per 50-Hz cycle, thus the pulse number is 23. The AC side of the converter bridge is connected to a series reactor, the converter reactor, providing low-pass filtering of the PWM pattern to give the desired fundamental frequency voltage. The power flow between the AC and DC side is defined by the fundamental voltage across the reactor, and by using the phase shift and amplitude of this voltage to vary the PWM pattern, the active and reactive power can be controlled independently. The converter reactor, one for each phase, is a large air-cooled, air-core reactor with a magnetic shield around it to eliminate magnetic fields outside the reactor. To ensure power quality, the harmonics created by the VSC converter are on the AC side filtered by two AC shunt filters, connected on the 195-kV bus between the converter reactor and the power transformer. These filters are tuned to the 32 nd and 60 th harmonics, thus short circuiting the major AC harmonics created with optimal PWM switching at pulse number 23. The optimal PWM switching method cancels characteristics harmonics lower than the 31 st harmonic. On the DC side, the DC capacitor and smoothing reactors, in series with each pole cable, suppress DC-side harmonics. LI Page 1-16

31 2 Technology Screening on Submarine HVDC Cables 2.1 Introduction Three types of submarine power cable can be considered for high-voltage direct current (HVDC) operation, namely: 1. Self-contained, fluid-filled cables (SCFF cables); 2. Mass-impregnated cables (MI cables); 3. Cross-linked polyethylene cables (XLPE cables). SCFF and MI cables have insulation consisting of paper tapes impregnated with an oil-based compound but are distinguished by the type of impregnant and by the requirement of a fluid pressurizing system. In the case of the SCFF cables the impregnant is a low-viscosity synthetic oil - an alkylbenzene - which is maintained under pressure by oil-pumping stations placed at one or both cable ends. MI cables, on the other hand, employ a high viscosity fluid which is not subject to drainage at the maximum design temperature of 50 to 55 o C and hence these cables do not require fluid pressurization. Both HVDC SCFF and MI cables have a long service history and proven reliability in service. Until recently XLPE insulation has not been used for HVDC applications, because its very high electrical resistivity - which helps make it a good material for AC operation - causes space charge accumulation under direct voltage that limits the polarity reversal that is required for twoway power flow. Until recently the HVDC systems used the well-proven Line Commutated Converters (LCC). The more conventional LCC technology can be implemented as a bi-pole, i.e. in the event of a major component loss, the system can operate as a mono-pole at 50% power, provided the earth return is ensured. ABB introduced its HVDC Light system in 1998 (Asplund et. al. 1998). This system employs a new converter technology designated Voltage Source Converter (VSC) based on Insulated Gate Bipolar Transistors (IGBT) transistors which permits the power flow to be controlled without the need for polarity reversals. In addition, the converter stations can be operated with networks with small capacity of short-circuit power. At the same time conventional XLPE insulation was replaced with a modified XLPE to render it less susceptible to the effects of space charges (Carstensen et. al. 1999). Siemens introduced the VSC systems under the brand name HVDC PLUS. LI Page 2-1

32 Table 2-1 summarizes the majority of important HVDC submarine cable links either in service or under construction worldwide at the present time and specifies the type of cable used for the interconnection. As can be seen, by referring to this table, the total installed cable length is in the order of 3,000 km and the total service experience can be summarized as approximately 52,000 km years. Other significant conclusions include the following: MI cables account for approximately 80 % of the entire installed cable length; SCFF cables are only used for relatively short routes (a few 10s of km). This is due to problems of maintaining positive oil pressure at locations remote from the land-based pumping stations; The state of the art in long-length MI cable technology is the 450 kv, 253 km Sweden to Poland link in the Baltic Sea. In terms of water depth (not indicated in the table) the world record of DC cables is currently held by the Italy-Greece MI cable at a maximum water depth of 1,000 m; The 150 kv, 330 MW Cross Sound (USA) cable system is the first submarine cable system to operated with the relatively new voltage source control (VSC) converter technology introduced by ABB. Flexible splices are also the state of the art for XLPE cables; The KII Channel submarine cable link between the Japanese Islands of Honshu and Shikoku employs four 500 kv SCFF cables. The route length of 50 km is a world record for SCFF cables. 2.2 HVDC Submarine Cable Installation Configurations: Monopole and Bipole As already indicated in the previous Section SCFF cables must be excluded for the Malta - Sicily submarine cable link because of the marine route length of about 100 km plus line route on Sicily. The choice of suitable cable types reduced therefore to two; HVDC MI cable or HVDC XLPE cable. It is clear from Table 2-1 that the HVDC MI submarine cable has seen extensive service over many years and has a proven reliability in service with very few faults due to internal defects, almost all failures being due to third party marine activities. Because of this burial along the entire cable route is now a de facto standard. On the other hand there is limited experience with HVDC Light Converters combined with XLPE submarine cables with only two links in the service. The first of these, the Cross Sound cable was installed in However the total service experience with both underground and submarine cables has been good with 660 km of 150 kv DC cable in service with a total service experience of 2,500 km years with no reported service failures. In view of this satisfactory experience both MI and HVDC cable types will be given further consideration. LI Page 2-2

33 HVDC Interconnection Date Voltage (kv) Power (MW) Length (km) Cable Type Hokkaido-Honshu (Japan) x 42 SCFF Fenno-Skan (Swe-Finland) MI Cook Strait 2 (N. Zealand) x 40 MI Skagerrak 3 (Nor-Den) MI Baltic Cable (Swe-Ger) MI Swepol (Swe Pol) MI KII Channel (Japan) x 49 SCFF Moyle (UK) x 55 MI Italy - Greece MI Cross Sound (USA) x 42 XLPE BassLink (Australia) MI Estlink (Estonia-Finland) x 75 XLPE Neptune (USA) MI Norned (Nor-Netherlands) x MI Sapei (Sardinia-Italy) x MI Britned (UK-Netherlands) x MI Table 2-1: Listing of many of the World s Major DC Submarine Cable Links Although there are only two suitable HVDC submarine cable types, consideration must be given to the installation configuration and to the need to cater for the ground/sea return current as follows: HVDC transmission can be either monopolar or bipolar. In the bipolar case, the two poles operate at equal and opposite polarities, and the current circulates around the bipolar circuit. Therefore there is no need for the provision of a separate return current path (unless the two cable poles are installed along two separate marine routes and monopolar operation is planned LI Page 2-3

34 in case of the failure of one of the cables). In monopolar operation, on the other hand, a return path is required. This can be provided in at least three different ways: Ground/sea return via an anode-cathode electrode system; Separate cable referred to as a metallic return cable; A return conductor integrated into the HVDC cable. The various configurations in use are illustrated in the sketch presented in Figure 2-1. Ground/sea return systems have been used extensively since the 1950s and continue to be used. A recent example of the use of such a system is the 2001 Italy-Greece 400 kvdc, 500 MW Interconnection. Two sea electrodes are used. The anode consists of 39 bars of titanium and is located near Greece in the Corfu Strait, while the cathode is a bare copper ring located in Italy near Cape Otranto (Giorgi et. al. 2002). Figure 2-1: Various HVDC Submarine Cable Installation Configurations LI Page 2-4

35 In the last few years concern (probably unwarranted) about possible electrolytic corrosion of subsea steel structures and adverse environmental effects on fish and fauna have meant that, in some cases, ground/sea return paths are no longer accepted. For example, the Neptune Project in the USA and the BassLink Project in Australia both employ separate metallic return cables. Monopolar transmission is more cost effective than bipolar at most power transmission levels at least up to 600 MW (Giorgi et. al. 2002). This was probably the reason why N. Ireland Electricity opted for the installation of two monopoles rather than a single bipole for their Moyle Project a 250 kvdc, 500 MW link between Scotland and N. Ireland. This project is also of interest since it was the first application of an HVDC submarine cable with an integrated metallic conductor. This cable type employed for the Moyle Project is referred to as an HVDC MI-IRC (Integrated Metallic Return) submarine cable (Balog and Evenset. 2002). Figure 2-2 shows the construction of and HVDC MI-IRC Submarine cable. Figure 2-2: Construction of an HVDC-IRC submarine cable showing the concentric copper return conductor and steel wire armour LI Page 2-5

36 Figure 2-3: Details of the Estlink HVDC Light Project All of the installation configurations described above can be considered with conventional converter technology. However, in the case of VSC technology only bipolar transmission is possible, the converter do not operate in mono-polar mode. Figure 2-3 provides details of the Estlink HVDC Light Scheme. 2.3 HVDC Submarine Cable Design Study In this Section of the present report various provisional HVDC submarine cable designs have been developed specifically for the proposed Malta-Sicily Project. The target characteristics and the design parameters employed for a nominal power transfer of 200 MW are as follows: Main Electrical Characteristics Nominal Voltage U o : Maximum Voltage: Lightning Impulse Voltage: Nominal Rated Power: kvdc 1.05 U o 2.7 U o 200 MW LI Page 2-6

37 2.3.2 Installation Data Submarine route length: Land route length: Maximum Water depth: 100 km 20 km less than 200 m Environmental and Permissible Operating Conditions Maximum ambient temperature: 25 o C (at cable burial depth) Burial depth for thermal design: 1.5 m Thermal resistivity of soil/seabed: 1.0 K.m/W Maximum operating temperatures: 55 o C (MI cable) Maximum operating temperatures: 65 o C (XLPE cable) Maximum DC stress: 30 kv/mm (MI cable) Maximum DC stress: 40 kv/mm (XLPE cable) Maximum impulse stress: 80 kv/mm (MI cable) Maximum impulse stress: 55 kv/mm (XLPE cable) The basic HVDC submarine cable construction employed throughout is shown in Figure 2-4. This is a single wire armoured type suitable for water depths up to ~200 m. For deep water applications an anti-torsion double wire armour as shown in Figure 2-1 will be required. However, the addition of another armour wire layer will have only a minor effect on the delivered power though there will of course be an increase in cable mass. The increase in cable mass can be minimized by using flat steel strip instead of round wire. Conductor Insulation Lead Sheath Steel Tape Reinforcement Polythene Jacket Steel Armour Wire Figure 2-4: Cross Section of a Typical HVDC Submarine Cable LI Page 2-7

38 2.3.4 HVDC Cable Designs HVDC MI Monopole with Remote Return (ground/sea electrodes) Voltage: 250 kvdc Delivered Power: 202 MW Losses: 2.6 MW DC stress: 23 kv/mm Impulse stress: 78 kv/mm Conductor size: 630 mm 2 (copper) Cable diameter: 94 mm Cable mass: 28 kg/m HVDC MI Monopole Bundled with a Metallic Return Cable Voltage: 250 kvdc Delivered Power: 200 MW Losses: 4.0 MW DC stress: 25 kv/mm Impulse stress: 80 kv/mm Conductor size: 800 mm 2 (copper) Cable diameter: 95 mm Cable mass: 29 kg/m HVDC MI Monopole with Integral Return Conductor Voltage: 250 kvdc Delivered Power: 201 MW Losses: 3.0 MW DC stress: 25 kv/mm Impulse stress: 77 kv/mm Conductor size: 1200 mm 2 (copper) Cable diameter: 115 mm Cable mass: 41 kg/m HVDC MI Bipole with Cables Bundled Voltage: Delivered Power: Losses: DC stress: Impulse stress: Conductor size: 150 kvdc 202 MW 4.0 MW 18 kv/mm 64 kv/mm 630 mm 2 (copper) LI Page 2-8

39 Cable diameter: Cable mass: 87 mm 25 kg/m HVDC Light Bipole with XLPE Cables Bundled Voltage: 150 kvdc (possible up to 200 kvdc) Delivered Power: 200 MW Losses: 3.5 MW DC stress: 13 kv/mm Impulse stress: 55 kv/mm Conductor size: 630 mm 2 (copper) Cable diameter: 91 mm Cable mass: 26 kg/m General Features From a technical point of view all of the above designs are considered to be feasible for the proposed Sicily-Malta Project. Favourable configurations with high availability are: LCC converters with 2 parallel special MI cables with integrated return conductor (refer to Moyle); VSC converters with 4 parallel XLPE cables. ABB have provided the following converter construction schedules (Rudervall et. al., 2000) Natural commutated HVDC: 3 years CCC based HVDC: 2 years VSC based HVDC: 2 years Three other factors which need to be taken into account when making a final selection of the HVDC technology for the Project are the following: HVDC MI submarine cable suppliers are extremely busy with large scale HVDC projects whereas extrusion lines have capacity. Prysmian has also developed HVDC modified XLPE cables which are type approved and which have undergone long term testing. Siemens are also able to offer VSC technology under the brand name HVDC PLUS. Relative cost information from the cable industry were collected on the alternatives detailed above. The relative costs for the entire supply and install projects including cables and converters in the order of least to most expensive are as follows: LI Page 2-9

40 1. Monopole with ground/sea return electrodes (least expensive) 2. HVDC Light or HVDC Plus 3. Monopole with metallic return cable 4. HVDC cable with integral return 5. Conventional Bipole (most expensive) 2.4 Ancillary Equipment Issues Optical Fibre Control Cable According to information recently received from Nexans optical fibre specialists and Prysmian s Chief Engineer a submarine optical cable for control and communication would require at least one repeater in the case of a total route length of 120 km. On the other hand, the Basslink HVDC system with approximately 290 km submarine cable is in operation without any repeater for the optical fibre cables in the bundle. This link is in operation since April Submarine repeaters are designed for low power operation in order to maximise the mean time before failure. On land where repeaters are accessible and easily replaced if required, it is possible to have repeater spacing in the order of 400 km. Because of this both Nexans and Prysmian recommend that the optical cable be laid in a separate campaign and widely separated from the power cables. Three times the maximum water depth is recommended as necessary in case of repair. This allows the necessary extra cable length, which is laid as a bight, to be laid without overlap of the nearest neighbour cable Temperature Measurement Temperature measurement using optical fibre sensors (DTS) is limited to a range in the order of 30 km. In this case temperature monitoring would only be possible at the inshore ends of the cable route. However, since the high ambient temperatures are also expected to be found in these locations it is recommended that such temperature monitoring be planned for. Optical fibres can be placed in a laser-welded stainless steel tube which can then replace one of the armour wires. Consideration should also be given to a back-up system which could be microwave based or, alternatively, since control information is unlikely to be significant in terms of transmission rates it may be that a dedicated telephone line could be adequate. Expert advice on this will need to be sought in due course. LI Page 2-10

41 2.5 Summary Following a review of the present state-of-the-art in HVDC submarine cable technology, it is concluded that there are two classes of HVDC cable which can be considered to be suitable for a 120 km, 200 MW Sicily-Malta HVDC Interconnection. These are (i) HVDC MI (Mass Impregnated) Cables, and (ii) HVDC XLPE Cables. HVDC MI cables employ an insulation wall consisting of kraft paper tapes impregnated with a high viscosity fluid which is not subject to drainage at the maximum design temperature of o C and hence these cables, unlike oil-filled cables, do not require fluid pressurization. HVDC MI cables have a long service history with over 3,000 km of cable in service and a total service experience greater than 52,000 km years. There have been very few service failures which have not been associated with damages caused by third party marine users. The new converter technology designated Voltage Source Converter (VSC) is based on IGBT transistors which permits the power flow to be controlled without the need for polarity reversals. At the same time conventional XLPE insulation was replaced with a modified XLPE to render it less susceptible to the effects of space charges. Two major HVDC Light submarine cable systems are in service at the present time and no reported service failures. Various installation configurations such bipolar and mono-polar are discussed and provisional submarine cable designs are developed for the following six different installation possibilities, namely: HVDC MI mono-pole with ground/sea return current; HVDC MI mono-pole bundles together with a metallic return cable; HVDC MI mono-pole with integral return conductor; HVDC MI bi-pole with cable bundled together; HVDC XLPE cables with VSC single block; HVDC XLPE cables with parallel VSC blocks. Finally, it is concluded that while all of the above technical solutions are feasible the HVDC Light XLPE solution (also available as HVDC PLUS from a second manufacturer) offers interesting prospects for the Sicily-Malta Interconnection including the following: Lowest overall installed system cost; Shortest construction time; Best availability of supply at the present time. However, it is to mention that VSC technology is not essentially bi-polar, the failure of one converter or cable means the complete loss of power transmission. LI Page 2-11

42 3 Technology Screening on Submarine NG Pipeline Interconnections 3.1 Existing Off-shore Gas Pipelines in the Mediterranean Sea Compared to other part of the World such as the North Sea or the Gulf of Mexico the Mediterranean Sea has only a few off-shore gas pipelines which are mainly interconnection pipelines from on-shore gas fields in Northern Africa (Algeria, Libya) to southern European Markets such as Italy and Spain. Figure 3-1: Overview Map Gas Pipelines in the Mediterranean Sea LI Page 3-12

43 3.1.1 Existing Gas Off-Shore Pipelines in the Mediterranean Sea The first of such interconnection natural gas pipeline was the Trans-Mediterranean Pipeline (TransMed; also Enrico Mattei gas pipeline), which is a natural gas pipeline from Algeria via Tunisia to Sicily and further to mainland of Italy. The first phase of pipeline was constructed in and second phase in The current capacity of pipeline is 24 billion cm³ of natural gas annually. There are plans to expand the capacity up to 33.5 billion cm³ by 2012.The 155 km long offshore section has its landfall in Tunisia at El Haouaria, in the Cap Bon region and consists of 3 lines with diameter of 20 inches and 2 lines with diameter of 26 inches ending inmazara del Vallo in Sicily. The off-shore section is operated by a joint venture of ENI and Sonatrach, TMPC. The TransMed pipeline was laid by Saipem in the Sicilian Channel at a maximum water depth of 610 m which was a record at the time. Saipem developed a new laying vessel (CASTORO 6) especially for this project. In the first phase (1978 to 1983) the diameter of the off-shore section was restricted to 20 inches and during the second phase (1991 to 1994) the diameter of the off-shore section was increased to 26 inches dues to technology advances for the pipeline steel, laying methodology and availability of larger laying vessels. The second interconnection pipeline is the so called Maghreb-Europe Gas Pipeline (MEG) is a 1,450 km long natural gas pipeline, which links the Hassi R'mel field in Algeria via Morocco with gas consumers in Spain. The MEG supplies mainly Spain and Portugal, as well as Morocco with natural gas. The pipeline was commissioned by the End of The annual capacity of the pipeline is 8.6 billion cm³ of natural gas, and the total cost (including on- and off-shore sections) was about 2.3 billion USD. A plan to expand the capacity to 12 billion cm³/a is in progress. The sub sea section (2 x 22 inch lines) of the MEG crosses the Strait of Gibraltar at a max. depth of 400 m and is only 45 km long. The third interconnection line is the so called Greenstream pipeline. It is with a length of about 540 km the longest off-shore pipeline in the Mediterranean Sea and reaches a maximum depth of 1,127 m. Construction of the pipeline begun in summer 2003 and commissioning of the pipeline was in October The off-shore section has a diameter of 32 inches and starts in Mellitah (Libya) to Gela, in Sicily, Italy. Greenstream has a capacity of 8 billion cm³/a. Eni is the operator, with a 50% stake, for the joint development of the fields. The other partner, with an identical stake, is the National Oil Corporation (NOC), the Libyan state-owned oil company. The Greenstream pipeline is supplied from Bahr Essalam offshore field and Wafa field near Algerian border, 530 km from the compressor station in Mellitah. LI Page 3-13

44 3.1.2 Planned Gas Off-Shore Pipelines in the Mediterranean Sea There are several new gas pipeline projects in the Mediterranean Sea in more or less advanced planning phases: MEDGAZ is a proposed off-shore gas pipeline between Algeria and Spain. The pipeline will start from the Hassi R'mel field in Algeria and the first section will run to the port of Beni Saf. The offshore section will start from Beni Saf and the proposed landfall site will be at the Perdigal Beach in the coast of Almería, Spain. The pipeline will connect to the existing Almería-Albacete gas pipeline. MEDGAZ is a consortium of five leading energy companies: Sonatrach (36%), CEPSA (20%), Iberdrola (20%), Endesa (12%) and GDF (12%). The length of Algerian onshore section is 547 km and the offshore section will be around 210 km. The initial capacity of 48-inches onshore and 24-inches offshore pipeline will be 8 billion cm³ of natural gas annually. The maximum water depth is about 2,160 m. Total estimated costs of project are 900 Mio EUR, including 630 Mio EUR for offshore section. The preparation of Medgaz project started already back in The feasibility study was carried out in The EPC contract was awarded in February 2007 and construction works have already started. At present, the pipeline is supposed to be operation by July Updates on construction progress is available on the MEDGAZ website España Algeria Figure 3-2: Routing MEDGAZ Pipeline (source Medgaz.com) LI Page 3-14

45 GALSI is a proposed natural gas pipeline connecting gas fields in Algeria via Sardinia to the Italian mainland (see routing in figure 3.3 below). The pipeline will start from the Hassi R'mel field in Algeria and the 640 km long first section will run to El Kala at the coast of Mediterranean Sea. The 310 km long offshore section will be laid between El Kala and Cagliari, Sardinia. The Sardinian section from Cagliari to Olbia is about 300 km long. The offshore section between Sardinia and the Italian mainland is 280 km. The proposed landfall site will be Castiglione della Pescaia. The Galsi pipeline will connect to the existing Italian gas grid at a point in Tuscany. The offshore sections have a diameter of 22 inches and the onshore section a diameter of 48 inches. The initial capacity of pipeline will be 9 to 10 billion cm³ per annum. The feasibility study was completed in The pipeline is expected to come operational in 2008/09. The company for construction of Galsi was incorporated on 29 January 2003 in Milan. The shareholders of Galsi are Sonatrach (Algeria) 36%; Edison S.p.A. (Italy); Enel (Italy) 13.5% ; Wintershall, the subsidiary of BASF (Germany) 13.5% ; Hera Trading (Italy) 9%; Sfirz (Italy) 5% ; Progemisa (Italy) 12%. Figure 3-3: Routing GALSI Pipeline (Source: Petroleum Economist) LI Page 3-15

46 There are two competing gas interconnector pipeline projects which are in mutually exclusive. The first is the long proposed Greece Italy gas Interconnector (sponsored by Edison) and the second is a interconnection pipeline from Albania to Italy called Trans Adriatic Pipeline (TAP) which is sponsored by EGL. Both pipeline projects have the objective to bring natural gas from the Caspian region into Italy. Figure 3-4 is a preliminary route for the Greece Italy Gas Interconnector. Figure 3-4: Routing Greece Italy Gas Interconnector (Source: Petroleum Economist) Figure 3-5: Routing Trans Adriatic Pipeline (Source: EGL) LI Page 3-16

47 The Trans Adriatic Pipeline brings natural Gas from Azerbaijan (Shah Deniz Gas Condensate Field) via the South Caucasus Pipeline (SCP) into Turkey and on via Greece and Albania to a landfall point in Brindisi Italy (See Figure 3-5). 3.2 General Methodology for Off-Shore Gas Pipelines Sub sea pipeline technology in general and in particular sub sea pipeline laying methodology has dramatically improved over the past 20 years. This is mainly due to the development of much larger pipeline vessels which allow a substantial increase in lift capacity and tension for ever larger pipelines and deeper water. As shown in Figure 3-6 below the maximum water depth for a 20 inch sub sea pipeline was about 600 m in 1984 and it is 2,300 m in Also significant improvements were made in pipe materials steel as well as the internal and external coating systems to protect against corrosion. The major difference in designing onshore and off-shore pipelines is that onshore pipelines have their biggest stress during operation whereas off-shore pipelines have the biggest stress during the actual pipe laying i.e. lowering down to the bottom of the sea. In particular the curvature of the welded pipeline to achieve the close to vertical departure angle from a horizontal welding deck is usually the critical issue during the pipe laying process. Excessive high curvature of the pipeline could lead to overstress and permanent plastic deformation of the pipes which results in increasing strains at the 12 o clock position. Figure 3-6: State of the Art as in 1984 and 2006 LI Page 3-17

48 For pipelines in ever deeper water new pipe laying methodologies had to be developed. Depending on water depth and pipe diameter different laying methodologies have to be applied to minimize the curvature of the pipeline on its way down to the seabed. The schematics in Figure 3-7 show the S-Lay methodology with a horizontal deck (left) and with a horizontal reel (right). The horizontal reel is more time consuming (i.e. more costly) but limits the curvature (i.e. stress) on the pipeline. These pipe laying methodologies are commonly used for water depth of up to 300 to 600 m depending on pipe diameter and pipe materials. For pipe laying in water depth of more than 500 m and larger diameter pipes the so called J-lay method is used to lower the pipeline to the sea bed. The method is so-named because the configuration of the pipe as it is being assembled resembles a J. Lengths of line pipe are joined to each other by welding or other means while supported in a vertical or near vertical position by a tower and, as more pipe lengths are added to the string, the string is lowered to the sea bed or ocean floor. The J-lay method is inherently slower than the S-lay method and is therefore more costly. The J-curve pipe-laying technique represents a logical extension of the industry s capability into deepwater. The J-lay method offers an alternative to the conventional lay barge in that the stinger requirements for deepwater are greatly reduced. The purpose of a stinger in the J-lay configurations is to change the angle at the top of the pipeline to a vertical orientation. The orientation of the pipeline at the surface does not have a large over-bend region and thus results in relatively small horizontal and vertical reactions on the stinger. Figure 3-7: Schematic of S-Lay Methodology with a Horizontal Deck and a Horizontal Reel LI Page 3-18

49 Figure 3-8: Schematic of J-Lay Methodology l The method is attractive as the bending stresses are low, the horizontal force required for station keeping is within the capability of dynamic positioning systems, and the use of modular towers allows derrick barges and moderately sized support vessels to be equipped for pipeline installations. Figure 3-8 above shows a typical J-lay arrangement for deep and ultra deep pipe lay applications.the figures below presents pictures of modern pipe laying vessels for each of the before mentioned pipe laying methodology. Figure 3-9: Picture of S-Lay Vessel Piper (Owner is Acergy) LI Page 3-19

50 Figure 3-10: Picture of Reel-Lay Vessel Apache (Owner is Technip) Figure 3-11: Picture of J-Lay Vessel Balder (Owner is Heerema) LI Page 3-20

51 3.3 Design Consideration for Sub Sea Pipelines in the Mediterranean Sea The following are the principle design issues for sub sea pipelines: Pipeline must be large enough to carry fluid effectively; Should not corrode (internal and external); Must be strong enough not to burst or buckle; Must be heavy enough to remain in place (considering buoyancy, waves and currents; Must be constructible. The following design stages have to be observed: System design; Desk top planning and routing; Meteo marine data collection/studies; Site investigations (offshore survey): o Soils investigations; o Bathymetry, sub-bottom profiling, magnetometry, side scan sonar; o EIA water and soil sampling. Pipeline stress calculations; Geohazards; Crossings; freespans and seabed rectification works; Materials and welding; Pipeline protection; Landfalls (including scour analysis); Corrosion; Risk Analysis. LI Page 3-21

52 3.3.1 System Design for Sub sea Pipelines The system design defines as a minimum the following main parameters: Pipeline diameter (flow rate and pressure); Number of compressor stations and valves; Main pipeline sections (on-shore and off-shore). Figure 3-12: Typical Pipeline Profile (Example for Trans Adria Pipeline) Figure 3-13: Typical Pipeline Schematic Overview (Example for Trans Adria Pipeline) LI Page 3-22

53 3.3.2 Desktop Planning and Routing Desktop planning and routing includes the following activities: Physical Factors about the Water: o o o Depth (avoid very deep and shallow water); Waves (avoid high waves areas and concentrations of wave energy); Currents (avoid high currents). Physical Factors about the Seabed (hard, soft, rough, physical obstructions, instability, etc); Other users of the seabed (services, fishing, military, dumping, mining, navigation etc); Other users of the sea depth profile (military (gunnery, submarines), sensitive areas) Construction (production facilities, platforms etc.); Environment (in deep water - sediment turbidity, in shallow water birds, fish, mammals, coral reefs, sea plants); Politics (avoid other operator s blocks, jurisdictions and countries. Figure 3-14: Typical routing plan for a sub sea section (Example for Trans Adria Pipeline) LI Page 3-23

54 Figure 3-15: Typical sea bed contours for a sub sea section (Example for Trans Adria Pipeline) Meteo Marine Data Collection/Studies Meteo Marine data collection includes the following: Waves heights and periods (for landfall design and construction use); Tidal streams and currents (full depth profiles); Water levels; Wind data (for construction use); Seawater salinity and temperature (full depth profiles). Please note that in developed countries and areas of natural resource exploration this is usually already publicly or privately available in raw form which then has to be processed, often using modelling techniques into useful data for the design. In some cases it is necessary to have long term measurement (expensive) of: Waves; Currents; Water levels; Wind. LI Page 3-24

55 Figure 3-16: Typical Off-Shore Survey Vessel Site Investigation (Off-Shore Survey) A typical off-shore survey includes: Soils investigations (sampling); Bathymetry, sub-bottom profiling, magnetometry, side scan sonar; EIA water and soil sampling. LI Page 3-25

56 Seabed soil investigation: Various methods to determine the soil composition and its mechanical/ chemical and organic properties will be applied. Vibro Coring A vibracore device uses a vibration source to sink a sample barrel into unconsolidated, watersaturated sediments. The vibrations cause disturbance in the sediment that is in contact with the sample barrel to facilitate penetration. The disturbance is minimal and sedimentary structures are preserved in the sample. These samples are suitable for both environmental and geotechnical projects such as beach restoration, construction evaluation, pollution localization, pre-dredge studies, stratigraphic research, and others. Figure 3-17: Typical Vibro-Coring Drop/Gravity/Piston Corers Gravity corers provide a rapid means of obtaining a continuous core sample in water depths down to several thousand meters. Depending upon their deployment and operating systems, gravity corers can be deployed from a wide range of vessels. A gravity corer consists of a steel tube in which is inserted a plastic liner to retain the core sample. The penetrating end of the tube is fitted with a cutter and a concave spring-steel core-catcher to retain the sample when the corer is retracted from the soil and recovered to the ship. One of the simplest geotechnical LI Page 3-26

57 devices, the impetus of gravity acting on the heavy, freefalling device is the motive force that drives the corer into the soil. Sediment cores of the seabed are obtained by means of a hollow tube or box which is driven into the sediment by means of gravity or a reactionary force and taken up to obtain a continuous, undisturbed cross-section core of the seabed. The core is extruded or cut open for analysis by means of sub sampling the chemical, biological, and physical properties of the ground. The sediment cores provide information about the composition of the sediment column such as what is living in the sediments, sedimentation rates, magnetic properties, total organic carbon, grain size sampling, trace metal concentrations, and organic pollutants. A coring program is an important way to ground truth the remote sensing done in acoustic and video surveys. In the case studies the seabed cores were obtained by means of a vibrocorer manufactured and supplied by Quaternary Resources. The vibrocorer can achieve better results than a drop corer in most sedimentary conditions. The cores are very similar and are used in conjunction with side-scan sonar, sub-bottom profilers, multibeam bathymetry, and grab sampling to map benthic habitats. Figure 3-18: Typical Drop/Gravity/Piston Corers LI Page 3-27

58 Grab Sampling Grab sampling is the simple process of bringing up surface sediments from the seafloor. It cannot be used to characterize different sedimentary layers since a mixture of sediments is produced when they are brought up, therefore, it is only used for the surface. This method has neither the ability nor the ergonomic qualities to penetrate the ground to depth. Once it is launched, the jaws of the grab sampler open and it descends to the seafloor. A spring closes the jaws, and they trap sediments or loose substrate. The grab sampler is then brought up to the surface where its contents are studied in detail. Figure 3-19: Typical Grab Sampling Box Corer This is one of the simplest and most commonly used sediment corers. The stainless steel sampling box can contain a surface sediment block as large as 50 cm x 50 cm x 75 cm with negligible disturbance. Once the sediment is recovered onboard, the sediment box can be detached from the frame and taken to a laboratory for sub sampling and further analysis. The core sample size is controlled by the speed at which the corer is lowered into the ocean bottom. When the bottom is firm, a higher speed is required to obtain a complete sample. LI Page 3-28

59 A depth pinger or other depth indicator is generally used to determine when the box is completely filled with sediment. Once the core box is filled with sediment, the sample is secured by moving the spade-closing lever arm to lower the cutting edge of the spade into the sediment, until the spade completely covers the bottom of the sediment box. Seabed investigation using bathymetry: A bathymetric map is a map of the seabed showing the changes in depth. Contour lines are drawn at particular depths, just as is done on Ordnance Survey maps. Many modern bathymetric maps use color to indicate depth. Figure 3-20: Typical Sea Bed Bathymetry (Echo Sounding) LI Page 3-29

60 EIA, water and soil sampling: In order to determine the impact on the environment during the pipe laying process a comprehensive study of all organic life on the sea bed along the pipeline route has to be carried out. This is achieved through sampling of water, soil and organic life. Water sampling devices range from a bucket dropped over the side of a small boat to large water bottles sent toward the deep ocean seafloor on a wire. Probably the most commonly used water sampler is known as a rosette. It is a framework with 12 to 36 sampling bottles (typically ranging from 1.2 to 30 liter capacity) clustered around a central cylinder, where a CTD (Conductivity Temperature Depth) or other sensor package can be attached. Figure 3-21: Typical Rosette Water Sampler LI Page 3-30

61 Sediment Corers: Sediment Corers are used to sample the organisms that live on or just below the surface of the ocean floor (the benthos), while displaying the structure of the sediment. Sediment Corers work by boring a large tube into the benthos and then bringing up a column, or core, of sediment intact within the tube. Caps can automatically seal off the ends of the core after it has pulled up a sample, protecting the sample and keeping it intact. Different sizes and approaches work with different organisms and sediment types. With benthic corers, scientists obtain samples containing organisms (including the very small ones, microbes) found in the benthos, as they are found naturally. Scientists can then identify what species are in the sediment as well as how abundant they are. Other information can also be gained, such as how they live and move in the sediment. This technology minimizes injury to potentially delicate organisms whether from shallow coastal waters or from abyssal depths. Figure 3-22: Typical Sediment Corers LI Page 3-31

62 3.3.5 Pipeline Stress Calculations The methodology to calculate wall thickness and to determine suitable pipe materials, the typical stress situations for a sub sea pipeline includes (i) internal pressure; (ii) external pressure and (iii) layability, see schematic calculation process below: Figure 3-23: Typical Methodology for Pipeline Stress Calculations LI Page 3-32

63 3.3.6 Geohazards Geohazard risks include: Seismic and volcanic activities; Water (e.g. tsunami, flooding, wind and sea state); Mass movements and erosion; Liquefaction; Collapsing soil; Swelling and shrinkage soil; Aggressive ground; Groundwater. Figure 3-24: Typical Geohazard Analysis and Interpretation of a Sea Bed LI Page 3-33

64 3.3.7 Pipeline Crossings, Free Spans and Sea Bed Rectification Uneven seabed lead often to free spans for the pipeline that add additional stress to the internal and external pressure of pipeline. The limiting span lengths depend on the structural parameters of the pipelines, the soil conditions, waves and currents. Maximum allowable free span lengths during operation vary from 16 m to approximately 70 m. In soft soil conditions, the span lengths may be allowed beyond this level, typically up to 200 m. The non-allowable free spans along the pipeline route can be identified from the geophysical surveys of the route. To avoid excessive stress in these sections, either a re-route has to be found to obtain more favourable sea bed conditions or sea bed rectification measures have to be introduced. Sea bed rectification could include evasive measures such as dredging or non invasive measures such as additional pipeline supports using suitable materials. Figure 3-25: Typical Free Span Section (upper left) and Non Evasive Sea Bed Rectification LI Page 3-34

65 Figure 3-26: Typical Evasive Sea Bed Rectification using Dredger (left) and Backhoe (right) Figure 3-27: Typical Evasive Sea Bed Rectification using Cutter Suction (left) and Bucket (right) Figure 3-28: Typical evasive Sea Bed Rectification using ROV (Remote Operated Vehicle) LI Page 3-35

66 3.3.8 Materials and Welding For line pipe material the Carbon Manganese Steels requirements are: Strength; Weldability; Toughness; Resistance to cracking; Corrosion resistance. Additional factors for material selection are: Corrosion allowance; Use of inhibitors; work hardening; alloying and cladding. Factors that influence the choice of grade: Costs; Transport (care during); Welding amounts; Buckling tendency; Ease of coating; Stability on seabed; Sour service material complexity. Traditional Welding Methodologies used for sub sea pipelines: Submerged arc welding; Shielded metal arc welding; Gas metal arc welding. Newer Welding Methodologies (still at novelty stage): Friction welding; LI Page 3-36

67 Explosion welding; Electron beam; Laser welding. Inspection Methods: Radiography; Ultrasonic testing; Time of flight; Hardness; Visual; Engineering critical assessment. Figure 3-29: Typical Semiautomatic Welding Machine on Horizontal Platform for S-Lay LI Page 3-37

68 3.3.9 Pipeline Protection Various protection measures are used in order to protect the sub sea pipeline: Laying the pipeline in a prepared trench is one protection measure. Concrete coating not only provides the required negative buoyancy for the pipeline but also protection against external mechanical impacts. Figure 3-30: Typical Concrete Coatings for a Sub Sea Pipeline Covering the sub sea pipeline with soil has many reasons (i) provides cover and protection from mechanical impact and (ii) increases thermal insulation for heated pipelines (waxy crude oil). Figure 3-31: Typical Soil Cover for a Sub Sea Pipeline LI Page 3-38

69 Landfall Design and Constructability Landfalls need to be carefully planned in terms of environmental impact, constructability and general access. Figure 3-32: Typical Landfall using a Pull-in on Rollers Figure 3-33: Typical Landfall using a Pull-in Mechanism on Rollers for Prefabricated Pipeline Sections LI Page 3-39

70 Figure 3-34: Typical Landfall using a Floating Ditch for Pull in Prefabricated Pipeline Sections Figure 3-35: Typical Landfall using Horizontal Drilling for Least Environmental Impact LI Page 3-40

71 Corrosion Protection of Sub Sea Pipelines The following measures are applied regarding the corrosion protection of sub sea pipelines. Pipeline Coatings: Various internal and external corrosion coatings can be applied: Asphalt and coal tar enamels (with concrete coating); Three-layer polyolefin coatings (PE/PU/PP); Fusion bonded epoxy (electrostatically changed powder); Internal flow coating or corrosion protection. Cathodic Protection: Sacrificial anodes are typically: Aluminum; Zinc. Figure 3-36: Typical Clamp-on Anodes for Sub Sea Application LI Page 3-41

72 Risk Analysis Matrix The typical risk analysis for sub sea pipelines considers: Hazardous dumping grounds; Geohazards; Military activity; Shipping and fishing trawler risk; Pipeline corrosion; Material failure. Figure 3-37: Typical Risk Analysis Matrix LI Page 3-42

73 4 Power Generation and Supply System on Malta Malta operates an isolated national electricity generation and supply system that is not connected to any other electrical energy system. The required electrical energy is generated in Malta by the utility Enemalta Corporation (EMC). In the following sections the main characteristics of the system will be explained. The description of the power generation system includes e.g. the technologies applied, installed and available capacities, fuel types and fuel consumption. Furthermore, the geographic and technological structure, capacity and operational characteristics of the power distribution system will be treated. 4.1 The Existing Power Generation System Historical Development and Current State of Power Generation At present EMC operates two power stations, which satisfy the electrical energy demand of the Islands of Malta and Gozo. Delimara Power Station (DPS) bears a nominal capacity of 304 MW. The plant consists of two 60 MW steam turbines (ST), two 37.5 MW open cycle gas turbines (OCGT) and one 110 MW combined cycle gas turbine (CCGT). The CCGT unit is configured by two 37.5 MW gas turbines and one 36 MW ST. At present the CCGT unit is typical operated at 1+1 mode. Therefore the actual generation figures registered in recent years are wide below the practically possible sentout of the unit. Table 4-1 provides the development of the gross power generation in recent years. In total DPS generated 1,075 GWh/a in 2006, a proportion of 47% of the entire system s power generation of this year. The major share of DPS s generation is contributed by the steam turbines (77% in the year 2006). These units are utilised to cover a major part of the Maltese system s base load. The CCGT operated to cover intermediate and peak load provides some 22% of DPS s generation. Finally the remaining 1% is generated by the OCGTs to compensate highest peak load requirements during the summer and winter seasons. Figure 4-1 illustrates the trends in DPS s power generation by the individual type of technology. While in sum the CCGT and OCGT s generation amounts are nearly stable (in particular from 2004 on) the highest increase of power generation is observed for the two steam turbines. The total annual generation rose from 568 GWh/a in 2000 to 830 GWh/a in 2006 by 46%. LI Page 4-1

74 Item Year* DPS CCGT 335, , , , , , ,220 DPS STs 568, , , , , , ,092 DPS GTs 25,359 27,681 10,952 16,989 17,567 4,062 5,198 Total 928, , ,442 1,058,302 1,042,184 1,055,371 1,074,510 * Fiscal year Table 4-1 : Gross Generation in MWh/a Delimara Power Station ( ) DPS CCGT DPS STs 1, [GWh/a] 1, [GWh/a] DPS OCGTs 1,000 [GWh/a] Figure 4-1: Gross Generation by Technology Delimara Power Station ( ) LI Page 4-2

75 Marsa Power Station (MPS) bears a nominal capacity of 267 MW. The plant consists of one 37.5 MW OCGT and eight STs with capacities between 10 MW (unit 1 and 2); 30 MW (unit 3 to 7) and 60 MW (unit 8). The STs are designed for using one common steam header (except 60 MW ST 8); Table 4-2 provides the development of MPS s gross power generation in recent years. In total the plant generated 53% of the entire system s power generation in The generation of the OCGT dedicated to cover peak load requirements is very low (only some 0.1% of MPS total). The remaining 99.9% are produced by the steam turbines. According to oral explanations of the EMC s station management, unit 1 and 2 are only used as back-up. The major proportion of MPS s generation is contributed by the most efficient units 8 and 3. Figure 4-2 provides the trends in MPS s power generation by the type of technology. The annual generation of the steam turbines rose from almost 990 GWh/a in 2000 to nearly 1,200 GWh/a in 2006, equal to a percentage increase of 21%. Item Year* MPS STs 990,656 1,062,871 1,144,053 1,147,603 1,172,330 1,207,108 1,194,558 MPS GT 5,130 16,556 1,578 2, ,694 Total 995,786 1,079,427 1,145,631 1,149,713 1,172,708 1,207,774 1,196,252 * Fiscal year Table 4-2 : Gross Generation in MWh/a Marsa Power Station ( ) MPS STs MPS OCGT 1,200 [GWh/a] 1, ,200 1, [GWh/a] Figure 4-2: Gross Generation by Technology Marsa Power Station ( ) LI Page 4-3

76 4.1.2 Installed and Available Capacity The nominal capacity of the Delimara Power Station of 304 MW is reduced to 270 MW since the CCGT unit is derated from 107 MW available capacity to 90 MW during summer as a result of high ambient temperatures. Due to the same reason, the two OCGT units are derated to 30 MW from 37.5 MW. As an example, Figure 4-3 provides the average monthly temperatures ( ) and their impact on the capacity rating of the Delimara combined cycle unit. The nominal capacity of the Marsa Power Station of 267 MW is reduced to 225 MW, since 20 MW from the steam turbines 1 and 2 are not operational. Furthermore the OCGT capacity is derated during summer from 37.5 MW to 30 MW. In total the steam units 3 to 8 are derated from 210 MW to typically 195 MW, also as a result of high sea water and air temperatures. The following Tables 4-3 and 4-4 provide selected general information such as type of technology, manufacturer, age and nominal capacity for each unit of both power stations. In cooperation with Enemalta and the MRA a comprehensive data base regarding the existing EMC generation facilities was established. This data base includes all relevant technical, economic and environmental aspects necessary to simulate the power generation system which will be discussed in more detail within the frame of Work Package II. 30 [ C ] [ MW ] Average Temperature in C Rated Capacity in MW Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Figure 4-3: Average Monthly Temperature Profile and Capacity Rating (Example: DPS CCGT) LI Page 4-4

77 Unit Manufacturer Year of Commissioning Age Nominal Capacity ST Unit 1 Steam BHEL a 60 MW ST Unit 2 Turbines BHEL a 60 MW OCGT Unit 1 Gas GE a OCGT Unit 2 Turbines GE a CCGT Unit 1 Combined GE a 30 MW Summer 37 MW Winter 30 MW Summer 37 MW Winter 90 MW Summer 107 MW Winter Table 4-3 : General Unit Data Delimara Power Station Unit Manufacturer Year of Commissioning Age Nominal Capacity ST Unit 1 Tosi a (10 MW) Back-Up ST Unit 2 Tosi a (10 MW) Back-Up ST Unit 3 Tosi a 30 MW ST Unit 4 Steam Tosi a 30 MW ST Unit 5 Turbines GE 1982 (refurbished) 25 a 30 MW ST Unit 6 GE 1983 (refurbished) 24 a 30 MW ST Unit 7 Ansaldo 1984 (refurbished) 23 a 30 MW ST Unit 8 Parsons 1987 (refurbished) 20 a 60 MW OCGT Unit 1 Gas Turbine GEC Alst(h)om a 30 MW Summer 37 MW Winter Table 4-4 : General Unit Data Marsa Power Station LI Page 4-5

78 4.1.3 Fuel Characteristics and Consumption At present EMC s electricity generation is ensured through the combustion of liquid fossil fuels. Heavy fuel oil (HFO) is applied in all DPS and MPS steam turbines. Gasoil is burned in the DPS and MPS open cycle gas turbines, as well as in the DPS combined cycle unit. Several fuel switches were already realised in the past. Until the early nineties a number of MPS boilers operated on coal basis. Beside a fuel substitution from coal to HFO, EMC switched from high sulphur fuel oil to low sulphur fuel oil three years ago. Further fuel related environmental improvements are under consideration, so that from the beginning of 2008 gasoil 0.2% Sulphur (S) will be replaced by gasoil 0.1%S. The average net calorific values (NCV) applied in this study regarding the energy content of the liquid fossil fuels of the existing generation system are: HFO 2%S: 40,496 kj/kg HFO 1%S: 40,910 kj/kg Gasoil 0.2%S : 42,750 kj/kg Gasoil 0.1%S : 42,950 kj/kg The Carbon Dioxide (CO 2 ) equivalent which is used to calculate the amount of Green House Gas Emissions (GHG) is related to the energy content of the fuel types. The CO 2 equivalent applied in this study amounts to: HFO: t CO 2 /TJ Gasoil : 74,07 t CO 2 /TJ Table 4-5 provides the trend in the annual amounts of fuels utilized in the Delimara power station. While the consumption of gasoil decreased between 2002 and 2006 by 30%, the annual consumption of heavy fuel oil raised to nearly 218,000 metric tons by some 45%. A first indica- Item Year* DPS Gasoil 0.2%S CCGT 26,819 66,613 65,102 47,526 50,273 46,439 DPS HFO 1%S STs** 188, , , , , ,970 DPS Gasoil 0.2%S GTs 9,359 3,671 6,001 5,895 1,385 1,902 Total Gasoil 0.2%S 36,178 70,284 71,103 53,421 51,658 48,341 * Fiscal year ** Utilisation of HFO 2%S until 2004/2005 Table 4-5 : Annual Fuel Consumption in Metric tons Delimara Power Station ( ) LI Page 4-6

79 DPS CCGT DPS STs [t/mwh] [t/mwh] DPS OCGTs [t/mwh] Figure 4-4: Specific Fuel Consumption (Related to Gross Generation) Delimara Power Station ( ) tion of the energy conversion efficiency for the different technologies of DPS brings out the above Figure 4-4. The lowest specific fuel consumption amongst all of the technologies applied in the station is observed for the combined cycle unit. It amounts to an average of t/mwh during the recent years. The steam turbine units possess a reference value of t/mwh and the open cycle gas turbine units some t/mwh. The trend analyses show that the highest band width in the specific fuel consumption are observed regarding the gas turbines operating in partial load by highly varying heat rates. Over the given time period, the following average efficiencies (related to net generation figures) were evaluated for DPS: DPS Combined cycle: 39.7% DPS Gas turbines: 24.2% DPS Steam turbines: 31.7% LI Page 4-7

80 Table 4-6 presents the annual consumption of fuels utilized in the Marsa power station. The consumption of gasoil was marginal in recent years. The gas turbine required only 701 tons in Analogue to the DPS trend, the annual consumption of heavy fuel oil raised over the given period. An increase of 12% was registered between the years 2001 and The specific fuel consumption of the OCGT amounted to t/mwh. This is the highest value within the comparison of the reference figures of all units of the EMC power generation system. Furthermore the specific fuel consumption is characterised by high variation due to the partial load operation of the gas turbine (0.481 t/mwh maximum in 2004; and t/mwh minimum in 2001). As an average, the specific fuel use of all MPS STs was t/mwh in This is 18% higher compared to the reference value derived for the DPS STs. Only a low rate of fluctuations was determined for the period under consideration (some 4.1% deviation between t/mwh maximum in 2003; and t/mwh minimum in 2005). Item Year* MPS HFO 1%S STs** 334, , , , , ,098 MPS Gasoil 0.2% GT 6, * Fiscal year ** Utilisation of HFO 2%S until 2004/2005 Table 4-6: Annual Fuel Consumption in Metric tons Marsa Power Station ( ) MPS STs MPS OCGT [t/mwh] [t/mwh] Figure 4-5: Specific Fuel Consumption (Related to Gross Generation) Marsa Power Station ( ) LI Page 4-8

81 Over the given time period, the following average efficiencies (related to net generation figures) were evaluated for MPS: MPS Steam turbines: 26.4% MPS Gas turbine: 20.1% Outlook To prepare a series of upcoming work steps within the frame of this Energy Interconnection Study, several simulations regarding the operation of the existing generation system were carried out. A precise reproduction of the current conditions is the base for any further analysis, strategic planning and decision making procedures. An exemplary result of the initial system simulation is shown in Figure 4-6. The graph presents the operation of MPS and DPS power generation facilities to cover the load during a typical working day of the transition period of the fiscal year The most efficient steam turbines (DPS ST1 and ST2 1 ; MPS ST3 and ST8) are dispatched to satisfy base load requirements. The remaining MPS STs and the DPS CCGT cover the intermediate load. Although constantly lowest specific fuel consumption and highest efficiency (see previous section) due to the highest fuel costs, the gasoil fuelled DPS combined cycle gas turbine is ranked behind all HFO fuelled steam turbines in the dispatch merit order, and generates only a proportion of less than 30% of its potential sent-out. As the result, the low efficient MPS generates the main share of electrical energy with some 60.8% (23,072 MWh/w) during the entire exemplary week. The same configuration of the power generation system and the same time frame were used in the second simulation run (Figure 4-7). Hypothetically it is assumed that gasoil 0.2%S fuel is replaced by low-priced natural gas. Consequently, the most efficient unit would rank first in the merit order. Furthermore, the net efficiency of the CCGT would increase by approximately 7% points due to the switch from 1+1 to 2+1 operation mode and avoid a further partial load operation. The share of electrical energy provided by MPS would decrease to less than 35% (over the entire week: 13,169 MWh/w). To optimise the resource utilisation for the future development of the Maltese power supply system a number of promising alternatives will be investigated in the Work Packages II and III of this study. One complex task is the assessment of gas supply to the island. This exercise requires an adequate estimation of the future gas requirements. 1 Usually the transition periods are reserved to carry out maintenance works. In the example it is assumed that one DPS ST and one MPS ST are out of operation. LI Page 4-9

82 Figure 4-6: Simulated Actual Dispatch of MPS and DPS Generation Units Transition Period (2006) LI Page 4-10

83 Figure 4-7: Simulated Hypothetical Dispatch of MPS and DPS Generation Units Transition Period (2006) LI Page 4-11

84 Based on the findings regarding the current conditions of the power generation system and under consideration of possible measures within the mid term and long term planning period (e.g. construction of new generation facilities; re-powering of DPS steam turbines to combined cycle) the following scenarios regarding the estimation / projection of the future gas demand will be treated: Case I High Gas Demand Scenario: Complete fuel switch in the power generation system from gasoil and HFO to gas. This exercise will consider the fuel substitutions in the existing DPS 110 MW CCGT; the two existing DPS 37.5 MW OCGTs; the one existing MPS 37.5 MW OCGT and the two existing DPS 60 MW STs. Furthermore, all new generation facilities are assumed to burn gas. This case will not consider either an HVDC link or new generation facilities using fuels other than gas. Case II Base Gas Demand Scenario:: Partial fuel switch in the power generation system from gasoil 0.2%S (gasoil 0.1%S from 1 st January 2008 on, respectively) to gas. This exercise will consider the fuel substitutions in the existing DPS 110 MW CCGT, the two existing DPS 37.5 MW OCGTs and the two existing DPS 60 MW STs. A switch in the MPS will not be taken into consideration (marginal generation of the MPS 37.5 MW OCGT). Furthermore, the new generation facilities are assumed to burn gas and a new HVDC link between Sicily and Malta will be taken into account. Case III Low Gas Demand Scenario: Partial fuel switch in the power generation system from gasoil 0.2%S (gasoil 0.1%S from 1 st January 2008 on, respectively) to gas. This exercise will consider the fuel substitutions in the existing DPS 110 MW CCGT and the two existing DPS 37.5 MW OCGTs. A switch in the MPS will not be taken into consideration (marginal generation of the MPS 37.5 MW OCGT). Furthermore, the new generation facilities are assumed to burn other fuels than gas and a new HVDC link between Sicily and Malta will be taken into account. LI Page 4-12

85 4.2 The Existing Power Network The Maltese electricity utility Enemalta Corporation (EMC) supplies about 250,000 customers on a small area of 316 km². The transmission system is rather small; the network consists mainly of an urban and a rural distribution grid. The break down of this system under geographical and technological aspects is illustrated in the following subchapter. The distribution system is exposed to different kinds of losses, which are analysed and described in detail in Chapter 5.3 of this report. Moreover, the capacity of the current system is nearly depleted during peak load; hence, modifications have to be considered in view of increasing demand and the development of additional generation facilities to be examined in line with the study at hand. EMC is already addressing and undertaking different measures for the expansion of its distribution network. A more detailed reflection on the capacity and constraints of Malta s distribution system is presented in Subchapter Geographic and Technological Structure of the Transmission and Distribution System EMC operates currently the following four voltage levels for their transmissions and distribution network: 132 kv; 33 kv; 11 kv; 400/230 V whereas the frequency of electricity supply is 50 Hz. The switchgears, being denominated as distribution centres 2, transform within the supply system power from the 132 kv and 33 kv feeders to 11 kv. This voltage is furthermore converted to 400/230 V by one of the distribution substations spread all over the inhabited Maltese Islands. Voltage Levels 132 kv The 132 kv was established in the early 90s. It is a radial network which has evolved to a network with a total length of 8 km, operating with two distribution systems. One is located between the Delimara Power Station (DPS) near Marsaxlokk in the South-East of the Malta Island and the only operating 132 kv distribution centre in the country, Marsa South DC, which is located near Marsa Power Station (MPS) in Marsa, i.e. rather in the centre of the island. The 2 The term distribution centre is not to be confused with an administrative entity. It describes merely a switchboard for the transformation from 132 kv and 33 kv to 11 kv. LI Page 4-13

86 second one is located between Marsa South Distribution Centre and Mosta (also located centrally). The 132 kv lines are depicted in black colour in Figure 4-8 below. The 132 kv system is presently extended to the new 132 kv substation Kappara for which further tunnelling for 132 kv lines (two tunnels between DPS and Marsa South as well as between Santa Venera and Kappara) is under construction. The 132 kv network is foreseen to become the transmission system for the transport of generated electricity to 132/33 kv distribution centres which are and will furthermore be spread strategically over the inhabited area of Malta. Voltage level 33 kv The distribution system of the 33 kv level consists of 154 km underground cables and 60 km overhead lines. This indicates as well EMC s policy to install further 33 kv circuits underground. As the only two electricity generation plants of the Republic of Malta, Marsa Power Station and Delimara Power Station, are located on the Island of Malta. Gozo, the secon inhabited island of the Maltese archipelago, is connected to Malta by three 33 kv submarine cable circuits passing via the Island of Comino. As shown on the map in Figure 4-8, the cables go from Vendome in the north of the Malta Island via Comino to Gozo. There is one distribution centre on each of the islands of Gozo and Comino, whereas 16 more are spread over the island of Malta. All of them transform the 33 kv voltage to 11 kv. Equal to the 132 kv network, the 33 kv network is also a radial network with few interconnections between the various distribution centres. For this envisaged set-up and in order to share redundancies of the whole network, it is foreseen to construct the 132 kv network in the form of a closed ring loop. Voltage level 11 kv The 11 kv system extends with a length of 1,041 km as underground cable network. Underground installation is also foreseen for future circuits. In addition, 159 km of 11 kv overhead lines are still in service. In order to facilitate transformation from 11 kv to a voltage level for final supply, the 11 kv system comprises 1,075 indoor type substations and 132 pole mounted transformers in order to step down the 11 kv to 400/230 V, serving thus approximately 250,000 customers. For some customers on industrial or commercial level, the supply of electricity is directly ensured with a voltage of 11 kv. Like domestic customers, small and medium entities in the industrial and commercial sector are serviced on 400/230 V level, supplied from the distribution substations. The 11 kv network used to be an open ring structure, but has over the time evolved to an interconnected meshed network. Voltage level 400/230 V Unlike as on other voltage levels in Malta, the majority of 400/230 V lines are overhead lines. The exceptions are the capital Valletta and Floriana. The low voltage system is a three phase 4 LI Page 4-14

87 Figure 4-8: Maltese Distribution System wire system and admits a tolerance on the voltage level of -10% to +10%. As already described, domestic customers and customers of small and medium commercial and industrial entities are serviced on 400/230 V level Capacity and Operational Constraints The demand on electricity has increased in the recent years on the Maltese islands and is expected to continue in the future. Network modifications and extensions are expected, especially considering the possible expansion measures which are examined in line with this LI Page 4-15

88 study, comprising the decommissioning of the MPS, additional generation sources at the DPS, off-shore wind power generation, an interconnection with Europe and possible connection with third party or distributed generators. In view of these aspects, the distribution system is already and will be suffering constraints concerning the capacity of the distribution lines. These are by now operating close to their maximum capacity, and in some areas even the security of (n-1) is not maintained anymore. A failure in operating will cause prolonged and expanded interruption of supply. Thus, measures to expand the current system are undertaken: Tunnelling for the extension of the 132 kv network under construction; further tunnelling for 33 kv lines is foreseen. The expansion and reinforcement measures shall be realised under a two phase plan. Milestones of the two phases, which shall be accomplished by 2009 and 2013 respectively, are the following: Commissioning of new 132 kv substations at Mosta, Kappara, Marsa (i.e. Marsa 2 Distribution Centre); Commissioning of five more 33/11 kv substations; Completion of the 132 kv ring network; Reinforcement of Bugibba Distribution Centre, Mellieha Distribution Centre and the Distribution Centres in the Sliema region by new 33 kv feeders; Reinforcement of new 132 kv feeders from DPS and by connection to the European Grid. The cost for the expansion measures are estimated to be around EUR 227m. For the majority of the measures, the awarding of turnkey contracts by EMC is expected in order to comply with the time schedule as proposed in the Transmission Plan for the horizon 2006 to The undergoing 33 kv network reinforcement is hampered due to delays with the works for the 132 kv line tunnelling. If the system expansion is facing further postponements, the capacity of the system will not be sufficient to bear the estimated load, not to mention any spare capacity or network security. The 132 kv network is envisaged to become the backbone of the transmission system. In order to enhance security by sharing redundancies of network connections, the expansion of the 132 kv network attempts a structure of a closed loop. LI Page 4-16

89 5 Analysis and Projection of the Electricity Demand This chapter of the report deals with the electricity demand in the Republic of Malta. The chapter starts with the description of the historical development of electricity demand. The analysis of the historical evolution contributes an important input to the review of the load forecast provided by the national utility Enemalta Corporation, which is one of the major work steps within the frame of system expansion planning. As for any forecast, it must nevertheless be stated that the quality and correctness of results can only be examined through ex-post comparison. Different forecasts are often prepared for different intentions. These intentions influence the choice of methodology and are also being reflected in the assumptions underlying the forecast. Only by comparing former forecast results and the actual development of the electricity demand, a definite judgement about the approach can be given. Regarding the review of load forecasts thus the analysis focuses on the methodological approach and the assumptions applied. This then supports the derivation of conclusions regarding the projected load development and its applicability for expansion planning. 5.1 Historical Development of the Electricity Demand In the following, the historical development and the current situation of the electricity demand in the Republic of Malta will be discussed. Table 5-1 shows the development of peak demand and of annual electricity demand for the period 1990 to The demand figures include the final consumption and network losses, auxiliary uses of the power plants are not covered. According to figures provided in the annual reports of Enemalta, electricity consumption in the Republic of Malta increased by an average of 6.2% per year between 1990 and 1995; by an average of 3.1% per year between 1995 and 2000; and by an average of some 3.9% per year over the recent period 2000 to Over the entire study period the amount of annual electricity consumption has nearly doubled from 1,144 GWh/a by 1990 to 2,263 GWh/a by The peak demand grew in total to 189% from 214 MW by the year 1990 to 405 MW by The average growth rate amounts to 6.9%/a over the time period from 1990 to 1995; 2.0%/a 1995 to 2000; and 2.3%/a in recent years 2000 to It thus grew less than gross the annual electricity demand. This trend leads to a steady increase of the electricity system s load factor over the past decade (see Table 5-2). As it can be observed in Figure 5-1, another major difference between the development of peak load and annual electricity consumption is that whereas annual electricity consumption grew rather steadily, the development of peak load is characterised by a number of decreases e.g. LI Page 5-1

90 Item Year* Annual Electricity Demand in GWh/a 1,144 1,180 1,336 1,352 1,426 1,548 Average Load in MW Peak Load in MW * Fiscal year n: from October year n-1 to September year n Item Year* Annual Electricity Demand in GWh/a 1,554 1,581 1,612 1,724 1,802 1,826 Average Load in MW Peak Load in MW Item Year* Annual Electricity Demand in GWh/a 1,931 2,083 2,116 2,215 2,263 Average Load in MW Peak Load in MW * Fiscal year n: from October year n-1 to September year n Table 5-1 : Annual electricity consumption, average and peak load ( ) between the years 1995 and 1997; between the years 2003 and 2004 as well as between the years 2005 and Such peak load fluctuations lead to high variations of load factors. Due to the drop of peak load in 2006 the load factor increased from 62% to 64%. From 1994 to 1995 the load factor decreased by more than 5% points within one year only. Since the peak load occurs in summer and air-conditioning plays a key role on the size of the annual peak, it is assumed that cool summers are the reason for the decreases of peak loads. Item Year* Load Factor 61% 55% 58% 62% 64% * Fiscal year n: from October year n-1 to September year n Table 5-2 : Development of System s Load Factor in Selected Years ( ) LI Page 5-2

91 Peak Load in MW Annual Electricity Demand in GWh/a 2,500 2,000 1,500 1, Figure 5-1: Historical Development of Annual Demand and Peak Load ( ) 5.2 Electricity Consumption by Sector Within this section we give an overview of the electricity consumption of the main consumer groups in the Republic of Malta. Particular consideration is given to the three sectors with the highest electricity consumption in the period 1990 to 2005: residential, commercial and industry. The development of the electricity demand of the different customer groups over the time period under consideration is depicted in Figure 5-2. The values include the sectoral final (billed) consumption, but no losses are considered in the figure. An overview of the losses between electricity demand at sent-out level and final electricity demand on the demand side is given in the following section. LI Page 5-3

92 2,000 1,800 1,600 1,400 Industrial Sector 1,200 1,000 Commercial Sector Residential Sector Street Lighting and Others Figure 5-2: Sector Break Down of Final (Billed) Electricity Consumption in GWh/a ( ) 100% 75% Industrial Sector 50% Com m ercial Sector 25% Residential Sector 0% Street Lighting and Othe rs Figure 5-3: Sectors Proportions of Final (Billed) Electricity Consumption ( ) LI Page 5-4

93 5.2.1 The Residential Sector (RS) The residential sector is the largest customer sector in the Republic of Malta. The current proportion of the electricity demand of this sector amounts to more than a third of the total. The share of the residential consumption grew from 32% (331 GWh/a) in 1992 to 37 % (669 GWh/a) in This rise of domestic electricity consumption can be primarily attributed to the increased use of air conditioning devices (summer period) and electrical space heating devices (winter period) in private households. Table 5-3 below provides figures regarding the development of the specific electricity consumption in the residential sector. While the population number raised by some 0.8% per year, the annual consumption in households increased by 5.6% over the period under consideration. This development leads to an average annual growth rate of 4.7% with regard to the specific RS per capita consumption which grew from 813 kwh/capita (1992) to approximately 1,660 kwh/capita (2005). Item Year Population* 362, , , ,039 Final RS Electricity Consumption in GWh/a Specific RS Consumption per Capita in kwh/capita 913 1,077 1,381 1,657 * Source: National Statistics Office, National Census 2005 and Historical Data Series Table 5-3 : (Specific) Electricity consumption in the residential sector ( ) The Commercial Sector (CS) The commercial sector is the second largest costumer sector in the Republic of Malta. With currently 567 GWh/a it consumes 15% less than the residential sector. The percentage share of the commercial sector in total final consumption increased form 26% in 1992 to 30% in 2000 and stabilised afterwards at a level between 31.1% and 32.1%. LI Page 5-5

94 Item Year Final CS Electricity Consumption in GWh/a Table 5-4 : Electricity consumption in the commercial sector ( ) As illustrated in Table 5-4 the consumption of electrical energy has more than doubled during the period 1992 to The average growth rate amounted to 5.8 %/a, similar to the value established for the residential sector over the same period The Industrial Sector (IS) The industrial sector of the Republic of Malta is small. The main branches are tourism, electronics, ship building and repair, construction, food and beverages, pharmaceuticals, footwear, clothing and tobacco. Only some 23% of the GDP is contributed by this sector (74% by the commercial sector, and the remaining 3% by agriculture). The low proportion of energy intensive branches is the main reason for the comparatively low overall system load factor (see section 5.1). Among the major customer groups the industrial sector ranks last. With currently 518 GWh/a it consumes 23% less than the residential sector. Furthermore, the percentage share of the industrial sector in total final consumption decreased form 39% in 1992 to only 29% in The sector lost its originally dominating role over the past 15 years. Table 5-5 provides the absolute final consumption figures for selected years in the period 1992 to While a strong increase of some 6.4%/a is observed during the early nineties, the consumption dropped by an average of -0.5%/a between the year 1995 and In recent years the absolute electricity consumption of the sector increased again. It reached nearly the average growth rate of 1.9%/a evaluated for the entire period under study. Item Year Final IS Electricity Consumption in GWh/a Table 5-5 : Electricity consumption in the industrial sector ( ) LI Page 5-6

95 5.3 Losses between Final Demand and Demand at Sent-Out level The following Table 5-6 shows a comparison of the final electricity demand and the demand at sent-out level. While the final demand is equal to the metered and billed amount of electrical energy, the demand at sent-out level corresponds to the annual net generation of the two power stations Marsa and Delimara (total annual generation minus stations self consumption). The difference between the two annual data series provides an estimation of the overall losses including both, technical network losses and non-technical losses (caused by errors in metering and/or statistics, and caused by power stealing). Item Year Net Generation in GWh/a 1,314 1,522 1,802 2,132 Final (Billed) Consumption in GWh/a 1,032 1,259 1,490 1,794 Losses in GWh/a Losses in % 21% 17% 17% 16% Table 5-6 : Evaluation of Losses ( ) Over the period under study the percentage losses decreased by 5% points from almost 21% in 1992 to 16%. Enemalta estimates some 7% regarding the technical losses for the supply of electricity (Source: Electricity Generation Plan ). While such technical loss figures would be acceptable for medium and low voltage distribution networks, the remaining 9% nontechnical losses are remarkably high. A significant amount of approximately 200 GWh/a (complying nearly the entire annual net generation of Delimara s gasoil fuelled CCGT unit) is not billed to the utility s customers. 5.4 Seasonal Load Characteristics Following the annual consumption characteristics, seasonal and monthly load characteristics will be analysed in this section. In the following tables monthly peak loads are given for the years 1990 to 2005 (Table 5-7), together with their percentage shares in the respective absolute annual peak loads (Table 5-8). Until the year 2002 the yearly peak was metered during the winter season (mainly in the months December and January). From then on the annual peak shifted and was recorded during the summer season. The peak load occurs in August in the year 2003 (397 MW) and also in the year 2005 (411 MW). In 2004 the annual peak was registered in July by some 387 MW. LI Page 5-7

96 Table 5-7 : Maximum Demand - Absolute in MW ( ) LI Page 5-8

97 Table 5-8 : Maximum Demand Adimensional in % ( ) LI Page 5-9

98 100% 80% 60% 40% 20% Trend 0% Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Figure 5-4: Monthly Patterns of the Maximum Load in Recent Years ( ) The season with the lowest daily peak over the given period was always spring. In the years 1999, 2000 and 2001, April was observed as the month with the lowest daily peak. In all other years the lowest daily peak values were observed in May. Figure 5-4 above illustrates the seasonal and monthly peak load patterns in recent years Daily Load Patterns - Working Days After the monthly electricity consumption and the monthly peak load, daily load characteristics will be described. The load is recorded for each hour per day at Maltese local time (equal to Central European Time). The figures presented in the following show exemplary load patterns of working days for each season (values were normalised to daily peak loads). In accordance to the systematics applied by the Union for the Co-ordination of Transmission of Electricity (UCTE, see also Subchapter 7.1) load profiles for the third Wednesday of January (characteristic for winter time), April (characteristic for spring time), July (characteristic for summer time), and October (characteristic for autumn time) are depicted in the following figure. LI Page 5-10

99 [MW] Load ( ) in MW Load ( ) in MW Load ( ) in MW Load ( ) in MW [hours] Figure 5-5: Typical Load Profiles of Working Days (2005) The most similar load shapes can be observed for the working days in the transition periods (spring and autumn). Lowest load figures occur during the night hours 01:00 am to 05:00 am (between 160 MW to 170 MW in spring, and.177 MW to 188 MW in autumn). The peak load is recorded in the evening hours (07:00 pm, respectively 08:00 pm), mainly caused by the residential sector (lighting). The load shape during a working day in summer encloses the largest energy amount as integral of the load over the time. Minimum loads appear during the night hours 02:00 am to 06:00 am (between 250 MW and 270 MW). The maximum load is observed during noon (12:00 to 01:00 pm). It is mainly caused by air-conditioning devices applied in all sectors described in previous sections. Finally, the typical load shape of a working day in winter possesses the most significant load bulk during the evening hours (06:00 pm to 09:00 pm). Such load characteristics can be attributed to the utilisation of space heating and lighting appliances in particular in the residential sector. Minimum loads appear in the night hours between 01:00 am and 05:00 am (between 190 MW and 196 MW). LI Page 5-11

100 5.4.2 Daily Load Patterns - Weekend Days By the same way applied in the previous section, the load patterns during weekend days are compared (see Figure 5-6). In all seasons the load shapes are more flattened compared with those regarding selected working days. In particular the load pattern of the summer weekend day shows a very flat shape. The daily minimum load is only 23% lower than the daily maximum load (228 MW at 06:00 am; 295 MW at 09:00 pm). Additional electricity consumption for lighting purposes replaces the decreasing electricity consumption for cooling purposes during the evening hours. The load pattern of a typical weekend day in winter bears resemblance to those of the weekend days in the transition periods. As already observed in the previous section the winter pattern possesses the most significant load bulk during the evening hours (06:00 pm to 09:00 pm) due to lighting and space heating needs. In the presented graph the minimum load amounts to 178 MW, the maximum reaches some 299 MW. The transition periods load patterns provide the lowest load figures. In the night hours in spring a load of only 154 MW is required by the system. This is only some 40% of the highest load figures observed during the analysis of sample load patterns [MW] Load ( ) in MW Load ( ) in MW Load ( ) in MW Load ( ) in MW [hours] Figure 5-6: Typical Load Profiles of Weekend Days (2005) LI Page 5-12

101 5.5 Electricity Demand Forecast The electricity demand forecast is an essential prerequisite for the utility s planning activities, in particular for the expansion planning of the power generation and supply system. If projected demand levels are too low, serious adverse economic consequences for consumers and the economy at large could occur. If projected demand levels are too high, excess resources can impose undue financial hardships on the utility and its consumers. In addition, this situation results in unnecessary and high economic opportunity costs associated with resource misallocation. In general there are three main approaches which can be applied to forecast the demand of (electrical) energy. The Top-Down Approach considers the major customer groups (at least residential, commercial and industrial sector) to arrive at a nation-wide forecast. It is mainly based on the analysis of historical and current values and the projection of future development of macroeconomic indicators, such as the Gross Domestic Product (GDP) and the GDP contribution by sector. Furthermore, demographic data (population number, historical and future growth rate) need to be evaluated, general previous trends of electricity consumption identified and political preferences and objectives (electrification programmes, demand side management measures) have to be considered. In applying the top-down approach energy related data, such as: the electricity intensity as given by the ratio between electricity consumption and GDP by branch or sector, the specific electricity consumption per household and / or capita need to be determined. The main advantages of the top-down approach are the comparatively low number of input data and information required, and the relatively low effort for data gathering, calculation and forecast modelling. It must be borne in mind that the top-down approach is only applicable for nation-wide projections and does not allow detailed regional classifications. Moreover, the top-down-analysis depends mainly on other forecast data, in particular on projections for the economic and demographic development. The Bottom-Up Approach considers the major customer groups (e.g. residential, commercial and industrial sector) as well as sub-classes (e.g. rural and urban households) and regions (per district, per substation, etc.). The approach is mainly based on a comprehensive knowledge of the individual characteristics of the individual customer groups and sub-classes (historical and present). To derive the projection of the future energy demand the following information need to be considered: the mid-term and long term production planning (and related energy demand) of the major branches of the manufacturing industry; LI Page 5-13

102 general developments, e.g. (re-)construction programs in the commercial and institutional sector; the number of new plots / dwellings to be connected to the supply grid and development of the specific energy consumption per household and/or capita. The Trend-Extrapolation Approach investigates the dependence on time of the variable to be predicted itself, which is therefore considered to be the most auspicious factor. The justification for this approach is therefore given by expecting past patterns of a curve to continue in future. This simplicity is bought by not taking into account other factors. Hence, by applying solely the trend-extrapolation approach it is not possible to consider interdependencies with economic, demographic or policy variables nor users behaviours or attitudes. Out of the listed characteristics, this method is best applicable on a short-term basis. The latest available electricity demand forecast for the Republic of Malta was established in the year 2005 and is provided within the Electricity Generation Plan of the national utility Enemalta Corporation. The peak load forecast covers the period 2006 to 2015 (see Table 5-9). The anticipated electrical energy demand projection covers the period 2006 to 2020 (see Table 5-10). The applied methodology can be described as a mix between the above explained bottomup approach and the trend-extrapolation approach. First, the average linear growth rate in recent years was evaluated. Within the forecast calculations, this linear trend is assumed as natural increase (peak load additional 12 MW each year). In a second step the expected demand of new major projects was added to the values Item Year* Peak Load in MW Annual Growth Rate % a-a 2.9% 4.5% 4.5% 5.6% 4.7% Annual Increase Absolute in MW Item Year* Peak Load in MW Annual Growth Rate % a-a 4.1% 3.6% 3.1% 3.0% 2.9% Annual Increase Absolute in MW * Fiscal Year Table 5-9: Peak Load Forecast Enemalta Corporation ( ) LI Page 5-14

103 determined in the trend-extrapolation. Such projects are the opening and operation of Mater Dei Hospital with an expected 10 MW net increase over St Luke s Hospital, the Manoel Island and Tigné (14 MW), the Pender Place (8 MW) and the Smart City Ricasoli (30 MW). As the result, the Enemalta peak load forecast leads to 511 MW in the year 2010 and 602 MW in the year 2015 (compared with actual 405 MW in the fiscal year 2006, see Table 5-1). The annual growth rates vary between 2.9% and 5.6%. Along the lines of the peak load projection the annual electrical energy demand was forecasted. In terms of the long term development of the demand several demand side management measures were considered (e.g. energy efficient building design, introduction of efficient combined heat and power installations as well as concentrated solar energy for heating and cooling purposes). An annual growth rate between 2.1% and 4.9% is observed regarding the short and midterm planning period. Over the long term period the growth rate decreases slightly and reaches some 1.2% in the year Item Year* Annual Electricity Demand in GWh/a 2,311 2,389 2,507 2,625 2,693 Annual Growth Rate % a-a 2.1% 3.4% 4.9% 4.7% 2.6% Annual Increase Absolute in GWh/a Item Year* Annual Electricity Demand in GWh/a 2,781 2,859 2,937 3,015 3,093 Annual Growth Rate % a-a 3.3% 2.8% 2.7% 2.7% 2.6% Annual Increase Absolute in GWh/a Item Year* Annual Electricity Demand in GWh/a 3,133 3,173 3,213 3,253 3,293 Annual Growth Rate % a-a 1.3% 1.3% 1.3% 1.2% 1.2% Annual Increase Absolute in GWh/a * Fiscal Year Table 5-10: Electrical Energy Demand Forecast Enemalta Corporation ( ) LI Page 5-15

104 The comparison of the results of both projections brings out that the peak load is estimated to grow significantly faster than the overall annual energy demand. In this regard the system s load factor would decrease continuously and reach 59% in 2015 and approximately 56% in 2020 (applying a further natural-increase-extrapolation of 12 MW regarding the peak load development). In general the applied forecast approach deems reasonable. Nevertheless, recent developments should be considered within a revised (updated) electricity demand scenario. Own analyses of the historical peak load development validated a linear growth of approx. 12 MW (see Figure 5-7). Nevertheless the growth over the last five years was below this long term trend value. Furthermore, the forecasted 2006 peak load and 2006 annual energy demand figures do not match the actual figures. The actual peak load and the actual demand are applied as initial values within the updated forecast. Furthermore a trend extrapolation of only 11 MW (natural increase) is utilised. Over the long term projection period between 2020 and 2030 average annual growth rates derived from preceding years are carried forward. The results of the updated demand forecast are provided in Table Peak Load in MW Trend (increase linear MW) Figure 5-7: Trend in Peak Load Development ( ) LI Page 5-16

105 Item Year* Annual Electricity Demand in GWh/a 2,263 2,311 2,389 2,507 2,625 Peak Load in MW Item Year* Annual Electricity Demand in GWh/a 2,693 2,781 2,859 2,937 3,015 Peak Load in MW Item Year* Annual Electricity Demand in GWh/a 3,093 3,173 3,253 3,453 3,653 Peak Load in MW * Fiscal Year Table 5-11: Updated Electrical Energy Demand and Peak Load Forecast ( ) 1, Peak Load in MW Electricity Consumption Demand in GWh/a 4,000 3,500 3,000 2,500 2,000 1,500 1, Figure 5-8: Historical and Projected Development of Peak Load and Energy ( ) LI Page 5-17

106 6 Market Analysis on Oil and Gas Prices 6.1 General Market Forces and Pricing Mechanism In general it should be pointed out that the hydrocarbon markets are not efficient markets. In efficient markets, supply and demand are the governing forces that determine the price of any commodity. However, the hydrocarbon market is a notable exception. In fact the supply of crude oil is since September 1960 regulated by the OPEC producers, which have shown remarkable discipline in the past 3 to 5 years to regulate crude oil supply in order to keep the price of crude oil within a desired range, i.e. between 50 and 65 USD/bbl. In 2006 OPEC countries produced about 43.5% of the world crude oil. Most notable is also the correlation between political World events such as (i) the Iranian revolution in 1978/79; (ii) Iraqs invasion of Kuwait in 1990 and (iii) Invasion of Iraq in All those events have had major long and short terms impacts at the crude oil price. Figure 6-1: Crude Oil Prices from in relation to World Events (Source BP Statistical Review) LI Page 6-1

107 It was in 1972, when OPEC started to be more assertive in their control of the supply side. OPEC also used the oil supply to the West as a political instrument over the West s foreign policy in the Middle East. During 1986 and 1997 was a relative stable and predictable period in relation to the crude oil price. Although never officially confirmed by OPEC, but it was said that OPEC wanted to achieve a medium price of 18 USD/bbl during that time period, which in fact they succeeded in. The detrimental effects of the Asian financial crisis in 1997/98 had only a short effect on crude oil prices but the political uncertainties in the Middle East, Nigeria and Venezuela coupled with strong energy demand increases in Asia in particular China and India pushed crude oil prices to levels above 50 USD/bbl. Figure 6-2: Crude Oil Prices from (Source BP Statistical Review) LI Page 6-2

108 The price of crude oil has an effect on all other hydrocarbon fuels such as refinery products and natural gas including Liquefied Natural Gas (LNG). Natural gas prices are set different in various parts of the world. However, due to the exchangeability of hydrocarbon fuels there is of course a link between the price of crude oil and the price of natural gas. The relationship between crude oil prices and natural gas prices is strongest in Europe where most natural gas is purchased under long term take-or-pay contracts with a strong indexation to prices for crude oil and heavy fuel oil. The US has the most developed spot and future financial markets for gas, and therefore the weakest link between gas prices and oil prices. However, the figure below demonstrates that there is still a relationship of gas prices to oil prices. The relationship weakens above a crude oil price of 40 USD/bbl, partially reflecting the effects of supply substitution and demand destruction above 40 USD/bbl Henry Hub ($/mmbtu) WTI ($/bbl) Figure 6-3: Relationship between Crude Oil Prices, Natural Gas Prices in the US (Source Energy Intelligence) LI Page 6-3

109 In the United States natural gas is traded on a 30 day basis at the New York Mercantile Exchange (NYMEX) and Henry Hub is the physical pricing point for natural gas futures. Spot and future prices set at Henry Hub are denominated in USD/mmbtu (millions of British Thermal Units) and are generally seen to be the primary price set for the North American natural gas market. North American unregulated wellhead and burner tip natural gas prices are closely correlated to those set at Henry Hub. Import of LNG is in competition with the prices set in the individual markets for natural gas delivered in pipelines. The price differentials between the individual price mechanisms for gas in different continents can be significant. These price differentials provide the rationale for so called Arbitrage Trading 3, which is becoming more and more popular since LNG cargos can be redirected from LNG terminals in the Unites States or Spain to LNG terminals in the UK. Figure 6-4: Natural Gas Prices from (Source BP Statistical Review 2007) 3 Arbitrage trading is simply the trading of securities when the opportunity exists during the trading day to take advantage of differences in value between the markets the trades are made within. LI Page 6-4

110 There are of course short term or seasonal factors that influence the price of hydrocarbons regardless of the regional pricing mechanism. These factors are: Inventory levels (especially crude oil and refinery product). If for example inventory levels for heating oil are high after a relative warm winter period, the price of heating oil will decrease almost irrespective of the crude oil price level. Refinery capacity constraints (i.e. during maintenance shut-downs) that coincide with times of high demand for gasoline (i.e. during summer travel period) will increase the cost of gasoline and some other refinery products. 6.2 General Forecasts for Future Hydrocarbons Process Taking into account the many uncertainties such as (i) World events; (ii) Regional stability in the Middle East; (iii) Future OPEC production quotas and (iv) Global economic growth makes it is a risky if not impossible undertaking to come up with reliable long term price forecasts for the future price of hydrocarbons World Total Energy Consumption Quadrillion BTU World Total Energy Consumption Figure 6-5: Global Energy Consumption from (Source EIA) LI Page 6-5

111 However, in cooperation with other institutions the Energy Information Administration (EIA) has prepared a price forecast until the year The underlying assumptions for the forecast are (i) Projected global population growth; (ii) Projected global economic development and (iii) Projected increased use of available alternative energy sources. The EIA forecasts predicts that the global energy consumption will increase from about 480 Quadrillion BTU/annum in 2007 to about 700 Quadrillion BTU/a by This includes the anticipated increase in use of alternative energy options such as bio fuels, wind, solar, geothermal etc. The forecast for hydrocarbon prices mainly crude oil and natural gas is as follows. The conventional wisdom amongst the energy analysts is that the current crude oil price level of above 70 USD/bbl will not be sustainable in the long term and will lead to demand destruction for hydrocarbons. If political stability in the Middle East returns and Iraq will ramp up production to the levels before Gulf War I in 1990, the crude oil price is predicted to level off at about 50 USD/bbl in the year Crude Oil price Forecast in 2005 US$ US$/bbl Forecast Figure 6-6: Forecast of Crude Oil Prices from (Source EIA) LI Page 6-6

112 Henry Hub Spot Price in US$/MBTU Forecast Gas Price Forecast in 2005 US$ Figure 6-7: Forecast of Natural Gas Prices (Spot at Henry Hub) from (Source EIA) Price forecasts beyond 7 to 10 years have increased uncertainty factors. Given the price volatilities of the past decade, it is unlikely that the prices for crude and natural gas will be as smooth as shown in the above figures. In fact it is very likely that price spikes caused by political uncertainties will draw a different picture. However, short term price spikes have in the past not altered the prevailing overall market mechanisms as described at the beginning of this chapter. Given the general population growth and in particular economic growth in (i) developing nations such as China and India and (ii) the transition economies of the FSU (Former Soviet Union), the demand for hydrocarbons will remains strong and price levels below 35 USD/bbl are very unlikely. LI Page 6-7

113 6.3 Indicative Market Analysis for Selected Fuels An indicative market analysis for (i) Light Fuel Oil (Diesel); (ii) Natural Gas and (iii) LNG has been prepared. Compressed Natural gas (CNG) is not yet publicly traded in any sizeable from or shape, this is due to the lack of available infrastructure for CNG. Some countries have introduced miniature CNG pilot projects for CNG powered vehicles such as busses or trucks. However, CNG has still no sizeable market penetration that would allow the development of a commercial model for a large scale CNG supply to Malta. There are no CNG vessels that are currently operating to supply demand centres. Therefore CNG will not be considered in the further analysis. However, typical future applications for CNG would be the supply of small Islands or small remote areas that have no indigenous gas production or gas pipeline connection to supply gas. The graphs in the figure below show the price fluctuations in the past 20 month. It shall be noted that the volatility of the price for Diesel and 1% Fuel Oil is quite high. For example the average price for Diesel was about 600 USD/ton with seasonal increase of up to 20% during summer and 20% decrease during the winter month USD($)/MT 500 CIF MED Diesel CIF MED 1% Fuel Oil Oct-05 3-Nov-05 3-Dec-05 3-Jan-06 3-Feb-06 3-Mar-06 3-Apr-06 3-May-06 3-Jun-06 3-Jul-06 3-Aug-06 3-Sep-06 3-Oct-06 3-Nov-06 3-Dec-06 3-Jan-07 3-Feb-07 3-Mar-07 3-Apr-07 3-May-07 3-Jun-07 Figure 6-8: Prices for Diesel and 1% Fuel Oil in the Mediterranean Market from Oct to Jun LI Page 6-8

114 Diesel and Fuel Oil are refined products and refinery margins have increased only marginally over the past 10 years it is very likely that the price of Diesel and Fuel Oil will follow exactly the price fluctuation that are forecasted for crude oil. There has been a broad relationship between gas prices and oil prices historically. This relationship can therefore be used to estimate long-term LNG prices using oil price scenarios see figure below LNG Japan NBP UK Henry Hub USA Crude oil US$/mmbtu Figure 6-9: Relationship between Crude Oil, Natural Gas and LNG Prices (Source BP Statistical Review) LI Page 6-9

115 6.4 Procurement and Contracting Options for Selected Fuels Procurement and Contracting for Diesel and Fuel Oil Refined hydrocarbon products are delivered by marine vessels from a refinery directly to a port and storage facility (i.e. power plant) in Malta. The refined products such as diesel or fuel oils are usually publicly tendered on the short term market. In Malta s case, the fuel oil or diesel will most likely be purchased, in short term contracts between the Buyer (EMC) and traders of Mediterranean refineries. The price mechanism is fairly straight forward (products are indexed to regional crude oil prices) and the economies of scale for the marine transport from the refinery to the storage facilities are significant. I.e. the larger the vessel the less expensive is the transport component Procurement and Contracting for Natural Gas In Malta s case the financing of the infrastructure required (sub sea gas pipeline from Sicily to Malta) for the gas deliveries will be an integral part of the gas purchase agreements. Typically there is a separate legal entity (e.g. Transco) which will develop the pipeline. The financing of the pipeline is secured by a take or pay gas purchase agreement between Buyer (e.g. EMC) and Seller (e.g. ENI). Since the proposed gas pipeline from Sicily to Malta starts in Gela (i.e. at the landfall of the Green Stream pipeline) ENI and perhaps its JV partner NOC will most likely be the sellers of the natural gas for Malta. In any case the gas purchase agreement also specifies the transport tariff for the individual pipeline sections which will enable Transco to recover the capital expenditures (CAPEX) and the operational expenditures (OPEX) of the pipeline Contracting for LNG Supply Options There are a number of options available for the Buyer on how to structure the supply of LNG and on how to participate along the LNG value chain. The structure is mainly dependent on: The sourcing structure (e.g. point of sale, ex-ship, FOB); The selected partner; Desire of Buyer to move upstream; Ability to invest and carry risk. LI Page 6-10

116 The identified options can be summarised in three categories as follows: Ex-ship LNG supply to a re-gas terminal in Malta; FOB LNG supply from a terminal in a gas producing country (e.g. Algeria); Participation along the entire value chain. Commercial structure for Ex-ship LNG supply to a Re-gas Terminal in Malta Re-gas Co (a special purpose vehicle) purchases LNG under a long term likely to be take or pay LNG Sales & Purchase Agreement (LNGSPA) and sells the gas after re-gasification to local off takers under a long term Gas Sales & Purchase Agreement (GSPA). LNG Supplier LNGSPA Regas Co GSPA Off-taker Tolling Agreement Infrastructure provider Point of Sale: Jetty at Maltese coast Point of Sale: Entry into the Maltese gas grid Commercial structure for FOB LNG supply from a Terminal in a Gas Producing Country LNG Ship Co purchases LNG under a long term likely to be take or pay LNG Sales & Purchase Agreement (LNGSPA) and sells the LNG to Re-gas Co which sells the gas after regasification to local off-takers under a long term Gas Sales & Purchase Agreement (GSPA). LNG Ship Co charters the required LNG tankers under a Long Term Charter Agreement. LNG Ship Co and Re-gas Co could be combined into one special purpose vehicle if it is owned by the same stakeholders. LI Page 6-11

117 LNG Supplier LNGSPA LNG Ship Co LNGSPA Regas Co GSPA Off-taker Charter Agreement LNG tanker owner/operator Tolling Agreement Infrastructure provider Point of Sale: Jetty at liquefaction Point of Sale: Entry into the Maltese gas grid Commercial structure for participation along the entire LNG value chain Below is the outline of a typical value chain with its contractual structure. A participation along the entire LNG value chain is more complex than the previous options and comes with larger investments and requirements. Gas production/ processing PSA Liquefaction Co LNGSPA Marketing Co GSPA Off-taker Tolling Agreement Liquefaction owner/operator Charter Agreement LNG tanker owner/operator Tolling Agreement Regas owner/operator Legend: PSA: Production Sharing Agreement LNGSPA: LNG Sales & Purchase Agreement GSPA: Gas Sales & Purchase Agreement LI Page 6-12

118 6.4.4 Procurement Options for LNG Supply A tender is a typical procedure in the LNG market to find out whether a project is feasible and how strong the interest is. The tender process has usually the following three stages. Stage 1: Registration of Interest Test options on the market with selected suppliers (Keep options open) Seek Expression of Interest from selected suppliers on preferred option(s) Stage 2: Letter of Intent (Non binding) Continue selection process on preferred supply option(s) Prepare tender documents and Heads of Terms Seek Letter of Intent Stage 3: Implementation (Not included in our assignment) Request for binding offer and negotiations of a gas SPA Figure 6-10: Three Stage Tender Process for LNG Purchase It is recommended to tender/market test the two options (FOB and ex ship) and continue the discussions with the potential partners in parallel. Run tender in parallel and invite current parties to participate Continue with current discussions Seek Expression of Interest (EoI) for tender and/or partnering A parallel process keeps the options open and maintains a competitive environment and good momentum. The timing of the tender is controllable, however the progress of the partnering discussions is difficult to estimate and guarantee. The following Figure 6-11 illustrates as an example how the combination of the two processes could work. LI Page 6-13

119 Tender process Alternative Proposition Feasibility Stage List of suppliers/contacts Approach supplier/send Info Test interest/capabilities Send tender documents/hot request for LoI to interested parties Collect LoI s and produce shortlist Negotiations/final bid Consider alternative proposition (that meets Buyer s needs). Order of events are as follows: 1. Sign Confidentiality Agreement 2. Develop Buyer s proposition (what is on offer?): Marketing in Malta and/or Equity in regas and/or Participation in Upstream, Liquefaction, Shipping 3. Meet potential partners to discuss principles: ownership/structure/equity along the Value Chain costs FOB costs regas, transport, prices timing volume Agree principles with selected parties (agree MoU/LoI) Gas Sales Agreement Figure 6-11: LNG Sourcing Process as a combination of Tender and Alternative Pricing Issues Finally the major pricing issues are summarised, as follows: Current LNG deals into the UK are reported to be based on a market-based pricing approach, which reflects that the fact that the LNG buyer needs to have supplies priced competitively with gas prices in destination markets e.g. Henry Hub in the US, National Balancing Point (NBP) for UK/Ireland. From the buyer s perspective, the FOB price for LNG should be based on market prices less an allowance for onward costs of getting to market (shipping, re-gas and onshore transmission), i.e. a netback arrangement. This arrangement places the market price risk on the upstream LNG seller who may not wish to take this risk, preferring perhaps a more traditional oil-indexed approach. LI Page 6-14

120 Alternative arrangements are: o Netback price with cap and collar (based on market price of destination with a minimum and a maximum); o Oil-indexed pricing, but with base gas price set to provide LNG buyer with sufficient margin under current market projections; possibly with cap and collar; o Inclusion of periodic price re-opener if significant change in market conditions, o Use of hedging instruments to protect against oil-price or gas-price risk (for seller and buyer); o Some mix of oil and market-based pricing. LI Page 6-15

121 7 Market Analysis on Electricity Supply from Continental Europe 7.1 System Adequacy in Central Europe This section provides an assessment of the electricity supply system adequacy provided by the "Union for the Co-ordination of Transmission of Electricity" (UCTE). The UCTE, the association of transmission system operators in continental Europe in 23 countries, coordinates the operation and development of the electricity supply systems and provides a reliable market platform to all participants of the Internal Electricity Market (IEM) and beyond. The key challenge of the association is to keep the quality of the supply system at high level and to provide a sound basis for electricity markets in a broader Europe and its enlargement to the benefit of all market players and consumers. Figure 7-1 below gives an overview on the regions transmission system operators (TSO) associated to the UCTE and other umbrella organisations, such as the Scandinavian NORDEL, the UCTE NORDEL UKTSOA MALTA ATSOI ETSO EU MEMBERS Figure 7-1: Associations of Transmission System Operators in Continental Europe LI Page 7-1

122 British UKTSOA and the (northern) Irish ATSOI. The system adequacy assessment aims at providing all players of the European electricity market with an overview of: the generation and demand in the UCTE system; the adequacy analysis for overall UCTE and for main regional blocks; the transmission system adequacy. Beside an assessment of the current conditions (by 2007), a forecast is provided covering the period 2008 to The adequacy analysis is based on the comparison between available generation and load at three given reference time points of the year (3 rd Wednesday 11:00 am and 07:00 pm in January; 3 rd Wednesday 11:00 am in July based on Central European Time). The difference between available generating capacity and load at reference time point is called Remaining Capacity (RC) calculated under normal conditions. To assess adequacy, Remaining Capacity is compared to a given Adequacy Reference Margin (ARM) accounting for unexpected events affecting load and generation. The ARM is calculated for each country and for overall UCTE in order to cover the increase of load from the reference time point to the peak load (called margin against peak load ), and demand variations or longer term generation outages not covered by operational reserves. For the global overview of adequacy at UCTE level, the ARM is calculated as 5% of UCTE total Net Generating Capacity plus the sum of individual margins against peak load. Comparing the load figures during the above mentioned day times, at present the maximum load is observed during evening hours in the winter season (reference: January 3 rd Wednesday 07:00 pm). In the entire system the peak load amounted to 391,000 MW. The total installed generating capacity is Item Year National Generating Capacity Reliably Available Capacity Peak Load Remaining Capacity RC Adequacy Reference Margin ARM Table 7-1: UCTE - Generation System Adequacy Forecast in GW ( ) LI Page 7-2

123 1.6 times higher than the maximum load and amounts to 625,000 MW. The dominating power generating facilities are fossil fuelled power stations with a proportion of 52% (326 GW). Hydro power stations contribute a share of 22% (135 GW) and nuclear power stations contribute some 18% (111 GW). The remaining proportion of 8% is covered by other renewable energy sources than hydro (53 GW of which 42 GW are covered by wind power). Table 5-1 compares the installed national generating capacity with the maximum load over the period 2007 to The reliably available capacity figures consider maintenance and overhauls, outages, system services reserves and non-usable capacity (e.g. due to fluctuations in the use of renewable energy sources). In 2007 the actual reliably available capacity amounts to 391,200 MW (28% less than the installed capacity). The development of the national generating capacity is based on the UCTE scenario which takes into account future power plants whose commissioning can be considered as reasonably probable according to the information available for the European TSOs. This scenario is used to give the best view of possible evolution of adequacy provided expected investments in generation are made. Based on this assumption, the estimated investments would be sufficient to ensure the global adequacy over the period under study. The RC is staying at a comparable level with present situation (56 GW in the year 2007; 58 GW in the year 2020). But uncertainties on future developments and especially decommissioning which would result of regulatory context evolution, in relation with environmental Remaining Capacity RC in GW Adequacy Reference Margin ARM in GW Figure 7-2: UCTE Remaining Capacity and Reference Margin in GW ( ) LI Page 7-3

124 policies, are strong. Such decommissioning decisions, which are notified to TSOs with short delay, would negatively affect the margins. After the description of the expected development of the entire system, the following paragraphs provide details for selected regions of Continental Europe. Focus is given to the development of the Italian power generation and transmission system. For an individual country, RC minus the margin against the peak load should be at least 5% or 10% of the Net Generating Capacity (NGC). The synthetic feature is: to ensure the reliability of the system. RC should be higher or equal to the ARM defined as 5 or 10% of the NGC. The following two cases should be considered: Case I RC > ARM or RC = ARM In this case, the country has generating capacity available for export in most cases. Case II RC < ARM The country s system is likely to have to rely on import when facing in severe conditions. Thanks to expected commissioning of new conventional thermal plants, the remaining capacity of Italy is increasing. A large number of new plants have already started construction or are expected to do so. The Cambridge Energy Research Associates (CERA) expects that 17 GW of new capacity - mostly CCGTs will come online between 2007 and These plants will either replace old oil-fired units, sometimes as part of conversion programs, or add net capacity to the system. Item Year National Generating Capacity Reliable Available Capacity Peak Load Remaining Capacity RC Adequacy Reference Margin ARM Table 7-2: Italy - Generation System Adequacy Forecast in GW ( ) LI Page 7-4

125 The above Table 5-2 provides the projection of the peak load as well as the projection of the installed capacity in Italy. Under consideration of investments regarding the construction of new plants, re-powering of already existing units and subtracting the capacity of units to be decommissioned in the future, the installed capacity is expected to increase from 92 GW in 2007 to 112 GW in If these investments were actually confirmed and achieved, the situation of Italy would become quite different from what it was in the past. The RC would become higher than ARM from 2007 on. In 2020, the Remaining Capacity gets back under the ARM. Approximately 1 GW further investments would be needed in this year to achieve a total installed capacity of some 113 GW compared to an estimated peak load of 77 GW. It should be borne in mind that although the reliably available capacity of Italy s generation system is 15% higher than the maximum load the country imported lower-priced electrical energy in the past and is also expected to remain a net-importer in the future. An import export balance is presented in Figure 7-4. The Italian TSO Terna published the annual amount of electrical energy imported / exported in recent years. As shown in Table 7-3 some 45,580 GWh/a was imported, equal to 13% of the country s electricity consumption by 338,000 GWh/a in Remaining Capacity RC Adequacy Reference Margin ARM Figure 7-3: Italy Remaining Capacity and Reference Margin in GW ( ) LI Page 7-5

126 The main proportion of electricity delivered to Italy are: 52% via Switzerland; 33% from France; 12% via Slovenia. As an average load Italy imported 5.2 GW in As already mentioned above, Italy is expected to remain a net electricity importing country. Several investments are scheduled to improve the transmission interconnection structure. The main projects are: 380 kv Steinach (Austria) Prati; 400 kv Thaur (Austria) Bressanone; 220 kv Nauders (Austria) Curon / Glorenza; 380 kv Lienz (Austria) Cordignano; 380 kv Lienz Udine / Sandigro; and 380 kv Okroglo (Slovenia) Udine. 60,000 Exports (GWh/a) Imports (GWh/a) 50,000 40,000 30,000 20,000 10, ,000-20,000-30, Export (GWh) Import (GWh) Saldo (GWh) Figure 7-4: Italy Electricity Import and Export in Recent Years ( ) LI Page 7-6

127 Year Import in GWh/a Export in GWh/a Saldo in GWh/a , , , , , , , , , , ,328-1,103 48, ,580-1,618 43,962 Table 7-3: Italy Import and Export Balance ( ) According to information provided by the Albanian utility KESH, furthermore an EBRD financed feasibility study for an 85 km long 400 kv submarine DC interconnector between the port towns Vlora (Albania) and Brindisi is currently under preparation. As the result of already commissioned interconnection projects the exchange capacity between the main UCTE system and Italy will increase significantly by at least 2,000 MW over the period 2008 and To analyse transmission adequacy in a simplified way, a comparison between the average import (or export) capacity and the simultaneous import (or export) capacity can be carried out. At present Italy s simultaneous import capacity amounts to nearly 7,700 MW, limited to some 6,500 MW to France and Switzerland; 500 MW to Greece; 430 MW to Slovenia and approximately 220 MW to Austria. As described earlier, the average import capacity over an entire year amounts to 5,200 MW which is 68% of the reference capacity. Taking into consideration a load between 100 MW and 200 MW (only some 1% to 2% of the estimated installed interconnector capacity of Italy in 2010) which seems from today s point of view reasonable for further analysis within this study it can be stated, that physically the interconnected system between Italy and its neighbouring countries would be capable to absorb and transport such a volume. Beside the development of the cross-border electricity supply system one need to evaluate the extension of the domestic grid in Italy. According to the Grid Development Plan Terna provided the following information: Investments within the short term planning period ( ): In total 10,850 MVA new transformers at 380 kv voltage level; In total 2,430 MVA new transformers at 220 kv voltage level; LI Page 7-7

128 2,320 km new 380 kv transmission lines; 890 km new 120 to 150 KV transmission lines. Investments within the mid term planning period (after 2010): In total 4,000 MVA new transformers at 380 kv voltage level; In total 410 MVA new transformers at 220 kv voltage level; 920 km new 380 kv transmission lines; 190 km new 120 to 150 KV transmission lines. In total investments of 1,600 Mio EUR are estimated for short-term projects; and respectively 1,500 Mio EUR for mid-term projects. The investment program includes three major projects in Sicily. These are: (i) the second 380 kv AC link between the substations Sorgente and Rizziconi; (ii) the 380 kv AC single circuit line from Chiaronte to Cimmina; (iii) the 220 kv AC single circuit line from Partinico to Fulgatore. In accordance with UCTE the commissioning dates for the 380 kv lines are 2010, respectively Figure 7-5 shows the existing transmission grid of Siciliy, the link to Continental Europe as well as the planned system extensions. Figure 7-5: Sicily Current State and Development of the 220 kv and 380 kv Transmission System LI Page 7-8

129 After a detailed analysis of Italy further regions which could potentially supply electricity to Malta are described hereunder. Figure 7-6 provides the power import and export balance in Continental Europe. The following regions are summarised: Main UCTE The region includes Austria; Belgium; Bosnia Herzegovina; Croatia; France; Germany; Luxembourg; Slovenia; Switzerland and the Netherlands. South Eastern Europe The region includes Greece, Serbia, Montenegro and Macedonia CENTREL The region includes the Czech Republic; Hungary; Poland and Slovakia. Out of the above mentioned regions the ten countries with the largest installed generating capacity in 2007 are Germany: 124 GW; France: 116 GW; Italy: 92 GW; Spain: 79 GW; Poland: 33 GW; The Netherlands: 22 GW; Austria: 18 GW; Switzerland: 18 GW; Romania: 18 GW; and Belgium: 16 GW. An overview of the development of the generating capacity in Continental Europe is presented in Figure 7-7. Among the countries with the largest power generation sector, the highest capacity increase is expected for Spain (60% until 2020). Already since 2002, 17 GW of gas-fired (mostly CCGTs) capacity has been added. CERA - European Power Watch expects a further CCGT dominated capacity growth by 9 GW already in the short term planning period. Based on these investments in new plants, the Remaining Capacity (RC) is expected to grow from currently 6.0 GW to 7.8 GW in 2010 and 12.8 GW in In the Netherlands gas projects are also back on the agenda. The installed capacity is projected to grow by 54% until About 2 GW of new CCGTs are expected to be online for the short term. Due to a comparative slight increase of the domestic load (17% until 2020) the RC will increase in the future from 1.0 GW to 2.6 GW in 2010 and 4.7 GW in In Germany an increase of renewable-based generating capacity during the period from 2007 to 2020 is expected to be more than 30 GW, mainly in the North of Germany, so that it has to be transmitted to the main areas of consumption in the South and West of Germany. However, supplementary generation is needed from Around 4 GW of gas-fired plants are likely to be LI Page 7-9

130 UKTSOA NORDEL Island Operation GC RAC RL DSM RC ARM Generation Capacity Reliable Available Capacity Reference Load Demand Side Management Remaining Capacity Adequacy Reference Margin DC Lines in blue Figure 7-6: Continental Europe Import & Export Power Balance (January 2007) LI Page 7-10

131 added by 2010, and more are waiting in the pipeline. About 8 GW of coal projects are also scheduled to come online until However, a large share of added capacity will actually replace old fossil fuel-fired plants. Reserve margins will also be affected as nuclear plants are retired under the German phase-out program. The system s reserve margins will decrease significantly from today 9.9 GW to 8.2 GW in 2010 and 4.8 GW in The generating capacity of France is expected to increase by 23% to more than 140 GW in the year The French system remains the second largest in Europe behind Germany. The adequacy for the system is supposed to be met until 2010 provided that the load growth does not exceed 1.5% per year and that at least three of the combined cycle gas turbine projects launched by producers are actually achieved by CERA expects furthermore, approximate ly 3.3 GW of peaking capacity which will either be demothballed or added by After 2010, new generation will be needed to face consumption growth and to replace the decommissioning of oldest plants, mainly coal. About 1,000 MW per year of new capacity would be needed, apart Germany France Italy Spain Poland Netherlands Austria Switzerland Romania Czech Republic Belgium Portugal Greece Bulgaria Serbia Hungary Slovak Republic Bosnia - Herz. Croatia Slovenia Luxembourg Montenegro Macedonia Figure 7-7: Continental Europe Net Generating Capacity by Country in GW ( ) LI Page 7-11

132 from the new nuclear power plant EPR expected in 2012 and from the development of wind generation. Though combined cycle gas turbine expected projects may be an answer to this situation and projects will contribute to the stabilisation of the system s margins at their current level and even lead to a slight increase. RC is expected to grow slightly from 11.0 GW to 11.3 GW in 2010 and 13.6 GW in In Alpine Europe (Switzerland and Austria) reserve margins will tighten in the short term due to an average 18% increase of generating capacity. A number of projects have been announced, notably in Austria, but logistic and regulatory barriers need to be addressed to keep margins at their current level. The surplus of electricity in the north and the deficit of electricity in the south of Austria combined with insufficient north-south transmission capacity result in congestions on the transmission grid of Verbund-APG. The RC will grow slightly to 6.7 MW in the long term. The remaining capacity in Austria is relatively high because a large share of "Generating Capacity" consists of storage power plants (more than 6 GW). In Central and Eastern Europe reserve margins are likely to decrease for the region as a whole. Nuclear retirements, added to a small pipeline that falls short of covering additional needs, will lead to declining margins. Furthermore, large retirements (mainly ST technologies) are expected in the next decade. 7.2 Current and Future Electricity Price Levels This section deals with the historical development of electricity prices in recent years and provides an estimation of the future evolution of electricity purchase prices. As the basis for this exercise the main drivers for the cost of generating electricity will be assessed. The relevant costs of generating electricity can be divided into the following categories: Fixed costs Capital expenditures, i.e. the initial level of investment required to engineer, procure and construct a power plant. Fixed costs of operation and maintenance, e.g. staff salaries, insurance, rates and other cost which remain constant irrespective of the actual quantum of electrical energy sent-out. Variable costs Cost of fuel (if applicable) consumed in generating electricity. Variable costs of operation and maintenance, e.g. lubricating oil and chemicals, which are consumed in proportion to the actual amount of electrical energy sent-out. LI Page 7-12

133 The power generation system in the European Union is dominated by fossil fuelled power stations. In 2006 the installed capacity of gas burning plants was higher than the one of coal. At the end of 2006 the installed gas units capacity amounted to 154 GW that of coal units added up to some 152 GW. The overall capacity of oil fuelled power stations remained nearly constant by some 80 GW. Regarding such fossil fuel dominated systems, the main electricity generating cost components are: the capital cost on the fixed costs side; the fuel cost and therefore the fuel price on the variable costs side. To retrace the electricity costs trends in the past it is useful to take a look at the evolution of the above mentioned cost components. The market conditions and prices of relevant fuels supplied to Malta are already examined in Chapter 6 of this report. Although in recent years escalating fuel prices have taken centre stage in the sector, rising capital costs are now having an increasing impact on the electricity industry. Figure 7-8: Development of Specific Generation Capital Costs in EUR/kW ( ) LI Page 7-13

134 Figure 7-8 shows the specific capital cost of power generating technologies in the time period 2002 to All technologies bear an increasing trend of the specific capital cost of European power projects. Only over the past two years, capital costs have increased by around 30% for lignite or coal fired steam turbines and by around 15% by gas or gasoil fired combined cycle gas turbines. Today (first quarter of 2007) the average costs amounted to 1,300 EUR/kW of lignite fired steam turbines, 1,200 EUR/kW of coal fired steam turbines and some 500 EUR/kW of gas or gasoil fired combined cycle gas turbines. The following three main reasons are causing these increases: the dramatic increase of raw materials costs over the period under consideration (see Figure 7-9 below). Raw materials account for a large proportion of the entire power generation and supply (transmission and distribution) equipment; the transfer of stronger margins from utilities to equipment suppliers due to bottlenecks for individual components and skilled labour on the supplier s side; the reduction of competition and the consolidation among suppliers of equipment. Figure 7-9: Development of Raw Materials Costs in % ( ) LI Page 7-14

135 Figure 7-10: IHS Upstream Capital Costs Index in % ( ) Another capital cost criteria which is related to the cost of fuels supplied to the power stations is the cost of exploitation projects. In recent years, exploitation project cost for oil and gas escalated drastically above long term averages. The IHS upstream capital cost index tracks the costs of equipment, facilities, construction materials and personnel used in onshore and offshore gas and oil exploitation projects. By the end of the first quarter of 2007 the cost index reached an all time peak. Costs raised to 179% compared to the year In 2005 the index amounted to just 107% compared to the 100% figure in Having in mind the trends described above and examined already in chapter 6 one can understand easily why the liberalisation of many electricity markets in Europe does not lead automatically to a decrease of electricity generating costs and a drop of wholesale and retail prices. Figure 7-10 presents the historical development of the average European electricity prices for the (i) domestic (residential) sector; (ii) commercial (and small scale industry) sector; (iii) medium industry sector; (iv) large industry sector and (v) wholesale market. Furthermore, a short term projection by CERA is provided regarding the wholesale market price. With fully opening of the markets the degree of competition will develop faster. Further steps such as LI Page 7-15