© 2021 October | International Bank for Reconstruction and Development / The World Bank 1818 H Street NW, Washington, DC 20433 Telephone: 202-473-1000; Internet: www.worldbank.org Some rights reserved This work is a product of the staff of the World Bank. The findings, interpretations, and conclusions expressed in this work do not necessarily reflect the views of the World Bank, its Board of Executive Directors, or the governments they represent. The World Bank does not guarantee the accuracy of the data included in this work. The boundaries, colors, denominations, and other information shown on any map in this work do not imply any judgment on the part of the World Bank concerning the legal status of any territory or the endorsement or acceptance of such boundaries. Nothing herein shall constitute or be considered to be a limitation upon or waiver of the privileges and immunities of The World Bank, all of which are specifically reserved. 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All queries on rights and licenses should be addressed to World Bank Publications, The World Bank Group, 1818 H Street NW, Washington, DC 20433, USA; e-mail: pubrights@worldbank.org. All images remain the sole property of their source and may not be used for any purpose without written permission from the source. THE VALUE OF TRADE AND REGIONAL INVESTMENTS IN THE PAN-ARAB ELECTRICITY MARKET: INTEGRATING POWER SYSTEMS & BUILDING ECONOMIES OCTOBER 2021 CONTENTS 4 PREFACE 4.5. Key Challenges to Electricity Trade in the Pan- Arab Region 5 ACKNOWLEDGEMENTS 38 5. THE WORLD BANK’S 6 ABBREVIATIONS ELECTRICITY PLANNING MODEL 5.1. Key Features of the 7 EXECUTIVE SUMMARY Key Challenges to Advance Electricity Planning Model Electricity Trade in the Region 5.2. Description of the Cases Analytical Framework Analyzed Key Findings 42 6. MODELING INPUTS AND ASSUMPTIONS 14 1. STRATEGIC CONTEXT 1.1. Key Energy Developments 6.1. Existing Capacity Assumptions in the MENA Region 6.2. Planned and Under Construction Capacity 20 2. OVERVIEW AND PURPOSE OF THE REPORT 6.3. Peak Power and Energy Demand Projections 2.1. Current State of Power Systems in the Pan-Arab Region 6.4. Generation Technology Cost Assumptions 2.2. Studies of Pan-Arab Electricity Trade 6.5. Fuel Mix, Fuel Prices, and Consumption Limits 2.3. The Purpose of the Report 6.6. Renewable Energy Technologies 26 3. THE FUNDAMENTALS OF REGIONAL POWER 6.7. Costs of Failure to MARKET INTEGRATION Achieve Reliability of Supply 3.1. Development of Regional 6.8. Cross-Border Power Markets Interconnections 3.2. Benefits of Electric Power Trade 50 7. RESULTS 7.1. Peak Demand and Installed Capacity Projections 32 4. REGIONAL INTERATION OF ELECTRICITY MARKETS 7.2. Capacity Additions and IN THE PAN-ARAB REGION Investment Costs 4.1. The GCC Region 7.3. Total System Costs 4.2. Mashreq Region 7.4. Impact on Electricity Costs 4.3. Maghreb Region 7.5. Shared Benefits from 4.4. Rationale for Interconnecting Bilateral Trade the Three Subregions 7.6. Commercial Value of Trade 7.7. Impact of Trade on CO2 Emissions 94 APPENDIX D. INTENDED NATIONALLY DETERMINED 7.8. Impact of Energy Efficiency CONTRIBUTIONS (INDC) and Demand Response on the SUBMITTED BY SELECTED Benefits from Trade ARAB COUNTRIES 7.9. Summary of Potential Trade Benefits 95 APPENDIX E. SHARED ECONOMIC BENEFITS AND VALUE OF COMMERCIAL 64 8. TRANSMISSION INVESTMENT ANALYSIS TRADE IN ELECTRICITY IN US DOLLARS PER YEAR 8.1. Evaluating the Benefits of Interconnectors 8.2. Key Findings: Utilization of 98 APPENDIX F. ELECTRICITY PLANNING MODEL (EPM) Cross-Border Interconnectors METHODOLOGY and Benefit Analysis F.1. Notation 8.3. Transmission Interconnection F.2. Model Formulation Investment Costs F.3. Description of the Model F.4. Customized Configuration 80 REFERENCES of the Model F.5. Projected Demand Time Series 83 APPENDIX A. LITERATURE REVIEW 116 APPENDIX G. TRANSMISSION TECHNOLOGY AND COSTS 84 APPENDIX B. DETAILED INPUT ASSUMPTIONS G.1. Incompatibility of FOR THE ELECTRICITY Neighboring Systems PLANNING MODEL (EPM) G.2. 400 kV HVAC Transmission B.1. Installed Capacity and Lines and Substations Planned Capacity Additions G.3. HVDC Interconnections B.2. Energy and Peak Demand and Lines Growth Rates G.4. Assumptions for B.3. Typical Demand Profile Economic Studies B.4. Costs of Unserved Energy and Unmet Reserves 119 APPENDIX H. TECHNICAL CHARACTERISTICS AND B.5. Generation Technologies ESTIMATED PROJECT Capital Costs and Fuel Prices COST OF THE PROPOSED CROSS-BORDER 91 APPENDIX C. COUNTRY- SPECIFIC APPROACH TO TRANSMISSION LINES H.1. Summary Table of ESTIMATE CURRENT AND Transmission Options INTERNATIONAL GAS PRICES H.2. KSA-Northern Region Context Pan-Arab Countries C.1. Key Questions H.3. KSA-Egypt Mediterranean C.2. Summary of PAEM Model Coastal Interconnections Gas Price Assumptions H.4. Increasing GCCIA Power Trade Capability LIST OF TABLES 9 TABLE 1. Capacity Additions and Investment Costs 52 TABLE 14. Investment Requirements for Total Capacity Additions, by Case 16 TABLE 2. Obstacles to Meeting the Sustainable Development Goals in MENA 54 TABLE 15. Difference in Electricity Costs When Trading under Case 1: Current Gas Prices 29 TABLE 3. Illustration of Short- Term Economic Benefits from Electricity Trade 54 TABLE 16. Difference in Electricity Costs when Trading under Case 3: International 40 TABLE 4. Cases Considered for the Study Gas Prices 55 TABLE 17. Shared Economic 43 TABLE 5. Existing Installed Capacity by Technology and Benefits of Electricity Trade among the Arab Countries Country, in MW (2018) 57 TABLE 18. Commercial Value 44 TABLE 6. Planned/Under Construction Capacity by of Electricity Trade (Export or Import Value) among the Arab Technology and Country, in Countries MW (2018-30) 58 TABLE 19. Total Installed 45 TABLE 7. Technology Fuel, Heat Rate, and Costs Assumptions Capacity by Technology, MW 59 TABLE 20. Share of Total 46 TABLE 8. Regional Prices for Liquid and Solid Fuels Installed Capacity by Technology, including ($US/MMBTU) Renewable Energy Sources 47 TABLE 9. Current Natural Gas Price Assumptions, in US$/ 59 TABLE 21. Annual Average Growth Rate of Installed MMBTU, by Country Capacity by Technology, 2018-35 47 TABLE 10. International Natural Gas Price Assumptions, Based on EU Hub Prices, in 62 TABLE 22. Summary of Potential Electricity Trade US$/MMBTU, by Country Benefits across PAEM for the Period 2018-35 48 TABLE 11. Renewable Energy Capacity Factors 68 TABLE 23. Reinforced and Proposed New Interconnections 49 TABLE 12. Cross-Border Transmission Lines Assumptions, by Country 70 TABLE 24. Summary of Economic Benefits of Engaging in Regional Trade by Increased 51 TABLE 13. Projected Peak Demand and Total Installed Capacity by Utilization of Existing Cross- Border Interconnections Country, in GW, Case 0 (Base) 71 TABLE 25. Expected Flows and Utilization for 85 TABLE 33. Projected Average Annual Growth Rates Existing Cross-Border for Energy and Peak Demand Interconnections in 2035 90 TABLE 34. Natural Gas 72 TABLE 26. Summary of Economic Benefits for the Consumption Limit per Year, in Billion Cubic Meters (bcm) Pan-Arab Regional Trade by Commissioning Proposed 92 TABLE 35. Economic Natural Gas Prices in Arab Region, in $/ Cross-Border Interconnections MMBTU 73 TABLE 27. Expected Flows and Utilization of Proposed 92 TABLE 36. Country-specific Assumptions for Natural and Existing Cross-Border Gas Pricing without New Interconnections in 2035 Infrastructure 73 TABLE 28. Summary of Economic Benefits of 95 TABLE 37. Economic Benefit of Trade by Country (USD), Regional Trade between Case 1: Current Gas Prices GCC and Mashreq by Commissioning Proposed Cross-Border Interconnectors 95 TABLE 38. Economic Benefit of Trade by Country, Case 3: between Jordan, Saudi International Gas Prices Arabia, and Iraq. 96 TABLE 39. Economic Benefit 74 TABLE 29. Expected Flows and Utilization of of Trade by Country, Case 5: International Gas Prices, Proposed Cross-Border Carbon Caps Interconnections between GCC and Mashreq 96 TABLE 40. Commercial Value of Export Trade by Country, Case 1: Current Gas Prices 75 TABLE 30. Summary of Eco- nomic Benefits of Regional Trade between Mashreq and 97 TABLE 41. Commercial Value of Export Trade by Country, Maghreb by Commissioning Case 3: International Gas Prices Reinforced and Proposed Cross-Border Interconnectors among Morocco, Algeria, 97 TABLE 42. Commercial Value of Export Trade by Country, Tunisia, Libya, and Egypt Case 5: International Gas Prices, Carbon Caps 74 TABLE 31. Expected Flows and Utilization of Proposed Cross-Border Interconnectors 98 TABLE 43. EPM Main Inputs and Outputs between Mashreq and Maghreb (2035) 113 TABLE 44. Constraints and Features of EPM 78 TABLE 32. Summary Transmission Technical 117 TABLE 45. Cost Summary of Transmission Equipment Characteristics and Estimated Project Costs (EPC), $Million LIST OF FIGURES 13 FIGURE 1. Potential Electricity Trade Benefits (2018-35) 54 FIGURE 14. Total System Costs, Case 5 vs. Case 4 17 FIGURE 2. Selected MENA Countries’ Energy Price 56 FIGURE 15. Shared Economic Benefits of Trade Reforms and International for Cases 1, 3, 5 and 6 Oil Prices 57 FIGURE 16. Value of Trade 18 FIGURE 3. Global Weighted Average Total Installed Costs for Case 1 for the years 2020, 2025, 2030, and 2035 and Project Ranges for Solar PV, CSP, and Wind 57 FIGURE 17. Value of Trade for Case 3 for the years 2020, 21 FIGURE 4. Estimated Size of Selected Regional Electricity 2025, 2030, and 2035 Markets around the World 57 FIGURE 18. Value of Trade for Case 5 for the years 2020, 22 FIGURE 5. Share of Total Electricity Traded in Non- 2025, 2030, and 2035 OECD Regions (1990-2015) 57 FIGURE 19. Value of Trade for Case 6 for the years 2020, 28 FIGURE 6. Typical Phases of Regional Power Market 2025, 2030, and 2035 Integration 58 FIGURE 20. Total CO2 Emissions in 2018-35 34 FIGURE 7. Electricity Exchanges by GCC Members, 2014-17, in GWh 58 FIGURE 21. Total CO2 Emissions by Case, in Million Tons CO2 Equivalent, 2018-25 45 FIGURE 8. Projected Electricity Demand by 60 FIGURE 22. Renewable Energy Country, 2020-30, in TWh in Total Energy Generated 46 FIGURE 9. Regional and Country-by-Country Fuel Mix 61 FIGURE 23. Total System Costs, Case 3 vs. Case 6 for the Pan-Arab Region (2017) 61 FIGURE 24. Cumulative Capacity Addition by 2035, 47 FIGURE 10. Natural Gas Consumption Limit per Year, in GW in Billion Cubic Meters (bcm) 65 FIGURE 25. Analytical Framework Used to Assess 52 FIGURE 11. Total System Cost Comparisons (US$ Billion) the Benefit of Cross-Border Interconnections in the Pan- 53 FIGURE 12. Total System Costs, Case 1 vs. Case 0 Arab Region 66 FIGURE 26. Regional Network 53 FIGURE 13. Total System Costs, Case 3 vs. Case 2 with Existing Cross-Border Interconnections 69 FIGURE 27. Regional Network with Proposed and 77 FIGURE 37. Cross-Border Interconnection Utilization Reinforced Cross-Border Rates in 2035, when Trading Interconnections under International Gas Prices and Applying Demand-Side 69 FIGURE 28. Existing Cross- Border Interconnectors’ Measures (Case 6) Utilization in 2035 84 FIGURE 38. Existing Installed Capacity, by 2018, by 70 FIGURE 29. Annual Economic Benefits of Technology and Country, in MW Engaging in Regional Electricity Trade 84 FIGURE 39. Planned/Under Construction Capacity, by 2030, by Technology and 71 FIGURE 30. Proposed Cross- Border Interconnectors’ Country, in MW Utilization in 2035 85 FIGURE 40. Hourly, Seasonal Load Profiles, in 2018, by Country 72 FIGURE 31. Annual Economic Benefits of Engaging in Regional Electricity Trade 88 FIGURE 41. Technology Capital Cost ($ Million/MW) Using Proposed and Existing Interconnectors 88 FIGURE 42. Regional Prices for Liquid and Solid Fuels ($/ 74 FIGURE 32. Annual Economic Benefits of MMBTU) Engaging in Regional Electricity Trade Using 89 FIGURE 43. Current Natural Gas Price Projections, in $/ Proposed Interconnectors MMBTU, by Country 75 FIGURE 33. Annual 89 FIGURE 44. International Natural Gas Price Assumptions, Economic Benefits of Engaging in Regional Based on EU Hub Prices, in $/ Electricity Trade between MMBTU, by Country Mashreq and Maghreb 93 FIGURE 45. LRMC Incremental Production for 76 FIGURE 34. Cross-Border Interconnection Utilization Gas Fields in Algeria (up) and Egypt (down), in $/MMBTU Rates in 2035: Trading under Current Gas Prices (Case 1) 98 FIGURE 46. Structure of the World Bank Electricity 76 FIGURE 35. Cross-Border Interconnection Utilization Planning Model Rates (2035): Trading under International Gas Prices 117 FIGURE 47. Transmission Line Towers (Case 3) 77 FIGURE 36. Cross-Border 120 FIGURE 48. Coastal Interconnections Interconnection Utilization Rates 2035, when Trading under International Gas 15 BOX 1. The World Bank’s Regional Strategy in the Prices and Applying CO2 Middle East and North Africa Emission Limits (Case 5) PREFACE Energy demand in Arab countries continues to grow at a higher rate than economic growth. Meeting national electricity demand and exploiting their significant renewable energy resources (particularly, solar and wind) in a sustainable manner is a common challenge across all Arab countries. A number of analyses have pointed out that such countries would benefit greatly from the increased integration of their power systems, and the resulting opportunities for electricity trade.1 The prospects of regional electricity trade in Arab countries have been the focus of a number of studies in recent years. While the potential economic and technical benefits of trade are substantial, so are the challenges, necessitating a political will supported by a shared vision for regional electricity trade. Related plans would do well to be aligned with national goals and to put forward objectives, outline key trade drivers, and identify milestones and their timing. This study, The Value of Trade and Regional Investments in the Pan-Arab Electricity Market: Integrating Power Systems & Building Economies (VOTRI), quantifies the potential economic benefits that a Pan-Arab Electricity Market (PAEM) could bring if the countries2 across the Middle East and North Africa (MENA) were engaged in full electricity trade on a commercial basis. The World Bank’s Electricity Planning Model (EPM) was used to prepare the region’s least-cost capacity expansion and dispatch scenarios optimizing the regional power systems in the period 2018–35. The EPM, details of which are described in appendix F, demonstrates there are direct, sector-level gains from being able to efficiently develop and deploy generation assets at a regional level and optimize cross-border economic power trade (instead of each country developing its own generation resources). Such optimization approach is in line with the PAEM vision. These benefits include increased access to lower-cost, more efficient, and cleaner generation alternatives in an expanding market that can meet export as well as domestic electricity demand. The long-term vision is that the PAEM will be created in five stages that lead to a fully integrated market in 2035 and a fully competitive wholesale market in 2038. This study outlines the first stage of market development and paves the way for early operations of the market in the second stage, along with priority investments to maximize the realization of electricity trade benefits across the PAEM. 1 It is important to note that this study was completed before the COVID-19 pandemic was declared by the World Health Organization (WHO), and it was set to be released following the Arab Ministerial Council for Electricity (AMCE) extraordinary meeting planned in March 2020 to approve the PAEM agreements ratification. However, this meeting was moved to July 2020 due to the pandemic and, therefore, the study was not released. Despite the change in the meeting date, agreements were ratified and recommendations stated in this report are still relevant and timely. 2 In this study, the term “Pan-Arab countries” refers to 17 countries located across MENA–Algeria, Bahrain, Egypt, Iraq, Jordan, Saudi Arabia, Kuwait, Lebanon, Libya, Morocco, Oman, Qatar, Sudan, Syria, Tunisia, the United Arab Emirates, and Yemen–plus the West Bank and Gaza. Countries’ data were shared and gathered during and between four consultations: in Kuwait City, Kuwait, in November 2017; in Tunis, Tunisia, in March 2018; in Rabat, Morocco, in September 2018; and, in Algiers, Algeria, in January 2019. The countries that provided complete or partial data were Algeria, Bahrain, Iraq, Jordan, Kuwait, Libya, Morocco, Qatar, Saudi Arabia, and Sudan. For those countries missing model parameters, inputs were estimated from publicly available annual reports, online articles, and other sources. OCTOBER 2021 // 4 ACKNOWLEDGEMENTS This report was prepared by Dr. Ilka Deluque Curiel (Energy Consultant, and Principal Author) with support from Victor Loksha (Senior Energy Consultant) under the Pan-Arab Regional Energy Trade Initiative led by Waleed Alsuraih (Task Team Leader and Lead Energy Specialist), and comprising Alexander Huurdeman (co-Task Team Leader and Senior Energy Specialist), Emmanuel Py (Senior Energy Specialist), Mohammed Qaradaghi (Senior Energy Specialist), Debabrata Chattopadhyay (Senior Energy Specialist), Abdulaziz Al-Shalabi (Energy Specialist), Mark Njore (Program Assistant, Energy), Doug Bowman (Consultant, Senior Energy Specialist), John Irving (Consultant, Senior Power Engineer), Dr. Peter Meier (Consultant, Senior Energy Economist), Alona Kazantseva (Consultant, Energy Specialist), and Javier Inon (Consultant, Energy Specialist). The World Bank’s Pan-Arab Regional Energy Trade Initiative was incorporated by the World Bank’s Middle East and North Africa (MENA) Climate Action Plan, where it contributes specifically to commitment no. 5—enabling collective action. The initiative is also in line with the World Bank’s new MENA regional strategy, where it is an essential part of the focus on regional cooperation. The team is grateful to its regional management (inter alia, Anna Bjerde and Stefan Koeberle, Directors, Strategy and Operations, MNAVP; Sajjad Shah-Sayed, Manager, MNADE; and Deborah Wetzel, Director, AFWRI) and to its global practice management (Riccardo Puliti, Senior Director; Paul Noumba Um, Regional Director; and Erik Fernstrom, Practice Manager) for their support and funding. Vivien Foster (Chief Economist, Infrastructure) and Arthur Kochnakyan (Senior Energy Specialist) served as peer reviewers and substantively enhanced the quality of the report. The task team wishes to acknowledge the support and cooperation extended to it by members of the steering committee and of the study team of the Pan-Arab Electricity Market, who provided feedback on the report at its early stages. Further gratitude is owed to development partners and members of the private sector for sharing information and insights on both key energy sector development challenges and possible solutions. This publication was initially released at the First Pan-Arab Regional Energy Trade Conference held in Cairo, Egypt, on November 6-7, 2019. The conference was co-organized by the World Bank (with support from PPIAF and ESMAP), the Arab Fund, and the League of Arab States. The conference gathered Arab and international experts and decision makers to exchange experiences—creating momentum, a shared vision, and an action plan for regional energy trade and partnerships in both electricity and gas. Special acknowledgment — The task team wishes to acknowledge the generous funding provided for this report by the Public-Private Infrastructure Advisory Facility (PPIAF). PPIAF is a multi-donor trust fund housed in the World Bank Group that provides technical assistance to governments in developing countries. PPIAF’s main goal is to create enabling environments through high-impact partnerships that facilitate private investment in infrastructure. For more information, visit www.ppiaf.org. The financial and technical support by the Energy Sector Management Assistance Program (ESMAP) is gratefully acknowledged. ESMAP is a partnership between the World Bank and 19 partners to help low and middle-income countries reduce poverty and boost growth through sustainable energy solutions. ESMAP’s analytical and advisory services are fully integrated within the World Bank’s country financing and policy dialogue in the energy sector. Through the World Bank Group (WBG), ESMAP works to accelerate the energy transition required to achieve Sustainable Development Goal 7 (SDG7) to ensure access to affordable, reliable, sustainable and modern energy for all. It helps to shape WBG strategies and programs to achieve the WBG Climate Change Action Plan targets. The report was edited by Fayre Makeig and Stephen Spector. It was designed by Nursena Acar. 5 // ACKNOWLEDGEMENTS ABBREVIATIONS AC alternating current AUE Arab Union of Electricity CO2 carbon dioxide CSP concentrating solar power EIJLLPST Egypt, Iraq, Jordan, Libya, Lebanon, West Bank and Gaza, Syria, and Turkey ENTSOe European Network of Transmission System Operators for Electricity EPM Electricity Planning Model EU European Union EWA Electricity and Water Authority (Bahrain) GCC Gulf Cooperation Council GCCIA Gulf Cooperation Council Interconnection Authority GW gigawatt HVAC high voltage alternating current HVDC high voltage direct current IEA International Energy Agency INDCs intended nationally determined contributions ISCC integrated solar combined cycle LAS League of Arab States LNG liquefied natural gas MMBTU million British thermal units MW megawatt MWh megawatt-hour O&M operations and maintenance OECD Organisation for Economic Co-operation and Development OHTL Overhead Transmission Line PAEM Pan-Arab Electricity Market PA-REPT Pan-Arab Regional Energy Trade Platform PV solar photovoltaic SAOC Oman Electricity Transmission Company SIEPAC Central American Electrical Interconnection System TWh terawatt-hour USE unserved or unmet energy USR unserved reserve VoLL value of lost load VRE variable renewable energy Note: Economic and financial calculations expressed in US dollars refer to the US dollars (US$) of 2018. OCTOBER 2021 // 6 EXECUTIVE SUMMARY “The Value of Trade and Regional Investments in the Pan-Arab Electricity Market: Integrating Power Systems & Building Economies” (VOTRI), presents a compelling economic case for the increased integration of power systems among the Arab states to advance commercial cross-border electricity trade. A Pan-Arab Electricity Market (PAEM)3 operating across the Middle East and North Africa (MENA) would bring significant value to the treasuries, utilities, and citizens of the region. This value comes at a critical time, when energy demand far exceeds economic growth.4 Many of the region’s utilities are under financial strain and find themselves unable to invest in new infrastructure at the levels required to meet growing demand. Meanwhile, some countries realize that they have overinvested in supply and will soon have a supply glut after meeting domestic demand. In 2015, the region’s fiscal deficits averaged 9.3 percent of gross domestic product, and the economies with the largest deficits were also those with the highest levels of electricity subsidies. As economies adjust to their present fiscal situation, there will be a scarcity of financing available for the electricity sector.5 This implies a need to find sources of financing other than the public sector to support infrastructure investments that keep pace with increasing demand. The savings and benefits derived from electricity trade present a strategic opportunity for treasuries and utilities to ease their financial burdens, and best leverage their existing assets in case of a surplus. A number of detailed technical studies have made the case for regional economic integration, demonstrating the value of cross-border connectivity and the enhancement of electricity trade and investment opportunities. Over the past few years, several key drivers have started to reshape the global energy landscape and motivate countries’ transitions to cleaner energy. In particular, a low- carbon energy mix has become a priority in many countries; technological advances—enabled by generous financial support and mandatory requirements—have led to dramatic drops in the cost of renewable energy, especially wind and solar energy; the Paris Agreement on climate change was adopted in late 2015 by 196 countries and formally ratified in 2016; and there has been a scale up of energy subsidy reform programs across the Middle East and North Africa. In this context, the purpose of this report is to build on previous studies and assess the implications of various drivers for electricity trade in the PAEM. In particular, this report seeks to (i) assess the benefits of promoting electricity trade among countries in the Pan-Arab region; and (ii) identify the cross-border transmission investments promising the greatest return in terms of these benefits. The identified economic benefits from electricity trade consist of deferred new generation capacity investments due to the improved utilization of capacity resources across the region; fuel savings obtained by new renewable energy production and accessing lower fuel-cost generation from other countries in the region; and greater opportunity to meet capacity and energy reserve requirements at lower cost. 3 For the purposes of this study, the integration of 18 electricity markets across MENA is considered: Algeria, Bahrain, Egypt, Iraq, Jordan, Saudi Arabia, Kuwait, Lebanon, Libya, Morocco, Oman, Qatar, Sudan, Syria, Tunisia, the United Arab Emirates, the West Bank and Gaza, and Yemen. 4 The fast-emerging plan to build the PAEM to advance electricity trade across the Arab countries has been given even greater urgency by the dual crisis of COVID-19 and the oil price collapse. Electricity is one of the critical sectors that will help revive the Arab economies when they start to reopen and rebuild. Electricity trade has the potential to play a key role in those stages. 5 Shortage of financing from the oil price collapse has been amplified by the COVID-19 pandemic, leading to significant austerity measures implemented across the Arab world and delaying power generation projects. 7 // EXECUTIVE SUMMARY KEY CHALLENGES TO ADVANCE ELECTRICITY TRADE IN THE REGION Electricity trade among the Arab countries has historically been very low. Despite the fact that considerable cross-border interconnection capacity exists, only 2 percent of electricity produced in the MENA region is traded. The Gulf Cooperation Council (GCC) subregion is the most interconnected (compared with the Mashreq and Maghreb subregions).6 Still, barriers such as an uneconomical pricing framework constrain trade volumes and leave market participants to prefer exchanges “in-kind” (that is, electricity for electricity) rather than for cash, and to focus on emergency operations. Also, utilization of existing interconnection capacity is quite low, at 5 to 7 percent on average. Achieving higher volumes of electricity trade in the region requires addressing the following core challenges. • Countries need to develop and agree on a pricing approach suitable for cross-border trade and transmission “wheeling”7 on a commercial basis. Removing domestic subsidies on the fuel for power generation in each country engaged in cross-border trade is the key solution in the long term. Applying international fuel prices specifically to cross-border transactions without eliminating subsidies at home is a possible interim solution in the early phases of the regional market. However, countries are encouraged to accelerate the phasing out of these subsidies to fully exploit the potential of trade. • Regional institutions for power trade need to be established and empowered within a common framework that ensures efficient coordination. The development of regional institutions can build on current experience in the region. Governments would benefit by establishing designated and authorized national entities to institutionalize electricity trade in close coordination with the regional institutions envisaged under the PAEM governance framework. Governance documents, including the PAEM General Agreement and the Market Agreement, will form the legal basis for the institutions and the market they will support. • Harmonized regulations of cross-border trade need to be developed. The PAEM would establish needed market rules and grid codes (or technical requirements for different technologies and system configurations), with the understanding that Member States will advance needed reforms in their own territories at their own pace. Eventually, harmonized regulations will play a key role in realizing the ultimate PAEM’s vision of a competitive market. • Mobilizing finance for investment in generation and transmission assets is also needed. This is best prioritized within a coordinated regional planning framework that optimizes the investments and operations at the PAEM level and allows participating countries to meet domestic demand in cost-effective and efficient ways. 6 In this study, we refer to the Mashreq subregion as comprising eight countries/economies: Egypt, Iraq, Jordan, Lebanon, Libya, West Bank and Gaza, Sudan, and Syria. 7 Wheeling is the transportation of electric energy (megawatt-hours) from within an electrical grid to an electrical load outside the grid boundaries (https://en.wikipedia.org/wiki/Wheeling_(electric_power_transmission). OCTOBER 2021 // 8 ANALYTICAL FRAMEWORK The study explores a number of scenarios, or cases, each assuming a different set of economic and policy conditions. The period of analysis is 2018–35. To estimate the economic benefits of regional electricity trade, each case that assumes the possibility of trade (Cases 1, 3, and 5) has a complement case that assumes no such possibility (namely, Cases 0, 2, and 4, respectively), with three pairs of scenarios in all. In addition to the above cases, a demand-side policy scenario (Case 6) was added to study the impact that lower demand growth would have on electricity trade. The economic benefits of trade are calculated as the difference in system costs estimated for each pair (that is, with and without trade). The study considers cross-border power trade via both existing and planned interconnections. Although the three pairs of scenarios assume largely similar physical infrastructure, they differ in terms of the policies that underpin cross-border trade: • The first pair (Cases 0 and 1) assumes that natural gas in participating countries would be priced at its current, subsidized levels. • The second pair (Cases 2 and 3) assumes that all countries price domestic gas at international8 levels using European Union Hub prices as a proxy (i.e., unsubsidized gas prices). • The third pair (Cases 4 and 5) assumes the setting of carbon dioxide (CO2) emission limits in addition to a switch to international gas prices. KEY FINDINGS REQUIRED GENERATION CAPACITY DECREASES WITH TRADE Electricity trade decreases the total generation capacity required in the region. By 2035, Case 1 installs 11 GW less capacity relative to Case 0; Case 3 adds 15 GW less capacity relative to Case 2; and Case 5 saves as much as 63 GW relative to Case 4. In the demand-side policy scenario (Case 6) the Table 1. Capacity Additions and Investment Costs reduction in generation capacity is significant Case 0 Case 1 Case 2 Case 3 Case 4 Case 5 Case 6 compared to all trade scenarios in Cases 1, 3, CC 237 230 200 186 210 199 147 and 5. Table 1 illustrates the total cumulative CSP 1 0 1 0 161 98 0 capacity additions, in GW, by technology and GT 27 17 24 14 17 11 12 total investment cost. Hydro 1 1 1 1 3 3 1 PV 65 61 61 63 57 58 53 ST 1 - 1 - 1 1 - Wind 13 25 37 41 46 47 25 TRADE BRINGS REGIONAL Nuclear 3 2 40 47 48 63 23 Coal 13 13 13 13 11 11 13 POWER SYSTEM COST Total (GW) 361 350 379 364 553 490 274 Investment SAVINGS (US $billion) 263 252 366 368 745 625 253 Regional integration and electricity trade can Note: CC = combined cycle; CSP = concentrating solar power; GT = gas turbine; Hydro = hydroelectricity; PV = photovoltaic; ST = steam turbine; lead to massive cost savings. The region could GW = gigawatt. 8 Due to the lack of a global market price for natural gas, international gas prices are set to the estimates and projections of the trading hub closest to the region, in this case the European Union (EU) Hub. 9 // EXECUTIVE SUMMARY see tremendous benefits from tapping into a more diverse set of resources and pooling the operating reserves as well as generation capacity of more than one country. This allows the postponement of some expensive investments to meet national-level peak demand, while improving reserve margins, contributing to better security of supply. When natural gas is priced at current domestic levels, the total system costs decrease in present value terms by US$110 billion with the introduction of electricity trade, or by 8.2 percent of the system cost absent trade. Similar savings due to trade are achieved in the scenarios with unsubsidized (international) gas prices, in which case the total system costs decrease by US$107 billion. When the liberalization of gas prices is accompanied by the introduction of carbon caps in line with countries’ intended nationally determined contributions, the benefits of trade are even greater, reducing the system costs by US$196 billion, or by 13 percent. Finally, with demand-side (energy efficiency) policies assumed to gradually lower electricity demand (by 0.5 percent in 2020, 10 percent in 2025, and 20 percent in 2030–35), the system costs decrease by US$107 billion, or about 9 percent, relative to the scenario with trade under international gas prices but without demand-side policies. A large part of the trade benefits can be attributed to the ability of an integrated system to better meet each country’s demand and capacity reserve requirements. The composition of benefits varies greatly across the policy scenarios. With regional integration and trade, the costs of meeting reserve requirements fall especially sharply as trade enables greater access to reserves through cross-border transmission interconnections. The other cost-saving components differ by scenario. For example, there are large fuel cost savings due to electricity trade under both current and international gas prices, but not under carbon caps. On the other hand, much more capital expenditure is saved due to trade with carbon caps than without them. NATURAL GAS PRICES SIGNIFICANTLY AFFECT TRADE Adopting international gas prices would help ensure that generation technologies are competing on a level playing field. While the switch from current gas prices to international prices leads to higher installed capacity requirements and higher capital costs, the fuel cost savings more than offset these when the costs of gas subsidies are taken into account. Also, renewable technologies are deployed at a higher rate under international prices as they are more competitive under nondiscriminatory market conditions. Moreover, using international gas prices leads to reductions in carbon emissions. If the CO2 emissions under the case of using these prices are compared with those under the current domestic prices, the emission savings amount to 1.08 billion tons of CO2 equivalent when there is no trade, and to 1.24 billion tons when there is trade (cumulative over 2018-35). IMPACT ON ELECTRICITY SUPPLY COSTS The effect of trade on cost of electricity would vary across the region. The introduction of electricity trade would impact electricity costs differently in each country context. Many countries—mostly those with substantial generation gaps or low resources—could expect to see reductions. In some countries, the impact of trade on electricity costs would be marginal. In countries that are net exporters, the cost of electricity would increase. These are mainly gas exporters that have an incentive to invest more in generation capacity due to their ability to generate electricity at lower cost. However, as they install more generation capacity, the cost of electricity also rises as their effective demand, including export requirements, rises. They may need to utilize existing generators that would not otherwise be utilized without trade, or even to invest in progressively higher-cost generation technologies. OCTOBER 2021 // 10 TRADE UNLOCKS RENEWABLE ENERGY POTENTIAL AND REDUCES CO2 EMISSIONS Carbon policies that regulate emissions will be required in addition to trade to meet the region’s emissions reduction targets. The impact of power system integration and trade on the region’s CO2 emission trajectory was found to be moderately positive (that is, leading to moderate reductions in CO2 emissions relative to cases with no trade). However, this impact is less pronounced than that of the other key variables, such as the level of gas prices or the introduction of CO2emission limits. With gas prices at current levels, the CO2 emission reductions due to trade are almost negligible. The reductions become more significant when the gas prices are set at the EU Hub as a proxy. When CO2 emission caps are also introduced, the impact of trade decreases again, but the additional emission savings due to the caps are striking: 1.3 billion tons of CO2 without trade and about 1.1 billion tons with trade. Trade also decreases the cost of compliance with CO2emission targets, indicating the synergies existing between trade and the intended nationally determined contributions (INDCs) published by the Pan-Arab countries after the 21st Conference of the Parties (COP21) to the United Nations Framework Convention on Climate Change. The dynamics of CO2 emissions are driven to a large extent by the changing mix of generation technologies. By 2035, the share of zero-emission renewable energy technology in the region is expected to increase dramatically, albeit starting from a very low base (1.4 percent in 2018). In the six cases considered, the share of renewable energy (wind, solar photovoltaic, and concentrating solar power) in total installed capacity in 2035 reaches anywhere from 14.5 percent (Case 0) to 18.1 percent (Case 3) to 32.7 percent (Case 4). INVESTMENTS IN CROSS-BORDER INTERCONNECTION TO UNLOCK ELECTRICITY TRADE POTENTIAL Investments in cross-border transmission infrastructure are necessary to fully exploit the potential benefits of regional electricity trade by unlocking the trade opportunities beyond bilateral agreements. Under current assumptions for all the cases analyzed in this study, the lines that would be consistently utilized over 50 percent during the analysis period 2018-2035 are: • Algeria Tunisia • Saudi Arabia Yemen • Egypt Sudan • Syria Iraq • Jordan Egypt • Syria Lebanon • Libya Tunisia • Gulf Cooperation Council Interconnection • Saudi Arabia Egypt Authority (GCCIA) Bahrain • Saudi Arabia Jordan • Gulf Cooperation Council Interconnection Authority (GCCIA) Kuwait • Saudi Arabia Iraq • Gulf Cooperation Council Interconnection • Saudi Arabia Kuwait Authority (GCCIA) Saudi Arabia These transmission lines are therefore considered a priority for investments as they play a critical role in realizing the value of trade and overall trade benefits across the PAEM. Developing a comprehensive transmission investment plan that aligns national and regional system requirements is an important next step toward the envisioned PAEM. To assess the benefits of trade, this study considers 25 transmission investment projects across the region, including 15 projects that reinforce the existing transmission infrastructure and 10 projects of newly built transmission lines. In total, this would add 18.5 GW of cross-border transmission capacity. The initial estimated investment cost for these transmission projects reaches a total of $7.5 billion. 11 // EXECUTIVE SUMMARY Interconnection Reinforcements • Algeria Morocco, 600 MW • 3rd circuit of Jordan Syria, 200 MW • Egypt Jordan, 650 MW • Lebanon Syria, 730 MW • Egypt Sudan, 1,000 MW • Saudi Arabia GCCIA Interconnection, 600 MW • Egypt Gaza Strip, 175 MW • Kuwait GCCIA Interconnection, 600 MW • Jordan West Bank, 160 MW • Qatar GCCIA Interconnection, 1050 MW • Libya Egypt, 370 MW • UAE GCCIA Interconnection, 900 MW • 2nd circuit of Libya Egypt, 450 MW • Bahrain GCCIA Interconnection, 600 MW • 2nd circuit of Jordan Syria, 450 MW New Cross-Border Interconnections • Saudi Arabia Egypt, 3,000 MW • Saudi Arabia Iraq, 1,000 MW • Saudi Arabia Yemen, 500 MW • Jordan Iraq, 500 MW • Tunisia Libya, 500 MW • Oman Saudi Arabia, 1,000 MW • 2nd Circuit of Tunisia Libya, 500 MW • Kuwait Iraq, 1,000 MW • Saudi Arabia Jordan, 1,000 MW • Kuwait Saudi Arabia, 1,000 MW ESTIMATED ECONOMIC BENEFITS FOR MARKET PARTICIPANTS AND COMMERCIAL VALUE OF ELECTRICITY TRADE In addition to the above main method for estimating the benefits from trade and investment in the MENA region, based on total system cost savings, two alternative metrics have been also evaluated in this study. They point, respectively, to large benefits to be gained and shared by trading partners through bilateral transactions; and similarly large export and import values to be exchanged in the market, contributing to its liquidity. Economic benefits based on generation cost differentials that exist in many country settings across the region are very substantial and can be shared by trading countries. For three main cases with trade, these benefits are between US$32 billion (Case 3, international gas prices) and US$150 billion (Case 5, international gas prices and carbon caps). Commercial value of trade, a financial metric measuring the potential volume of export and import transactions in the market, has the same order of magnitude. The calculated values range between US$60 billion (Case 1, current natural gas prices) and US$167 billion (Case 5). Increasing the existing cross-border interconnections’ utilization, in the period 2018–35, results in an estimated US$72 billion in total system cost savings and US$23 billion in commercial value of trade. Investing in regional cross-border transmission projects to add a total of 18.5 GW of new or reinforced interconnectors to the regional network would increase total system cost savings by US$35 billion (to a total of US$107 billion, for Case 3) and the commercial value of trade by US$39 billion (to a total of US$62 billion, for Case 3) at a cost of US$7.5 billion. This indicates that investing $1 to expand regional cross-border trade saves $4.6 in total system costs and increases the commercial value of trade by $5.10 (in Case 3). OCTOBER 2021 // 12 Finally, figure 1 provides a summary of potential electricity trade benefits across the PAEM in 2018–2035 based on the analyzed cases and cross-border transmission investments. Figure 1. Potential Electricity Trade Benefits (2018–35) System costs savings Improving energy security: due to coordinated Unmet reserve cost savings: investment and trade: 32%–69% of total system $107–196 billion cost savings Shared Economic Bene ts Emissions reduction - lower from bilateral trade: cost of compliance with $32–150 billion Emission Reduction Targets: PAEM’s $86 billion cost reduction Bene ts in with trade Commercial Value of trade, 2018-2035 Enabling higher share of export/import value: $60–167 billion renewable energy: 16–28% of capacity in 2035 (vs. 1.4% 2018) Increased average Catalyzing private investment in cross-border transmission renewable energy technologies: capacity utilization: $64–305 billion 37–43% (vs. 5–7% in 2018) Source: World Bank modeling results 13 // EXECUTIVE SUMMARY THE VALUE OF TRADE AND REGIONAL INVESTMENTS IN THE PAN-ARAB ELECTRICITY MARKET: INTEGRATING POWER SYSTEMS & BUILDING ECONOMIES 1 STRATEGIC CONTEXT Starting from its significant update in 2015 (WBG to transformation, while keeping a focus on the 2015), the World Bank Group’s regional strategy fundamentals. in the Middle East and North Africa (MENA) The energy sector plays a key role in the builds on the platform of advancing peace and regional strategy. Throughout its recent stability directly, as a new area of engagement, updates (WBG 2015, 2018a, 2019a), the rather than working around conflict as an energy sector has been one of the strategy’s inevitable reality. This strategic shift has required key elements. This reflects the sector’s great deepening partnerships and convening more significance as: with regional partners, pushing more strongly for private investments, focusing more on regional • A key driver of economic growth and thus programs in key sectors, including energy, and an integral part of the World Bank’s twin applying innovative financing mechanisms goals— reducing poverty and promoting to attract capital from a more diverse pool of shared prosperity sources. • A critical element of the World Bank’s Regional cooperation has been established commitment to the United Nations as one of the four strategic pillars of the Bank’s Sustainable Development Goals (see table 2) engagement in MENA (see box 1). Regional • A significant arena of technological integration of infrastructure and markets is key to transformation, with attendant risks and establishing such cooperation. opportunities for the region’s fossil-fuel- dependent economies Box 1. The World Bank’s Regional Strategy in • A sector requiring substantial structural the Middle East and North Africa reform in many countries, including pricing/subsidy reforms, to restore The four fundamental pillars (“4 Rs”) macroeconomic and fiscal balances and underpinning the scope of the World Bank attract private investment Group’s engagement in the Middle East and North Africa region have been established • A significant contributor to regional as: (a) renewal of the social contract; (b) economies that is historically falling resilience to shocks, including those due behind its great potential for regional to refugee crises and climate change; (c) integration regional cooperation; and (d) recovery • A major component of climate change and reconstruction. The focus on these mitigation measures across all countries, fundamentals was further enhanced by particularly for those which submitted enlarging the strategy in 2019 to support their Intended Nationally Determined regional transformation for inclusive Contributions after the 21st Conference of growth and quality jobs. The strategy, the Parties (COP21) therefore, was strengthened by adding three more priorities, namely: human capital Regional trade in electricity, as well as in natural development; digital development; and gas, can become a transformative force for maximizing finance for development. market integration and sustainable development. In the Arab countries, there are great potential Source: WBG 2015, 2016a, 2017a, 2018a, 2019a. benefits from increasing electricity and gas trade beyond their current levels. Furthermore, regional integration is seen as a Table 2 shows that there are many areas in the transformative force. After the 2011 Arab Spring region’s energy sector development where a and various additional shocks that followed, the transformational impact can and should be region entered a period of relative stability— achieved in order to reach the Sustainable but conflicts remain across the region. The Development Goals. One area requiring radical enlarged MENA regional strategy (WBG 2019a) transformation is renewable energy, whose calls on the region to move from stabilization deployment is at a very low level across the 15 // 1. STRATEGIC CONTEXT Table 2. Obstacles to Meeting the Sustainable Development Goals in MENA SDG Name SDG Objective(s) Salient Issues/Challenges in MENA SDG 7: A ordable Ensuring access to a ordable, High energy access rates and a ordability, but signi cant challenges with energy and Clean Energy reliable, sustainable and security and environmental sustainability: modern energy for all - High energy intensity and the dominance of fossil fuels contribute to high GHG emissions - Renewable energy contributing only about 1% of the total energy mix SDG 8: Decent Promoting sustained, inclusive, -GDP growth has been below the global average in recent years, at a modest 1.7 Work and and sustainable economic percent in 2018 and forecast at 2.7 percent in 2021 Economic Growth growth, full and productive - Unemployment rates are high, especially among women employment and decent work - Opportunities for large youth population are constrained by lack of access to for all quality internet and digital money SDG 9: Industry, Building resilient infrastructure, Enormous capital needs for infrastructure (about US$2.5 trillion over the period of Innovation, and promoting inclusive and 2016–2030), leaving infrastructure nancing gaps in countries, including 0.9% of Infrastructure sustainable industrialization GDP in Saudi Arabia and fostering innovation SDG 13: Climate Urgent action to combat - On the mitigation side, urgent action is needed for phasing out energy subsidies, Action climate change and its impact higher energy e ciency and reduced gas aring and scaling up investment in renewables (including through cross-border market integration). - The region is very vulnerable to climate change, calling for mobilizing large funds for adaptation projects. Source: WBG 2018b; WEC 2017; MGI 2016. Note: GDP = gross domestic product; GHG = greenhouse gas; MENA = Middle East and North Africa; SDG = Sustainable Development Goal. region. A much greater role for renewables is attractive to investors and developers (WBG now possible, given that their installed costs per 2018c, 2019b). kilowatt are steadily falling worldwide. However, Recognizing the need to diversify their energy subsidized prices for electricity produced from sectors, many countries of the MENA region fossil fuels make it difficult for renewable energy have launched programs to increase the share to compete. of renewable energy in power generation— Generation fuel price subsidies, which are particularly solar and to a lesser degree onshore widespread in the MENA region, have several wind. This is meant to free up domestically undesirable effects. First, they promote inefficient produced hydrocarbons for export, ideally consumption decisions, leading to inefficient in the form of higher value-added refined or allocation of resources and unnecessary stress on petrochemical products. Particularly where the environment. Increased energy consumption those renewable energy technologies are results in increased energy infrastructure needs indigenous or the equipment is domestically and increased risk of energy supply disruptions. produced, they can also help to spur a local Second, and very important to this study, the technology ecosystem to foster employment underpricing of electricity hampers electricity (WBG 2019c). trade, and in turn leads to increases in the Political difficulties inherent to raising consumer overall cost of energy as countries plan and prices and to overcoming entrenched operate their energy systems from a domestic institutional, bureaucratic, and economic perspective rather than a more economic interests often impede plans to increase the regional perspective. Third, subsidies increase the role of the private sector in generation (and, financial burden on governments and utilities: it ultimately, transmission and distribution), to has been estimated that the region’s fiscal deficits reduce and eventually remove the energy price averaged 9.3 percent of gross domestic product subsidies on fuel inputs and electricity, and to (GDP) in 2015, and the economies with the minimize fiscal pressures on the public budget. largest deficits were also those with the highest As a result, the rate of domestic reform varies levels of electricity subsidies. Lastly, subsidies across the MENA region (WBG 2019c). lead to reduced exploration and development of domestic fuels (that is, oil and gas) because subsidized domestic energy prices are not OCTOBER 2021 // 16 1.1. KEY ENERGY Arab countries can also cooperate with one another to further explore the potential of DEVELOPMENTS IN electricity trade as a supplement to their capacity additions. And, although the region THE MENA REGION must overcome major challenges—such us chronic technical, institutional, and political Electricity consumption in the Pan-Arab region9 barriers—recent developments in the region has increased tenfold since 1980 as a result of make a strong case for fostering energy trade. several factors, including population growth, urbanization, industrialization, and the cost of electricity being made artificially low through OIL PRICE AND ENERGY government subsidies. Although in recent years demand growth rates have decreased, due PRICE REFORM to weaker economic activity and increases in Starting in 2014, the onset of persistently electricity costs as energy subsidies are reduced, low global oil prices, together with dramatic this study estimates that the region will need to increases in domestic oil consumption, sparked add capacity at 6 percent annually until 2025. This major energy pricing reforms across the corresponds to additions of almost 150 gigawatts MENA region. Since the budgets of several (GW), and investments of approximately governments in the region heavily depend on US$134 billion. Governments continue to tackle oil exports, reduced revenues created pressure this challenge by expediting new projects to reduce state spending. A number of countries and upgrading their infrastructure while also including Egypt, Saudi Arabia, Kuwait, Qatar, the encouraging the private sector to join as partners. United Arab Emirates, Oman, and Bahrain raised prices on energy products that had long been Besides continuing to invest heavily and increase fixed at very low levels (see figure 2). the role of the private sector in power generation, Figure 2. Selected MENA Countries’ Energy Price Reforms and International Oil Prices Source: ESCWA 2019 (based on EIA 2018). 9 This study refers to the “Pan-Arab region” as 17 countries located across the Middle East and North Africa region. These countries are: Algeria, Bahrain, Egypt, Iraq, Jordan, Saudi Arabia, Kuwait, Lebanon, Libya, Morocco, Oman, Qatar, Sudan, Syria, Tunisia, the United Arab Emirates, and Yemen, plus the West Bank and Gaza. 17 // 1. STRATEGIC CONTEXT As fuel subsidies constitute a barrier to electricity between 2010 and 2018, as deployment in trade in the region, raising fuel prices could facilitate China and India grew. Offshore wind installed cooperation among countries and provide an costs remain high as projects move into deeper opportunity for structural reforms. waters further offshore—raising foundation and installation expenditures. RENEWABLE ENERGY COST As the deployment of renewable energy technologies increases throughout the region TRENDS amid the continued decline of their costs, a The costs of commercially available renewable focus on facilitating electricity trade creates energy generation technologies continue to fall an opportunity to share domestic renewable and, given the excellent solar and wind resources of resources among countries. This would have the MENA region, these technologies have become substantial economic benefits and also lower a low-cost source of new power generation. carbon emissions. Some of the most relevant declines in installed capacity costs are illustrated in figure 3. The THE ROLE OF NATURAL GAS global weighted average total installed cost The Pan-Arab region accounts for about 41 for utility-scale solar photovoltaic (PV) fell from percent of the world’s proven gas reserves, yet US$4,621/kilowatt (kW) in 2010 to US$1,210/ only 16 percent of global gas production. The kW in 2018. Although concentrating solar power potential for the future expansion of the gas (CSP) costs remain high, they experienced a market, on both the supply and demand sides, substantial reduction since 2011. By 2018, greater is significant. Gas in many Arab countries has competitive pressures had reduced installed become a low-cost source of fuel for domestic costs to US$5,204/kW, with projects benefitting industry, a source of revenue for trade transit from greater solar resources. Onshore wind total countries, and a highly valued export commodity installed costs fell by an average of 20 percent to multiple destinations in Asia and Europe. Figure 3. Global Weighted Average Total Installed Costs and Project Ranges for Solar PV, CSP, and Wind Source: IRENA 2019. Note: USD/kW = U.S. dollar per kilowatt; PV = photovoltaic; CSP = concentrating solar power. OCTOBER 2021 // 18 Countries of the region can play the role of swing producers, taking advantage of their location to supply both Atlantic and Pacific markets. When compared with other fossil fuels, natural gas burns much cleaner and can also generate electricity on demand. Therefore, natural gas generation technology is capable of both reducing fossil-fuel-based greenhouse gas emissions and paving the way to an emissions- free future, playing a useful part alongside and as a backup for renewable energy sources. Natural gas could facilitate the transition to sustainable energy systems by improving the economics of renewable-compatible gas power plants and by finding possibilities for natural gas infrastructure to continue operating in a low- carbon world. 19 // 1. STRATEGIC CONTEXT THE VALUE OF TRADE AND REGIONAL INVESTMENTS IN THE PAN-ARAB ELECTRICITY MARKET: INTEGRATING POWER SYSTEMS & BUILDING ECONOMIES 2 OVERVIEW AND PURPOSE OF THE REPORT The Pan-Arab region has a significant Figure 4. Estimated Size of Selected Regional opportunity to advance its regional and Electricity Markets around the World national energy policy goals in a more efficient and integrated way with the introduction of electricity trade as part of a regional power market. Electricity trade within a well-integrated power market promises many benefits, such as enabling access to lower-cost generation resources and fuels, facilitating greater synergy between the different demand and renewable energy profiles among the countries of the region, and increasing the security of electricity supply to meet the region’s electricity load. Source: International Energy Agency Database. In cooperation with the League of Arab States, Note: All maps in this document are for illustration purposes of cross-border projects only and not intended to reflect any political boundaries. the World Bank developed a governance and CA = Canada; GW = gigawatt; SIEPAC = Central American Electrical institutional framework to establish the Pan- Interconnection System. Arab Electricity Market (PAEM). This is supported by the Pan-Arab Regional Energy Trade Platform (PA-RETP), initiated by the World Bank in 2016 to 2.1. CURRENT STATE advance the development of electricity and gas trade in MENA. The envisaged governance and OF POWER SYSTEMS institutional framework of the PAEM would help achieve regional integration and the benefits IN THE PAN-ARAB of power trade among the countries in the broad Pan-Arab region. This document is one REGION of the PA-RETP deliverables that was developed Electricity trade in the Pan-Arab region in close cooperation with the League of Arab has historically been very low, despite a States and its Member States. The analytical relatively high cross-border interconnection model used for the purpose of this document capacity (7.7 GW). Only 2 percent of is based on the World Bank’s power system electricity produced in the region is traded in planning models and is used to assess the some form. Utilization of the existing cross- benefits of promoting electricity trade among border transmission capacity is also quite low 18 countries in MENA. (approximately 5–7 percent), and generation The motivation for the PA-RETP initiative is capacity is underutilized (approximately 42 to enable the MENA region to attain all the percent). Furthermore, the region holds 41 benefits of the energy trade seen in other percent of worldwide gas reserves and 20 regions around the world. Figure 4 presents percent of worldwide gas production, yet some prominent examples of regional energy only 10 percent of the gas exported by MENA markets. Using the total generation capacity countries is traded in the region. At the same installed or peak demand to estimate the time, electricity demand in the region is market size of each region, figure 4 shows that expected to double in the 2018–35 time frame. the European Network of Transmission System Figure 5 shows the share of total electricity Operators for Electricity (ENTSOe) is the regional generated that was exchanged per year, from electricity market with the highest generation 1990 to 2015, in regions that were not part of capacity, at 1,030 GW; and the Central American the Organisation for Economic Co-operation Electrical Interconnection System (SIEPAC) has and Development (OECD). While Africa, the the lowest, at 10 GW. With 299 GW of generation non-OECD Americas, and the non-OECD Europe capacity installed in its countries by 2018, the and Eurasia regions reached percentages over 5 Pan-Arab region has the potential to develop into one of the largest regional electricity markets in the world. 21 // 2. OVERVIEW AND THE PURPOSE OF THE REPORT percent,10 the Middle East region reached only a regional standard. Lebanon, Libya, and 2 percent of electricity exchanged regionally in West Bank and Gaza have since joined, to 2008 and remained around that level until 2015. complete the list of members. This is the second-lowest share after Asia and • The Gulf Cooperation Council (GCC) lower even than regions with smaller electricity regional power interconnection, which market sizes, such as Africa and Central America. connects six countries in the Arabian Peninsula—Kuwait, Saudi Arabia, Bahrain, Qatar, the United Arab Emirates, and Figure 5. Share of Total Electricity Traded in Oman—is based on an agreement Non-OECD Regions (1990-2015) signed in 2009; it facilitates electricity exchanges among its members. This interconnection enhances capacity reserves and improves the reliability of supply (WBG 2013). The GCC plans to further expand interconnection to Iraq and the neighboring regions. • Saudi Arabia’s cross-border Source: IEA 2017. *IEA classification of the Middle East region does not interconnections plans could advance the include data for Algeria, Morocco, Tunisia and Libya. However, trade among integration among the above subregions. these countries has been historical minimal. Note: OECD = Organisation for Economic Co-operation and Development. These plans include the Egypt-Saudi electricity interconnection project, which is underway and is expected to start Countries within the MENA region have taken operating in 2023, with a capacity of 3,000 preliminary steps toward increasing regional megawatts (MW). There are also plans at electricity exchanges, in the form of bilateral different stages of maturity to interconnect contracts between individual countries and Saudi Arabia with Jordan, Iraq, and Yemen; other subregional initiatives. The primary as well as with Africa via Ethiopia. The latter regional interconnection schemes among Arab complements the current interconnection countries currently include: between Egypt and Sudan, which are both • The Maghreb regional interconnection, part of the Eastern Africa Power Pool. which includes Morocco, Algeria, and Although efforts to increase regional electricity Tunisia. It was initiated in the 1950s and trade within the MENA region have been ongoing has since evolved into multiple high- for a while, substantial work remains to realize the voltage transmission interconnections massive potential of a fully operational regional between the three countries. Morocco competitive market within a well-designed was later connected to Spain in the late governance and institutional framework. 1990s, and Morocco, Algeria, and Tunisia are now all synchronized with the Pan- European high-voltage transmission network. 2.2. STUDIES OF PAN- • The EIJLLPST (Egypt, Iraq, Jordan, Libya, Lebanon, West Bank and Gaza, Syria, ARAB ELECTRICITY and Turkey) regional interconnection; TRADE established by Egypt, Iraq, Jordan, Syria, and Turkey in 1988 as part of an effort Electricity trade in the Pan-Arab region has been to upgrade their electricity systems to the subject of several studies (see appendix A for more details). Most of these focus on a 10 Mainly, due to the eastern and southern African power subset of Arab countries, and only one of them pools (EAPP and SAPP) in Africa and the Central American employs a formal model to assess the costs Power Market (SIEPAC) in the non-OECD Americas. of regional policies and scenarios. Those that OCTOBER 2021 // 22 describe the challenges of enabling electricity Since the conclusion of the Paris Agreement trade do so from the perspective of a single in 2015, a number of important developments country at a time. Also, these studies do not have taken place, influencing decisions in the exploit all the synergies between individual Pan-Arab region’s power sectors. These include: country load and renewable energy patterns. • Rapid reductions in the capital costs of But in the real world, capacity expansion renewable energy technologies (mainly, decisions must consider the full demand and utility-scale solar photovoltaics) renewable resource variability (time blocks). While these issues are not relevant in systems • Changes in the electricity mix, from being with low levels of renewable penetration, dominated by liquid fuel toward using they become salient as soon as renewable natural gas as a transition fuel penetration is significant. • Electricity tariffs moving towards cost This study builds on this previous work by recovery amid energy subsidy reforms using a model that explicitly accounts for the • Increased focus on advancing regional following variables: electricity trade as a complement • The impact of decisions on demand and to capacity additions to meet renewable resources’ hourly variability, growing demand—mostly driven by using an investment model that a combination of countries with an incorporates hourly resolution data emerging supply surplus and those where demand is fast outpacing supply • Ways that interconnections may be used to operate generators more efficiently Considering these developments and their effect and to defer new capacity on the region’s power systems, an additional purpose of this report is to revisit the investment • Updated inputs that reflect the latest recommendations made in previous studies. regional trends The following sections of this report are divided • The need for reserve capacity, in light of the as follows: increasingly substantial role of renewables • Chapter 3 details the fundamentals of The main analytical work of the present study regional power market integration, the is based on results produced by the World development of regional power markets, Bank’s Electricity Planning Model (EPM), which and the benefits of electric power trade. determines least-cost generation expansion plans and optimal use of resources—including • Chapter 4 presents the background of the both generation and regional interconnections— regional integration of electricity markets under various conditions. The EPM is described in in the Pan-Arab region and the challenges more detail later in the report. it faces. • Chapter 5 describes the methodology applied to determine the economic 2.3. THE PURPOSE OF benefits of electricity trade and regional- level investments. THE REPORT • Chapter 6 summarizes the main technical This report presents the findings of an analytical and economic parameters of the existing study conducted by the World Bank’s Global power generation systems, the projected Energy Practice in the MENA region to (i) assess electric demand, the current status of the benefits of promoting electricity trade cross-border interconnections, and the among countries in the Pan-Arab region; and capacity expansion plans for each country (ii) identify which cross-border transmission included in this study. investments promise the greatest return in • Chapter 7 provides the long-term terms of these benefits. regional capacity expansion plan results 23 // 2. OVERVIEW AND THE PURPOSE OF THE REPORT under six scenarios (described in section 5.2), determines the economic benefit of electricity trade, and presents a sensitivity analysis to demand changes. • Chapter 8 extends the analysis of the results by proposing an analytical framework to perform a screening and prioritization of electricity interconnection investments. • Appendices A–H contain further data and documentation that support the main contents of the report. OCTOBER 2021 // 24 25 // 2. OVERVIEW AND THE PURPOSE OF THE REPORT THE VALUE OF TRADE AND REGIONAL INVESTMENTS IN THE PAN-ARAB ELECTRICITY MARKET: INTEGRATING POWER SYSTEMS & BUILDING ECONOMIES 3 THE FUNDAMENTALS OF REGIONAL POWER MARKET INTEGRATION Most regions of the world have substantial • When there is a significant difference in imbalances among their countries’ power the electricity production costs between systems, such as surplus generation capacity in countries, both exporting and importing one country and shortage in another. As a result, countries can mutually benefit from trade. opportunities arise for electricity trade and/ Removing transmission infrastructure bottlenecks or mutually beneficial investment. However, is essential to realizing the mentioned benefits. If realizing these opportunities often requires there is limited or no cross-border transmission greater integration of power systems, including capacity, then the required infrastructure must physical infrastructure and markets. be constructed. Similarly, sustained development Interconnected power systems can provide and closer integration of a region’s power markets more economic, reliable, and environmentally greatly enhance opportunities to achieve these friendly outcomes for all the power systems desired outcomes. within a region. The known benefits of regional integration in the electricity sector (WBG 2019d) include the following: 3.1. DEVELOPMENT • Overall generation and transmission costs can be substantially reduced OF REGIONAL POWER through coordination of expansion plans, optimal utilization of a more diverse set MARKETS of resources, and the sharing of reserves. The development of regional electric power This can allow the postponement of markets traditionally follows an incremental expensive investments to meet national- process of evolving trade regimes. This level peak demand, while improving the ensures that the underlying economics and reserve margins across the entire system, pricing remain fair as the institutions and with a corresponding reduction in costs. mechanisms necessary for a fully competitive • Security of supply and climate resilience wholesale electricity market are built. Figure can be enhanced through mutual 6 summarizes the typical phases of regional assistance among utilities, particularly power market integration. Following these in times of crisis. For example, in an phases, electricity trade tends to evolve emergency such as an unplanned outage, from bilateral trading between neighboring or whenever a country with insufficient countries to the formation of a regional energy generation capacity can only meet its and ancillary services market. Bilateral trading internal load through electricity imports. between neighboring countries can then evolve into bilateral or multilateral trading that runs • Regional integration can enable the through a third country. This can then increase greater utilization of low-carbon in complexity through the buying and selling of resources available in a region, in power across synchronized power systems from particular solar and wind technologies, one country market to others. Finally, a regional while helping build a more resilient energy and ancillary services market becomes system through greater diversification of formalized as an electric power pool. supply to mitigate risks associated with each environmental impact. • Power trade allows countries to gain 3.2. BENEFITS OF the advantages of economies of scale by developing larger projects that may ELECTRIC POWER TRADE not be justified by national demand projections alone and that can provide Electricity trade in a well-developed regional better returns if a significant portion of market can improve reliability of supply, reduce the generated electricity is exported. energy prices, protect against power shocks, relieve shortages, provide incentives for market 27 // 3. THE FUNDAMENTALS OF REGIONAL POWER MARKET INTEGRATION Figure 6. Typical Phases of Regional Power Market Integration Bilateral Interconnection Shallow Integration Deep Integration Planning and National planning and Some coordination of national Regional integration body empowered Investment investment investments with optimized to require investments in agreed upon Coordination regional investment plan regional plan to be implemented Regional Typically starts with 2 Interconnected grid involving a Operation of a fully synchronous, Connectivity countries, later a wider number of neighboring multi-country, interconnected power Architecture interconnected grid countries system Cross-Border Long-term bilateral power Long-term PPAs supplemented Electricity pricing competition achieved Trading purchase agreements (PPAs) with short-term markets and through a range of market mechanisms Arrangements cross-border transmission (spot, day-ahead, ancillary services, tari s transmission capacity auctions, etc.) Technical Simple rules agreed upon for Harmonization of rules, grid Harmonization of rules, grid codes, and and/or the operation of the codes, and transmission tari s transmission tari s Regulatory interconnected system Harmonization Source: The World Bank’s Power Systems Global Solutions Group. extension and integration and, in some cases, short intervals, such as when national facilitate decarbonization. The following generation capacity is sufficient, but subsections further explain some of the benefits spinning reserve capacity may be too low of electric power trade. (El-Katiri 2011). Payment for these types of exchanges usually RELIABILITY OF SUPPLY involves cash settlements, typically overseen by Trading electricity can improve the reliability a financial regulator, or payment can be in-kind of supply through the “pooling” of generation over a specified settlement period. Electricity capacity and national reserve capabilities exchanges require legal and institutional among countries. The national power systems frameworks, such as a multilateral legal can engage in trade with partnering countries framework for regional electricity trade and a and draw on their capacity when required, in a harmonized set of commercial rules for trade (El- situation such as an acute electricity shortage Katiri 2011). in one country, or when a power plant is To evaluate a power system’s reliability in unavailable due to upgrading or maintenance. generation expansion planning, power system There are three types of capacity exchanges: managers, designers, planners, and operators • Emergency supply of electricity. These have utilized a wide range of criteria in their are based on real-time transactions and respective areas of activity. The costs of failure to for a limited time (typically a few hours). reach reliable power supply may be expressed A country experiencing an immediate by several components falling into two main power shortage can request electricity categories. The first is the cost of unserved from the regional grid. energy (USE), typically assessed through the value of lost load (VoLL), defined as the value • Scheduled outages that are covered in dollars per megawatt-hour (MWh) placed by the regional grid. These transactions on a unit of electricity not supplied due to an involve the forward trading of electricity unplanned interruption. The second is the cost to cover planned shortages because of of unmet reserve (USR), defined as the cost due short-term capacity bottlenecks. to the system’s inability to meet operational • Spinning reserve capacity supplies. reserve requirements, in terms of margin These are for immediately supplying reserves (in $/MW) and spinning reserves the reserve capacity needed to cover ($/MWh) which may lead to an unplanned OCTOBER 2021 // 28 interruption. USE and USR are used to estimate • Firm energy supply. This trading the economic value of the cost of electricity approach provides a medium- or long- interruptions to electricity customers and the term solution for a country’s generation economy as a whole. capacity needs, based on a contract between two utilities. A national utility ECONOMIC BENEFITS FROM commits to supply specific amounts of electricity on a “take or pay” basis. This COMMERCIAL TRADE helps the importing country meet base or Electricity trade, undertaken for commercial peak load supply in cases where they are purposes, aims to exploit the differences unable or not incentivized to construct in system efficiencies and cost advantages their own power plants (El-Katiri 2011). between different producers (countries or Variation in chronological patterns of demand individual utility companies), achieved by across countries can create significant incentives purchasing lower cost electricity from available for commercial trade, resulting in economic sources (El-Katiri 2011). Economic benefits of savings and greater security of supply. As electricity trade arise from operational and different countries’ seasonal, monthly, and daily capital cost savings. The operational cost fluctuations in electricity demand may display savings mainly stem from regional differences in fuel prices, differences in chronological patterns of load, geographical diversity of Table 3. Illustration of Short-Term Economic renewable profiles, and the ability to efficiently Benefits from Electricity Trade meet operational reserve requirements. The Exporter Importer capital cost savings stem from differences in the chronological pattern of load and renewable Revenue (= P * Q) Cost with no trade (= Ci * Q) profiles that allow the pooling of generation Cost (= Ce * Q) Cost of import (= P * Q) resources at a regional level, requiring less Bene t = revenue - cost Bene t (savings) = (Ci - P) x Q generation capacity and lower planning reserve E.g.: requirements (WBG 2017b). Exporter Importer There are two main approaches to commercial P = 111 $/MWh Ci = 136 $/MWh electricity trade: Ce = 86 $/MWh P = 111 $/MWh • Economy energy exchanges. These are Bene t = 25 $/MWh Bene t (savings) = 25 $/MWh short-term electricity exchanges that take Total bene t = (136 - 86) $/MWh * Q = 50 $/MWh * Q advantage of differences in the short-run Source: Original compilation. Note: Ce = exporter’s production cost of electricity; Ci = importer’s marginal costs incurred by two countries’ production cost of electricity; MWh = megawatt - hour; P = price of utilities. Electricity is purchased from electricity; Q = quantity of electricity. where it is produced most cost-effectively, creating an increase in revenue for the significantly different patterns, countries can exporting national utility and a net benefit from smoothing out their individual savings for the importing utility. Table 3 peaks by importing other countries’ off- illustrates the resulting mutual benefits. peak electricity. As a general rule, seasonal In the example, the transaction to trade correlations of electricity demand are influenced quantity Q of electricity takes place at by the latitude and climate of jurisdictions (with price P. From the exporter’s perspective, countries further north requiring less energy the benefit is the extra revenue minus for cooling, etc., in summer), while intraday Ce, the exporter’s production cost of peaks are largely synchronous in the north- electricity. The importer receives the south direction but, on a universal time scale, benefit of the difference between the they have a characteristic time lag moving from importer’s own production cost Ci and east to west (Antweiler 2016). The time zone price P. The total benefit to be shared difference between Morocco and Saudi Arabia, between the two parties is (Ci - Ce) x Q. for example, could provide a sound basis for 29 // 3. THE FUNDAMENTALS OF REGIONAL POWER MARKET INTEGRATION intraday “reciprocal load smoothing,” should power trade between these countries become possible. OTHER BENEFITS The benefits of electricity trade extend beyond the enhanced reliability of supply and economic savings. Trade between countries supports economic and political stability as ties become stronger. It helps to secure the supply of gas to meet the growing electricity demand in a region, as well as to enable economic diversification by facilitating the growth of gas- based industries (WBG 2016b). Trade is also beneficial to meet renewable energy targets set in different countries in a region. This is because the aggregated regional renewable resource profile is typically smoother than the profiles of individual countries. Also, flexible resources in different countries can be pooled to complement renewable output and to provide ancillary services, such as spinning reserves, resulting in a less costly variable renewable energy integration (NREL 2013). At a broader level, these benefits could help the countries in the Pan-Arab region progress toward some of their national and regional goals. On a national level, some of these priorities are: achieving renewable targets at a lower cost, increasing energy efficiency, achieving Intended Nationally Determined Contributions, executing subsidy reforms, securely supplying a growing high- peak electricity demand, and facilitating the execution of new large investments with limited financing sources. On a regional level, priorities connected to electricity trade include: accomplishing the goals of the renewable energy regional strategy; fostering regional institutional cooperation; and establishing a market and an enabling environment for electricity trade (WBG 2018d). OCTOBER 2021 // 30 31 // 3. THE FUNDAMENTALS OF REGIONAL POWER MARKET INTEGRATION THE VALUE OF TRADE AND REGIONAL INVESTMENTS IN THE PAN-ARAB ELECTRICITY MARKET: INTEGRATING POWER SYSTEMS & BUILDING ECONOMIES 4 REGIONAL INTEGRATION OF ELECTRICITY MARKETS IN THE PAN-ARAB REGION Historically, the Pan-Arab region has had and key responsibilities. The PETA consists of a relatively high interconnection transfer three separate subagreements: (i) the Trading capacity, which reached 7.7 gigawatts (GW) by Agreement, including common legal terms and 2018. However, electricity exchanges as well conditions; (ii) the Interconnection and Use of as interconnection utilization have been very System Agreement; and (iii) the Interconnector low. In 2014 only 2 percent of the electricity Transmission Code (El-Katiri 2011). generated in the region was exchanged among The GCCIA cross-border interconnections were neighboring countries, less than 10 percent of established in three phases. In the first phase, the regional interconnection capacity was being completed in 2009, the GCCIA formed the GCC used, and load factors barely reached 2 percent north grid by connecting the power grids of the (WBG 2016b). The only interconnections utilized northern states of Kuwait, Saudi Arabia, Bahrain, at a reasonable level are Morocco Spain, Egypt and Qatar. This included the construction of a Gaza, and Jordan West Bank (WBG 2017b). 400 kilovolt (kV) grid in Kuwait, Saudi Arabia, Regional cooperation and governance are and Qatar, with a 400 kV submarine cable link to essential components in building regional Bahrain, as well as a back-to-back high voltage electricity markets. A top-down vision and direct current (HVDC) transmission line to a robust regulatory framework are needed connect the 60 hertz (Hz) Saudi Arabian system to facilitate electricity trade. The Gulf to the 50 Hz systems of the other GCC countries. Cooperation Council (GCC), Mashreq, and In the second phase, the interconnection Maghreb subregions have taken steps toward authority completed a 220 kV line between the transmission integration and coordination. United Arab Emirates and Oman, forming the However, the institutions required to facilitate GCC southern grid. This project also formed power trade and the harmonization of the Emirates National Grid by integrating the regulations are still underdeveloped and isolated networks of the various emirates and present challenges that must be addressed created an integrated northern grid in Oman. before there is region-wide electricity trade. The The third phase interconnected the north and following subsections give a brief background south grids. It included a double-circuit 400 of the subregional initiatives developed within kV line from Salwa to Shuwaihat (UAE) and a the Pan-Arab region. double- and single-circuit 220 kV, 50 Hz line from Al Ouhah (UAE) to Al Waseet (Oman) (WBG 2013). 4.1. THE GCC REGION The GCC interconnection primarily uses two vehicles for trade: The GCC Interconnection Authority (GCCIA) was established in 2001 and consists of six member • Scheduled exchanges. These are states: Kuwait, Saudi Arabia, Bahrain, Qatar, the prearranged bilateral trades between GCC United Arab Emirates (UAE), and Oman. Later, in Member States that are freely negotiated 2009, the members signed two agreements: the between the members. Once the General Agreement and the Power Exchange agreement is reached, the members must and Trade Agreement (PETA). The General procure transmission capacity rights for Agreement establishes the principles of electricity use of the GCC interconnection from the cooperation, such as the rights of interconnection, GCCIA. Once confirmation is received, the connection fees, interconnection performance trade is completed. defaults, termination of membership, and, more • Unscheduled exchanges. These are used broadly, the interconnection’s governing law. on a contingency basis. They improve The PETA is a commercial agreement among the reliability of supply by allowing power providers within the GCC subregion. It countries to access supply in the case of established the legal terms for commercial trade, an emergency (WBG 2013). such as the technical and financial details of the GCC regional power interconnection has project. It also outlines cost and contribution advanced the most in promoting electricity structures, emergency support mechanisms, 33 // 4. REGIONAL INTEGRATION OF ELECTRICITY MARKETS IN THE PAN-ARAB REGION exchanges within the Pan-Arab region. Figure countries have achieved grid interconnection 7 details the energy exchanges completed, levels that surpass those of other Arab states, in gigawatt-hours (GWh), among the GCC the utilization of the available transmission members between 2014 and 2017. Electricity capacity remains quite low. Part of the reason exchanges have increased over time, with the is that the trades are still primarily conducted balance of electricity traded increasing from “in-kind.” Essentially, this is electricity delivered 734.3 GWh in 2016 to 878.4 GWh in 2017 (an in an emergency, for electricity to be returned increase of 20 percent). Saudi Arabia and, more later. This type of transaction has a small share of recently, Kuwait and the United Arab Emirates volume in any power system, as compared with registered the highest quantities of exports the regular market-based transactions in which and imports. Although the volume of electricity the commodity (electricity) is exchanged for cash. traded has increased over time, a significant In turn, the lack of a transparent basis for pricing portion of it involves unscheduled exchanges electricity across countries with subsidized fuel to prevent emergencies. Member countries for electricity generation is the main reason why favor trading on an in-kind basis, over market- the parties tend to stick to in-kind transactions. based trading (in-cash), to settle unscheduled With the degree of fuel subsidy varying from exchanges (GCCIA 2017). country to country, it is difficult for them to agree on a fair price for the electricity being exchanged. Figure 7. Electricity Exchanges by GCC Leakage of a country’s domestic fuel subsidy to Members, 2014–17, in GWh a neighboring state—sometimes referred to as “exporting a subsidy”—is a distinct deterrent to electricity trade in the region. The energy- exporting countries have traditionally kept their retail electricity tariffs low as part of a political bargain whereby control is centralized in return for hydrocarbon wealth redistribution under generous social protection schemes. Artificially low tariffs are in turn supported by subsidized Source: GCCIA 2017. fuel inputs to generators from state-owned oil Note: GWh = gigawatt - hour; UAE = United Arab Emirates and gas companies, which bear the domestic cost in return for the right to sell fossil fuel abroad By 2016, the GCC interconnection had at a significant profit. As such, energy traded successfully been used in 1,692 incidents to at the wholesale price extends those subsidies stabilize and support Member States’ power to foreigners, and state-owned oil and gas systems. These transfers ranged from 100 companies object to this implicit wealth transfer megawatts (MW) to 3,000 MW in size and incurred when utilities sell power abroad (El-Katiri they provided greater stability to the grid and 2011; WBG 2013, 2019c). succeeded in avoiding partial or total blackouts Apart from ad hoc emergency exchanges, during some critical incidents in the GCC. bilateral contracts are the only form of cross- Moreover, these transfers had led to more than border trading that is relatively regular US$2.2 billion in savings between 2011 and among GCC countries. However, each bilateral 2016 from reducing installed capacity, operation electricity trade may require a lengthy process and maintenance (O&M) costs, and operational of government approval. Unless the approval reserves, as well as through avoiding procedure is streamlined (which requires a pre- programmed outages due to emergency agreed pricing methodology), the practice of support (GCCIA 2017). bilateral contracts will fall short of enabling rapid Despite the achievements noted above, the GCC response to supply and demand signals; day- subregion is still facing a number of barriers ahead trading, for example, will not be possible to expanding the volume of electricity traded (WBG 2019c). by its Member States. Thus, while the GCC OCTOBER 2021 // 34 4.2. MASHREQ REGION committees, which are not fully functional (WBG 2013). These permanent committees are the: The Mashreq countries/economies in this study • Steering committee. This committee is are: Egypt, Iraq, Jordan, Lebanon, Libya, West responsible for promoting reliable and Bank and Gaza, Sudan, and Syria. In 1988, in efficient operation of the interconnection the Mashreq region, Egypt, Iraq, Jordan, Syria, and the interconnected power systems and Turkey initiated an effort to upgrade their by coordinating design, planning, and electricity systems to a regional standard. Later, operating activities. they were joined by Lebanon, Libya, and West • Planning committee. This committee Bank and Gaza, to form the EIJLLPST (Egypt, Iraq, aims to foster greater coordination among Jordan, Libya, Lebanon, West Bank and Gaza, the members as well as determine if the Syria, and Turkey) regional interconnection (WBG plans conform to Steering Committee rules 2013). Transmission lines of 400 kV and 500 kV and guidelines. It plays an analytical and make up the EIJLLPST interconnection, linking planning role. the national power systems of its members. The regional grid further connects: Egypt to Libya • Operating committee. Each pair of through a 220 kV line; Syria to Turkey through a neighboring countries is required to 400 kV line; Iraq to Turkey through a 400 kV line maintain a bilateral operating committee. currently operating at 154 kV; and Iraq to Iran The operating committees are required through a 400kV line (WBG 2010). to take all actions necessary to ensure delivery and payment for power in The original five countries in the regional accordance with the interconnection interconnection—Egypt, Iraq, Jordan, Syria, and agreement and any agreement between Turkey—signed a general trading agreement the countries. in 1992. This established their commitment to develop interconnections, as well as shared Despite the interconnection agreement, there has objectives of providing mutual assistance and been limited trade of electricity over the network. sharing benefits as part of the network, to Tight generation supply in some countries, lack of improve the reliability of supply, and to improve a harmonized regulatory framework, limited access the region’s economies through the exchange of to national transmission networks, and the fact that surplus power. trade is, generally, restricted to a single government- owned entity in each country constrain electricity In 1996, the general trading agreement exchanges within the region. In addition to these was amended to become a comprehensive issues, the interconnected systems are often not agreement that outlines the terms and conditions synchronized, therefore, part of a national grid for use of the interconnection. The terms and system must be isolated from the main grid to conditions cover: (i) reserve sharing during accept imports from another country (WBG 2013). emergencies; (ii) capacity transactions; (iii) interchange of surplus power and energy; (iv) Overall, the national transmission systems in the regulation of energy flows to maintain schedules; Mashreq subregion are constrained by the lack of (v) regulation of reactive power flows; (vi) a regional coordination center and the lack of a transmission services—making each country’s formal regional market. These institutions would transmission facilities available for the purpose of facilitate market transactions, promote regional transmitting power and energy to other parties; trade, and compensate entities for providing (vii) operating reserves, including maintaining transport services, or determine the technical minimum levels of reserves and their sharing feasibility of transactions. A regional coordination between countries; (viii) the coordination of center would bring significant savings through maintenance schedules; and (ix) coordination of more optimal generation capacity planning, planning to increase reliability and maximize the reduced settlement costs (due to having only value of the interconnection. one central settlement system rather than five or more separate national ones), and reducing the The interconnection agreement also established cost of load interruptions (WBG 2010). the scope and duties for the permanent 35 // 4. REGIONAL INTEGRATION OF ELECTRICITY MARKETS IN THE PAN-ARAB REGION 4.3. MAGHREB REGION to meeting national-level peak demand and including opportunities for commercial trade based on short-term marginal cost differences. The Maghreb regional interconnection was A greater geographic scope means greater established in the 1950s by the North African diversification of resources available in each countries of Morocco, Algeria, and Tunisia. It subregion and greater ability to scale up has since evolved into multiple high-voltage deployment of renewable energy sources. For transmission interconnections between the the GCC, Mashreq, and Maghreb subregions, three countries. In 1997, these countries specific benefits from interconnection include connected to the European Network of the following: Transmission System Operators for Electricity (ENTSO-E) via the 2x400 kV alternating current • Connecting the GCC with the Mashreq (AC) interconnection between Spain and would solve one of the remaining Morocco. Also, Morocco, Algeria, and Tunisia are problems in intra-GCC trade: the region’s all synchronized with the pan-European high- relatively uniform load pattern, that is, the voltage transmission network (WBG 2013). typical summer peak and daytime peak demand in the afternoon hours (El-Katiri In 2003, the European Commission and the 2011). Notably, the Saudi Arabia Egypt energy ministers of the Maghreb nations signed interconnection planned for 2022 would a protocol with the objective of developing a benefit both countries by sharing their regional energy market that would eventually reserve capacity and in exchanging power be integrated into the EU electricity market. The on the basis of differences in daily and protocol called for the creation of mechanisms seasonal demand profiles. to facilitate trade, such as establishing how to deal with tariffs, trans-border networks and • Similarly, planned Saudi constraints, and compensation for network interconnections with Jordan (by 2023) damage. and Iraq (by 2025) would focus on using Saudi Arabia’s surplus capacity in off-peak Later, in 2010, the Maghreb nations signed hours and off-peak seasons. Furthermore, the Algiers Declaration. In this declaration, the connection with the Mashreq system these countries agreed to take steps toward would allow the GCC to subsequently harmonizing laws and regulatory frameworks develop the interconnection with Turkey and economic and technical conditions for to gain access to the EU market. The the creation of a viable market for electricity. emphasis would be on linking the Saudi They also agreed that this market would grid directly or through Iraq to the Turkish be based on network access provided on a grid by HVDC lines—to enable power nondiscriminatory and transparent basis and exchange with Turkey and, potentially, properly priced to promote trade (WBG 2013). to export renewable energy to European markets. 4.4. RATIONALE FOR • Connecting GCC (and the Mashreq) with the Maghreb, while still a long- INTERCONNECTING term prospect, is promising from two perspectives. First, it could smooth the THE THREE SUBRGIONS daily peaks in both the GCC and the Mashreq, given the significant time zone Based on the fundamentals of regional market difference between the two subregions. integration discussed earlier, power system Second, the solar power development interconnection has a number of basic benefits projects in the Maghreb (such as the for all participating countries. Expanding the Desertec project in Morocco) can turn geographic scope of interconnection means these countries into strong clean energy scaling up the same fundamental benefits— trading partners for the GCC (El-Katiri starting from deferring expensive investments 2011). OCTOBER 2021 // 36 4.5. KEY CHALLENGES has implemented a pilot project that will provide valuable experience for TO ELECTRICITY developing these institutions. In addition to requiring the authority to promote TRADE IN THE PAN- trade, these institutions also require adequate resources to achieve this ARAB REGION objective, such as analysis tools and data. • Harmonized regulations of cross- The GCC, Mashreq, and Maghreb have each border trade need to be developed. taken steps toward regional cooperation This requires developing a regional grid in their transmission networks but are still code and a regional commercial code facing market integration challenges. These that cover the technical and commercial vary by subregion, though several challenges aspects of regional trade. Developing affect the prospects of Pan-Arab market regulations for cross-border trading integration as a whole: would involve establishing a working • Countries need to develop and agree group that defines the rules for planning on a pricing approach suitable for and operating networks on a regional cross-border trade on a commercial level, such as through congestion basis. In many cases this might management guidelines. A commercial include domestic pricing reforms of code is required to establish a mechanism subsidized fuels, including natural and rules for trades where bids and offers gas. Artificially low fuel prices have are cleared and settled periodically. The effects throughout the supply chain Pan-Arab Electricity Market (PAEM) would of the electricity sector, hindering establish needed market rules and grid power trading among and within the codes (or technical requirements), with subregions. Most trading transactions the understanding that Member States are still conducted “in-kind” in the GCC, will advance needed reforms at their own currently the most advanced subregional pace. Harmonized regulations will play a market. In addition to discouraging key role in implementing the PAEM. trade, fuel subsidies promote inefficient • It is also necessary to mobilize finance consumption decisions, resulting in for investment in generation and increased infrastructure needs and transmission assets to meet demand. potentially increased supply disruptions. Introducing regional electricity trade Applying international fuel prices will reduce the need for new generation specifically to cross-border transactions capacity. However, it will require without eliminating subsidies at home investments to enhance or expand is a possible interim solution in the certain transmission lines. A more early phases of the regional market detailed transmission investment plan (WBG 2019b). However, countries are is an important next step. This is best encouraged to accelerate the phasing prioritized within a coordinated regional out of these subsidies to fully exploit the planning framework that optimizes the potential of trade. development and operations of the • Regional institutions for power trade PAEM, and allows participating countries need to be founded and empowered to meet demand in cost-effective and within a common framework that ensures efficient ways. efficient coordination. The development of institutions can build on existing bodies such as the CGGIA trading framework, the Mashreq committees, and the Algiers Declaration. The GCCIA 37 // 4. REGIONAL INTEGRATION OF ELECTRICITY MARKETS IN THE PAN-ARAB REGION THE VALUE OF TRADE AND REGIONAL INVESTMENTS IN THE PAN-ARAB ELECTRICITY MARKET: INTEGRATING POWER SYSTEMS & BUILDING ECONOMIES 5 THE WORLD BANK’S ELECTRICITY PLANNING MODEL This study uses a power system planning model • The utilization of the transmission lines developed in-house by the World Bank: the interconnecting states (important to design Electricity Planning Model (EPM). The EPM is an trade contracts) optimization model that determines a sequence • The impact of different market conditions of investment decisions to build new power (for example, fuel prices, fuel subsidies, generation capacities while optimizing the least- carbon limits, etc.) and technology cost cost option to meet resource, technological, assumptions on the optimal capacity environmental, policy, and any other specified expansion plan and the optimal energy mix constraints. An essential component of the model is the merit order or economic dispatching of existing • The cost of implementing specific and new generation capacity. The methodology environmental policies, such as renewable fully exploits the synergies between demand portfolio standards, caps on carbon and renewable energy profiles. The following emissions, taxes on carbon emissions, and subsections outline the model’s main capabilities, carbon emissions rates. its key assumptions, and the optimization The model is based on the following assumptions: objectives and constraints, after which the scenarios analyzed in this study are described. • The market participants are not strategic, and they behave in a perfectly competitive manner, that is, the power plant owners 5.1. KEY FEATURES submit their true costs as bids • The demand projection is exogenous OF THE ELECTRICITY to the model. The projected demand PLANNING MODEL is considered perfectly inelastic, which implies that the maximization of the social welfare can be replaced by minimization of The EPM is a long-term least-cost planning model the system cost that minimizes system costs over multiple years, including both fixed (annualized capital and fixed • The electricity trade among regions operation and maintenance [O&M]) costs and is economically efficient (optimal), variable (fuel and variable O&M) costs, subject which translates to a single objective of to meeting a number of physical constraints that minimizing costs for all countries include generation and transmission capacity • The pricing is assumed to be efficient and among zones, and spinning reserve and capacity does not provide incentives to market reserve requirements. The model determines: participants to deviate from the optimal • Hourly electricity costs with trade for behavior. different countries and zones, which are The objective of the modeling exercise is to essential to value the energy traded minimize at once the sum of fixed and variable • Wholesale power supply costs generation costs (discounted for time) for all zones and all years considered. This minimization • Where and how many renewable resources is subject to the following parameters: demand should be deployed to maximize their equals the sum of generation and unserved value to the system—a critical issue in energy; available capacity is existing capacity current Pan-Arab planning efforts plus new capacity minus retired capacity; • The optimal capacity additions over time generation does not exceed the maximum and to complement renewable generation minimum output limits of the units; generation accounting for existing generating units, is constrained by ramping limits; reserves are energy storage, demand-side response, committed every hour to compensate for and/or carbon constraints forecasting errors; renewable generation is constrained by wind and solar hourly availability; • The optimal retirement schedule of the excess energy can be stored in storage units to existing units over time be released later or traded between the other 39 // 5. THE WORLD BANK’S ELECTRICITY PLANNING MODEL zones; and the power flows are constrained by Table 4. Cases Considered for the Study transmission network topology and transmission Base Case Natural gas - current market prices, no electricity trading line thermal limits.11 (Case 0, CO) Case 1 (C1) Natural gas - current market prices, electricity trading As the overall objective of this study is to assess the benefits of electricity trade among countries, Case 2 (C2) Natural gas - international prices, no electricity trading it is important to highlight the following Case 3 (C3) Natural gas - international prices, electricity trading observations regarding the model: Case 4 (C4) Natural gas - international prices, no electricity trading, CO2 emissions limit • EPM does not account for the load flows Case 5 (C5) Natural gas - international prices, electricity trading, CO2 within a domestic transmission system emissions limit Case 6 (C6) Natural gas - international prices, electricity trading, • The model does account for wheeling demand-side measures based on the marginal cost of electricity, Note: CO2 = carbon dioxide. intrinsically, subject to line capacity constraints • Renewables generation technologies lack available for electricity trade in a regional power provision for excess reserve storage. pool scheme. To assess the impact that higher natural gas prices have on investment and regional 5.2. DESCRIPTION OF electricity trade, this study analyzes a set of cases where Pan-Arab countries use European THE CASES ANALYZED market prices (international prices) for natural gas (European Union Hub prices). Table 4 presents the seven cases considered Case 2 (C2), similar to the base case, assumes for analysis in this study. Six main cases (C0-C5) that cross-border interconnections are not are used to determine the benefits of electricity available for electricity trade, while Case 3 (C3) trade under various pricing and environmental assumes a fully integrated transmission network policy assumptions, while holding the electricity with trade. demand on the same trajectory for each case. Case 6 (C6) assumes a lower demand trajectory The study analyzes two more cases, Case 4 due to energy efficiency measures. (C4) and Case 5 (C5), to evaluate the impact of carbon policy on generation investments To assess the potential benefits of increased and trade. To build these two cases, the study trade among the power systems in the Pan- applies a policy that limits CO2 emissions from Arab region, the analysis starts with a baseline the power sector, starting in 2020 until 2035, to scenario (C0) that assumes no electricity the previously described cases, Case 2 and Case trade takes place and that countries use 3. To set these limits, consideration was first natural gas priced at current (local) levels for given to the Intended Nationally Determined electricity generation. In this base case, each Contributions (INDCs) that Pan-Arab countries country independently makes its own capacity published after COP21.12 However, it is difficult investments to satisfy its projected demand. to standardize an average reduction target for The base case can then be compared with the region. While some economies have not Case 1 (C1), a case that assumes existing and published their INDCs (namely, Libya, Syria, planned cross-border interconnections are and West Bank and Gaza), others lacked clarity fully operational, at transfer capacity levels, and on their CO2 reduction goals (Bahrain, Egypt, Iraq, Kuwait, Sudan, and the United Arab Emirates). The countries that have set INDCs 11 Section 6 and appendix B give details of input assumptions of the EPM. For a generic technical description of the inputs, outputs, and mathematical formulations used in the model, 12 2015 Conference of the Parties to the United Nations refer to appendix F. Climate Change Convention. OCTOBER 2021 // 40 have provided CO2 reduction targets under two categories: unconditional (ranging between 1 percent to 13 percent reduction from a business- as-usual scenario) or conditional on international support (ranging from 12.5 percent to 41 percent emissions reduction compared with a business- as-usual scenario) by the year 2030.13 Given the lack of uniformity of CO2 reduction targets by country, this study assumes a regional limit for CO2 emissions that begins as a 1 percent reduction in 2020 (from the baseline scenario) and reaches 18 percent by 2035. Finally, the study considers Case 6 to model the impact of a possible contraction in electricity demand relative to the other cases. Under Case 6, all the countries adopt demand-side measures, such as energy efficiency programs, in order to progressively reduce future electricity consumption. It is further assumed that the adoption of these measures will cause the systems to experience a demand reduction of 0.5 percent of the base demand (the demand projection used in all other cases of this study) in 2020, a reduction of 10 percent in 2025, and 20 percent in 2030 through 2035. Chapter 8 presents an economic planning framework for cross-border interconnections. This framework is used to identify the benefits among a specific group of interconnectors, to assess potential transmission investment opportunities, and to categorize interconnectors according to their average annual utilization rates. To prioritize interconnectors, the study considers both their potential utilization and their economic benefits. It is important to note that due to the complexity of the model, even if a single interconnector proves to be highly utilized and to have the most economic benefits by itself, the figures might change when interacting with other interconnectors from neighboring countries. Therefore, other criteria, such as countries’ willingness to cooperate and technical characteristics of the potential interconnector, should also be used to assess the feasibility of the transmission lines. 13 Appendix D contains a summary of the INDCs submitted by the Pan-Arab countries. 41 // 5. THE WORLD BANK’S ELECTRICITY PLANNING MODEL THE VALUE OF TRADE AND REGIONAL INVESTMENTS IN THE PAN-ARAB ELECTRICITY MARKET: INTEGRATING POWER SYSTEMS & BUILDING ECONOMIES 6 MODELING INPUTS AND ASSUMPTIONS This chapter details the input data and assumptions (25 percent) of steam turbine capacity. It also on a regional and national basis. These main data includes 2.3 GW of wind (<1 percent), 1.3 GW include existing, under construction, and planned of solar PV, and 525 MW of CSP. However, the generation; peak and energy demand projections first three mentioned fossil-fueled technologies and demand profiles; existing, under construction, dominate the capacity mix in the region, with and planned interconnections; natural gas price over 92 percent participation. projections, natural gas consumption limits, and In terms of capacity by country, Saudi Arabia liquid fuel prices; and capacity factors for renewable registers the highest amount of capacity with energy technologies. about 85 GW, followed by Egypt with 39 GW, the Overall, this study considers 11 generation United Arab Emirates with 32 GW, and Iraq with technologies: open cycle gas turbine, combined 30 GW. At the low end of the list are West Bank cycle gas turbine, steam turbine, diesel generator, and Gaza with 1.2 GW, Yemen with 1.5 GW, and hydroelectric, nuclear generation, coal-fired Lebanon with 3 GW. steam turbine, wind farm, solar photovoltaic (PV), concentrating solar power (CSP), and integrated solar combined cycle (ISCC). 6.2. PLANNED AND UNDER CONSTRUCTION 6.1. EXISTING CAPACITY CAPACITY ASSUMPTIONS Table 6 displays the generation capacity Table 5 presents the assumptions regarding additions, by technology and country, that are existing installed capacity by technology and either planned or are under construction over country. The total existing capacity for the region, the period of 2018–30. Under these plans and in 2018, is 299 gigawatts (GW). This includes 107.3 ceteris paribus (with other conditions remaining GW (36 percent) of combined cycle, 92.5 GW (31 the same), a total of 270 GW would be added to percent) of open cycle gas turbines, and 75.9 GW the regional generation capacity, of which 187 GW or almost 70 percent of the total would be Table 5. Existing Installed Capacity by Technology and Country, in MW (2018) Country CC GT ST DG Hydro Coal Wind PV CSP Total Algeria 6,907 10,368 2,435 - 276 - 10 432 150 20,578 Bahrain 3,096 700 125 - - - 1 10 - 3,932 Egypt 12,647 7,845 14,799 - 2,832 - 747 50 20 38,940 Iraq 4,952 15,079 5,995 1,769 2,524 - - - - 30,319 Jordan 2,837 188 242 810 - - 287 460 - 4,824 Kuwait 6,496 2,925 9,354 - - - 10 10 50 18,845 Lebanon 930 140 1,694 - 253 - - - - 3,017 Libya 3,995 4,638 1,190 - - - 28 - - 9,851 Morocco 834 1,230 600 292 1,770 2,895 1,1018 - 180 8,819 Oman 7,099 2,352 - 149 - - - - - 9,600 WB&G 1,140 - - 15 - - - - - 1,155 Qatar 7,470 4,408 - - - - - - - 11,878 Saudi Arabia 21,436 31,841 31,226 270 - - - - - 84,773 Sudan 458 220 906 535 2,250 110 - - - 4,479 Syria 2,800 967 3,324 - 1,571 - - - - 8,662 Tunisia 2,559 2,218 1,080 - 62 - 208 10 - 6,138 UAE 21,644 2,460 2,460 31 - - - 373 125 31,577 Yemen - 407 495 590 - - - - - 1,492 Total 107,300 92,470 75,925 4,461 11,539 3,005 2,309 1,345 525 298,878 Source: PLATTS database; Electricity and Cogeneration Regulatory Authority (http://www.ecra.gov.sa/en-us); Arab Union of Electricity (http://www.auptde. org/PublicationsCat.aspx?lang=en&CID=284); Qatar General Electricity & Water Corporation; Bahrain’s Electricity and Water Authority (EWA); Oman Electricity Transmission Company; Egyptian Electricity Holding Company 2017; Iraq’s Ministry of Energy; Jordan’s National Electric Power Company; Electricity of Lebanon; and Moroccan Ministry of Energy, Mining, Water and Environment. Note: CC = combined cycle; CSP = concentrating solar power; DG = diesel generator; GT = gas turbine; Hydro = hydroelectricity; MW = megawatt; PV = photovoltaic; ST = steam turbine; UAE = United Arab Emirates; WB&G = West Bank and Gaza. 43 // 6. MODELING INPUTS AND ASSUMPTIONS added by just four countries: Saudi Arabia (far to deviate from those shown in table 6. ahead of the others with 81 GW), Iraq, Egypt, and Algeria. Renewable energy capacity would be about 50 percent of the total additions, followed by the gas-fired combined cycle technology 6.3. PEAK POWER (25.5 percent), steam turbine technology (12.3 AND ENERGY DEMAND percent), and other technologies in substantially smaller shares. Renewable technologies would be PROJECTIONS represented by solar PV, CSP, and wind. PV is the most popular renewable technology due to the Energy demand and peak power projections data high solar radiance potential in the region and the were compiled from various sources, including decreasing installed capacity costs. In addition, ministries of energy and electricity companies of Saudi Arabia is the only country investing in ISCC different countries in the Pan-Arab region. Peak technology, aiming for two power plants totaling power and energy projections for the period 2 GW capacity. Although not reflected in table 6, the 2018–30 were provided by: The Arab Forum for model considers power plant retirement schedules. Environment and Development, Qatar General Electricity & Water Corporation; Bahrain’s Electricity Egypt, Saudi Arabia, and the United Arab Emirates and Water Authority; Oman Electricity Transmission plan to add nuclear technology to their mix (8.4 Company; Egyptian Electricity Holding Company; GW in total). Iraq’s Ministry of Energy; Jordan’s National Electric It must be kept in mind that, while the expansion Power Company; Electricity of Lebanon; and plans available from countries are instructive, the Moroccan Ministry of Energy, Mining, Water and optimization analysis in this study accommodates Environment. Some of the historical electricity a broader set of possible expansion paths for each demand figures were retrieved from the Arab technology. The resulting additional capacity Union of Electricity. The data on losses comes from targets by country and technology are expected the International Energy Agency. Table 6. Planned/Under Construction Capacity by Technology and Country, in MW (2018–30) Country CC GT ST DG Hydro Nuclear Coal ISCC RE Targets14 Total Algeria 10,800 - - - - - - - 22,000 32,800 Bahrain 4,125 - - - - - - - 700 4,825 Egypt 2,430 7,940 10,550 - 32 2,400 1,950 - 10,700 36,002 Iraq 15,000 2,500 13,000 - - - - - 6,200 36,700 Jordan 3,000 - 900 - - - - - 2,830 6,730 Kuwait 9,350 - - - - - - - 2,000 11,350 Lebanon 570 - - - 126 - - - 1,000 1,696 Libya 250 2,910 2,800 - - - - - 2,200 8,160 Morocco 2,400 - 38 - 1,375 - 3,026 - 10,000 16,839 Oman 1,245 - - 78 - - - - 2,650 3,973 WB&G 650 - - - - - - - - 650 Qatar 3,549 - - - - - - - 1,800 5,349 Saudi Arabia 12,913 30 4,490 - - 3,200 - 1,995 58,700 81,328 Sudan - - - 37 360 - 600 - 5,520 6,517 Syria 100 - - - - - - - - 100 Tunisia 450 - - - - - - - 4,700 5,510 UAE 2,299 - 1,440 - - 2,800 - - 5,030 11,569 Yemen - - - - - - - - - - Total 69,131 13,380 33,218 115 1,893 8,400 5,576 1,995 136,030 269,738 Source: PLATTS database; Electricity and Cogeneration Regulatory Authority (http://www.ecra.gov.sa/en-us); Arab Union of Electricity (http://www.auptde.org/ PublicationsCat.aspx?lang=en&CID=284); Qatar General Electricity & Water Corporation; Bahrain’s Electricity and Water Authority; Oman Electricity Transmission Company; Egyptian Electricity Holding Company 2017; Iraq’s Ministry of Energy; Jordan’s National Electric Power Company; Electricity of Lebanon; and Moroccan Ministry of Energy, Mining, Water and Environment. Note: CC = combined cycle; DG = diesel generator; GT = gas turbine; Hydro = hydroelectricity; ISCC = integrated solar combined cycle; MW = megawatt; RE = renewable energy (includes solar photovoltaic, wind, and concentrated solar power); ST = steam turbine; UAE = United Arab Emirates; WB&G = West Bank and Gaza. 14 Renewable energy targets include installed capacity additions for PV, CSP, and wind. These targets are based on the National Renewable Energy Action Plans released by each country in the study. OCTOBER 2021 // 44 Figure 8 presents annual energy demand figures by country for the years 2020, 2025, and 2030. 6.4. GENERATION The total regional electricity demand is projected to rise from 1,508 terawatt-hours (TWh) in 2020 TECHNOLOGY COST to 2,478 TWh in 2030. In 2020, the countries with ASSUMPTIONS the largest energy demand are Saudi Arabia (422 Capital costs and the fixed and variable operation TWh), Egypt (233 TWh), and Iraq (203 TWh). The and maintenance (O&M) costs of generation same three countries are the main consumers of technologies have a direct impact on the least- energy in 2030. cost investment plans. Table 7 displays, for each generation technology, the type of fuel, the heat Figure 8. Projected Electricity Demand by rate, the capital cost, and the fixed and variable Country, 2020–30, in TWh O&M costs with assumptions used in the study. Ideally these data should be plant specific, but due to limited access to cost data sources this study instead uses generalized information based on averages for each technology. The capital cost of a generation technology includes the cost of site preparation, construction, manufacture, commissioning, and financing of a power plant. Diesel generators have the lowest capital costs, at US$700/kilowatt (kW), Source: The Arab Forum for Environment and Development; Qatar General Electricity & Water Corporation; Bahrain’s Electricity and Water Authority; Oman and nuclear technology has the highest, at Electricity Transmission Company; Egyptian Electricity Holding Company 2017; Iraq’s Ministry of Energy; Jordan’s National Electric Power Company; Electricity US$5,500/kW (mainly due to construction of Lebanon; and Moroccan Ministry of Energy, Mining, Water and Environment and installation expenses). Among renewable provided the peak power and energy demand projections in the period 2018– 30. Some of the historical electricity demand figures were retrieved from the resources, decreasing module prices and higher Arab Union of Electricity (AUE). The data on losses comes from the International market competition has led, over the years, to Energy Agency (IEA). Note: ALG = Algeria; BAH = Bahrain; EGY = Egypt; IRQ = Iraq; JOR = Jordan; KSA = lower capital costs of solar PV (US$970/kW). CSP Saudi Arabia; KUW = Kuwait; LEB = Lebanon; LIB = Libya; MOR = Morocco; OMA technology has also experienced decreasing = Oman; WBG = West Bank and Gaza; QAT = Qatar; SUD = Sudan; SYR = Syria; TUN = Tunisia; TWh = terawatt-hour; UAE = United Arab Emirates; YEM = Yemen. capital costs; however, compared with other Table 7. Technology Fuel, Heat Rate, and Cost Assumptions Heat Rate Capital Cost ($ Fixed O&M Cost Variable O&M Technology Fuel (MMBtu/MWh) million/MW) ($/MW-yr) Cost ($/MWh) GT LCR 9.75 0.81 8,100 4.05 GT NG 9.75 0.81 8,505 4.46 CC NG 6.00 1.22 8,370 2.24 CC LNG 6.00 1.22 8,370 2.24 ST HCR 9.45 2.50 10,530 2.37 ST HFO 9.45 2.50 10,530 2.37 ST NG 9.45 2.50 10,530 2.37 ST Coal 8.74 2.90 32,100 4.61 DG Diesel 9.85 0.70 10,000 10 ISCC NG 7.45 3.77 31,180 4.42 Hydro Water - 2.00 14,130 - Wind Wind - 1.49 22,000 - Solar PV Sun - 0.97 10,000 - Solar CSP Sun - 4.40 40,000 4 Nuclear Uranium 10.48 5.50 96,200 2.21 Source: Pan-Arab: Based on two previous planning studies performed by King Fahad University of Petroleum (KFUPM) in 2011, and the World Bank in 2009; IEA 2014. Note: CC = combined cycle; CSP = concentrating solar power; DG = diesel generator; GT = gas turbine; HCR = heavy crude oil; HFO = heavy fuel oil; Hydro = hydroelectricity; ISCC = integrated solar combined cycle; LCR = light crude oil; LNG = liquefied natural gas; MMBtu = million British thermal units; MWh = megawatt- hour; MW-yr =megawatts per year; NG = natural gas; O&M = operation and maintenance; PV = photovoltaic; ST = steam turbine. 45 // 6. MODELING INPUTS AND ASSUMPTIONS generation technologies, it remains an amounts of coal for electricity production and that expensive option for least-cost expansion. hydro meets a significant portion of the demand in Sudan. The study assumes (except for Cases 0 and 1) 6.5. FUEL MIX, international prices for liquid and solid fuels. Table 8 presents the price assumptions for different fuels FUEL PRICES, AND (except natural gas) by year, in $/MMBTU. The coal CONSUMPTION LIMITS price increases at an average rate of 1.7 percent per year over the planning horizon to 2035. For most oil derivatives (heavy crude oil, heavy fuel The Pan-Arab region relies heavily on natural oil, light fuel oil, and Arabian super light crude) gas and oil derivatives to produce electricity. As and liquefied natural gas, the increase is close displayed in figure 9, the regional fuel mix (top), to 4 percent per year. In the case of shale oil, the in 2017, consisted of 65 percent gas, 29 percent increase is 3.3 percent per year. The study assumes oil, 3 percent hydro, 2 percent coal, and less that the cost of uranium remains unchanged over than 1 percent of wind and solar. When looking the planning horizon. at the fuel mix on a country by country basis (bottom), it is observed that Morocco is the only country in the region that uses significant Table 8. Regional Prices for Liquid and Solid Fuels (US$/MMBTU) Annual Average Growth Figure 9. Regional and Country-by-Country Fuel Coal 2018 4.00 2020 4.30 2025 4.80 2030 5.30 2035 5.30 Rate: 2018 –35 (%) 1.7 Fuel Mix for the Pan-Arab Region (2017) Diesel 10.00 15.20 19.10 19.10 19.10 3.9 Heavy crude oil (HCR) 7.80 11.80 14.90 14.90 14.90 3.9 Heavy fuel oil (HFO) 7.80 11.80 14.90 14.90 14.90 3.9 Light crude oil (LCr) 8.60 13.00 16.40 16.40 16.40 3.9 Arabian super light crude (SLCR) 11.80 15.80 18.90 18.90 18.90 2.8 Liquefied natural gas (LNG) 6.31 8.03 10.80 11.96 11.96 3.8 Refuse16(REF) 4.00 4.30 4.80 5.30 5.30 1.7 Shale Oil 0.40 0.50 0.60 0.70 0.70 3.3 Uranium 0.67 0.67 0.67 0.67 0.67 0.0 Source: World Bank Commodity Market Outlook, October 2016 (Coal and Crude Oil); U.S. Energy Information Administration, spot prices for fuel oil and other products: http://www.eia.gov/dnav/pet/pet_pri_spt_s1_d.htm. Note: MMBTU = million British thermal units. Shale oil, an unconventional oil produced from oil shale rock fragments, is available in Jordan. In order to assess the impact of natural gas price changes on regional electricity trade, this study considers two sets of natural gas prices by country: current prices and international prices. Table 9 presents the first set of prices, the current natural gas price by country. These prices were derived following a netback approach.17 Most countries have natural gas prices in the range of US$4.5–5.5 per million British thermal units (MMBTU) in 2018, 15 Million British thermal units. 16 Refuse is unprocessed municipal solid waste. Source: Arab Union of Electricity 2017. 17 For details on the assumptions employed to estimate Note: ALG = Algeria; BAH = Bahrain; EGY = Egypt; IRQ = Iraq; JOR = Jordan; KUW = Kuwait; LEB = Lebanon; LIB = Libya; MOR = Morocco; OMA = Oman; these prices, refer to a discussion on the value of gas, WBG = West Bank and Gaza; QAT = Qatar; SA = Saudi Arabia; SUD = Sudan; netbacks, and cost of production, by country: chapter 10 of SYR = Syria; TUN = Tunisia; UAE = United Arab Emirates; YEM = Yemen. World Bank and Ramboll (2017a). OCTOBER 2021 // 46 Table 9. Current Natural Gas Price Table 10. International Natural Gas Price Assumptions, Assumptions, in US$/MMBTU, by Country Based on EU Hub Prices, in US$/MMBTU, by Country Country 2018 2020 2025 2030 2035 Country 2018 2020 2025 2030 2035 Algeria 4.50 4.50 5.50 6.50 6.50 Algeria 5.00 5.00 6.00 7.00 7.00 Bahrain 5.00 5.00 6.00 7.00 7.00 Bahrain 5.50 5.50 6.50 7.50 7.50 Egypt 5.00 5.00 6.00 7.00 7.00 Egypt 5.00 5.00 6.00 7.00 7.00 Iraq 4.00 4.00 4.50 5.00 5.00 Iraq 5.00 5.00 6.00 7.00 7.00 Jordan 5.00 5.00 6.00 7.00 7.00 Jordan 5.50 5.50 6.50 7.50 7.50 Kuwait 5.00 5.00 6.00 7.00 7.00 Kuwait 5.50 5.50 6.50 7.50 7.50 Lebanon 5.50 5.50 6.50 7.50 7.50 Lebanon 5.50 5.50 6.50 7.50 7.50 Libya 4.30 4.50 5.50 6.50 6.50 Libya 5.00 5.00 6.00 7.00 7.00 Morocco 5.00 5.00 6.00 7.00 7.00 Morocco 5.50 5.50 6.50 7.50 7.50 Oman 3.50 3.50 4.50 5.00 5.00 Oman 5.00 5.50 6.50 7.50 7.50 WB&G 4.50 4.50 5.50 6.50 6.50 WB&G 5.50 5.00 6.00 7.00 7.00 Qatar 5.00 5.00 6.00 7.00 7.00 Qatar 5.00 5.50 6.50 7.50 7.50 Saudi Arabia 5.00 5.00 6.00 7.00 7.00 Saudi Arabia 5.00 5.00 6.00 7.00 7.00 Sudan 4.00 4.00 4.50 5.00 5.00 Sudan 5.00 5.00 6.00 7.00 7.00 Syria 5.00 5.00 6.00 7.00 7.00 Syria 5.50 5.50 6.50 7.50 7.50 Tunisia 5.00 5.00 6.00 7.00 7.00 Tunisia 5.50 5.50 6.50 7.50 7.50 UAE 5.50 5.50 6.50 7.50 7.50 UAE 5.50 5.50 6.50 7.50 7.50 Yemen 4.30 4.50 5.50 6.50 6.50 Yemen 5.00 5.00 6.00 7.00 7.00 Source: World Bank staff based on World Bank and Ramboll (2017b). Source: World Bank staff based on World Bank and Ramboll (2017b). Note: MMBTU = million British thermal units; UAE = United Arab Emirates; Note: MMBTU = million British thermal units; UAE = United Arab Emirates; WB&G = West Bank and Gaza. WB&G = West Bank and Gaza. increasing by approximately US$2/MMBTU to a Price.18 This study assumes that countries with range of US$6.5–7.5/MMBTU in 2030. relatively easy access to gas will be priced at the international price and countries with limited Table 10 presents the second set of natural gas access to gas will see a transportation cost of prices considered in this study, the international $0.5/MMBTU added to their gas price.19 gas prices by country. These prices were derived based on the spot price set on the closest gas Countries with ample gas resources—such as hub to the region, the European Union (EU) Hub Qatar, Saudi Arabia, Egypt, Iraq, and Oman—are Figure 10. Natural Gas Consumption Limit per Year, in Billion Cubic Meters (bcm) Source: World Bank and Ramboll 2017a; CIA: https://www.cia.gov/library/publications/the-world-factbook/geos/jo.html. Note: UAE = United Arab Emirates; WB&G = West Bank and Gaza;(*) For Yemen, these values for gas limits are an estimation based on current gas production and construction and the outlook for the end of the conflict and the recovery process (see table 35 for more details). 18 The evolution of international gas price was taken from Table 1 of World Bank and Ramboll (2017a). 19 See appendix C for country-specific approach. 47 // 6. MODELING INPUTS AND ASSUMPTIONS priced at the international natural gas price, percent). For CSP, Yemen (20 percent) and Jordan EU Hub. Economies with limited resources or (20 percent) have the highest capacity factors. For access to natural gas—such as Sudan, the West hydro, Egypt (55 percent) and Jordan (57 percent) Bank and Gaza, Morocco, and Lebanon—add stand out. transportation costs to their gas price. Due to the richness of renewable energy Limits on fuel consumption are an important resources in the Pan-Arab region, especially wind part of producing a model with realistic results. and solar, this study applies limits on capacity Specifically, for this study, it is important to deployment for these two technologies. It apply limits to natural gas consumption given constrains the total capacity of wind and solar PV that, based on the richness of the resource not to exceed 40 percent of peak demand by year, in the Pan-Arab region, it is the lowest-cost a limit applied to ensure that the transmission option. If gas availability is left unconstrained, network will manage the intermittency of these countries with cheap gas will consume as much renewable energy resources during peak hours. as needed, leading to solutions that might be unfeasible to implement. Some countries that have plenty of natural gas reserves have limited Table 11. Renewable Energy Capacity Factors infrastructure to generate electricity from gas, Country Wind (%) Solar PV (%) CSP (%) Hydro (%) while others are running low on reserves. Algeria 20 23 15 13 Bahrain 36 21 12 - Figure 10 presents the natural gas consumption Egypt Iraq 31 17 24 23 16 16 55 19 limits by year, by country.20 Qatar, Saudi Arabia, Jordan 30 26 20 57 Kuwait 16 21 13 - and Algeria have the highest availability of Lebanon 16 24 19 - natural gas for electricity production. Sudan, Libya 16 23 16 49 Morocco 21 22 17 17 West Bank and Gaza, and Morocco are the Oman 31 26 19 - economies with the lowest gas availability. WB&G Qatar 20 22 22 22 16 14 - - Saudi Arabia 38 26 19 - Sudan 13 24 16 32 6.6. RENEWABLE Syria 13 23 18 21 Tunisia 18 22 16 12 UAE 14 23 15 - ENERGY TECHNOLOGIES Yemen 18 27 20 - Source: Solar PV capacity factor was estimated based on PVOut data on specific locations by SolarGIS, https://solargis.com/; hydro: IHA 2017; wind and CSP: based on weather data provided by SolarGIS, wind and CSP profiles Table 11 displays the average annual capacity were estimated using the System Advisor Model (SAM), https://sam.nrel.gov/. factor for each renewable energy technology— Note: Capacity factor for CSP without storage. CSP = concentrating solar power; Hydro = hydroelectricity; PV = photovoltaic; UAE = United Arab wind, solar PV, CSP, and hydro—for each Emirates; WB&G = West Bank and Gaza. country. Five countries exhibit wind capacity factors above 30 percent: Bahrain (36 percent), Egypt (31 percent), Jordan (30 percent), Oman (31 percent), and Saudi Arabia (38 percent). For 6.7. COSTS OF solar PV, three countries have average capacity FAILURE TO ACHIEVE factors over 25 percent: Oman (26 percent), Saudi Arabia (26 percent), and Yemen (27 RELIABILITY OF SUPPLY To estimate the economic costs due to failure to maintain the reliability of supply, this study 20 These amounts were estimated by adding the production employs two criteria: the cost of unserved and import balances detailed in table 2 of World Bank and Ramboll (2017a). The figures for West Bank and Gaza energy and the cost of unmet reserve capacity were assessed from World Bank (2017: figure 3). Estimated requirements. The latter consists of two natural gas demand in the West Bank and Gaza is until components corresponding to two products that 2030 (ESMAP; data provided to the report by ECO Energy). the system operator might require generators For Sudan, although it has proven natural gas reserves (CIA, to provide during operation: planning reserve Economy watch, etc.), several sources indicate that Sudan does not consume or produce natural gas. Also, it does not margin and spinning reserves. The values of these have operating natural-gas-fueled generation capacity. components, further explained in appendix B, are OCTOBER 2021 // 48 Table 12. Cross-Border Transmission Lines Assumptions, by Country Transfer Limits (MW) Transfer Limits (MW) From-To/From-To From-To/From-To 2018 2020 2025 2030 2035 2018 2020 2025 2030 2035 ALG-MOR-ALG 400 400 1,000 1,000 1,000 JOR-SYR-JOR 350 350 800 1,000 1,000 ALG-TUN-ALG 300 300 300 300 300 KSA-GCCIA-KSA 1,200 1,200 1,800 1,800 1,800 BAH-GCCIA-BAH 600 600 1,200 1,200 1,200 KSA-YEM-KSA 0 0 500 500 500 EGY-JOR-EGY 450 450 1,100 1,100 1,100 KSA-OMA-KSA 0 0 0 1,000 1,000 EGY-KSA-EGY 0 0 3,000 3,000 3,000 KSA-KUW-KSA 0 0 0 1,000 1,000 EGY-LIB-EGY 180 180 550 1,000 1,000 KUW-IRQ-KUW 0 0 0 1,000 1,000 EGY-SUD-EGY 200 200 1,200 1,200 1,200 KUW-GCCIA-KUW 1,200 1,200 1,800 1,800 1,800 EGY-WBG 25 25 200 200 200 LEB-SYR-LEB 470 470 1,200 1,200 1,200 IRQ-KSA-IRQ 0 0 500 1,000 1,000 LIB-TUN-LIB 0 0 500 1,000 1,000 IRQ-SYR-IRQ 227 227 227 227 227 OMA-UAE-OMA 400 400 400 400 400 JOR-IRQ-JOR 0 0 500 500 500 QAT-GCCIA-QAT 750 750 1,800 1,800 1,800 JOR-KSA-JOR 0 0 500 1,000 1,000 UAE-GCCIA-UAE 900 900 1,800 1,800 1,800 JOR-WBG 40 40 200 200 200 Source: The Arab Forum for Environment and Development; Qatar General Electricity & Water Corporation; Bahrain’s Electricity and Water Authority; Oman Electricity Transmission Company; Egyptian Electricity Holding Company 2017; Iraq’s Ministry of Energy; Jordan’s National Electric Power Company; Electricity of Lebanon; Moroccan Ministry of Energy, Mining, Water and Environment; and Mediterranean Transmission System Operators (Mediterranean Project 1). Note: ALG = Algeria; BAH = Bahrain; EGY = Egypt; GCCIA = Gulf Cooperation Council Interconnection Authority; IRQ = Iraq; JOR = Jordan; KSA = Saudi Arabia; KUW = Kuwait; LEB = Lebanon; LIB = Libya; MOR = Morocco; MW = megawatt; OMA = Oman; WBG = West Bank and Gaza; QAT = Qatar; SUD = Sudan; SYR = Syria; TUN = Tunisia; UAE = United Arab Emirates; YEM = Yemen. assumed in this study as follows: • Unserved energy cost: $500/MWh • Planning reserve shortfall cost: $5,000/MW • Spinning reserve shortfall cost: $1,000/MWh 6.8. CROSS-BORDER INTERCONNECTIONS Table 12 displays each cross-border transmission line considered in this study, including both existing and planned lines, commissioning dates, and transfer limits. There are 10 transmission lines that are under construction or planned. This includes a 3,000 MW Egypt Saudi Arabia line that is to be commissioned in 2022. The following chapter details the results of the study, focusing on the potential benefits of engaging in regional electricity trade among the Pan-Arab countries using the assumptions described in this chapter. 49 // 6. MODELING INPUTS AND ASSUMPTIONS THE VALUE OF TRADE AND REGIONAL INVESTMENTS IN THE PAN-ARAB ELECTRICITY MARKET: INTEGRATING POWER SYSTEMS & BUILDING ECONOMIES 7 RESULTS Using the Electricity Planning Model (EPM), this study has generated projections of how the Pan- 7.1. PEAK DEMAND AND Arab region’s electricity sector will grow under different assumptions. The modeling results INSTALLED CAPACITY provide insights into how electricity trade will PROJECTIONS impact important areas of the region’s power system, such as total capacity and investment, Table 13 presents the projected total installed total system costs, cost of electricity, the capacity based on the results for Case 0 (which benefits of bilateral trade, carbon emissions, and assumes that no electricity trade takes place, gas transmission line utilization rates. prices for electricity production remain subsidized, and that each country independently makes its The model planning horizon comprises the own capacity investments to satisfy its projected period 2018–35. Model input data, for the demand) along with peak demand by country. years 2018–30, were compiled from various sources: the Arab Forum for Environment and Development; Qatar General Electricity & Water Corporation; Bahrain’s Electricity and 7.2. CAPACITY Water Authority; Oman Electricity Transmission Company; the Egyptian Electricity Holding ADDITIONS AND Company; Iraq’s Ministry of Energy; Jordan’s National Electric Power Company; Electricity of INVESTMENT COSTS Lebanon; and the Moroccan Ministry of Energy, Electricity trade can defer capacity additions Mining, Water and Environment. Some of the through more efficient use of generation assets. historical electricity demand and capacity This can alleviate the financial strain on the Pan-Arab figures were retrieved from the Arab Union of region’s utilities and treasuries, since when trade is Electricity and the International Energy Agency. enabled, countries can defer capital investments in The projection of relevant input parameters, electricity infrastructure that would otherwise be such as energy demand, for the period 2030–35 required for them to meet growing demand. Table was estimated by using the same growth rates 14 presents the capacity additions required for each that are projected for the period 2025–30. case and the cumulative investment figures. Table 13. Projected Peak Demand and Total Installed Capacity by Country, in GW, Case 0 (Base) 2018 2020 2025 2030 2035 Country Peak Installed Peak Installed Peak Installed Peak Installed Peak Installed Demand Capacity Demand Capacity Demand Capacity Demand Capacity Demand Capacity Algeria 12.9 20.6 15.2 27.9 18.6 27.9 22.4 33.6 27.3 36.2 Bahrain 3.6 3.9 4.1 4.7 4.8 8.1 5.7 8.9 6.8 9.4 Egypt 31.6 38.9 40.4 52.2 53.2 69.2 69.1 90.9 90.5 113.9 Iraq 24.0 30.3 28.0 39.8 41.0 66.4 60.0 85.1 76.8 102.5 Jordan 3.6 4.8 4.1 6.1 5.3 7.1 6.7 8.4 8.9 10.4 Kuwait 13.6 18.8 16.4 20.7 20.9 25.4 23.2 29.2 26.4 32.6 Lebanon 3.6 2.2 3.6 2.7 3.8 5.8 4.4 7.3 5.1 7.7 Libya 5.0 9.9 6.3 9.2 7.2 17.8 8.2 19.7 9.4 20.4 Morocco 6.5 8.8 7.5 17.0 9.5 21.8 11.9 24.0 15.1 25.3 Oman 7.3 9.6 9.3 11.2 11.9 12.7 15.2 16.7 19.5 20.8 WB&G 1.4 1.2 1.6 1.4 2.1 3.3 2.6 3.9 3.2 3.7 Qatar 7.8 11.9 8.7 11.0 9.8 13.1 10.7 13.1 11.7 12.1 Saudi Arabia 69.9 84.8 76.9 90.2 94.1 126.1 109.6 139.4 124.3 154.9 Sudan 3.2 4.5 5.5 5.8 10.1 11.2 18.6 15.8 34.5 19.6 Syria 5.7 8.7 6.9 10.5 8.3 14.3 10.0 12.6 12.1 13.3 Tunisia 3.8 6.1 4.6 6.8 5.9 7.7 7.0 9.3 8.8 10.9 UAE 23.4 31.6 34.0 34.0 45.5 48.4 58.1 62.9 69.6 73.6 Yemen 1.4 1.5 1.7 1.6 2.2 2.4 2.7 2.6 3.7 2.9 Total Capacity 298.07 352.82 488.74 583.53 670.19 Source: World Bank staff based on EPM output. Note: GW = gigawatt; UAE = United Arab Emirates; WB&G = West Bank and Gaza. 51 // 7. RESULTS Table 14. Investment Requirements for Total Capacity Additions, by Case Scenario Capacity Addition Capacity Investment Baseline Comparison (relative to Case 0) 2018-35 (GW) 2018-35 (NPV in $ million)a $ million % change Case 0 361 262,672 - - Case 1 350 251,865 (10,817) -4% Case 2 379 365,749 103,077 39% Case 3 364 367,513 104,841 40% Case 4 553 745,058 482,387 184% Case 5 490 624,877 362,206 138% Case 6 274 252,568 (10,104) -4% Source: World Bank staff based on EPM output. Note: Each of the capacity investment figures in this table is the sum of the discounted values of investment costs for each year through 2035. Yearly investment costs used in the calculation are not annualized. GW = gigawatt; NPV = net present value. In Case 0, the baseline scenario, 361 gigawatts Case 6, which assumes a lower electricity demand (GW) of new capacity will be added by 2035, than all the other cases, stands out as the least requiring a cumulative investment of US$262.7 capital-intensive one. The required installed billion in generation. When electricity trade is capacity is 87 GW less than in the baseline Case 0, introduced under Case 1, which still uses the and the investment need is 4% below the baseline. current gas prices, the capacity additions and When the cases with trade and without trade are investment decrease. Cumulative investment falls compared, using the same time horizon (2018–35), by US$10.8 billion, a 4 percent reduction, and it turns out that Case 1 saves 11 GW of installed capacity additions are reduced by 11 GW. capacity and US$10.8 billion in capital costs relative The use of international gas prices results in to Case 0; Case 3 saves 15 GW but increases the higher capacity additions and investment. In Cases capital costs by US$1.8 billion versus Case 2; and 2 and 3, the assumed transition to international Case 5 saves 63 GW and as much as U$120.2 billion gas prices (EU Hub prices) is accompanied by in capital costs versus Case 4. increased cumulative investment needs. This is due to the displacement of gas-fired technology by more capital-intensive options requiring no 7.3. TOTAL SYSTEM fossil fuel inputs. Specifically, Case 2 requires US$103.1 billion more in cumulative investment COSTS than the baseline, a 39 percent increase. Case 3 requires US$104.8 billion more than the baseline, Introducing electricity trade reduces total a 40% increase. However, this is more than offset system costs in all scenarios. In doing so, it can by a reduction in other costs as discussed in the save the Pan-Arab region’s utilities and treasuries next subsection on total system costs. money that can be allocated to other policy In Cases 4 and 5, the introduction of a cap on carbon emissions further increases the required Figure 11. Total System Cost Comparisons (US$ billion) capacity additions and total investments. Relative to other cases, the carbon cap scenarios are marked by a substantial uptake of the capital- intensive concentrating solar power (CSP) technology. Case 4 would require 553 GW in additional capacity and a cumulative investment of US$482.4 billion more than the baseline, a 184 percent increase. Relative to Case 4, the cumulative investment figures are reduced in Case 5 when trade is introduced. Still, Case 5 requires US$362.2 billion more in cumulative investment than the baseline. Source: World Bank staff based on EPM output. Note: CO2 = carbon dioxide; EU = European Union. OCTOBER 2021 // 52 priorities. Figure 11 displays the total costs for trade in Case 1. Figure 12 shows the cost components each scenario. The dark-blue bars represent contributing to this result. The capital expenditures the cases with no trade and the light-blue bars decrease to some extent, as trade enables the region represent the cases with trade. to invest in and access cheaper generation sources. Fuel costs are reduced as the system transitions from The cost components comprising the total system expensive liquid fuels to gas. The costs to meet the costs are shown in figures 12, 13, and 14. The total reserve requirements fall especially sharply as trade system costs consist of a typical set of electricity enables greater access to reserves through cross- generation costs and, for Cases 0 and 1, one specific border transmission interconnections. type of opportunity cost related to the cost of subsidy on natural gas being used as fuel for electricity The benefits from trade have similar proportions in generation. Generation costs consist of annualized the scenarios that assume a transition of the region capital expenditure (CAPEX), fuel costs, fixed and to international gas prices. While Case 2 has a total variable operation and maintenance (O&M) costs, system cost of US$1,317 billion, this decreases by and the costs to procure spinning reserves, as well as US$107 billion, or 8.1 percent, with the introduction penalties for unmet demand (or “unserved energy”) of trade in Case 3. The capital expenditures are and unmet reserve requirements. The latter penalty slightly lower with trade, even as more renewables occurs when the system fails to comply with the are deployed when gas is priced at international required reserve capacity, including spinning reserves. levels. This is because the difference in total capacity Finally, the mentioned opportunity cost is related to additions, 15 GW less in Case 3, offsets the higher using natural gas for electricity production instead of cost of investing in more renewables. Moreover, selling it for export revenue. this reduction in cost is accompanied by reductions in other cost components, notably the fuel costs As shown in figure 11, Case 0 has a total system cost of and unmet capacity reserves, working in favor US$1,335 billion and this decreases by US$110 billion, of the scenario with trade (figure 13). Unlike the or 8.2 percent, with the introduction of electricity scenarios with current gas prices, the opportunity cost of using gas for electricity (i.e., gas subsidy Figure 12. Total System Costs, Case 1 vs. Case 0 cost) is no longer included since the domestic and international gas prices are equalized. Figure 13. Total System Costs, Case 3 vs. Case 2 Source: World Bank staff based on EPM output. Note: CAPEX = capital expenditure; NPV = net present value; O&M = operation and maintenance. 21 The annualization of the capital investment costs (CAPEX) Source: World Bank staff based on EPM output. is a built-in feature of the calculation of total system costs Note: CAPEX = capital expenditure; NPV = net present value; O&M = operation and maintenance. in the EPM. The model applies an annualization formula to every investment cost value throughout the planning horizon. The advantage of annualization is that, for any given year, the CAPEX cost component can be more easily Finally, when gas price liberalization is also compared with the running cost components such as fuel accompanied by the introduction of carbon caps, and O&M. A notable disadvantage is that the net present the benefits from trade are even greater. As was value (NPV) of a stream of annualized CAPEX values over a certain time period (for example, 2018–35) is not directly shown in figure 11, Case 4 has total system costs comparable with the NPV of a stream of full values of of US$1,491 billion. This decreases by US$196 investment costs for the same time period, when the full billion, or 13.1 percent, with the introduction of values are included without annualization. trade in Case 5. It must be noted that the two 53 // 7. RESULTS cases with carbon caps have much higher Table 15. Difference in Electricity Costs When CAPEX costs than all other scenarios. This is Trading under Case 1: Current Gas Prices because carbon caps require higher levels of Country 2018 (%) 2020 (%) 2025 (%) 2030 (%) 2035 (%) deployment of carbon-free technologies such as Algeria -0.32 2.56 3.96 -1.17 -0.87 Bahrain -7.72 5.60 0.00 -6.36 -8.27 wind and CSP that have high CAPEX but no fuel Egypt -0.90 -1.27 0.92 1.47 1.70 requirements. Iraq -5.76 0.00 -0.23 -0.20 -0.18 Jordan 6.64 -0.94 -25.63 -22.37 -5.13 Kuwait -0.94 -11.78 1.76 0.20 0.42 Lebanon -48.10 -26.38 -36.73 7.29 11.53 Figure 14. Total System Costs, Case 5 vs. Case 4 Libya 0.00 -0.20 -0.02 1.52 0.50 Morocco 23.44 31.67 -11.44 2.30 2.56 Oman 0.77 0.65 5.35 0.22 3.88 WB&G -1.03 0.00 0.02 0.84 15.47 Qatar 5.49 4.10 32.59 23.12 25.50 Saudi Arabia 2.35 -1.24 -6.17 -5.31 8.46 Sudan -6.28 -7.13 -40.88 -26.39 -15.82 Syria -1.03 -11.05 7.70 2.75 -0.69 Tunisia 2.75 -4.44 -0.94 -54.65 -24.59 UAE 0.21 -25.94 1.00 2.29 2.43 Yemen 0.00 -3.69 -32.80 -43.20 -35.89 Source: World Bank staff based on EPM output. Note: Negative values indicate there is a reduction in annual marginal cost of electricity. UAE = United Arab Emirates; WB&G = West Bank and Gaza. Source: World Bank staff based on EPM output. Note: CAPEX = capital expenditure; NPV = net present value; O&M = operation and maintenance. that lack the generation capacity or resources to meet their load in a cost-effective manner. However, the exporting countries also receive revenues from 7.4. IMPACT ON this trade, which can be spent on other policy priorities such as social programs. ELECTRICITY COSTS When trade is enabled with international gas prices, the trend is similar. Countries that have cost The introduction of electricity trade impacts the increases are mainly gas-exporting countries and, cost of electricity in each country. In some cases, on average, countries with low gas availability it significantly reduces the cost of electricity, but will see their cost of electricity decrease, but cost other countries will experience increases in their changes are not as pronounced (table 16). This is electricity costs. because when international gas prices are used When trade is enabled with current gas prices, instead of current gas prices, the gas prices are most countries see only a marginal change in their homogeneous across the region. When imbalances current cost of electricity (table 15). Some countries see a larger increase in the cost of their electricity. Table 16. Difference in Electricity Costs when Oman and Qatar, for example, see electricity costs Trading under Case 3: International Gas Prices increase for each time period through 2035. In Country 2018 (%) 2020 (%) 2025 (%) 2030 (%) 2035 (%) Qatar, costs will increase by 33 percent in 2025 and Algeria -0.31 2.56 0.99 -0.52 -0.63 by 25 percent in 2035. On the other hand, Jordan, Bahrain -8.04 4.23 8.95 2.91 0.66 Lebanon, Sudan, and Yemen may see sharply Egypt Iraq 0.47 -3.76 -1.13 2.26 0.33 0.31 1.07 -0.50 0.65 0.27 decreased costs by 2025. The countries that have Jordan 2.81 -4.58 -23.87 -15.43 -8.79 cost increases are mainly gas-exporting countries. Kuwait Lebanon -0.39 -48.06 -6.33 -25.88 -3.71 -36.95 -0.62 7.57 1.07 10.86 They have an incentive to invest more in generating Libya 0.00 -0.80 0.21 0.19 0.00 Morocco -22.97 31.01 -9.79 2.12 0.34 capacity due to their ability to generate electricity Oman 0.41 0.58 8.95 4.55 2.39 at lower prices. However, as they install more WB&G -0.99 0.00 0.02 2.09 15.81 Qatar 4.21 2.97 21.51 11.70 5.09 generation, the cost of electricity also rises as they Saudi Arabia -1.94 -1.49 -0.96 -0.85 -2.25 may be investing in progressively more expensive Sudan -6.28 -7.13 -40.86 -26.26 -15.82 Syria 0.87 -11.05 7.54 0.39 -1.44 generation technologies. Tunisia 2.78 -4.31 0.17 -52.64 -24.54 UAE 0.23 -25.83 -1.64 2.33 3.01 These countries must invest more heavily in Yemen 0.00 1.03 -27.35 -38.88 -33.82 generation resources that are required in order to Source: World Bank staff based on EPM output. Note: Negative values indicate there is a reduction in annual marginal cost of generate additional electricity to export to countries electricity. UAE = United Arab Emirates; WB&G = West Bank and Gaza OCTOBER 2021 // 54 like this are reduced, it is more expensive for generation in different countries. In the simplest case countries with ample gas availability to produce of bilateral trade, the shared benefit from trade is the electricity for export, and marginal cost differences product of the cost differential and the volume of among countries will not be as significant. electricity traded. In general, countries seeing cost increases in Shared Benefit from Trade = (Ci - Ce) x Q the earlier years may find their costs eventually Where: decreasing. The temporary increase is mainly driven • Ci, in $/megawatt-hour (MWh), is the by the need to overcome an initial transmission marginal cost of electricity of the importing infrastructure deficit that hinders the optimal levels country without trading; of trade. In 2020–25, as many new transmission lines are commissioned, broader trade within the region • Ce, in $/MWh, is the marginal cost of the will bring the costs down, with electricity importers exporting country without trading; and being the most direct beneficiaries. • Q, in MWh, is the quantity (or volume) of electricity traded over a time period. 7.5. SHARED BENEFITS In a calculation done for this report (see appendix E for details), trade was assumed to take place through FROM BILATERAL TRADE the interconnections already existing as well as new ones built over the period to 2035. For simplicity, it The form of economic benefits discussed in this was assumed that the benefits of trade were always subsection is a useful additional metric to gauge the divided equally between the trading countries, benefits from trade. These are meant to complement which is the case when the price P of the trade is set (but not to replace) the more comprehensive at midpoint between the importer’s and exporter’s account of the benefits based on total system cost production costs, that is, P = (Ci + Ce)/2. Table 17 savings discussed earlier. Its advantage is relative shows the aggregate results from the calculation. simplicity and the possibility to apply the method Figure 15 shows the annual shared economic to a variety of time frames. For the short term, it benefits of the exchanges of electricity for Case 1, can produce useful results based on current data Case 3, Case 5, and Case 6, for specified years (2020, rather than relying on long-term projections. 2025, 2030, and 2035). Case 5 exhibits the highest However, it can also be applied for the 2018–35 shared economic benefits among all the cases, with period considered in this report. The limitations of annual benefits above $10 billion in some countries the method are due to the omission of potentially (whereas the highest annual benefits for all other important variables (e.g., system reliability costs) cases stays below $2.5 billion). This is because to exogenous to the inputs in its basic formula. achieve the CO2 limits imposed in Case 5, the price of As was explained in chapter 3, electricity trade can electricity increases in the region as countries have to bring substantial economic benefits to the region invest in higher-cost low-carbon technologies. through a relatively simple process of utilizing While all countries receive the benefits from trade, the differentials in the marginal costs of electricity Egypt, Sudan, Saudi Arabia, Tunisia, and Libya have Table 17. Shared Economic Benefits of Electricity Trade among the Arab Countries Shared Bene ts from Trade, NPV over Cases 2018–2035, $ Billion Case 0: Natural gas current prices, no electricity trading N/A Case 1: Natural gas current prices, electricity trading 40.3 Case 2: Natural gas international prices, no electricity trading N/A Case 3: Natural gas international prices, electricity trading 32.2 Case 4: Natural gas international prices, no electricity trading, CO2 emissions limit N/A Case 5: Natural gas international prices, electricity trading, CO2 emissions limit 150.0 Case 6: Natural gas international prices, electricity trading, CO2 emissions limit 25.3 Source: World Bank staff based on EPM output. Note: CO2 = carbon dioxide; NPV = net present value; N/A = not applicable; EE = energy efficiency; DR = demand response. 55 // 7. RESULTS the highest figures for the benefits of trade in all cases except Case 5; Sudan and Tunisia receive these 7.6. COMMERCIAL benefits, mainly as importers, from exchanging electricity with Egypt and Libya, respectively. With VALUE OF TRADE carbon caps (Case 5), Saudi Arabia emerges as the Commercial value of bilateral trade is the other largest beneficiary, in years 2030 and 2035, because important metric to complement, rather than of the increase of the utilization of the new cross- replace, the economic value of the benefits based border lines coupled with a significant increase in on the total system cost savings. The formula for the cost of electricity in the countries engaging in the commercial value of trade is VoT = (Ci + Ce)/2 x exchanges with it, as they have to invest in higher- Q, using the same inputs as in the shared benefits cost, low-carbon technology, such as CSP, to comply formula. with the CO2 emission limits.22 Based on the projected generation costs and quantities of electricity flowing through the lines, Figure 15. Shared Economic Benefits of Trade table 18 shows that the value of electricity traded for Cases 1, 3, 5, and 6 can be between US$59.5 billion and US$166.6 billion. It is important to stress the commercial (or financial, rather than economic) nature of the value of trade discussed here. Since the exporter’s revenue is the importer’s cost, the region-wide monetary net value of trade at any time is zero. However, the metric is still useful as a measure of the overall market activity in the region, whether its volume is measured as the total exporters’ revenue or the total importers’ cost. On an absolute as well as net basis, it also shows each country’s position in exports and imports. Figures 16–19 display the value of trade as the annual exporters’ revenue and importers’ cost, in US$ billion, for the years 2020, 2025, 2030, and 2035 for Cases 1, 3, 5, and 6. For most cases, Saudi Arabia is a major exporter, both in absolute and net terms, especially in the later years of the analysis: 2025–30 and afterwards. Egypt is a major player as well, with export and import transactions rivaling those of Saudi Arabia and even exceeding them in absolute terms in Case 6 (energy efficiency). Applying carbon caps, Case 5, has an important effect on defining a country as a net importer or exporter. For instance, for most cases, Algeria, Oman, Qatar, Iraq, Libya, and Syria are considered net exporters and Morocco and Jordan are considered net importers; however, once CO2 targets are required, their role as importers/ Source: World Bank staff based on EPM output. exporters will change.23 This is because of their Note: ALG = Algeria; BAH = Bahrain; EGY = Egypt; IRQ = Iraq; JOR = Jordan; KSA = availability of carbon-free generation technologies. Saudi Arabia; KUW = Kuwait; LEB = Lebanon; LIB = Libya; mm = million; MOR = Morocco; OMA = Oman; WBG= West Bank and Gaza; QAT = Qatar; SUD = Sudan; SYR = Syria; TUN = Tunisia; UAE = United Arab Emirates; YEM = Yemen. 23 It is important to note that Syria’s power system has to be further evaluated to reflect the realities of system costs, 22 For details on the shared economic benefit of bilateral supply availability, demand, and level of damage caused by trade estimates for all the cases, refer to appendix E. conflict in the country. OCTOBER 2021 // 56 Table 18. Commercial Value of Electricity Trade (Export or Import Value) among the Arab Countries Value from Trade, NPV over Cases 2018–2035, $ Billion Case 0: Natural gas current prices, no electricity trading N/A Case 1: Natural gas current prices, electricity trading 59.5 Case 2: Natural gas international prices, no electricity trading N/A Case 3: Natural gas international prices, electricity trading 62.9 Case 4: Natural gas international prices, no electricity trading, CO2 emissions limit N/A Case 5: Natural gas international prices, electricity trading, CO2 emissions limit 166.6 Case 6: Natural gas international prices, electricity trading, CO2 emissions limit 59.6 Source: World Bank staff based on EPM output. Note: CO2 = carbon dioxide; NPV = net present value; N/A = not applicable; EE = energy efficiency; DR = demand response. Figure 16. Value of Trade for Case 1 for the Figure 18. Value of Trade for Case 5 for the years 2020, 2025, 2030, and 2035 years 2020, 2025, 2030, and 2035 Source: World Bank staff based on EPM output. Source: World Bank staff based on EPM output. Note: ALG = Algeria; BAH = Bahrain; EGY = Egypt; IRQ = Iraq; JOR = Jordan; KSA = Note: ALG = Algeria; BAH = Bahrain; EGY = Egypt; IRQ = Iraq; JOR = Jordan; KSA Saudi Arabia; KUW = Kuwait; LEB = Lebanon; LIB = Libya; mm = million; MOR = = Saudi Arabia; KUW = Kuwait; LEB = Lebanon; LIB = Libya; mm = million; MOR = Morocco; OMA = Oman; WBG= West Bank and Gaza; QAT = Qatar; SUD = Sudan; Morocco; OMA = Oman; WBG= West Bank and Gaza; QAT = Qatar; SUD = Sudan; SYR = Syria; TUN = Tunisia; UAE = United Arab Emirates; YEM = Yemen. SYR = Syria; TUN = Tunisia; UAE = United Arab Emirates; YEM = Yemen. Figure 17. Value of Trade for Case 3 for the Figure 19. Value of Trade for Case 6 for the years 2020, 2025, 2030, and 2035 years 2020, 2025, 2030, and 2035 Source: World Bank staff based on EPM output. Source: World Bank staff based on EPM output. Note: ALG = Algeria; BAH = Bahrain; EGY = Egypt; IRQ = Iraq; JOR = Jordan; KSA Note: ALG = Algeria; BAH = Bahrain; EGY = Egypt; IRQ = Iraq; JOR = Jordan; KSA = = Saudi Arabia; KUW = Kuwait; LEB = Lebanon; LIB = Libya; mm = million; MOR = Saudi Arabia; KUW = Kuwait; LEB = Lebanon; LIB = Libya; mm = million; MOR = Morocco; OMA = Oman; WBG= West Bank and Gaza; QAT = Qatar; SUD = Sudan; Morocco; OMA = Oman; WBG= West Bank and Gaza; QAT = Qatar; SUD = Sudan; SYR = Syria; TUN = Tunisia; UAE = United Arab Emirates; YEM = Yemen. SYR = Syria; TUN = Tunisia; UAE = United Arab Emirates; YEM = Yemen. 57 // 7. RESULTS 7.7. IMPACT OF TRADE Figure 21. Total CO2 Emissions by Case, in Million Tons CO2 Equivalent, 2018–35 ON CO2 EMISSIONS The impact of trade on CO2 emissions in the region was also considered. As figure 20 shows, the impact of trade per se is moderately positive (that is, it leads to moderate reductions in CO2 emissions). However, it is less pronounced than the impact of the other key factors involved, such as the transition to international gas prices, or the introduction of CO2 emissions limits. When trade is introduced while the Source: World Bank staff based on EPM output. Note: CO2eq = carbon dioxide equivalent. gas prices are at current levels, the CO2 emissions reduction is almost negligible. It is more significant when the gas prices are set at international levels If the CO2 emissions under international gas prices and even more so once energy efficiency (EE) and are compared with those under the current domestic demand response (DR) measures are also adopted. prices, the emission savings amount to 1.08 billion When, in addition to considering international tons of CO2 equivalent when there is no trade, to gas prices, CO2 emissions caps are introduced, the about 1.24 billion tons when there is trade, and to impact of trade is small again, but the impact of the 1.92 billion tons after also adopting energy efficiency CO2emission limits themselves is quite significant. and demand response measures. If, in addition to international gas prices, CO2 caps are introduced, the additional savings will amount to 1.26 billion tons of Figure 20. Total CO2 Emissions in 2018–35 CO2 without trade and 1.08 billion tons with trade. The growth of CO2 emissions over time seems inevitable (figure 21) but the growth rate depends on the case analyzed, with the “greener” cases (Case 4 and Case 5) yielding more moderate emission growth rates. For example, the average annual emission growth rate for Case 5 is 1.5 percent, versus 3.6 percent in Case 0. Although the average annual emission growth rate for Case 6 is 2.2 percent, higher than in Case 5, figure 21 shows that in the years 2025 Source: World Bank staff based on EPM output. Note: bn tCO2eq = billion tons of carbon dioxide equivalent; CO2 = carbon and 2030 CO2 emissions for Case 6 are lower than for dioxide; EE = energy efficiency; DR = demand response. Case 5. Table 19. Total Installed Capacity by Technology, MW Year 2035 Year 2035 Year 2035 Year 2035 Year 2035 Year 2035 Year 2035 Year 2018 Case 0 Case 1 Case 2 Case 3 Case 4 Case 5 Case 6 CC 106,392 382,073 374,850 345,241 330,932 355,277 343,749 291,897 CSP 525 2,244 1,366 2,278 2,278 161,809 98,712 1,382 GT 93,298 94,067 83,940 91,102 91,102 84,073 77,821 79,589 Hydro 11,382 10,348 10,348 10,348 10,348 12,458 12,458 10,348 DG 4,461 1,388 1,420 1,386 1,386 1,393 1,383 1,351 PV 1,345 72,580 69,214 69,160 69,160 64,669 65,666 60,414 ST 75,358 51,738 50,496 51,738 51,738 51,110 51,110 50,496 Wind 2,309 22,033 34,938 46,205 46,205 55,507 56,283 34,719 Nuclear - 11,602 10,768 48,796 55,131 56,028 71,751 31,210 ISCC - - - - - - - - Coal 3,005 22,083 22,083 22,135 22,122 20,095 20,614 22,051 TOTAL: 298,075 670,191 659,422 688,389 673,101 862,419 799,547 583,457 Source: World Bank staff based on EPM output. Note: CC = combined cycle; CSP = concentrating solar power; DG = diesel generator; GT = gas turbine; Hydro = hydroelectricity; ISCC = integrated solar combined cycle; MW = megawatt; PV = photovoltaic; ST = steam turbine. OCTOBER 2021 // 58 The dynamics of CO2 emissions in Cases 1 to 3 and in total installed capacity over the period 2018–35. Case 6 are driven to a large extent by the changing While total installed capacity grows at about 4.0–6.4 mix of generation technologies. Applying CO2 percent per year, renewable energy sources grow emissions policy (such as carbon caps in Cases mostly at double-digit rates, although CSP has rates 4 and 5) will provide a path for controlling these below 10 percent in Cases 1–3 and 6. emissions. Tables 19 and 20 show the generation Figure 22 takes the total energy generated by mix in absolute terms (in MW) and as a share of technology by case, Cases 0 to 5, to illustrate the total installed capacity. Wind, solar PV, and CSP are dynamics of penetration of the three mentioned the three zero-emission renewable energy sources renewable energy sources in the total energy in the calculation. output over time. It is observed that renewable As table 20 shows, the share of zero-emission energy output increases with higher natural gas renewable energy technology is expected to prices (comparing Case 2 versus Case 0 and Case increase dramatically in all six cases considered, 3 versus Case 1), as higher fuel prices make these albeit starting from a very low base in 2018. technologies more economically competitive. When a carbon policy is introduced (Cases 4 and Table 21 shows the average annual growth rates Table 20. Share of Total Installed Capacity by Technology, including Renewable Energy Sources Year 2018 Year 2035 Year 2035 Year 2035 Year 2035 Year 2035 Year 2035 Year 2035 (%) Case 0 (%) Case 1 (%) Case 2 (%) Case 3 (%) Case 4 (%) Case 5 (%) Case 6 (%) CC 35.7 57.0 56.8 50.2 49.2 41.2 43.0 50.0 CSP 0.2 0.3 0.2 0.3 0.2 18.8 12.3 0.2 GT 31.3 14.0 12.7 13.2 12.0 9.7 9.7 13.6 Hydro 3.8 1.5 1.6 1.5 1.5 1.4 1.6 1.8 DG 1.5 0.2 0.2 0.2 0.2 0.2 0.2 0.2 PV 0.5 10.8 10.5 10.0 10.5 7.5 8.2 10.4 ST 25.3 7.7 7.7 7.5 7.5 5.9 6.4 8.7 Wind 0.8 3.3 5.3 6.7 7.4 6.4 7.0 6.0 Nuclear 0.0 1.7 1.6 7.1 8.2 6.5 9.0 5.3 ISCC 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Coal 1.0 3.3 3.3 3.2 3.3 2.3 2.6 3.8 Total: 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0 RES, MW 4,179 96,858 105,518 117,643 121,864 281,985 220,661 96,515 RES, % 1.4 14.5 16.0 17.1 18.1 32.7 27.6 16.5 Source: World Bank staff based on EPM output. Note 1: CC = combined cycle; CSP = concentrating solar power; DG = diesel generator; GT = gas turbine; Hydro = hydroelectricity; ISCC = integrated solar combined cycle; PV = photovoltaic; RES = renewable energy sources; ST = steam turbine. Note 2: The solar PV potential in the report is based on the solar mapping results estimated by the World Bank for every country. However, the ability to realize such renewable energy capacity potential to meet domestic demand and/or regional trade is subject to each country’s priorities, as well as specifics of sector development context and readiness. Table 21. Annual Average Growth Rate of Installed Capacity by Technology, 2018–35 Case 0 (%) Case 1 (%) Case 2 (%) Case 3 (%) Case 4 (%) Case 5 (%) Case 6 (%) CC 7.7 7.7 7.2 6.9 7.4 7.1 6.1 CSP 8.9 5.8 9.0 5.8 40.1 36.1 5.9 GT 0.0 -0.6 -0.1 -0.8 -0.6 -1.1 -0.9 Hydro -0.6 -0.6 -0.6 -0.6 0.5 0.5 -0.6 DG -6.6 -6.5 -6.6 -6.7 -6.6 -6.7 -6.8 PV 26.4 26.1 26.1 26.2 25.6 25.7 25.1 ST -2.2 -2.3 -2.2 -2.3 -2.3 -2.3 -2.3 Wind 14.2 17.3 19.3 19.8 20.6 20.7 17.3 Nuclear 9.9 9.4 21.0 22.0 22.1 24.1 17.4 ISCC 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Coal 12.5 12.4 12.5 12.5 11.8 12.0 12.4 Total 4.9 4.8 5.0 4.9 6.4 6.0 4.0 RES 20.3 20.9 21.7 21.9 28.1 26.3 20.3 Source: World Bank staff based on EPM output. Note: CC = combined cycle; CSP = concentrating solar power; DG = diesel generator; GT = gas turbine; Hydro = hydroelectricity; ISCC = integrated solar combined cycle; PV = photovoltaic; RES = renewable energy sources; ST = steam turbine. 59 // 7. RESULTS Figure 22. Renewable Energy in Total Energy Generated Source: World Bank staff based on EPM output. Note: CSP = concentrating solar power; Hydro = hydroelectricity; PV = photovoltaic; RES = renewable energy sources; TWh = terawatt-hour. OCTOBER 2021 // 60 5), both renewable and nuclear generation decreasing demand growth requires fewer significantly increase their participation in the capacity additions. energy mix in order to comply with the policy Total cumulative capacity additions in Case 3 mandate. After adopting energy efficiency add up to 364 GW; this decreases by 90 GW, and demand response measures and enabling or 25 percent, under Case 6 (total of 274 GW). electricity trade, total energy generation Figure 24 presents the changes, by technology, decreases (Case 6 vs Case 2) due to overall in cumulative capacity additions by 2035. It is regional electricity demand reduction. observed that, when comparing Case 6 to Case 3, practically all technologies experience reductions 7.8. IMPACT OF ENERGY in their deployment, most notably combined cycle (39 GW reduction or 21 percent), solar PV (10 EFFICIENCY AND DEMAND GW reduction or 16 percent), and wind (15 GW reduction or 38 percent). RESPONSE ON THE BENEFITS FROM TRADE Figure 24. Cumulative Capacity Addition by 2035, in GW As energy efficiency and demand response programs are becoming increasingly relevant in the Pan-Arab region, this section assesses the impact of decreasing energy demand projections on the benefits from trade in the region. Specifically, this run of the model compares Case 6 with Case 3 in order to determine the impact of changes in electricity demand on total systems costs. Figure 23 shows the results of the comparison. Source: World Bank staff based on EPM output. While Case 3 has a total system cost of US$1,211 Note: CC = combined cycle; CSP = concentrating solar power; DG = diesel generator; GT = gas turbine; GW = gigawatt; Hydro = hydroelectricity; PV = billion, this decreases by US$107 billion, or 9 photovoltaic; ST = steam turbine. percent, with the consideration of demand-side measures in Case 6. The capital expenditures and other costs components are reduced as 7.9. SUMMARY OF Figure 23. Total System Costs, Case 3 vs. Case 6 POTENTIAL TRADE BENEFITS This chapter provided insights into how electricity trade will impact important areas of the region’s power systems using the EPM, including total capacity and investment, total system costs, cost of electricity, the benefits of bilateral trade, carbon emissions, and transmission line utilization rates. Table 22 presents a summary of potential electricity trade benefits across the Pan-Arab Source: World Bank staff based on EPM output. Electricity Market (PAEM) in 2018–35 based on the Note: CAPEX = capital expenditure; NPV = net present value; O&M = comparison between the cases with trade allowed operation and maintenance. (Case 1, 3, 5 and 6) and the cases without trade (Case 0, 2 and 4). 61 // 7. RESULTS Table 22. Summary of Potential Electricity Trade Benefits across PAEM for the Period 2018–35 Shared Cost Savings Total Economic Commercial Average Energy for CO2 Share of Investment Trade System Cost Bene ts Value of Transmission Security Emissions Renewable in Renewable Case Savings (US$ Trade (US$ Utilization in Improvement Compliance Capacity Technologies (US$ billion) billion) billion) 2035 US$ billion Installed (US$ billion) Case 1 $110 $109 $60 41% 38% N/A 16% $64 Case 3 $107 $32 $62 37% 38% N/A 18% $88 Case 5 $196 $150 $167 43% 53% $86 28% $305 Case 6 $213 $25 $60 37% 63% N/A 17% $68 Source: World Bank EPM calculations. OCTOBER 2021 // 62 63 // 7. RESULTS THE VALUE OF TRADE AND REGIONAL INVESTMENTS IN THE PAN-ARAB ELECTRICITY MARKET: INTEGRATING POWER SYSTEMS & BUILDING ECONOMIES 8 TRANSMISSION INVESTMENT ANALYSIS In addition to the assessment of potential economic benefits of electricity trade, this report 8.1. EVALUATING seeks to develop an understanding of the relative merits of various transmission interconnections THE BENEFITS OF between national power systems.24 Some of INTERCONNECTORS them have been previously discussed and debated in other studies. However, they need to Using the formulation of the electricity planning be reassessed in light of the substantial changes model described in chapter 6, this transmission to the countries’ demand-supply situation, the investment analysis assesses the benefit of existing growing role of renewable energy in the Pan- and proposed cross-border interconnections in the Arab region, and the recent developments in Pan-Arab region by comparing the changes in total establishing the Pan-Arab Electricity Market cost of the system and interconnection utilization (PAEM) with increased interest to advance using the following modified scenarios: electricity trade by countries with surplus • Business as Usual (BAU): Under this generation capacity. scenario, natural gas is priced at international The aim of this chapter is to present an economic levels but no electricity is traded through planning framework for cross-border cross-border lines, that is, electricity interconnections in the region and apply it to generation in each country is used to supply existing and proposed interconnectors to assess demand in that country (same as Case 2, see potential transmission investment opportunities. section 5.2). It provides a preliminary assessment of investment • Existing Interconnections: Building on cost estimates that should serve as a baseline the BAU, under this scenario, cross-border for a framework to prioritize the cross-border electricity trade is enabled only for existing interconnections proposed in this study to realize interconnections throughout the entire the commercial electricity trade benefits in the PAEM. planning horizon. Figure 25. Analytical Framework Used to Assess the Benefit of Cross-Border Interconnections in the Pan-Arab Region Source: World Bank staff. Note: CAPEX = capital expenditure. 24 Although it is not in the scope of this study, it is important to highlight that a more detailed estimation of transmission interconnections exchanges and costs will require engaging in detailed load flow studies for each identified interconnection. 65 // 8. TRANSMISSION INVESTMENT ANALYSIS • Proposed Interconnections: Building on costs for each scenario with interconnectors the existing interconnection scenario, under are compared with those of the BAU scenario. this scenario, cross-border electricity trade is • Greater reliability: Greater ability to meet enabled for existing and proposed new and demand and reserves, which can in turn reinforced interconnections, commissioned reduce the amount of unserved energy. To at different periods of the planning horizon assess this benefit, yearly unmet demand (same as Case 3, see section 5.2). (damage/economic loss because of unmet Figure 25 summarizes the analytical framework demand) and unmet reserve (penalty for used to assess the benefit of proposed new or unmet spinning reserve requirements) costs reinforced cross-border interconnections in the Pan- for each scenario with interconnectors are Arab region. compared with those of the BAU scenario. In this chapter, the assessment of potential economic benefits from electricity trade will EXISTING CROSS-BORDER mainly focus on the following categories: INTERCONNECTIONS IN THE • Deferred capacity: Better utilization of PAN-ARAB REGION capacity resources across the zones in Based on interconnection data collected from annual the region, which can contribute to a reports from electricity and transmission companies decrease in the total capacity needed in the region and other regional studies, figure 26 to meet demand. To assess this benefit, presents the transmission lines that are considered yearly capital costs for each scenario with to model the “existing interconnections” scenario. It is interconnectors are compared with the important to notice that the three subregions are not capital costs of the BAU scenario. currently interconnected, which makes it a priority to • Fuel savings: Access to lower fuel cost focus on identifying critical interconnectors that will generation from other zones within the lead to a true Pan-Arab regional electricity market. For region. To assess this benefit, yearly fuel instance, it is critical to develop the interconnections Figure 26. Regional Network with Existing Cross-Border Interconnections Source: Based on data from Table 12. Note: The transfer capacities of the existing transmission lines represented in this figure are based on the limitations set by contracting arrangements between the interconnected countries. In some cases, the design capacities of currently installed cross-border lines are higher. OCTOBER 2021 // 66 between Tunisia and Libya, between Egypt and EXISTING REGIONAL Saudi Arabia (currently under construction), and between Saudi Arabia and Jordan or Iraq. INTERCONNECTIONS Enabling trade based just on the utilization of the PROPOSED NEW AND existing transmission interconnections: REINFORCED CROSS-BORDER • Decreases total system costs by US$71 INTERCONNECTIONS IN THE billion (compared with the case without trade, Case 2) PAN-ARAB REGION • Increases the annual average utilization26 Table 23 describes the details on location, from 5–7 percent in 2018 to 36 percent in transfer capacity, and commissioning year of the 2035 new and reinforced interconnections proposed in this study. Notice that critical interconnections • Results in shared economic benefits of have been proposed such as the lines Tunisia US$13 billion Libya, Saudi Arabia Egypt, Saudi Arabia Jordan, • Exhibits an estimated commercial value of and Saudi Arabia Iraq. trade of US$23 billion Figure 27 illustrates how the regional network • Improves energy security by 23 percent would look by 2035 based on the proposed investment projects. It shows an overlay of the • Increases the share of renewable existing interconnections (black arrows) with technologies in the energy mix to 17.6% by the proposed interconnections (green arrows) 2035 including their transfer limits, in MW, and • Requires an investment of US$86.5 billion commissioning year. However, as the various in renewable technologies. countries become increasingly intertwined, a Figure 28 illustrates the interconnectors, and the complex situation will arise requiring extensive direction, that are used more than 50 percent by load flow and system stability studies to 2035 (in orange). It also indicates that Algeria, determine the impact of power exchanges on Saudi Arabia, Jordan, and Libya are electricity their various domestic networks. Some may exporters while Tunisia, Lebanon, Kuwait, and require significant additional costs to evacuate Bahrain are electricity importers. power, relieve bottlenecks, and maintain system security. Table 24 presents the potential benefits, for the period 2018–35, from engaging in regional electricity trade by increasing the utilization of existing cross-border interconnectors. Total economic benefits amount to US$71 billion 8.2. KEY FINDINGS: derived mainly from fuel savings and system reliability improvements. This is a remarkable UTILIZATION OF finding considering the fact that $71 billion in costs savings can effectively be achieved CROSS-BORDER without any hard investment in new physical INTERCONNECTORS interconnection. There is of course a need to improve coordination and related control AND BENEFIT ANALYSIS facilities, but the cost of such softer measures is likely to be a small fraction of the savings. The following subsections analyze the interconnections’ utilization throughout the 26 Annual average interconnection utilization refers to the entire planning horizon of the study and assess unitless ratio calculated by dividing the yearly electricity economic benefits. flowing over a transmission line by the maximum possible yearly electricity flow. 67 // 8. TRANSMISSION INVESTMENT ANALYSIS Table 23. Reinforced and Proposed New Interconnections25 Increased Total Capacity Commissioning Reinforced Interconnections (MW) Capacity (MW) Year 1 Algeria (Ghazaouet/Tlemcen) Morocco (Oujda) 600 1,000 2025 2 Egypt (High Dam) Sudan (Merow) 1,000 1,200 2025 3 Egypt (El Arish) Gaza Strip 175 200 2025 4 Egypt (Towiba) Jordan (Aqaba) 650 1,100 2025 5 Jordan (Amman West) West Bank 160 200 2025 6 Libya (Tobruk) Egypt (Saloum Sidi Krir PP) Stage 1 370 550 2025 7 Libya (Tobruk) Egypt (Saloum) Stage 2 450 1,000 2030 8 Jordan (Amman North) Syria (Dir Ali) Stage 1 450 800 2025 9 Jordan (Amman North) Syria (Dir Ali) Stage 2 200 1,000 2030 10 Lebanon (Ksara) Syria (Dimas) 730 1,200 2024 11 Saudi Arabia GCCIA Interconnection System 600 1,800 2025 12 Kuwait GCCIA Interconnection System 600 1,800 2025 13 Qatar GCCIA Interconnection System 1,050 1,800 2025 14 UAE GCCIA Interconnection System 900 1,800 2025 15 Bahrain GCCIA Interconnectoin System 600 1,200 2025 Commissioning Proposed New Interconnections Total Capacity (MW) Year 16 Saudi Arabia (Medinah) Egypt (Badr) 3,000 2023 17 Saudi Arabia (Jazan) Yemen (Saana/Tiaz/Aden) 500 2025 18 Tunisia (Bouchemma) Libya (Melitia) Stage 1 500 2023 19 Tunisia (Bouchemma) Libya (Melitia) Stage 2 500 2027 20 Saudi Arabia (Qurayyat) Jordan (Qatranah) 1,000 2027 21 Saudi Arabia (Hail) Iraq (Karbala) 1,000 2027 22 Jordan (Amman East) Iraq (Qa’im) via Azraq NPS 500 2025 23 Saudi Arabia (Ras Abu Gamys) Oman (Ibri IPP) 1,000 2027 24 Kuwait (Subiyah) Iraq (Basra) 1,000 2027 25 Kuwait (Jahra) Saudi Arabia (Qaisumah/Rafha) 1,000 2027 Source: Proposed by World Bank staff after consultations with countries representatives. Note: MW = megawatt. 25 Even if the commissioning year of one or more cross-border interconnection project are delayed, the projects proposed in this table are still relevant as a baseline for regional investments between the PAEM countries. To further detail the economic benefits of trade, PROPOSED AND REINFORCED figure 29 illustrates the annual benefit over time, by cost category (left) and the changes in capacity INTERCONNECTORS additions (right) in years 2020, 2025, 2030, and 2035. Accounting for existing, proposed, and Table 25 presents the expected electricity flows reinforced interconnections to engage in for the existing cross-border interconnections regional electricity trade increases the annual and their respective utilization for the year 2035, average utilization from 5–7 percent in 2018 to organized from the highest interconnection 35 percent in 2035. There are 14 interconnectors utilization to the lowest. Some interconnections that are consistently used, in the cases where with lower utilization can exchange a higher electricity trade was enabled, more that 50 amount of electricity than those with higher percent in 2035. Figure 30 illustrates the utilization. For instance, with an interconnection interconnectors, and their direction, that are utilization of 31 percent, the line from the United used more than 50 percent by 2035 (in red). Arab Emirates (UAE) to the Gulf Cooperation It indicates that Algeria, Egypt, Syria, and Council Interconnection Authority (GCCIA) registers Saudi Arabia are electricity exporters while an electricity volume of 2,409 gigawatt hours Iraq, Kuwait, Bahrain, Yemen, Sudan, Morocco, (GWh) in 2035. This is higher than the flow in the Lebanon, and Tunisia are electricity importers. interconnector from Libya to Egypt, 1,555 GWh in Table 26 presents the potential benefits, for 2035, which has a utilization of 99 percent. the period 2018–35, from engaging in regional electricity trade by commissioning proposed OCTOBER 2021 // 68 Figure 27. Regional Network with Proposed and Reinforced Cross-Border Interconnections Source: Proposed by World Bank staff after consultations with countries representatives. Note: KSA = Saudi Arabia; MW = megawatt; UAE = United Arab Emirates; WB&G = West Bank and Gaza. Figure 28. Existing Cross-Border Interconnectors’ Utilization in 2035 Source: World Bank staff based on EPM output. Note: All maps in this document are for illustration purposes of cross-border projects only and not intended to reflect any political boundaries. GCCIA = Gulf Cooperation Council Interconnection Authority; MW = megawatt; UAE = United Arab Emirates; WB&G = West Bank and Gaza. and reinforced cross-border interconnectors increasing the utilization of existing cross- in the Pan-Arab region. Allowing regional border interconnections, will lead to even electricity trade will result in important economic more economic benefits. The incremental benefits, potentially amounting to US$107 benefits of planned interconnections over and billion, derived mainly from savings on costs above that of the existing interconnection is needed for maintaining capacity reserve and $35 billion (= $107 billion minus $72 billion). fuel savings. This means that investing in more The decreasing incremental benefits from regional interconnectors, compared to only the new interconnectors indicate that most 69 // 8. TRANSMISSION INVESTMENT ANALYSIS Table 24. Summary of Economic Benefits of Engaging in Regional Trade by Increased Utilization of Existing Cross-Border Interconnections Total System Fuel Costa Capital Costb Reliabilityc O&M Costd Scenario Cost ($ million) ($ million) ($ million) ($ million) ($ million) Without any cross-border 1,317,531 850,346 180,307 120,605 166,274 interconnectors, BAU Pan-Arab system With increased utilization 1,246,055 831,426 181,558 65,751 167,320 of existing cross-border interconnectors Bene tse 71,476 18,920 -1,251 54,854 -1,047 Source: World Bank staff based on EPM output. Note: Total discounted cost of operating the regional power system in the period of 2018–35, assuming discount rate of 6 percent. (a) Total cost of fuel consumed in the period of 2018–35; (b) Total annualized cost of building new generation capacity in the period 2018–30, assuming a weighted average cost of capital (WACC) of 6 percent; (c) Includes the cost of unserved energy plus the cost of unserved reserves; (d) Includes fixed and variable operation and maintenance cost; and (e) Economic benefits are estimated as the difference between the discounted cost of the power system without using cross-border interconnectors minus the discounted cost of the system using existing cross-border interconnectors. BAU = business as usual. Figure 29. Annual Economic Benefits of Engaging in Regional Electricity Trade (Years 2020, 2025, 2030, and 2035: Left—Using Existing Interconnectors; Right—Changes in Capacity Additions) Source: World Bank staff based on EPM output. Note: CAPEX = capital expenditure; CC = combined cycle; CS = concentrating solar power; DG = diesel generator; GT = gas turbine; GW = gigawatt; HY = hydroelectricity; O&M = operation and maintenance; PV = photovoltaic; ST = steam turbine; WI = wind; NK = nuclear; SC = coal-fired steam turbine. of the benefits have already been achieved by by system cost category (left) and the changes better utilization of existing interconnectors. As in capacity additions (right) in years 2020, 2025, discussed later in more detail, this would typically 2030, and 2035. Changes in capacity additions entail some of the planned interconnections show increased deployment of renewable being loaded lightly, albeit these would also and nuclear energy. They also show decreased generate savings. It is uncertain whether the deployment of fossil-fueled generation that incremental benefit of $35 billion would cover would otherwise be deployed for capacity the investments needed for all of the proposed reserve, mainly combined cycle and gas turbine interconnectors. To determine this, a major technologies. engineering study would be required to assess Table 27 presents the expected electricity flows the costs. Nevertheless, a discounted $35 billion for the existing and proposed cross-border over 18 years (which represents typically between interconnections and their respective utilization half and one-third of the life of a transmission for the year 2035, organized from the highest asset) can support upward of 100 major interconnection utilization to the lowest. The interconnection projects, which far exceeds the first 18 interconnections represent potential number of projects that are considered as part of transmission investments that will strengthen this study. electricity trade in the region, amounting to a To further detail the economic benefits of trade, total of 130 terawatt-hours (TWh) of electricity figure 31 illustrates the annual benefit over time, traded in 2035. OCTOBER 2021 // 70 Table 25. Expected Flows and Utilization for Existing Cross-Border Interconnections in 2035 From To Flow in Utilization From To Flow in 2035 Utilization 2035 (GWh) in 2035 (%) (GWh) in 2035 (%) Egypt Sudan 1,749 100 Qatar GCCIA 1,930 26 Libya Egypt 1,555 99 GCCIA UAE 1,798 21 Algeria Tunisia 2,498 94 Jordan WB&G 53 15 Syria Lebanon 3,594 87 Syria Jordan 431 14 Jordan Egypt 3,329 85 GCCIA Qatar 581 10 Saudi Arabia GCCIA 8,686 81 GCCIA Saudi Arabia 997 10 GCCIA Kuwait 7,150 66 Egypt WB&G 19 9 Oman UAE 2,135 55 Jordan Syria 248 8 Iraq Syria 1,014 51 Bahrain GCCIA 237 5 Syria Iraq 958 48 Lebanon Syria 89 2 GCCIA Bahrain 2,556 47 Egypt Jordan 81 2 Morocco Algeria 1,204 34 UAE Oman 41 1 UAE GCCIA 2,409 31 Kuwait GCCIA 87 1 Algeria Morocco 1,039 29 Egypt Libya - 0 Source: World Bank staff based on EPM output. Figure 30. Proposed Cross-Border Interconnectors’ Utilization in 2035 Source: World Bank staff based on EPM output. Note: All maps in this document are for illustration purposes of cross-border projects only and not intended to reflect any political boundaries. GCCIA = Gulf Cooperation Council Interconnection Authority; MW = megawatt; UAE = United Arab Emirates; WB&G = West Bank and Gaza. BENEFITS OF SELECTED Algeria–Tunisia, Tunisia–Libya and Libya–Egypt interconnections. INTERCONNECTORS Connecting GCC and Mashreq subregions: To illustrate how the analytical framework Table 28 presents the potential benefits proposed in this section can be applied to the for the first set of interconnectors, over the assessment of specific interconnectors, and period 2018–35, from engaging in regional based on the list of potential interconnection electricity trade by increasing the utilization investments in the Pan-Arab region (table 23), of proposed cross-border interconnectors this study has selected two sets of cross-border between Saudi Arabia–Iraq, Jordan–Iraq, and interconnections as follows: the first set, the Saudi Arabia–Jordan. Total economic benefits Saudi Arabia–Iraq, Jordan-Iraq, and the Saudi amount to US$2.2 billion derived mainly from Arabia–Jordan Interconnections; and the fuel cost savings and some system reliability second set, consisting of the Algeria–Morocco, improvement. This is a significant savings above 71 // 8. TRANSMISSION INVESTMENT ANALYSIS Table 26. Summary of Economic Benefits for the Pan-Arab Regional Trade by Commissioning Proposed Cross-Border Interconnections Total System Fuel Costa Capital Costb Reliabilityc O&M Costd Scenario Cost ($ million) ($ million) ($ million) ($ million) ($ million) Without any cross-border 1,317,531 850,346 180,307 120,605 166,274 interconnectors, BAU With proposed and 1,211,011 825,912 178,018 40,637 166,445 reinforced cross-border interconnectors Bene tse 106,520 24,434 2,289 79,968 -171 Pan-Arab With increased utilization 1,246,055 831,426 181,558 65,751 167,320 system of existing cross-border interconnectors With proposed and 1,211,011 825,912 178,018 40,637 166,445 reinforced cross-border interconnectors Bene tse 35,044 5,514 3,540 25,114 876 Source: World Bank staff based on EPM output. Note: Total discounted cost of operating the regional power system in the period of 2018–35, assuming discount rate of 6 percent. (a) Total cost of fuel consumed in the period of 2018–35; (b) Total annualized cost of building new generation capacity in the period 2018–30, assuming a weighted average cost of capital (WACC) of 6 percent; (c) Includes the cost of unserved energy plus the cost of unserved reserves; (d) Includes fixed and variable operation and maintenance cost; and (e) Economic benefits are estimated as the difference between the discounted cost of the power system without using cross-border interconnectors minus the discounted cost of the system using all (existing and planned) cross-border interconnectors. BAU = business as usual. Figure 31. Annual Economic Benefits of Engaging in Regional Electricity Trade Using Proposed and Existing Interconnectors (Years 2020, 2025, 2030, and 2035: Left—Using Existing Interconnectors; Right—Changes in Capacity Additions) Source: World Bank staff based on EPM output. Note: CAPEX = capital expenditure; CC = combined cycle; CS = concentrating solar power; DG = diesel generator; GT = gas turbine; GW = gigawatt; HY = hydroelectricity; O&M = operation and maintenance; PV = photovoltaic; ST = steam turbine; WI = wind; NK = nuclear; SC = coal-fired steam turbine.. the cost of these interconnectors (see table 32). Connecting the Mashreq and the Maghreb: The benefits of the second set of interconnectors To further detail the economic benefits of trade, are also assessed. Table 30 presents the potential figure 32 illustrates the annual benefit over benefits, for the period 2018–35, from engaging time, by cost category (left) and the changes in regional electricity trade by commissioning in capacity additions (right) in years 2020, the proposed cross-border interconnectors. 2025, 2030, and 2035 for the selected set of The economic benefits are calculated at US$8 interconnections. billion derived mainly from system reliability Table 29 presents the expected electricity flows improvements and fuel cost savings. for the proposed cross-border interconnections To further detail the economic benefits from the and their respective utilization for the year 2035, second set of selected interconnectors, figure organized from the highest interconnection 33 illustrates the annual benefit over time, by utilization to the lowest. OCTOBER 2021 // 72 Table 27. Expected Flows and Utilization of Proposed and Existing Cross-Border Interconnections in 2035 From To Flow in Utilization From To Flow in 2035 Utilization 2035 (GWh) in 2035 (%) (GWh) in 2035 (%) Libya Egypt 8,760 100 UAE GCCIA 4,993 32 Libya Tunisia 8,647 99 Oman Saudi Arabia 2,759 32 Egypt Sudan 9,714 92 Saudi Arabia Oman 2,308 26 Saudi Arabia Kuwait 7,959 91 Qatar GCCIA 3,630 23 Saudi Arabia Yemen 3,983 91 Kuwait Iraq 1,979 23 Algeria Tunisia 2,377 91 Morocco Algeria 1,914 22 Saudi Arabia GCCIA 13,634 87 Jordan WB&G 276 16 Syria Lebanon 9,029 86 UAE Oman 480 14 Saudi Arabia Egypt 20,792 79 GCCIA Qatar 1,954 12 GCCIA Kuwait 12,052 76 Egypt Saudi Arabia 2,779 11 Saudi Arabia Jordan 6,411 73 Iraq Saudi Arabia 929 11 Jordan Egypt 5,952 62 Egypt WB&G 184 11 Iraq Kuwait 5,924 60 Jordan Saudi Arabia 856 10 GCCIA Bahrain 5,959 57 Egypt Jordan 917 10 Oman UAE 1,944 56 GCCIA Saudi Arabia 1,436 9 Iraq Jordan 2,306 53 GCCIA UAE 872 6 Iraq Syria 1,008 51 Bahrain GCCIA 467 4 Saudi Arabia Iraq 4,432 51 Jordan Syria 389 4 Syria Iraq 942 47 Kuwait Saudi Arabia 373 4 Syria Jordan 3,390 45 Lebanon Syria 87 1 Jordan Iraq 1,960 45 Yemen Saudi Arabia 21 1 Algeria Morocco 3,078 35 Sudan Egypt 22 0 Source: World Bank staff based on EPM output. Note: GCCIA = Gulf Cooperation Council Interconnection Authority; GWh = gigawatt-hour; UAE = United Arab Emirates; WB&G = West Bank and Gaza. Table 28. Summary of Economic Benefits of Regional Trade between GCC and Mashreq by Commissioning Proposed Cross-Border Interconnectors between Jordan, Saudi Arabia, and Iraq Total System Fuel Costa Capital Costb Reliabilityc O&M Costd Scenario Cost ($ million) ($ million) ($ million) ($ million) ($ million) Iraq, Jordan and Saudi Arabia without 542,191 351,940 101,158 9,754 79,339 interconnectors Iraq, Jordan, and Saudi Arabia with 540,007 341,591 107,673 9,348 81,395 proposed interconnectors Bene tse 2,184 10,350 -6,515 406 -2,057 Source: World Bank staff based on EPM output. Note: Total discounted cost of operating the regional power system in the period of 2018–35, assuming discount rate of 6 percent. (a) Total cost of fuel consumed in the period of 2018–35; (b) Total annualized cost of building new generation capacity in the period 2018–30, assuming a weighted average cost of capital (WACC) of 6 percent; (c) Includes the cost of unserved energy plus the cost of unserved reserves; (d) Includes fixed and variable operation and maintenance (O&M) cost; (e) Economic benefits are estimated as the difference between the discounted cost of the power system without using cross-border interconnectors minus the discounted cost of the system using selected, planned cross-border interconnectors. cost category (left) and the changes in capacity 99 percent and 98 percent, respectively. additions (right) in years 2020, 2025, 2030, and However, the interconnections between Algeria 2035. Annual economic benefits result, mainly, and Morocco, in both directions, exchange from fuel savings and increased reliability in the the largest amount of electricity among all the systems of these five countries as renewable projects, a total of 17 TWh. energy technologies, solar PV and wind, increase their participation in the energy mix. SENSITIVITY TO ENERGY- Table 31 presents the expected electricity flow SECTOR-RELATED POLICIES for the proposed cross-border interconnection Employing the energy policies described for among Morocco, Algeria, Tunisia, Libya, Egypt Cases 1 and 5 (see section 5.2), the study can and their respective utilization for the year 2035. also infer the sensitivity of interconnection The interconnections from Libya to Tunisia and utilization to changes in natural gas prices and from Libya to Egypt have the highest utilization, environmental policies. Figures 34, 35, 36, and 73 // 8. TRANSMISSION INVESTMENT ANALYSIS Table 29. Expected Flows and Utilization of Table 31. Expected Flows and Utilization of Proposed Cross-Border Interconnections Proposed Cross-Border Interconnections between GCC and Mashreq between Mashreq and Maghreb (2035) (through Jordan, Saudi Arabia, and Iraq, in 2035) (through Reinforced and Proposed Interconnectors among Morocco, Algeria, Tunisia, Libya, and Egypt) From To Flow in Utilization 2035 (GWh) in 2035 (%) From To Flow in Utilization Saudi Arabia Jordan 451 49 2035 (GWh) in 2035 (%) Saudi Arabia Iraq 907 47 Libya Tunisia 2,446 99 Jordan Iraq 1,969 45 Libya Egypt 2,366 98 Jordan Saudi Arabia 927 11 Algeria Tunisia - 90 Iraq Saudi Arabia 4,139 10 Algeria Morocco 8,573 28 Iraq Jordan 4,251 10 Morocco Algeria 8,643 18 Source: World Bank staff based on EPM output. Egypt Libya 1,549 0 Note: GWh = gigawatt-hour; WB&G = West Bank and Gaza. Tunisia Algeria - 0 Tunisia Libya - 0 Source: World Bank staff based on EPM output. 37 display the annual utilization rate for each Note: GWh = gigawatt-hour; WB&G = West Bank and Gaza. cross-border transmission line considered in this study, for the year 2035, engaging in In figure 35, the countries with the highest level electricity trade under current natural gas of exports on their lines are Algeria, Saudi Arabia, prices (Case 1), international gas prices (Case Qatar, and Syria. The countries with the highest 3), CO2 emissions limits (Case 5), and energy level of imports on their lines are Iraq, West Bank efficiency and demand response adoption (Case and Gaza, Kuwait, Tunisia, and Morocco. The lines 6), respectively. The vertical axis represents with utilization >95 percent are: the origin of the transmission line and the horizontal axis represents the line’s destination. Algeria Tunisia, Egypt Sudan, Iraq Jordan, The numbers in the cells represent the Libya Egypt, Libya Tunisia, Qatar GCCIA, utilization of the line (as a fraction from 0 to 1) Saudi Arabia Yemen, Saudi Arabia Kuwait, in 2035. If it is marked in red then the utilization Saudi Arabia Egypt, and GCCIA Kuwait. is >90 percent and at or close to full capacity, Countries with large reserves of gas have declining possibly even overloaded. Light red (80–90 rates of transmission line utilization over time percent), orange (60–70 percent), yellow (30–60 under international gas prices (Case 3, figure 35). percent), light green (10–30 percent), and dark While there are significant investments in gas green (0–10 percent) mark the other levels of generation under this case, there is not enough of utilization. a generation price differential between countries Figure 32. Annual Economic Benefits of Engaging in Regional Electricity Trade Using Proposed Interconnectors Between GCC and Mashreq (Years 2020, 2025, 2030, and 2035: Left—between GCC and Mashreq through Jordan, Saudi Arabia and Iraq; Right—Changes in Capacity Additions) Source: World Bank staff based on EPM output. Note: CAPEX = capital expenditure; CC = combined cycle; CS = concentrating solar power; DG = diesel generator; GT = gas turbine; GW = gigawatt; HY = hydroelectricity; O&M = operation and maintenance; PV = photovoltaic; ST = steam turbine; WI = wind; NK = nuclear; SC = coal-fired steam turbine. OCTOBER 2021 // 74 Figure 33. Annual Economic Benefits of Engaging in Regional Electricity Trade between Mashreq and Maghreb (Years 2020, 2025, 2030, and 2035: Left—Benefits through Reinforced and Proposed Interconnectors among Morocco, Algeria, Tunisia, Libya, and Egypt; Right—Changes in Capacity Additions) Source: World Bank staff based on EPM output. Note: CAPEX = capital expenditure; CC = combined cycle; CS = concentrating solar power; DG = diesel generator; GT = gas turbine; GW = gigawatt; HY = hydroelectricity; O&M = operation and maintenance; PV = photovoltaic; ST = steam turbine; WI = wind; NK = nuclear; SC = coal-fired steam turbine.. Table 30. Summary of Economic Benefits of Regional Trade between Mashreq and Maghreb by Commissioning Reinforced and Proposed Cross-Border Interconnectors among Morocco, Algeria, Tunisia, Libya, and Egypt Total System Fuel Costa Capital Costb Reliabilityc O&M Costd Scenario Cost ($ million) ($ million) ($ million) ($ million) ($ million) Morocco, Algeria, Tunisia, Libya, Egypt 308,270 228,926 28,637 4,256 46,452 without interconnectors Morocco, Algeria, Tunisia, Libya, Egypt 300,260 224,304 27,705 1,882 46,368 with Proposed interconnectors Bene tse 8,010 4,622 932 2,373 84 Source: World Bank staff based on EPM output. Note: Total discounted cost of operating the regional power system in the period of 2018–35, assuming discount rate of 6 percent. (a) Total cost of fuel consumed in the period of 2018–35; (b) Total annualized cost of building new generation capacity in the period 2018–30, assuming a weighted average cost of capital (WACC) of 6 percent; (c) Includes the cost of unserved energy plus the cost of unserved reserves; (d) Includes fixed and variable operation and maintenance (O&M) cost; (e) Economic benefits are estimated as the difference between the discounted cost of the power system without using cross-border interconnectors minus the discounted cost of the system using selected, planned cross-border interconnectors. for trade relative to the case with current gas an importer of electricity; and, when CO2 emission prices (Case 1). However, international gas limits are introduced, Qatar becomes an electricity prices will not reduce utilization rates, as the importer, as indicated in figure 36. system will deploy more renewable and nuclear When demand-side measures are applied, the generation technologies and maintain overall overall average interconnection utilization rate interconnection utilization rates. The average remains unchanged—36 percent, as in Case 3. utilization rate for current gas prices (Case 1) is However, as seen in figure 37, unlike the carbon caps estimated at 40%, international gas prices (Case 3) policy (Case 5), there are not significant changes at 36%, and 45% with CO2 emissions limits (Case in terms of direction of electricity trade flows. For 5, figure 36). instance, in the GCCIA Kuwait interconnection, the Although the overall annual average utilization is latter remains a net importer. However, significant not significantly affected by energy policies, the changes in terms of the magnitude of average utilization of some interconnectors changes in utilization can be found. For example, the average terms of magnitude and direction. For instance, utilization of the interconnection from Saudi Arabia in Case 1 Qatar is an electricity exporter, as the to Egypt decreases from 79 percent in Case 3 to country prices its gas low and enjoys ample 22 percent in Case 6, affecting the prioritization of natural gas reserves. However, as the gas price these interconnectors and indicating that further increases, Qatar becomes neither an exporter nor feasibility studies should be conducted. 75 // 8. TRANSMISSION INVESTMENT ANALYSIS Figure 34. Cross-Border Interconnection Utilization Rates in 2035: Trading under Current Gas Prices (Case 1) Source: World Bank staff based on EPM output. Note: ALG = Algeria; BAH = Bahrain; EGY = Egypt; GCCIA = Gulf Cooperation Council Interconnection Authority; IRQ = Iraq; JOR = Jordan; KSA = Saudi Arabia; KUW = Kuwait; LEB = Lebanon; LIB = Libya; MOR = Morocco; OMA = Oman; WBG = West Bank and Gaza; QAT = Qatar; SUD = Sudan; SYR = Syria; TUN = Tunisia; UAE = United Arab Emirates; YEM = Yemen. Figure 35. Cross-Border Interconnection Utilization Rates (2035): Trading under International Gas Prices (Case 3) Source: World Bank staff based on EPM output. Note: ALG = Algeria; BAH = Bahrain; EGY = Egypt; GCCIA = Gulf Cooperation Council Interconnection Authority; IRQ = Iraq; JOR = Jordan; KSA = Saudi Arabia; KUW = Kuwait; LEB = Lebanon; LIB = Libya; MOR = Morocco; OMA = Oman; WBG = West Bank and Gaza; QAT = Qatar; SUD = Sudan; SYR = Syria; TUN = Tunisia; UAE = United Arab Emirates; YEM = Yemen. OCTOBER 2021 // 76 Figure 36. Cross-Border Interconnection Utilization Rates in 2035, when Trading under International Gas Prices and Applying CO2 Emission Limits (Case 5) Source: World Bank staff based on EPM output. Note: ALG = Algeria; BAH = Bahrain; EGY = Egypt; GCCIA = Gulf Cooperation Council Interconnection Authority; IRQ = Iraq; JOR = Jordan; KSA = Saudi Arabia; KUW = Kuwait; LEB = Lebanon; LIB = Libya; MOR = Morocco; OMA = Oman; WBG = West Bank and Gaza; QAT = Qatar; SUD = Sudan; SYR = Syria; TUN = Tunisia; UAE = United Arab Emirates; YEM = Yemen. Figure 37. Cross-Border Interconnection Utilization Rates in 2035, when Trading under International Gas Prices and Applying Demand-Side Measures (Case 6) Source: World Bank staff based on EPM output. Note: ALG = Algeria; BAH = Bahrain; EGY = Egypt; GCCIA = Gulf Cooperation Council Interconnection Authority; IRQ = Iraq; JOR = Jordan; KSA = Saudi Arabia; KUW = Kuwait; LEB = Lebanon; LIB = Libya; MOR = Morocco; OMA = Oman; WBG = West Bank and Gaza; QAT = Qatar; SUD = Sudan; SYR = Syria; TUN = Tunisia; UAE = United Arab Emirates; YEM = Yemen. 77 // 8. TRANSMISSION INVESTMENT ANALYSIS 8.3. TRANSMISSION must be complemented by suitable transmission cost information, with due consideration of INTERCONNECTION the technological options available. Unit cost estimates such as the transmission line costs per INVESTMENT COSTS kilometer (km) and the unit costs of the required terminal or transformer substation equipment are Ultimately, the analysis of economic benefits from available from various consultants active in the selected interconnection projects discussed above MENA region (see appendix G for details). Table 32. Summary Transmission Technical Characteristics and Estimated Project Costs (EPC), $ Million Reinforced Interconnections Technical Characteristics Distance EPC (km) US$M 1 Algeria (Ghazaouet/Tlemcen) Morocco (Oujda)1 Existing HVAC OHTL 2*220kV and 2*400kV N/A $0.0 2 Egypt (High Dam) Sudan (Merow) HVAC OHTL 500 kV plus 4 bays 730 $374.9 3 Egypt (El Arish) Gaza Strip2 OHTL 200kV rated 950MVA 45 $250.0 4 Egypt (Taba) Jordan (Aqaba) Second line 400kV, HVAC Submarine Cable 13 $150.0 5 Jordan (Amman West) West Bank (JDECO-4) HVAC OHTL 400 kV 40 $39.4 6 Libya (Tobruk) Egypt (Saloum-Sidi Krir PP) Stage 1 500kV line from Sidi Krir to Saloum HVDC BtB, 616 $493.4 400KV to Tobruk 7 Libya (Tobruk) Egypt (Saloum) Stage 2 HVDC BtB/Trafos Upgraded to 1000MW 616 $196.0 8 Jordan (Amman North) Syria (Dir Ali) Stage 1 HVAC OHTL 400 kV plus two bays 105 $53.4 9 Jordan (Amman North) Syria (Dir Ali) Stage 2 each end 10 Lebanon (Ksara) Syria (Dimas) HVAC OHTL 400 kV 42 $44.7 11 Saudi Arabia GCCIA Interconnection System3 Third 600MVA BtB HVDC link 400 kV at Al-Fadhili 0 $0.0 12 Kuwait GCCIA Interconnection System3 Third 650MVA Auto Trafo plus 4 L Trafo bays 0 $7.4 13 Qatar GCCIA Interconnection System3 Existing 2*1900MVA 400kV connections 0 $18.0 14 UAE GCCIA Interconnection System3 Existing 2*1400MVA GCC Grid Lines 0 $0.0 15 Bahrain GCCIA Interconnection System3 Existing 2*750MVA 400 kV lines 0 $6.8 Distance EPC Proposed New Interconnections Technical Characteristics (km) US$M 16 Saudi Arabia (Medinah) Egypt (Badr) OHTL HVDC to Tabruk; 20km submarine cable 1,500 $2,500.0 over Gulf of Aqaba; HVAC OHTL 500kV to Badr City, Egypt in service 2024 17 Saudi Arabia (Jazan) Yemen (Saana/Tiaz/Aden) Jazan 380kV via HVDC BtB OHTL 400 kV 581 $482.6 18 Tunisia (Bouchemma) Libya (Melitia) Stage 1 HVAC OHTL 400kV plus switchbays 250 $125.1 19 Tunisia (Bouchemma) Libya (Melitia) Stage 2 250 20 Saudi Arabia (Qurayyat) Jordan (Qatranah) First Stage HVDC 3 Way Connect Saudi-Jordan-Iraq 165 $425.4 21 Saudi Arabia (Hail) Iraq (Karbala) Hail to Rafha to Arar, Saudi 380kV OHTL and 729 $683.8 HVDC Arar, Saudi to Karbala, Iraq 22 Jordan (Amman East) Iraq (Qa'im) via Azraq NPS Second Stage HVDC 3 Way Connect Saudi-Jordan-Iraq 523 $390.0 23 Saudi Arabia (Ras Abu Gamys) Oman (Ibri IPP) HVDC line with Converters both ends 688 $633.5 24 Kuwait (Subiyah) Iraq (Basra) AC Double circuit OHTL 400kV 122 $66.3 25 Kuwait (Jahra) Saudi Arabia (Qaisumah/Rafha) 380kV OHTL from Rafha to Qaisumah, Saudi; to 492 $611.8 400kV HVDC BtB at border Saudi-Kuwait-Iraq Source: Based on WBG (2019e); Gökhan (2014); WBG Consultant, John R. Irving. Note: JDECO = Jerusalem District Electricity Company 1 Existing capacity of 1200 MVA is constrained by PPA between Morocco and Algeria. The nominal capacity of existing cross- border interconnections between Morocco and Algeria allows the maximum transfer capacity to be increased from 400MW to 1000MW at no extra cost. 2 Lack of investment in its domestic transmission infrastructure limits Gaza’s capability to import power. Increasing power imports from Egypt to Gaza is contingent on upgrading the existing 220kV network throughout the Sinai region, as well as building a 40km 220kV line from Rafah to Jabalia, Gaza. Cost estimate includes 2018 ESMAP estimation of $200m to strengthen Gaza grid to evacuate power supplied from Egypt. 3 Costs of upgrades in the GCCIA system are for the additional transformer capacity required at the respective grid 400/220kV substations, assuming the capacity of the existing facilities has been installed in accordance with the CIGRE 2012 paper: “GCC Interconnection Grid: Operational Studies for the GCC Interconnection with United Arab Emirates (UAE)”. The nominal capacities otherwise applied for the 2018 studies are based on PPA limitations set by the GCCIA that are currently being reviewed by their consultants. No provision is allocated for upgrading the respective 220kV national networks that supply the GCCIA Member Countries. OCTOBER 2021 // 78 Based on an initial desk study (WBG 2019e), and has its own advantages in transmission table 32 presents preliminary estimates of and distribution, as its voltages can be more transmission investment costs for key potential easily stepped up and down. HVAC is the interconnection projects. Following these cost system of choice for all domestic transmission estimations, the 15 selected interconnection and distribution (T&D) networks. On the other reinforcement projects will require investments hand, HVDC should be used for connections of about $1.6 billion and the proposed 10 new via (i) undersea cable > 40km; (ii) asynchronous interconnection projects of almost $5.9 billion. systems (60Hz Vs 50hz) and (iii) long In total, this amounts to $7.5 billion in cross- interconnections > 500km without intermediate border transmission project investments for the substations. HVDC is also used to stabilize region. Comparing the total cost estimates to underlying HVAC systems and has advantages the $35 billion of estimated economic benefits connecting intermittent generation to HVAC of adding these projects to the regional network systems.28 (see table 26), indicates that investing $1 billion to expand regional cross-border trade saves $4.6 billion in system costs. Appendix H details the technical characteristics and estimated project costs (EPC) for the interconnection options listed in table 32. The growing role of high voltage direct current (HVDC) technology in transmission interconnections is an important trend. As the examples above indicate, HVDC is becoming a key element of power system integration in the MENA region (as well as worldwide)—largely due to its lower unit costs for long-distance transmission projects and its ability to tightly control power flows between independent synchronous systems. In addition, alternating current (AC) power grids are standardized for 50 Hz in some countries and 60 Hz in others and it is impossible to interconnect them. An HVDC link makes this possible by converting AC to direct current (DC) and back again either with a converter station or with two converters separated by an HVDC line.27 Moreover, HVDC terminals could act like large batteries capable of mitigating intermittency of wind or solar generating plants. The successful operation of the Saudi GCC Grid in pioneering the use of HVDC in its various forms to integrate 50 Hz and 60 Hz high voltage alternating current (HVAC) power systems is a model for enabling economic trading of generation resources by neighboring countries (WBG 2019e). HVDC and HVAC technologies complement each other quite well for best results in a power system economy. 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World Energy Trilemma Index 2017: Monitoring the Sustainability of National Energy Systems. London: WEC in partnership with Oliver Wyman. OCTOBER 2021 // 82 APPENDIX A. settlement scheme (the GCC unscheduled exchanges are settled in-kind “like for like” but LITERATURE REVIEW the scheduled exchanges are scheduled at the “true” price, before any subsidy). Bottlenecks Electricity trade in the Pan-Arab region has within national networks also present technical been the subject of previous studies. A careful barriers (for example, voltage limits in Jordan review of these studies has helped guide this might hinder trade between Egypt and Syria), report and helped ensure that it provides value as does the limited interconnection capacity, through original insights and is based on the which limits the room for trade after reserving most recent data. This section provides an capacity for emergency support. Finally, there is overview of the previous studies and highlights limited gas trade due to the limited gas pipeline their main contributions. infrastructure and high liquefied natural gas (LNG) prices that favor exports out of the region. Some broad points that the previous studies establish are that: gas trade is more favorable Recommendations that are broadly endorsed for bulk energy trade between countries due to by this body of studies include: (i) developing its low cost and because desalination makes it mechanisms that will make regional more attractive to have power plants close to coordination easier and facilitate information load (WBG 2009); interregional gas trading plans sharing (CESI 2014); (ii) grid code alignment have not moved forward in part because of (WBG 2010); (iii) clear legal frameworks for the perception that they would involve higher transaction settlement; and (iv) establishing degrees of dependency and due to uncertainty a clearing house on a regional level (CESI in gas policies (El-Katiri 2011); and the benefits 2014). Actions that some of the reports cite as of electrical interconnections seem to arise important for establishing a greater degree of because of: (i) differences in load patterns, (ii) coordination in the region include conducting differences in plant efficiencies due to age, a rigorous cost/benefit analysis with detailed (iii) expanding benefits for new capacity due models of transmission and distribution, price to economics of scale/scope, (iv) bypassing reforms, and the examination of alternative implementation obstacles, (v) pooled resources contract options. for electricity generation and reserve provision, The CESI (2014) feasibility study assessing the and (vi) increased capacity for renewables due benefits of electricity trade is the only study to more geographical diversity (CESI 2014; El- that includes most Arab countries (18), provides Katiri 2011; WBG 2009, 2010, 2013). estimates for benefits over the planning period Past reports also identify some of the obstacles 2012–30 (at approximately US$40 billion), and to electricity trade (WBG 2010, 2013; CESI 2014; incorporates natural gas into the operational El-Katiri 2011). Current electricity trade is limited benefits (at approximately 86 percent of total to a small subset of interconnections, with benefits due to increased use of natural gas). Egypt participating in some trade and the Gulf However, the CESI study has some important Cooperation Council (GCC) interconnection limitations. It does not incorporate renewable providing energy support through its profiles at the operational level, it has unscheduled energy exchanges (for a total limited information on reserve sharing and of 922,479 megawatt-hours [MWh] in 2014). deliverability requirements, and it has limited Scaling up the existing trade is hindered by: transmission representation. Furthermore, (i) the absence of an independent body to the recent evolution of fuel prices and cost act as a clearing house for trades; (ii) the use reductions achieved in renewable generation of different grid codes in the region; (iii) the technology further establish the need for different levels of grid reliability; (iv) the limited an updated analysis that more accurately number of players currently participating in reflects the operational benefits of trade bilateral contracts at the national level; (v) a while accounting for the latest technology lack of transparency in the framework for issues improvements and cost figures. such as net transfer capacity; and (vi) the GCC 83 // APPENDIX A. LITERATURE REVIEW APPENDIX B. DETAILED Figure 39. Planned/Under Construction Capacity, by 2030, by Technology and INPUT ASSUMPTIONS Country, in GW FOR THE ELECTRICITY PLANNING MODEL (EPM) This Appendix contains figures and charts that complement the information supplied in Section 6 describing the EPM inputs and assumptions. B.1. INSTALLED CAPACITY AND PLANNED CAPACITY Source: Electricity and Cogeneration Regulatory Authority (http://www. ecra.gov.sa/en-us); Arab Union of Electricity (http://www.auptde.org/ ADDITIONS PublicationsCat.aspx?lang=en&CID=284); Qatar General Electricity & Water Corporation; Bahrain’s Electricity and Water Authority; Oman Electricity Transmission Company; Egyptian Electricity Holding Company 2017; Iraq’s The information in this section was collected Ministry of Energy; Jordan’s National Electric Power Company; Electricity of from publicly available annual electricity reports, Lebanon; and Moroccan Ministry of Energy, Mining, Water and Environment Note: ALG = Algeria; BAH = Bahrain; CC = combined cycle; CSP = communications with the power system offices concentrating solar power; DG = diesel generator; EGY = Egypt; GT = gas turbine; GW = gigawatt; Hydro = hydroelectricity; IRQ = Iraq; JOR = Jordan; of the ministries of energy of some countries and KSA = Saudi Arabia; KUW = Kuwait; LEB = Lebanon; LIB = Libya; MOR = power plants databases such as PLATTS. Morocco; MW = megawatt; OMA = Oman; WBG = West Bank and Gaza; PV = photovoltaic; QAT = Qatar; ST = steam turbine; SUD = Sudan; SYR = Syria; TUN = Tunisia; UAE = United Arab Emirates; YEM = Yemen. Figure 38. Existing Installed Capacity, by 2018, by Technology and Country, in GW B.2. ENERGY DEMAND AND PEAK POWER GROWTH RATES Table 33 shows the energy and peak power demand average annual growth rates by country. The percentages in the table represent the average annual growth for the planning horizon analyzed (2018–35). For example, in the case of Algeria, a 5 percent energy growth refers to the annual increase in demand experienced every year starting Source: PLATTS database; Electricity and Cogeneration Regulatory Authority in 2018 until 2035. The same estimation applies to (http://www.ecra.gov.sa/en-us); Arab Union of Electricity (http://www. the growth rates for the peak demand. The average auptde.org/PublicationsCat.aspx?lang=en&CID=284); Qatar General Electricity & Water Corporation; Bahrain’s Electricity and Water Authority; energy demand growth rate for the region is 5.6 Oman Electricity Transmission Company; Egyptian Electricity Holding percent and the average peak power growth rate Company 2017; Iraq’s Ministry of Energy; Jordan’s National Electric Power Company; Electricity of Lebanon; and Moroccan Ministry of Energy, Mining, is 5.4 percent. The countries experiencing the Water and Environment. highest average growth rate in energy and peak Note: ALG = Algeria; BAH = Bahrain; CC = combined cycle; CSP = concentrating solar power; DG = diesel generator; EGY = Egypt; GT = gas power demand are: Sudan (16.3 percent for energy turbine; GW = gigawatt; Hydro = hydroelectricity; IRQ = Iraq; JOR = Jordan; KSA = Saudi Arabia; KUW = Kuwait; LEB = Lebanon; LIB = Libya; MOR = and 15.9 percent for peak); Egypt (6.9 percent for Morocco; MW = megawatt; OMA = Oman; WBG = West Bank and Gaza; PV energy and 6.7 percent for peak); and Oman (6.6 = photovoltaic; QAT = Qatar; ST = steam turbine; SUD = Sudan; SYR = Syria; TUN = Tunisia; UAE = United Arab Emirates; YEM = Yemen. percent for energy and 6.3 percent for peak). The countries with the lowest average energy and peak demand growth are: Qatar (2.7 percent for energy and peak); Saudi Arabia (3.1 percent for energy and 3 percent for peak); and Lebanon (3.4 percent for energy and 3.3 percent for peak). OCTOBER 2021 // 84 Table 33. Projected Average Annual Growth Rates for Energy and Peak Power Demand Country Peak Demand (%) Energy Demand (%) Algeria 4.7 5.0 Bahrain 3.8 4.3 Egypt 6.7 6.9 Iraq 1.3 4.9 Jordan 5.3 5.5 Kuwait 4.5 5.0 Lebanon 3.3 3.4 Libya 4.2 4.6 Morocco 5.2 5.6 Oman 6.3 6.6 WB&G 5.5 5.9 Qatar 2.7 2.7 Saudi Arabia 3.0 3.1 Sudan 15.9 16.3 Syria 4.8 4.9 Tunisia 5.4 6.0 UAE 7.9 4.6 Yemen 5.9 6.0 Source: Electricity and Cogeneration Regulatory Authority (http://www. ecra.gov.sa/en-us); Arab Union of Electricity (http://www.auptde.org/ PublicationsCat.aspx?lang=en&CID=284); Qatar General Electricity & Water Corporation; Bahrain’s Electricity and Water Authority; Oman Electricity Transmission Company; Egyptian Electricity Holding Company 2017; Iraq’s Ministry of Energy; Jordan’s National Electric Power Company; Electricity of Lebanon; and Moroccan Ministry of Energy, Mining, Water and Environment. Note: UAE = United Arab Emirates; WB&G = West Bank and Gaza. B.3. TYPICAL DEMAND PROFILE Figure 40 illustrates the hourly, seasonal load profile assumptions by country (CESI 2012), in alphabetical order. Figure 40. Hourly, Seasonal Load Profiles, in 2018, by Country 85 // APPENDIX B. DETAILED INPUT ASSUMPTIONS FOR THE ELECTRICITY PLANNING MODEL (EPM) OCTOBER 2021 // 86 B.4. COSTS OF UNSERVED ENERGY AND UNMET RESERVES This study employs two criteria to evaluate the power system reliability, cost of unserved energy and cost of unmet reserve capacity requirement. Cost of unserved energy (USE) is defined as the value (in $ per MWh) placed on a unit of electricity not supplied due to an unplanned interruption. Cost of unmet reserve (USR) is defined as the value placed on the inability of the system to meet operational reserves requirements, in terms of margin reserves (in $ per MW) and spinning reserves (in $ per MWh) which may lead to an unplanned interruption. USE and USR are used to provide an economic value to the cost of electricity interruptions to electricity customers and the economy as a whole. These values are used to inform several investment and refurbishment decisions on the electrical power system, with the aim of optimizing the reliability of the network. The USE is assessed through the value of lost load (VoLL) which is an exogenous assumption that significantly affects the total nonserved energy in the system and the investment decisions of peaking units. There is not a universally acceptable VoLL and different methods have been applied to estimate a reasonable value for the unserved energy. Typical values used in developed economies vary between US$4,000/MWh and US$40,000/MWh while in developing countries between US$1,000/MWh and US$10,000/MWh. Due to the large number of countries included in this study and the diversity of the reliability requirements on each power system, this study assumes a VoLL of US$500/MWh. For USR, the capacity expansion model used in this study, EPM, considers two products that the system operator might require generators to provide during operation: (i) planning reserve margin and (ii) spinning reserves. In the first Source: CESI 2012. product, planning reserve margin (PRM), planners Note: GW = gigawatt; UAE = United Arab Emirates. usually consider an extra capacity requirement (in percentage of projected peak) to account for forecasting error in demand projections. Typical values for the PRM vary between 8–15 percent. EPM considers that interconnections can be accounted for as reserve margin. Note that intermittent units do not contribute toward 87 // APPENDIX B. DETAILED INPUT ASSUMPTIONS FOR THE ELECTRICITY PLANNING MODEL (EPM) meeting the PRM requirements at their full system when it does not meet the spinning capacity but at a fraction specified by the planner, reserve requirements, called value of lost load of typically as their capacity factor during a set of spinning reserve and the value is assumed to be peak hours. EPM applies an economic penalty to US$1,000/MWh. the system when it does not meet the set PRM requirements, called reserve shortfall and the B.5. GENERATION value is assumed to be US$5,000/MW. TECHNOLOGIES CAPITAL The second product, spinning reserves, refers to the unloaded generation that is synchronized COSTS AND FUEL PRICES and ready to serve additional demand. Spinning reserves provide the capability above firm system Figure 42. Regional Prices for Liquid and Solid demand required to provide for regulation, Fuels ($/MMBTU) load-forecasting error, equipment forced and scheduled outages, and local area protection. The amount of spinning reserve required depends on several factors that the planner/ operator considers such as the load level and the associated forecasting error, the forecasting error attached to the renewable generation, and the size of the largest unit committed on the system to be able to accommodate N-1 outages. In EPM spinning reserve can be provided by interconnections additionally to systemwide reserve requirements. Zonal requirements apply Source: World Bank Commodity Market Outlook, October 2016 (Coal and Crude Oil); U.S. Energy Information Administration, spot prices for fuel oil to accommodate for outages on transmission and other products: http://www.eia.gov/dnav/pet/pet_pri_spt_s1_d.htm. Note: HCR = heavy crude oil; LCR = light crude oil; LNG = liquefied natural lines connecting adjacent regions/zones/nodes. gas; MMBTU = million British thermal units; REF = refuse; SLCR = Arabian Also, EPM applies an economic penalty to the super light crude; VR = Vacuum Residual. Figure 41. Technology Capital Cost ($ million/MW) Source: Based on two previous planning studies performed by King Fahad University of Petroleum (KFUPM) in 2011, and the World Bank in 2009; IEA 2014. Note: CSP = concentrating solar power; HCR = heavy crude oil; HFO = heavy fuel oil; IGCC = Integrated Gasification Combined Cycle; LCR = light crude oil; mm = million; MW = megawatt; NG = natural gas; PV = photovoltaic. OCTOBER 2021 // 88 Figure 43. Current Natural Gas Price Projections, in $/MMBTU, by Country Source: World Bank staff based on World Bank and Ramboll (2017b). Note: MMBTU = million British thermal units. Figure 44. International Natural Gas Price Assumptions, Based on EU Hub Prices, in $/MMBTU, by Country Source: World Bank staff based on World Bank and Ramboll (2017b). Note: UAE = United Arab Emirates; MMBTU = million British thermal units. 89 // APPENDIX B. DETAILED INPUT ASSUMPTIONS FOR THE ELECTRICITY PLANNING MODEL (EPM) Table 34. Natural Gas Consumption Limit per Year, in Billion Cubic Meters (bcm) Country 2020 2025 2030 2035 Algeria 100.0 104.0 94.0 94.0 Bahrain 27.0 25.0 24.0 24.0 Egypt 75.0 76.0 70.0 70.0 Iraq 45.0 55.0 58.0 58.0 Jordan 8.0 8.0 8.0 8.0 Kuwait 10.6 18.8 22.2 22.2 Lebanon 2.0 2.0 2.0 2.0 Libya 17.0 20.0 25.0 25.0 Morocco 1.0 5.0 5.0 5.0 Oman 38.0 38.0 34.0 34.0 WB&G 0.4 0.8 1.0 1.0 Qatar 209.0 259.0 259.0 259.0 Saudi Arabia 132.0 132.0 132.0 132.0 Sudan 0.1 0.1 0.1 0.1 Syria 3.0 11.0 11.0 11.0 Tunisia 6.0 6.0 6.0 5.0 UAE 90.0 76.0 76.0 64.0 Yemen29 0.4 2.9 2.9 6.3 Source: World Bank and Ramboll 2017a; CIA: https://www.cia.gov/library/ publications/the-world-factbook/geos/jo.html. Note: UAE = United Arab Emirates; WB&G = West Bank and Gaza. 29 Due to the ongoing conflict in Yemen, the natural gas and oil production have decreased dramatically and its LNG facility (production to export to Asian countries) has been put in stand by since. These values for gas limits are an estimation based on current gas production and construction and the outlook for the end of the conflict and the recovery process (CIA Factbook: https://www. cia.gov/library/publications/the-world-factbook/geos/ ym.html; World Energy Council: https://www.worldenergy. org/data/resources/country/yemen/gas/; gas production chart: https://ycharts.com/indicators/yemen_natural_gas_ production). OCTOBER 2021 // 90 APPENDIX C. COUNTRY- Our understanding: The second issue relates to the details of the International Gas Price scenario SPECIFIC APPROACH which at present relies on the World Bank gas commodity price forecast reflective of a median TO ESTIMATE CURRENT gas price synonymous to the European gas prices. The debate in the consultations seem to AND INTERNATIONAL suggest using U.S. gas price benchmark (which is significantly lower than what we are using GAS PRICES at present) or Asian liquefied natural gas (LNG) prices (which may be substantially higher than our Communication Title: Gas price assumptions in current set of assumptions). The second question Pan-Arab regional energy trade and investments therefore is: plan modeling Author: PAEM Modeling Team, World Bank 2. Which regional gas/LNG price should be tied Date: October 25, 2018 to the International Gas Price scenario? There was no clear closure on either of these two CONTEXT issues in the consultations. As the Bank team The PAEM consultations in Morocco (on noted during the discussion, there is no objection September 2018) reopened the discussion on to the fundamental idea of using a cost-based gas price assumptions for both the “Local Pricing” estimate of gas. In fact, the Local Pricing scenario and “International Gas Price” scenarios. This note is premised precisely on that idea but getting an summarizes: (i) two key questions that are yet to estimate of gas prices that requires for all gas fields be answered; (ii) current gas price assumptions in all relevant countries is a significant task. We in the model; and (iii) seeks suggestions from the had agreed to go back and take a closer look at PAEM study team leader to close the current data our assumption that are based on the World Bank gap so that the modeling task can move forward Gas Trade report (World Bank and Ramboll 2017b). with a view to finalizing the results around As we have summarized in the next section, the January 2019. We would like to note that there report—which is by far the most recent authentic are other inputs that are being sought from the estimate of gas prices that we could find in the participating member countries that is already literature—indeed tries to estimate the marginal happening and is expected to be completed cost of gas. Second, we also expressed the opinion by mid-October. As such it would be greatly that a reliance on a U.S.-centric gas price is not appreciated if revisions to gas prices could be advisable given it is a gas producing/export region finalized in October too. that is not a good representative “opportunity cost” for the Middle East and North Africa (MENA) C.1. KEY QUESTIONS region. The Asian LNG price is indeed an option but may be on the high side for at least a good share of Our understanding: The principal concern leveled the gas. at the current gas price assumptions is that they are not reflective of true cost of production (as C.2. SUMMARY OF PAEM in the Local Pricing scenario), nor reflective of a sustainable energy future for the region because MODEL GAS PRICE of their reliance on highly volatile international ASSUMPTIONS gas prices (as in the second scenario). The question therefore arises as to: 1. The natural gas prices presented in table 35 were used as gas price assumptions 1. Is there a way to include a new scenario for the World Bank’s Electricity Planning better reflective of marginal cost of Model. These prices were extracted from the production in gas producing countries above-mentioned report, in which they are and apply a suitable approach for described as economic gas prices that result projecting it forward that is realistic and from doing country-specific assumptions for sustainable? gas prices under existing infrastructure. 91 // APPENDIX C. COUNTRY-SPECIFIC APPROACH TO ESTIMATE CURRENT AND INTERNATIONAL GAS PRICES 2. The country-specific assumptions derived Table 35. Economic Natural Gas Prices in the from a combination of using the marginal Arab Region, in $/MMBTU cost of production, as the economic price, Country 2018 2020 2025 2030 for those countries that have existing Algeria 4.5 4.5 5.5 6.5 infrastructure (that is, existing gas fields) Bahrain 5.0 5.0 6.0 7.0 and international gas price (from the EU Egypt 5.0 5.0 6.0 7.0 Iraq 4.0 4.0 4.5 5.0 Hub) +/- transportation costs (US$0.5/ Jordan 5.0 5.0 6 7.0 million British thermal units [MMBTU]) for Kuwait 5.0 5.0 6.0 7.0 the other countries. Table 36 details the Lebanon 5.5 5.5 6.5 7.5 assumptions of this approach. Libya 4.3 4.5 5.5 6.5 Morocco 5.0 5.0 6.0 7.0 In the Gas Trade report there is a section Oman 3.5 3.5 4.5 5.0 WB&G 5.5 5.5 6.5 7.5 (section 10, page 104) attempting to detail the Qatar 2.5 2.5 2.5 2.5 valuation of gas and gas supply approach by Saudi Arabia 3.0 3.0 3.0 3.0 country. As an example, figure 45 illustrates the Sudan 5.5 5.5 6.5 7.5 Syria 5.5 5.5 6.5 7.5 estimated long-run marginal costs (LRMCs) of Tunisia 5.0 5.0 6.0 7.0 incremental production in Algeria and in Egypt, UAE 5.0 5.0 5.0 5.0 which indicates that economic gas prices rely on Yemen 5.0 5.0 6.0 7.0 marginal cost estimates. Source: World Bank and Ramboll 2017a: section 4, page 38, table 10. Note: UAE = United Arab Emirates; MMBTU = million British thermal units; The methodology for assessing future marginal WB&G = West Bank and Gaza. costs (to calculate the LRMC30) of domestic gas Table 36. Country-specific Assumptions for Natural Gas Pricing without New Infrastructure Country Applied Pricing Assumption Comment Algeria EU price minus transportation cost to the EU Reference price in Algeria determined by pipeline and LNG connections to the EU prices. Bahrain Qatar + transport Assuming connection to Qatar—close to the cost of developing the ultra-deep elds o shore. Egypt EU price Egypt prices are the highest in the region. The EU price is chosen as a proxy. Iraq Marginal production costs Not connected to the world market and has large reserves. Marginal cost of production drives the cost of gas to the power sector. Jordan Egypt + transportation Assuming that the Arab Gas Pipeline is operational, the prices should be connected to Egypt. Kuwait Qatar + transport Price in Qatar + cost of importing via LNG. Libya EU price minus transportation cost to the EU EU price minus transportation cost to the EU Reference price in Libya determined by the pipeline and connection to the EU prices. Morocco Algeria + transportation This price should not deviate too much from the Algerian prices. Thus, this will be driven by the European price. Oman Qatar + transport Connected to Qatar via the Dolphin Pipeline. WB&G Egypt + transportation Assuming that the Arab Gas Pipeline is operational, the prices should be connected to Egypt. Qatar Marginal production costs Connected to the world market but no possibilities for additional LNG export. The North Field determining the marginal cost. Saudi Arabia Marginal production costs Not connected to the world market and has large reserves. Marginal cost of production drives the cost of gas to the power sector. Syria Egypt + transportation Assuming that the Arab Gas Pipeline is operational, the prices should be connected to Egypt. Tunisia Algeria + transportation This price should not deviate too much from the Algerian prices. Thus, this will be driven by the European price. UAE Qatar + transport Connected to Qatar via the Dolphin Pipeline. Yemen Export price Japan—shipping Minor domestic market—most gas for export. Thus, the price must be LNG price in Japan minus the shipping and transportation costs. Source: World Bank 2016: 8. Note: EU = European Union; LNG = liquefied natural gas; UAE = United Arab Emirates. 30 The breakeven price of gas field production (estimated using production level, reserves, CAPEX, and OPEX for each field) is used as reference for the LRMC, which is defined as the average change in projected operating and capital expenditure attributed to future increases in gas production levels. OCTOBER 2021 // 92 supply examined, if possible, the development gas, and provide marginal cost curves for costs in terms of capital expenditure (CAPEX) specific countries, some data challenges and operating expenditure (OPEX) of the four to with these detailed cost curves (figure five largest new gas fields for each country. Data 45, top) were found which prevented a assumptions were retrieved from companies direct match with the point estimates involved in the development of the fields, that appear in the economic gas prices industry, and governments sources (reports, provided in table 35. After detailed publications, interviews). When data were not verification of the cost curves provided available, estimations were based on previously in the report in chapter 10, it is observed sanctioned major gas and petroleum projects in that inconsistencies with the data led to MENA. A weighted average capital cost (WACC) of the final gas price estimates presented 10 percent was used. (For further details on each in the report.32 Specifically, in figure 45, country see section 8, pages 77–86, of the report.) the cost curve for Algeria (up) gives gas prices between US$2.8–7.5/MMBTU to production values ranging 0–19 Figure 45. LRMC Incremental Production for billion cubic meters per year (bcm/y). Gas Fields in Algeria (up) and Egypt (down), Additionally, the report documents that, in $/MMBTU currently, the gas production of Algeria is approximately 88 bcm/y,33 which is outside of the range of the cost curve, implying a very high gas price, thus, explaining the assumption made for Algeria in table 36 (to use pipeline and LNG connections to the EU prices to determine the price for Algeria). In the case of Egypt, with an estimated gas production of 44 bcm/y, using the cost curve presented in figure 45 leads to a very high price of gas for Egypt (about US$6/MMBTU), resulting in the assumption stated in table 36 for Egypt’s gas prices (Egypt prices are the highest in the region. The EU price is chosen as a proxy). 2. However, we are not aware of any Source: World Bank and Ramboll 2017b—Algeria: section 10, page 123, better estimates being available having figure 59; Egypt: section 10, page 164, figure 93. Note: bcmpa = billion cubic meters per annum; LRMC = long-run marginal consulted internally and with our external cost; MMBTU = million British thermal units. gas pricing advisers. 1. Although sections 8 and 10 of the World Bank and Ramboll (2017b) report offer details on gas valuation for each country, indicate a price range31 for the value of 31 The lower bound of this range results from netback prices for the major current or future exporting countries, that is, the minimum price producers would be willing to sell gas. The upper bound is a product of how much a power producer would be willing to pay for gas if the alternative was heavy fuel oil (HFO) or coal (considering both new power 32 World Bank and Ramboll 2017b: section 4, page 38, table 10. plants and conversion of existing HFO to gas). 33 World Bank and Ramboll 2017b: section 4, page 46, table 11. 93 // APPENDIX C. COUNTRY-SPECIFIC APPROACH TO ESTIMATE CURRENT AND INTERNATIONAL GAS PRICES APPENDIX D. INTENDED NATIONALLY DETERMINED CONTRIBUTIONS (INDC) SUBMITTED BY SELECTED ARAB COUNTRIES Country Date Summary INDC Share of global GHG in 2012 (%) Algeria 4/9/2015 4/9/2015 A 7–22% reduction in GHG emissions by 2030, compared to business-as-usual. The 0.34 lower end is unconditional whereas the top end of ambition is dependent on provision of climate nance and access to technology. Bahrain 24/11/2015 Sets out a number of policies and actions that will contribute to “low greenhouse gas emission 0.06 development.” It highlights its Economic Vision 2030, which seeks to diversify the country’s economy and reduce its dependence on oil and gas. Egypt 11/11/2015 To achieve “high CO2 mitigation levels” through measures including phasing out energy 0.56 subsidies within 3–5 years and, potentially, a national carbon market. Also aims to use renewable and nuclear power sources. Requires international support of US$73 billion. Includes section on adaptation. Iraq 12/11/2015 [INDC only available in Arabic] 0.30 Jordan 10/9/2015 A 14% reduction in emissions compared to business-as-usual levels by 2030, 1.5% of which is 0.05 unconditional and 12.5% is conditional upon international support. The country will need around US$5 billion to ful ll the conditional side of its pledge. Lists speci c projects that will be implemented to hit the target. Includes adaptation actions. Kuwait 24/11/2015 To “move to a low carbon equivalent economy” and avoid an increase in emissions above 0.19 business-as-usual projections, conditional on international support. Lebanon 30/09/2015 An unconditional 15% emissions cut in 2030, compared to business-as-usual, or a 0.04 conditional 30% reduction. Aims for 15% of power and heat energy to be renewable in 2030, or 20% with international support. Includes section on adaptation. Libya INDC not yet submitted 0.16 Morocco 5/6/2015 An unconditional 13% reduction on business-as-usual emissions by 2030, with a conditional 0.15 32% reduction if Morocco receives new sources of nance and enhanced support. Oman 19/10/2015 An unconditional 2% emissions cut in 2030, relative to business-as-usual levels. This will be 0.12 achieved through an unquanti ed “increase” in renewables and “reduction” in gas aring. Will develop climate legislation. Includes short section on adaptation. Additional e orts would require international support. Qatar 20/11/2015 Focuses on actions that will bring about economic diversi cation that will also bring down 0.20 emissions, but does not set a reduction target. Saudi 10/11/2015 An “ambitious” program of renewable energy investment and “economic diversi cation,” along 1.05 Arabia with energy e ciency and carbon capture and storage. Expects emissions savings of up to 130 million tons of CO2 equivalent in 2030, relative to business-as-usual. Includes section on adaptation. Sudan 10/11/2015 To reach 20% renewable share in the power mix by 2030. Includes detailed per-technology aims 0.94 and targets for energy e ciency. Aims to raise forest area to 25% of Sudan by 2030. Includes section on adaptation. Pledge conditional on international support. Syria INDC not yet submitted 0.15 Tunisia 16/09/2015 A 41% reduction in carbon intensity by 2030, compared to 2010 levels. Speci cally, in the energy 0.08 sector, Tunisia will reduce carbon intensity by 46%. The rst 13% of its target is unconditional; the remainder depends on international support. Together, the country’s plans for mitigation and adaptation will cost US$20 billion. UAE 22/10/2015 To “limit” emissions and increase the share of “clean energy” in the energy mix to 24% by 2021, 0.39 up from 0.2% in 2014. Includes section on adaptation actions with mitigation co-bene ts. Yemen 23/11/2015 A 1% emissions cut by 2030 compared to business-as-usual projections, or a 14% cut conditional on 0.08 international support. Conditional pledge would include 15% of power coming from renewables by 2025. Includes section on adaptation. Source: UNFCCC synthesis report 2015, https://www4.unfccc.int/sites/submissions/indc/Submission%20Pages/submissions.aspx Note: CO2 = carbon dioxide; GHG = greenhouse gas; INDC = Intended Nationally Determined Contribution; UAE = United Arab Emirates. OCTOBER 2021 // 94 APPENDIX E. SHARED ECONOMIC BENEFITS AND VALUE OF COMMERCIAL TRADE IN ELECTRICITY IN US DOLLARS PER YEAR34 Table 37. Economic Benefit of Trade by Country (USD), Case 1: Current Gas Prices Country 2020 2025 2030 2035 Algeria 81,123,285 60,746,199 95,074,072 184,227,830 Bahrain 39,962,613 92,503,816 134,957,159 151,746,614 Egypt 140,119,195 676,203,387 798,741,103 2,414,275,560 Iraq 91,831,806 57,696,977 194,315,781 197,118,420 Jordan 245,555,365 78,237,407 203,061,523 256,508,633 Kuwait 30,623,722 241,215,979 449,589,832 449,973,501 Lebanon 83,972,497 172,890,692 68,304,239 89,201,115 Libya 3,242,524 31,618,380 401,636,180 527,317,413 Morocco 70,620,358 55,219,219 32,297,394 46,494,635 Oman 38,016,799 18,919,008 97,304,485 123,016,362 WB&G 130,486,420 4,425,108 1,205,838 7,800,796 Qatar 121,738,397 269,662,876 276,141,804 275,971,673 Saudi Arabia 118,901,376 517,701,622 955,106,484 1,186,520,684 Sudan 81,527,373 446,108,715 459,172,223 1,881,493,569 Syria 332,280,214 191,773,427 98,810,220 154,944,200 Tunisia 13,414,084 30,457,058 449,591,135 610,630,304 UAE 100,825,563 144,697,797 159,901,363 167,076,320 Yemen - 108,773,148 119,287,891 213,187,089 Total $1,724,241,590 $3,198,850,816 $4,994,498,728 $8,937,504,720 $72,809,529,346 Discounted, i=6% $1,534,568,877 $2,127,418,490 $2,482,112,854 $3,319,071,244 $40,282,354,841 Source: World Bank staff based on EPM output. Note: UAE = United Arab Emirates; WB&G = West Bank and Gaza. Table 38. Economic Benefit of Trade by Country, Case 3: International Gas Prices Country 2020 2025 2030 2035 Algeria 81,071,582 41,117,870 9,485,518 155,564,532 Bahrain 26,629,265 61,826,812 29,718,355 35,818,696 Egypt 132,859,184 637,856,144 601,620,338 2,161,013,848 Iraq 82,300,113 46,410,524 116,762,630 125,372,460 Jordan 231,016,391 73,924,596 139,108,996 171,788,594 Kuwait 15,870,089 68,112,099 159,427,011 150,509,832 Lebanon 83,455,060 171,606,048 66,356,016 82,983,764 Libya 2,991,882 33,228,893 467,413,270 506,186,444 Morocco 68,409,090 35,575,810 23,245,778 32,586,897 Oman 26,408,867 17,940,510 57,396,982 79,439,933 WB&G 129,817,769 3,894,152 1,504,615 7,715,458 Qatar 83,979,467 85,366,777 53,611,116 44,040,900 Saudi Arabia 126,911,614 331,977,325 345,332,115 596,603,683 Sudan 81,527,373 447,242,437 459,108,694 1,882,322,041 Syria 316,380,387 178,933,156 108,301,660 150,313,459 Tunisia 14,563,392 33,332,373 434,593,378 588,507,710 UAE 108,525,447 125,662,063 112,671,022 117,570,592 Yemen - 67,049,499 75,796,890 164,340,746 Total $1,612,716,972 $2,461,057,088 $3,261,454,386 $7,052,679,587 $56,557,469,708 Discounted, i=6% $1,435,312,364 $1,636,743,524 $1,620,842,911 $2,619,114,254 $32,157,666,104 Source: World Bank staff based on EPM output. Note: UAE = United Arab Emirates; WB&G = West Bank and Gaza. 34 Total and Discounted Total values are calculated over the 2018 – 2035 period. 95 // APPENDIX E. SHARED ECONOMIC BENEFITS AND VALUE OF COMMERCIAL TRADE IN ELECTRICITY IN US DOLLARS PER YEAR Table 39. Economic Benefit of Trade by Country, Case 5: International Gas Prices, Carbon Caps Country 2020 2025 2030 2035 Algeria 62,934,782 62,244,435 758,750,595 467,484,082 Bahrain 160,202,534 378,557,889 910,255,766 1,238,924,771 Egypt 366,785,514 630,041,975 6,829,349,656 5,031,126,784 Iraq 161,113,550 2,141,156,596 3,651,404,953 3,541,928,282 Jordan 570,885,550 1,531,662,104 3,838,331,061 3,262,880,341 Kuwait 304,104,134 636,160,602 3,488,754,065 4,214,071,137 Lebanon 25,440,601 218,931,485 (22,553,993) (34,550,148) Libya 58,019,482 25,668,299 (221,443,621) 279,465,444 Morocco 63,976,033 62,971,320 776,293,237 304,167,997 Oman 83,054,216 18,400,778 704,608,849 1,600,555,457 WB&G 88,023,981 17,228,397 74,629,301 185,495,565 Qatar 501,685,594 195,375,633 875,619,506 1,177,333,312 Saudi Arabia 326,771,179 1,955,565,795 10,322,107,813 10,218,001,307 Sudan (40,883,667) 309,957,753 (267,175,637) 1,207,123,652 Syria 417,366,283 930,736,121 1,097,055,210 1,277,317,936 Tunisia 22,013,143 (31,788,829) (189,314,652) 227,479,275 UAE 576,028,604 227,125,393 2,243,216,817 2,840,455,424 Yemen - 105,089,327 87,785,723 777,053,292 Total $3,847,521,511 $9,415,085,071 $34,957,674,647 $37,816,313,911 $301,121,356,982 Discounted, i=6% $3,424,280,448 $6,261,569,302 $17,372,893,322 $14,043,633,429 $150,073,341,233 Source: World Bank staff based on EPM output. Note: UAE = United Arab Emirates; WB&G = West Bank and Gaza. Table 40. Commercial Value of Export Trade by Country, Case 1: Current Gas Prices Country 2020 2025 2030 2035 Algeria 222,768,531 380,219,029 459,952,031 581,141,811 Bahrain - 43,801,205 26,955,926 16,638,696 Egypt 189,983,468 1,053,438,943 1,173,153,898 2,664,529,791 Iraq 189,991,552 196,120,062 710,020,014 739,815,621 Jordan 496,955,756 395,883,339 481,592,007 583,296,492 Kuwait 7,812,451 - 74,761,806 104,568,460 Lebanon - 13,750,330 22,405,107 30,731,162 Libya 24,021,059 434,235,454 962,316,367 1,425,195,513 Morocco 10,597,911 13,143,724 33,140,105 45,571,265 Oman 136,349,340 135,737,221 135,468,382 128,501,402 WB&G - - - - Qatar 279,181,716 580,305,272 644,736,936 661,861,219 Saudi Arabia 41,256,109 1,772,276,724 3,037,285,313 3,131,273,885 Sudan - 260,992 4,869,714 2,112,418 Syria 332,286,308 592,609,445 573,012,571 740,047,965 Tunisia 7,498,138 3,950,226 20,381,108 - UAE 307,913,045 244,901,740 351,397,850 347,687,798 Yemen - - - 292,535 Total $2,246,615,383 $5,860,633,707 $8,711,449,135 $11,203,266,034 $109,217,217,023 Discounted, i=6% $1,999,479,693 $3,897,656,137 $4,329,323,333 $4,160,494,377 $59,471,721,243 Source: World Bank staff based on EPM output. Note: UAE = United Arab Emirates; WB&G = West Bank and Gaza. 34 Total and Discounted Total values are calculated over the 2018 – 2035 period. OCTOBER 2021 // 96 Table 41. Commercial Value of Export Trade by Country, Case 3: International Gas Prices Country 2020 2025 2030 2035 Algeria 242,783,016 283,062,415 273,616,723 473,689,918 Bahrain - 300,726,716 79,664,245 49,600,474 Egypt 233,739,006 2,256,786,054 2,211,598,535 2,849,818,908 Iraq 199,523,245 190,950,157 546,623,595 596,183,690 Jordan 386,336,263 578,868,122 654,350,434 631,851,541 Kuwait 53,130,327 607,466 144,928,883 149,963,156 Lebanon - 13,274,056 21,536,037 23,804,717 Libya 16,806,958 389,561,909 1,084,908,659 1,465,053,414 Morocco 11,127,281 40,984,395 146,714,153 116,572,392 Oman 161,621,447 172,164,812 266,654,778 280,965,115 WB&G - - - - Qatar 340,290,357 527,695,530 432,085,995 223,126,113 Saudi Arabia - 587,604,821 2,461,095,463 3,625,041,427 Sudan - - 2,992,720 2,192,210 Syria 331,789,091 644,736,246 748,631,863 862,752,259 Tunisia 7,963,310 7,347,836 100,215,380 - UAE 403,912,733 284,314,879 354,982,566 396,619,775 Yemen - - 805,928 2,060,415 Total $2,389,023,035 $6,278,685,414 $9,531,405,956 $11,749,295,524 $115,800,394,282 Discounted, i=6% $2,126,221,996 $4,175,684,398 $4,736,816,752 $4,363,270,301 $62,895,476,371 Source: World Bank staff based on EPM output. Note: UAE = United Arab Emirates; WB&G = West Bank and Gaza. Table 42. Commercial Value of Export Trade by Country, Case 5: International Gas Prices, Carbon Caps Country 2020 2025 2030 2035 Algeria 191,472,058 295,934,872 287,832,237 1,039,628,549 Bahrain 179,873,506 851,203,261 281,166,821 2,326,739 Egypt 428,362,856 2,221,443,770 6,574,733,042 6,389,782,642 Iraq 4,743,367 6,401,350 - - Jordan 886,317,131 2,275,130,596 5,285,463,448 4,757,711,483 Kuwait 445,973,338 406,313,397 3,517,992,441 3,699,949,041 Lebanon - 86,854,012 90,913,679 88,572,936 Libya 114,356,276 184,627,070 649,692,372 465,151,047 Morocco 13,355,054 79,490,257 1,450,428,378 710,267,330 Oman 78,924,290 90,623,396 284,748,761 18,352,804 WB&G - - - - Qatar 840,205,400 389,001,039 292,096,623 4,869,345 Saudi Arabia 213,464,388 3,394,780,614 14,612,097,257 14,751,616,022 Sudan - 2,529,597 107,061,146 - Syria 569,542,693 1,443,638,088 1,538,366,951 1,245,937,527 Tunisia 45,502,351 122,999,084 136,977,031 410,347,671 UAE 793,570,458 702,588,874 3,194,967,396 3,854,645,202 Yemen - - 1,305,377 18,412,468 Total $4,805,663,167 $12,553,559,277 $38,305,842,961 $37,457,570,805 $330,562,594,952 Discounted, i=6% $4,277,023,111 $8,348,833,898 $19,036,830,398 $13,910,409,004 $166,557,220,362 Source: World Bank staff based on EPM output. Note: UAE = United Arab Emirates; WB&G = West Bank and Gaza. 34 Total and Discounted Total values are calculated over the 2018 – 2035 period. 97 // APPENDIX E. SHARED ECONOMIC BENEFITS AND VALUE OF COMMERCIAL TRADE IN ELECTRICITY IN US DOLLARS PER YEAR APPENDIX F. INPUTS AND OUTPUTS OF ELECTRICITY PLANNING THE MODEL EPM requires a set of detailed input parameters MODEL (EPM) that characterizes the power system of each METHODOLOGY of the countries analyzed in this study. These inputs are used to determine specific outputs that later are processed to assess the potential The World Bank’s Electricity Planning Model benefits of engaging in regional electricity (EPM) is a long-term, multiyear, multizone trade. Table 43 summarizes the main inputs and capacity expansion model with economic outputs of the model. On the inputs side, hourly dispatch. The objective of the model is to electric demand and renewable resources minimize at once the sum of fixed and variable profiles are key to capture the seasonal generation costs (discounted for time) for all variations that impact the performance of the zones and all years considered, subject to the power system. Also, generation technologies following properties and constraints: costs coupled with fuel prices and the amount • Demand equals the sum of generation of fuel available for generation would help and nonserved energy, determine the type of capacity additions. On the outputs side, changes in wholesale • Available capacity is existing capacity plus electricity costs, fuel consumption, and total new capacity minus retired capacity, CO2 emissions, together with the volume of • Generation does not exceed the max and electricity traded, will be relevant to assess the min output limits of the units, potential gains from trade. • Generation is constrained by ramping limits, • Reserves are committed every hour to Table 43. EPM Main Inputs and Outputs compensate forecasting errors, Inputs Outputs Wind resource historical hourly Optimal generation • Renewable generation is constrained by availability investments wind and solar hourly availability, Solar resource historical hourly Capacity utilization factor of availability individual technologies • Excess energy can be stored in storage Demand historical hourly data Energy contribution of units to be released later or traded and growth expectation individual technologies between the other zones, and Fuel prices and fuel Fuel consumption consumption limits • Transmission network topology and Topology and thermal limits of Carbon dioxide emissions transmission line thermal limits. the transmission lines from the power sector Fixed and variable cost of Wholesale electricity prices The model is an abstract representation of the generating technologies real power systems with certain limitations Flexibility options available Volume and value of (hydro, storage, demand-side electricity traded among described in more detail in section F.3. management, etc.) zones/jurisdiction Source: World Bank staff. Note: EPM = Electricity Planning Model. Figure 46. Structure of the World Bank Electricity Planning Model Long-Term Short-Term MODELING ASSUMPTIONS Planning/Investment Operation Capacity expansion Economic dispatch The model is derived based on the following assumptions: Multi-year multi-zone capacity expansion with economic dispatch Source: World Bank staff. 1. The market participants are not strategic, and they behave in a perfectly competitive manner, that is, the power plant owners submit their true costs as bids. OCTOBER 2021 // 98 2. The projected demand is considered perfectly inelastic, which implies that the F.1. NOTATION maximization of the social welfare can be replaced by minimization of the system cost. INDICES AND SETS 3. The trade among regions is economically efficient (optimal), which translates to a single objective of minimization of cost for all regions. Please note that in practice, achievement of the economically optimal outcome will probably require the establishment of an independent system operator for the whole region. 4. The pricing is efficient and does not provide incentives to market participants to deviate from the optimal behavior. WHAT CAN THE MODEL DO? • Determine hourly cost of electricity with trade for different countries and zones, which is essential to value the energy traded. • Determine the cost to the consumer. • Determine where and by how much renewable resources should be deployed to maximize their value to the system— critical issue in current planning efforts. • Determine the optimal capacity additions over time to complement renewable generation accounting for existing generating units, energy storage, demand- side response, and/or a carbon constraint. • Determine the optimal retirement schedule of the existing units over time. • Assess the utilization of the transmission lines (important to design trade contracts). • Determine the impact of different market conditions (for example, fuel prices, fuel subsidies, carbon limits, etc.) and technology cost assumptions on the optimal capacity expansion plan and the optimal energy mix. 35 The generators already planned are included in any of • Determine the cost of implementing the two sets depending on criteria such as their capacity, specific environmental policies: renewable status of their construction process, etc. portfolio standards, cap on carbon 36 Type of resources considered as renewables might be emissions, tax on carbon emissions, and different from country to country or state to state. For example, some states do not include hydropower towards carbon emissions rate. their renewable targets (for example, California does not The power system planning model is described in count large hydropower toward the renewable portfolio standards) while others such as Oregon do (DSIRE n.d.). detail in sections F.2–F.5. 99 // APPENDIX F. ELECTRICITY PLANNING MODEL (EPM) METHODOLOGY VARIABLES PARAMETERS 38 Note that ramping capabilities of generator are usually expressed in MW/min and then based on the minutes the operating reserve requirement is defined, we can estimate the capability in MW and subsequently express it in percentage of installed capacity. In the United States, 10 minutes is typical time for operating reserves and 5 minutes for regulation reserves. OCTOBER 2021 // 100 101 // APPENDIX F. ELECTRICITY PLANNING MODEL (EPM) METHODOLOGY F.2. MODEL FORMULATION OCTOBER 2021 // 102 103 // APPENDIX F. ELECTRICITY PLANNING MODEL (EPM) METHODOLOGY F.3. DESCRIPTION OF containing as many hours as the set D × Q × T × Y. It is convenient though to keep all the four sets THE MODEL since they reveal some fundamental assumptions of the model: (i) days are used to reflect the chronological sequence of the time slices used INDICES AND SETS for ramping and storage constraints as we will All sets used in the formulation can be classified further explain in the constraints section; (ii) in two major categories: time and power system quarters are used to reflect seasonality in the related. Four sets belong to the first category: load patterns, the availability of thermal power D, Q, T, Y which represent different time scales units, and the thermal limits of transmission lines; considered in the model: days, quarters, hours, (iii) years are used to represent annual trends on and years. Hour is the smallest unit of time demand growth and keep track of the lifetime of used in this formulation and we could use the units; and finally (iv) hours are commonly used as same formulation using just one set for time the smallest time unit in long-term models since OCTOBER 2021 // 104 the day-ahead scheduling models schedule met. All generation costs of the system are generation units on an hourly basis. considered: (i) fixed costs including annualized capital cost payments for new generators39 Three sets are power system related. Set G and fixed operation and maintenance costs, (ii) includes all generating units. Depending on variable costs including the fuel costs and any the size of the system, we might decide to use variable operation and maintenance costs, (iii) set g to model individual units of the power cost to procure spinning reserves, (iv) carbon tax system for a small system or aggregated units payments, and (v) penalties for unmet demand that represent multiple units of the same and unmet reserve requirements at the system or technology for a large system. We use the term the zonal level. technology to refer to different technologies or different fuels used: for example, coal steam turbines, natural gas combined cycle, LOAD APPROXIMATION natural gas combustion turbines, wind The model is usually employed to decide or farms, solar photovoltaic panels, geothermal, explore optimal generation investment plans hydropower, and diesel generators. Depending at the country or multi-country level. Thus, on the resources available in a country, some modeling all the 8,760 hours of a year does not technologies might not be present. As the seem a practical option. Moreover, the reader model stands now, elements of set G are should bear in mind that we model future years mapped to sets F and Z, which stand for fuel and for which we have forecasts on specific values for zones, respectively. Set Z is one of the major sets the power system such as energy consumption used in power systems since the power system and highest amount of power demanded during is a network and physical laws (widely known as the year (also known as peak power). Kirchhoff’s laws) govern the flow of power over We use the forecasts provided along with historical the transmission lines. Given that, a set such as detailed data on the chronological profiles of set Z which captures the spatial dimension of demand to generate future load time series. More the system is necessary. At the finest granularity, details on the procedure followed to generate set Z might contain buses of the power system the projected load time series are provided in but in case we model larger systems, set Z the section F.5. From the resulting load time might contain zones of a power system or even series, a limited number of days, per quarter in countries. Note that the modeler usually decides the year, are selected to represent the hourly on the spatial granularity based on the presence demand profile of a specific year. In the most of common regulatory rules or pricing schemes recent iteration of the model we select three days in a zone or/and based on the congestion per quarter in a year. The first day is the one (24 observed on transmission lines connecting hours) that contains the maximum peak in the adjacent regions. Finally, set F includes the quarter. The second is the day that contains the different fuels used and we model it to keep minimum peak in the quarter. The third is the 24- track of the consumption of different fuels hour day that contains the average per hour in since for certain fuels domestic upper bounds the quarter. In total the load demand in a year is on consumption might apply or/and issues of represented by 12 days (3 days x 4 quarters). energy security might be involved in case of imported fuels. In addition, different types of fuels have different carbon content and lead to different emissions of carbon dioxide, which VALUE OF LOST LOAD are important to track in case environmental The Value of Lost Load (VoLL) is an exogenous policies exist. assumption that significantly affects the total nonserved energy in the system and the OBJECTIVE FUNCTION investment decisions of peaking units. There is no universally acceptable VoLL and different The objective function in this model minimizes the total system cost including violation/ penalty terms for constraints that are not 39 Capital costs of existing generators are considered sunk costs and are not included in the objective function. 105 // APPENDIX F. ELECTRICITY PLANNING MODEL (EPM) METHODOLOGY methods have been applied to estimate a TRANSMISSION NETWORK reasonable value for the unserved energy. Typical values used in developed economies CONSTRAINTS vary between US$4,000/MWh and US$40,000/ Kirchhoff’s laws are physical laws governing MWh while in developing countries between the flows over transmission lines in a network. US$1,000/MWh and US$10,000/MWh (Van Der According to the first Kirchhoff law, also known as Welle and Van Der Zwaan 2007). In addition, KCL (Kirchhoff’s Current Law), the sum of injections studies indicate that factors such as the timing in a node should equal zero. In our formulation, of the interruption or the duration of a blackout KCL corresponds to equation (9). There, we can see might affect the VoLL (Van Der Welle and Van that the power provided by generators and storage Der Zwaan 2007). “The intersection between the should be equal to demand (minus the unmet cost function of non-served energy and the cost demand) plus/min outflows/inflows from the node function of the peaking technology determines to adjacent nodes. the number of hours in a year for which it is cheaper to curtail demand rather than supply the full peak. If the maximum number of hours with non-served energy is fixed by the reliability criteria of choice, we can use the criterion to (9) derive an analytical expression for the Value of Lost Load” (De Sisternes 2013): Note that the second Kirchhoff Law (or widely known as KVL, Kirchhoff’s Voltage Law) is valid for power systems but for reduced power systems, it might not apply depending on the method of network reduction followed. In this particular formulation, KVL is not considered. Another important feature of our model relates “Alternatively, we can assume that some demand to modeling of transmission losses. We model is sensitive to price, avoiding the price going transmission losses as a percent reduction of the above some certain threshold below the values imported electricity at each node. In particular, term presented above. In reality, this is achieved through contracts with special customer groups that are willing to reduce their demand during peak hours, or with grid elements that can at equation (9) models injections to node z and we supply electricity on an ad-hoc basis. Elements can see how the loss factor reduces the amount of within this category are emergency generators energy imported. On the contrary, the outflow is located in critical infrastructures and public fully considered at the origin node of the network: facilities such as hospitals, government, etc., used for back-up power in case of blackouts, staying idle when the system is operating normally. These generators could potentially be used to deliver electricity when prices are high, Another common constraint for transmission without jeopardizing their back-up generator networks refers to the capacity limits of functionality. Typically, back-up generators are transmission lines. In particular, as equation (10) fueled with expensive diesel, and if they are used implies, the flow over a specific line cannot exceed in the mode just described, the system VOLL a certain limit, which is defined either by thermal would take the value of the variable cost of these limit of the line or upper bounds imposed by generators (~500 $/MWh)” (De Sisternes 2013). reliability considerations. Note that we model flows over a particular transmission line with two positive variables, one for each direction. Please observe that the transmission limit parameter might change per year to reflect planned upgrades or OCTOBER 2021 // 106 additions to the transmission network. Moreover, indicates that interconnections can be accounted the transmission limit differs per season since for as reserve margin. Note that intermittent units ambient temperature affects the capacity available do not contribute towards the planning reserve for power transfers. constraint at their full capacity but at a fraction specified by the planner, for example, in the U.S. (10) markets this fraction is calculated based on available historical data as the capacity factor during a set of peak hours (Hobbs and Bothwell 2016).40 SYSTEM REQUIREMENTS In our formulation, we model two products that the system operator might require generators (13) to provide during operation: (i) energy and (ii) spinning reserves. As per the North American Electric Reliability Corporation’s (NERC n.d.) GENERATION CONSTRAINTS definition, spinning reserves refers to “unloaded We decide to include spinning reserves since generation that is synchronized and ready they will “consume” capacity that could be used to serve additional demand.” Note that more for power generation. products exist, especially in organized U.S. wholesale markets such as nonspinning reserves or flex ramp. Operating reserves (spinning and (14) nonspinning reserves) provide the capability above firm system demand required to provide Equation (14) assures that the power generated by for regulation, load-forecasting error, equipment the unit along with the spinning reserves provided forced and scheduled outages, and local area by the same unit do not exceed the unit’s capacity.41 protection (NERC n.d.). Moreover, under the Note that the capacity is augmented by an spinning reserves different products might exist overload factor. This factor is typically 10 percent with respect to the response times required, etc. for those generators that can handle overload conditions for a short period of time, and zero The amount of spinning reserve required for those generators that cannot handle such depends on several factors that the planner/ conditions. operator considers such as the load level and the associated forecasting error, the forecasting Given that spinning reserve products are error attached to the renewable generation, usually defined with respect to response time and the size of the largest unit committed on of generator to a certain dispatch signal, only a the system to be able to accommodate N-1 certain percentage of the generator’s unit qualify outages. Equation (12) indicates that spinning as a reserve offer. We capture this characteristic in reserve can be provided by interconnections. On the model through equation (15). top of systemwide reserve requirements, zonal requirements apply to accommodate for outages (15) on transmission lines connecting adjacent regions/zones/nodes. (11) 40 For the first model runs, capacity credit was considered at full capacity. This will be modified in the next runs but it is not expected to change the model results significantly. 41 Depending on the scope of the project, the dispatch (12) constraint (14) might be slightly different. For example, the ReEDS model implemented by the National Renewable Planners usually consider a planning reserve Energy Laboratory (NREL) (Short et al. 2011) treats quick start capacity service provided by a generator in the same margin (PRM) to account for forecasting error way as spinning reserves under constraint (14) and on in demand projections. Typical values for the top of that, it accounts for planned and forced outages by PRM vary between 10–15 percent. Equation (13) considering average outage rates. 107 // APPENDIX F. ELECTRICITY PLANNING MODEL (EPM) METHODOLOGY Ramping constraints acknowledge that the RENEWABLE GENERATION generation units have inertia in changing their outputs and differences in generation MODELING outputs between consecutive hours should Renewable generation differs from conventional be constrained by the ramping up and down units in that its output is, to a certain extent, capabilities of the unit. uncontrollable and intermittent. The power generated by renewables such as wind or solar (16) depends on wind velocity or solar irradiation. Collecting historical data that register weather information (such as wind speed, temperature, (17) wind direction, etc.) or the power generation output by installed renewables at specific Another important feature of generators is locations, analysts usually employ statistical the minimum load. The minimum load can methods such as k-means to reduce the either be determined based on technical amount of hours required to approximate the specifications provided by the manufacturer intermittent nature of renewables (Baringo and or be calculated as an “economic” minimum Conejo 2013). In this particular application, the beyond which the unit can provide energy generation profile for each renewable energy economically. The minimum load constraint technology (such as wind or solar PV) is defined is really important for unit commitment and by the hourly capacity factor, in a year, of a requires the use of binaries variables that make generic power plant of each type, modeled sure the constraint is enforced when the unit is at a specified location. Then, given this hourly on. However, in the planning models operations profile for a year, we choose the amount of days are approximated through a simple dispatch modeled based on the days selected for the model for representative hours of the year. In the load approximation (see section F.4), that is, the same manner, an approximation of the minimum renewable profile during the 12 days in the year load constraint is applied for some thermal selected, for load, is maintained. units the minimum load constraint is judged to be important. In this particular application, (20) the modelers decided that the minimum load constraint is relevant only for a subset of the days Note that the renewable profile is highly dependent modeled and the constraint is activated only for on the region/location the resource is located. This those days. Constraint (18) is forcing all units to formulation implicitly models that aspect since generate power equal to at least their minimum g might have different elements for the same loading levels for specific days in the year. generation technology at different locations. (18) CONCENTRATING SOLAR POWER (CSP) MODELING Generating units require maintenance every CSP technology modeling differs from other year. Given that, we should consider the units renewable technologies due to the complexity as unavailable for certain periods during the derived by its storage capabilities. The CSP year. In this particular application, we consider configuration considered in this model consists a uniform availability factor per quarter to of two integrated subsystems: the thermal account for maintenance. storage system and power cycle. Thermal storage is modeled using a simple energy balance approach that includes charging and discharging energy. The power cycle model provides a simple mechanism for modeling the conversion from the (19) thermal energy output from the solar field, and thermal storage into electrical energy. OCTOBER 2021 // 108 Four more constraints are formulated to fix the (21) capacity at prespecified levels in certain years. • The first constraint states that the total Equation (21) indicate that at any time the CSP capacity of a new generator equals the storage level cannot exceed its storage capability. capacity of that new generator built the previous year plus the capacity to be built the current year: (22) (27) The power output of the solar panel is calculated • The second constraint forces the capacity by multiplying the nameplate capacity of the CSP at the first year of the horizon to be equal power plant, the capacity factor of the system, to the known level: and the solar multiple, then, dividing this by the turbine and solar field efficiencies (Equation (22)). (28) (23) • Third constraint forces the capacity of planned and candidate units at zero for years preceding the commission year of Equation (23) indicates that all the power output the unit. In other words, this constraint produced by CSP generators at any given zone, takes into account construction times and cannot exceed the nameplate capacity. Finally, makes sure that enough time is allowed Equations (24) and (25) detail the power balance for a unit to become operational. formulations for the power cycle and thermal storage subsystems. (29) • The fourth constraint forces the capacity of existing units at zero in case they exceeded their lifetime. Note that a similar constraint would apply for new (24) units in case more than 20 years were modeled. Given that the lifetime of any new generator is at least 20 years, no new generator is foreseen to retire in the (25) horizon we model. TIME CONSISTENCY OF (30) POWER SYSTEM ADDITIONS AND RETIREMENTS STORAGE MODELING We use constraint (26) to track the capacity in Economically efficient storage in power systems consecutive years. In particular, generation capacity has mainly been pumped hydro storage for a at year y equals capacity at previous year plus any considerable amount of years. Nowadays, more investment minus any retirement at year y. storage technologies are being added on the power system. However, for the time being no investments in new storage technologies (26) are considered. The existing pumped hydro 109 // APPENDIX F. ELECTRICITY PLANNING MODEL (EPM) METHODOLOGY storage units are aggregated at the zonal levels and represented as one unit with characteristics (32) reflecting the ones provided by all units in the zone. Storage is modeled differently compared to conventional units since it requires two more variables: (i) one to keep track of the storage (33) level and (ii) one to model the charging of the unit. The generator output of conventional units Constraint (34) forces the storage unit to corresponds to the output of the storage unit discharge all its energy during the day. when it is discharged. Moreover, the chronological Essentially, it assumes daily cycles for the storage sequence of the time slices is important in order to units, where the unit is charged during off-peak make sure that the simulated operation is feasible, hours and discharged during peak hours. for example, we cannot discharge a storage unit if the charging of the unit has not preceded. Finally, storage of energy requires the conversion of electricity to another form of energy, for example, mechanical for flywheels or chemical for fuel cells (34) and common batteries. The conversion of one form of energy to another involves losses that we should Note that storage units can be charged or take into account in our models. discharged at a rate, which cannot exceed Three constraints are used to make sure that the a specific value. To model this behavior, we operation of storage would be feasible taking into include constraints (35) and (36), respectively. account the time sequence of load blocks. The time sequence in this particular application is relevant at (35) the week level. As a result, we initialize the storage levels at the first hour of each week modeled and (36) assume that zero storage level would be available at the beginning of one week because of storage Similarly, the energy stored in a storage unit operations during the previous week. Constraint cannot exceed its designed capability. (31) enforces this initialization: (37) (31) Moreover, we include some constraints that Then constraints (32) keeps track of the energy represent the storage operations43: stored in the unit between consecutive hours of the First, the power provided by the storage unit at same day: the energy stored in the unit at time slice any time slice t should not exceed the energy t equals the energy stored in the unit at time slice stored at the unit at the beginning of the time t-1 plus any injection discounted by the efficiency slice t: minus any discharge at time t. Third, constraint (33) makes sure that the last time slice of the previous (38) day plus any injection discounted by the efficiency minus any discharge at time t is equal to the energy Second, the energy stored in the unit cannot stored in the unit at time slice t.42 exceed a certain limit as indicated by constraint (37). In that case, the maximum amount of 42 Note that the representation of storage in the model is a 43 These constraints might be redundant, but the modelers discrete approximation of the actual operation of storage. decided to include them to make sure the storage operational For example, in reality the storage level of a unit will schedule is feasible. However, if the model size challenges the change within an hour depending on the charging or the computational power available to the planner, the planner discharging. might want to reconsider their (de)activation. OCTOBER 2021 // 110 injection of power to the storage unit cannot exceed the energy differential between the storage level at the beginning of the period and the maximum amount of energy that can be (43) stored in the unit: Constraint (44) represents a budget constraint. It limits the capital expenses withdrawal to be lower (39) than a prespecified amount. In this formulation, we assume that the MaxCapital parameter is similar to the maximum debt payments that a INVESTMENT CONSTRAINTS power system planner can do over the horizon. Planners consider several constraints when they decide on a generation investment plan. Common constraints refer to budget, land use, scheduling of new construction, and consumption of specific fuels for energy security considerations. (44) Constraint (40) usually reflects land use considerations, regulation that imposes an upper An alternative constraint that addresses the bound on capacity of specific technologies, or same concern but relies on different information simply resource potential (for example, for wind is expressed by constraint (49). In that case, the there is a finite amount of locations where wind planner does not know the maximum amount farms can provide the capacity factor modeled). of debt payments that the power plant owners might make but he has a good understanding of the maximum capital available to the system for (40) investment. In that case, the sum of the overnight capital expenditure is not allowed to exceed this Constraint (41) is usually employed to reflect known budget. practical limitations on construction and spread the construction of new units more uniformly over (49) time. For example, it seems unrealistic that the whole system capacity can be built in one year. (41) (45) Constraint (42) imposes an upper bound on (46) fuel consumption. This upper bound might correspond to the fuel reserves a country might have at its disposal or the capacities of refinement (47) units or importing units such as size of LNG terminals. Constraint (43) simply estimates the fuel (48) consumption. Note that in case we want to reduce the number of variables in our model, we can get Another policy mechanism related to carbon rid of the fuel variable since it is defined in terms of emissions is a carbon tax (less popular than the the generation variable. cap-and-trade system at present). We model the carbon tax as part of the objective function. (42) Note that the carbon tax does not correspond to an actual cost for the society since it is a transfer payment for emitters to the government. It reflects an actual cost, though, only if it attempts 111 // APPENDIX F. ELECTRICITY PLANNING MODEL (EPM) METHODOLOGY to monetize the public health cost and the damage available to the analyst and explain the rationale to the environment. However, it reflects an actual for their use. Finally, in the last column of the cost for the power system since generators would table we report if the flag was active or not for the probably have to pay the tax to the government and results provided as part of the study. that’s why it is part of the objective function (8). On top of the flags associated with constraints, we also include a flag that allows us to either load as input data test cases to test if the model behaves properly. (8) Please keep in mind that depending on the purpose of each study and the available data, LIMITATIONS OF THE MODEL different constraints might be identified as As any model, this model also has some redundant. For example, in cases of limited limitations since it is an approximation of the real knowledge of the transmission capabilities we system. Two major limitations of the model are might not be able to formulate constraint (10). the following: Another example could be constraint (40) in (i) Transmission network representation: We cases where no limits on investment in certain assume zero congestion within each zone technologies or regions apply. modeled. Moreover, KVL is omitted and the expansion of transmission network is not part of the model. (ii) The model is deterministic and no uncertainty F.5. PROJECTED with respect to assumed parameters, etc, is taken into account. DEMAND TIME SERIES Planning models usually rely on an approximate representation of the demand through a F.4. CUSTOMIZED discretized Load Duration Curve. The number or CONFIGURATION OF “steps” that a Load Duration Curve should have to efficiently allocate future capacity between THE MODEL different technologies and regions depends on a number of factors such as the number of candidate technologies in terms of different characteristics, The model developed as part of this study is the shape of the load curve, and the variability quite comprehensive, incorporating various of intermittent resources. Number of “steps” or constraints related to generation investments, “representative hours” differs per study but it is operation of the power system, and policy. usually around 10–30 discrete demand levels. Depending on the scope of each study for which it is used, analysts can decide on the subset The objective of this study is the assessment of of constraints they would like to use for the trade benefits that could be achieved through intended analysis. Activation and deactivation higher degree of coordination between 18 different of different sets of constraints is straightforward countries. The number of the regions along with when “flags” are used. One flag can be the importance of the best possible representation associated with one or multiple constraints of the coincidence of net load conditions across and depending on the value of the flag, the the countries led us to the conclusion that a respective constraint might be included or higher number of discrete demand levels would excluded from the model formulation. Usually, be required. So, the modeling team decided that when the flag has a positive value the constraint four representative weeks with hourly granularity is included in the formulation but when the flag for load and renewable energy resources would be has a zero value, the constraint is not part of a good approximation of the conditions that the the formulation. In table 44, we list all the flags power system operators might face in practice. OCTOBER 2021 // 112 Table 44. Constraints and Features of EPM Flag Constraints Rationale Status for the Associated Analysis Mingen_constraints (18) Many planning models omit minimum load constraints since it is hard to Inactive approximate its binary nature with a linear constraint. Spinning_Reserve_ (11), (12), (15) High-level planning models might not consider spinning reserves because Active constraints the relative comparison of generation units in terms of reserve costs is similar to the one based on energy costs and the approximate accuracy of the power forecast makes the consideration of reserves redundant. However, reserve consideration might be important if certain units cannot qualify as reserve providers or/and they have variable energy pro les. Planning_reserve_ (13) Margin reserves Active constraints Ramp_constraints (16), (17) Ramp constraints are meaningful only when the time sequence of the Inactive time blocks is respected. Moreover, in case individual generation units are aggregated to form one aggregated unit, enforcement of the constraint might not be relevant because ramping capability will actually vary with the number of units that are online, and generating power. Fuel_constraints (42) Fuel constraints might not be relevant when access to high quantities of Active internationally traded fuels such as lique ed natural gas and oil is easy and facilities for fuel handling are bigger than the size of the fuel needs of the power system. Another reason that might render the fuel constraints redundant could be the enforcement of environmental policies. In that case, certain policies might implicitly require much lower fuel consumption than the consumption that would be possible based on capacity of fuel-handling facilities or available fuel reserves. Third, another set of constraints that might implicitly take into account fuel constraints is constraint (40). By limiting the capacity of new generators, an upper bound on consumption of certain fuels is implied. Capital_constraints (44) In economies where access to capital for power system investment nancing Inactive is easy, constraint (44) might not be needed. CO2path_constraints (46) Constraint (46) imposes CO2 caps on zones of the system. Constraint (46) Inactive might be relevant in case di erent environmental targets/policies apply for the di erent zones, for example, when each zone is a di erent country or state. However, in case zones represent di erent buses of the power system of a region with single environmental targets, constraint (46) might not have a practical meaning. CO2total_constraints (48) Constraint (48) represents a single environmental policy on carbon Inactive emissions, applicable for the whole system. Constraint (48) might not be relevant when the system consists of zones that correspond to countries with di erent environmental goals. Source: World Bank staff. Note: CO2 = carbon dioxide Upon decision on granularity of load compensate for the lower confidence associated representation in the system, the modeling with the projected load time series. team faced two decisions: (i) we could rely on For all countries modeled, CESI has provided us historical data to do a retrospective assessment with projections on future annual consumption of trade benefits that the region could have and future peak power. For most of them, the gained by coordinating their power systems projection was provided to CESI by the Arab more closely; or (ii) project the demand series Fund for Economic and Social Development. in the future to estimate potential future benefits that region might gain by increasing Based on those input data, we followed a two- the coordination of their power systems. We step procedure to estimate the 8,760-point decided to follow the second approach since series for future demand. First step aimed to it might give more valuable insights to policy estimate the future load duration curve and makers given that new challenges faced by second step aimed to reorder the hourly load the system will be taken into account and levels from the load duration curve to form a the higher value of those insights might chronologically ordered load curve. 113 // APPENDIX F. ELECTRICITY PLANNING MODEL (EPM) METHODOLOGY FUTURE LOAD DURATION For most countries, historical data of hourly granularity were obtained from a feasibility CURVE ESTIMATION study published in 2014 (CESI-Ramboll 2014). Based on experience, modelers thought that an For nine countries, data are from 2010. Iraq’s odd order polynomial described by the following data are from 2009 and 2011 data are used formula: a*(x+b)k+c*x+d approximates the for Algeria, Egypt, Oman, Qatar, and Tunisia. load duration curve with satisfying accuracy. For three countries (Lebanon, West Bank and Knowledge of four parameters is required to Gaza, Syria), limited historical information was generate load data using this formula. To estimate available in the public domain and we describe the four different parameters, for a given order k in section F.5 approach followed to generate the each time, a system of four nonlinear equations synthetic historical time series. is solved using Matlab. The four nonlinear For the second requirement, we assumed that equations are based on (i) projected peak power, the allocation of energy across the six zones (ii) projected minimum load, (iii) projected power used for Saudi Arabia will be in the future at an interim hour, and (iv) projected energy. identical to the allocation observed in 2010. Detailed description of the equations can be Moreover, we assumed that the ratio of the found below: sum of the individual peaks of the system over the coincident peak will be constant at the (1.6a) 2010 levels for the future and then the relative relationship of the individual peaks between each other will remain the same. We describe (1.6b) the assumptions in mathematical form below: (1.6e) (1.6c) (1.6d) (1.6f ) Different odd orders for the polynomial are tested from 5 to 17 and the algorithm chooses REORDERING THE the odd order which has the lowest mean square error for the historical 8760-datapoints PROJECTED LOAD LEVELS TO load duration curve. FORM A CHRONOLOGICALLY As discussed earlier in this section, the Energy ORDERED LOAD CURVE and Peak Power is available for all countries of the model. However, further assumptions are For all systems included in the model, we have required for: either actual or synthetic historical data. We assume that there is a one-to-one mapping • The minimum and interim power for all between the order of an hour in the load countries. duration curve (x) and the order of the hour in • All four assumptions for the subregions the chronological load curve (y=f(x)). Assuming we use to model Saudi Arabia because that this one-to-one mapping will be valid in the the projections provided apply to the future, we assign the load level corresponding to whole system. the x hour of the load duration curve to the f(x) hour of the future year. For the first requirement, we decided to project minimum power and interim power by keeping Given that the weekly patterns of the constant in the future the historical ratio of those chronological load curve are quite significant quantities to energy. The interim hour selected in most of the systems modeled (that is, load is was 1,000 (load sorted) hours of the year. significantly higher during workdays than the OCTOBER 2021 // 114 non-workdays), the “mapping” is slightly shifted. In case the first day of the future year is later in the week (assuming the first day is Sunday), we assign the first same-day in the historical year to the future year and shift the days from the first week of the historical year to the last week of the future year. The reverse assumption is followed when the future first day is an earlier day in the week. It is important to note that the projections provided are in the local time zone and we shift the final loads selected by the week selector to a common time zone. 115 // APPENDIX F. ELECTRICITY PLANNING MODEL (EPM) METHODOLOGY APPENDIX G. G.2. 400 KV HVAC TRANSMISSION TRANSMISSION LINES TECHNOLOGY AND AND SUBSTATIONS COSTS Preliminary cost estimates of 400 kV transmission lines and substations are based G.1. INCOMPATIBILITY on data from regional projects that reflect the environmental conditions in the Pan-Arab OF NEIGHBORING region. The determination of HVAC transmission line “loadability” is a function of the voltage, SYSTEMS conductor and bundling sizes, and the length of the line. For short 400 kV lines (that is, up to a Interconnection of power networks on the 100 km) the most economic loadability will be Arabian Peninsula is faced with complex about half the maximum thermal rating of the issues relating to incompatible national power line—as determined by the aggregate bundled systems, damage by war, and political enmity. conductor cross-sectional area—typically about However, the successful operation of the 1,200 MW. For longer 400 kV lines, the loadability Saudi GCC Grid in pioneering the use of high is determined by the surge impedance loading voltage direct current (HVDC) in its various (SIL) of the line—that is, about 500–700 MW as forms to integrate 50 hertz (Hz) and 60 Hz determined by tower structures and conductor high voltage alternating current (HVAC) power spacings. For 400 kV lines longer than 400 km systems is a model for enabling economic stability limits may determine the maximum trading of generation resources by neighboring allowable load that can be as low as 20 percent countries. The continued deployment of both of the thermal rating. HVDC and 400 kilovolt (kV) HVAC transmission Various consultants working in Arabia interconnections between Pan-Arab countries (Norconsult, PB Power, KEMA, and JICA [JERA- will facilitate staged restoration of power Nippon Koei]) have developed standard security in war-torn countries as well as estimates of cost per kilometer for a typical providing technical advantages in managing the double circuit 400 kV line, along with item cost rapid growth of intermittent renewable power rates for extra high voltage (EHV) switchgear, from solar and wind generation. transformers, and reactive components. Their In this respect HVDC-HVAC terminals at estimates are based on the designs already in each end of the HVDC line can provide use in Iraq (PB Power; figure 47, left) and Jordan stabilizing functions to enhance the security (JICA; figure 47, center) and within the Saudi 50 of the respective HVAC systems by enabling Hz 400 kV GCC system. Figure 47 (right) shows a power to be switched on and off without +-500 kV HVDC line in the United States. the complications and delays involved in the procedures of re-synchronization of large neighboring power systems. Moreover, HVDC terminals can act like large batteries capable G.3. HVDC of mitigating intermittency of wind or solar INTERCONNECTIONS generating plants. In this respect they can be used to earn additional revenue in a power AND LINES market requiring ancillary services to maintain power system stability. The use of HVDC technology is necessary to enable interconnection between neighboring asynchronous power systems. It is also possible a new type of technology using Variable Frequency Transformers (VFT) may be applicable in some OCTOBER 2021 // 116 Figure 47. Transmission Line Towers G.4. ASSUMPTIONS FOR ECONOMIC STUDIES The cost estimates provided herein should be considered as base costs that exclude land cost and physical contingencies due to uncertainties circumstances, especially when the power related to (i) substation foundations, (ii) terrain and transfer levels are less than about 300 MW (CIGRE foundations, (iii) contracting, (iv) financing, etc. HVAC 2006). Thus, when a 50 Hz and a 60 Hz power lines are expected to be double circuit 400 kV towers system meet at a common border, an HVDC built to standards well established in the region. back-to-back (BtB) converter facility is necessary HVDC lines will be expected to follow the practice for power transfer from one side to the other. used in the Saudi Arabian 600 kV line, technical However, having been thus forced to invest in details of which are not available at this time. an HVAC-HVDC-HVAC facility, consideration For estimating the investment costs of selected should be given to the technical and economic transmission interconnection projects discussed in advantages of using the HVDC transmission this report, the following unit costs were used: interconnection between two terminal HVAC- HVDC converters. In this respect the construction cost of a HVDC transmission line is typically about Table 45. Cost Summary of Transmission Equipment half the cost of an equivalent capacity double- Summary of $Thous/ circuit HVAC transmission line. Rating Unit Length unit Unit costs 400 kV D/C 3*560mm SIL 600 km >200 km 423 A typical 500–600 kV HVDC transmission line (as lines MW n-1 used in Saudi Arabia) comprises two circuits (one 400 kV S/C 3*560mm SIL 600 km >200 km 264 lines MW n positive, one negative) together with a ground 400 kV D/C 3*560mm SIL 400 km >200 km 395 return circuit for use when any one circuit suffers lines MW n-1 500 kV HVDC Dbl cct Bipole km 372 line short circuits or insulation failure. When both 400 kV T/L Bay 1,000 MW CB, Bay 2,000 HVDC circuits are in full operation there will be meters, bus a potential difference of 1,200 kV between them 380 kV T/L Bay 400 MW CB, Bay 1,340 meters, bus and no current flows through the ground circuit. 400 kV Reactor CB, Fixed reactor kVA 20 However, each circuit is capable of 50 percent of HVDC BtB 500 MVA Converter MVA 0.336 the rating using the ground return if the other HVDC Converter 500 MVA Converter MVA 0.16 Transformer CB, 400/161 kV kVA 10.58 circuit fails. The capability of the HVDC can be Auto CB, 400/161 kV kVA 8.46 built in stages to match transfer requirement—for Transformer example, by operating initially in the monopole Source: WBG 2019e Note: BtB = back-to- back; CB = Circuit Breaker; D/C = Double Circuit; HVDC mode then later upgrading to the double pole = high voltage direct current; km = kilometer; kV = kilovolt; kVA = kilo volt- mode with backup earth return. ampere; mm = millimeter; MVA = Mega Volt-Ampere; MW = megawatt; S/C = Single Circuit; SIL = Surge impedance loading; T/L = Transmission Line. 117 // APPENDIX G. TRANSMISSION TECHNOLOGY AND COSTS These costs should be used in the economic analysis by applying at least a 15 percent physical and 10 percent price contingencies. For construction of a conventional 400 kV transmission a three-to-four year construction should be used with annual disbursement of 20 percent, 30 percent, 30 percent, 20 percent; likewise, for substations and HVDC: 10 percent, 50 percent, 30 percent, 10 percent. OCTOBER 2021 // 118 APPENDIX H. TECHNICAL CHARACTERISTICS AND ESTIMATED PROJECT COST OF THE PROPOSED CROSS-BORDER TRANSMISSION LINES H.1. SUMMARY TABLE OF TRANSMISSION OPTIONS Summary of Pan Arab Power Trade Options (PTO) and Estimated Project Costs (EPC) for Selected Projects PTO Reinforced Interconnection Distance EPC Increased Commission Technical Characteristics # (km) US$M Capacity (MW)/1/ Year 1 Algeria (Ghazaouet/Tlemcen) – Existing HVAC OHTL 2*220kV 0 $0.0 600 2025 Morocco (Oujda) and 2*400kV 2 Egypt (High Dam) – Sudan (Merow) HVAC OHTL 500 kV plus 4 bays 730 $374.9 1,000 2025 3 Egypt (El Arish) – Gaza Strip OHTL 200kV rated 950MVA 45 $250.0 175 2025 4 Egypt (Taba) – Jordan (Aqaba) Second line 400kV, HVAC 13 $150.0 650 2022 Submarine cable 5 Jordan (Amman West) – West Bank (JDECO-4) HVAC OHTL 400 kV 40 $39.4 160 2025 6 Libya (Tobruk) – Egypt (Saloum – 500kV line from Sidi Krir to Saloum 616 $493.4 370 2025 Sidi Krir PP) HVDC BtB, 400kV to Tobruk 7 Libya (Tobruk) – Egypt (Saloum) HVDC BtB/Trafos Upgraded 616 $196.0 450 2030 to 1000MW 8 Second circuit of Jordan (Amman 450 2025 North) – Syria (Dir Ali) HVAC OHTL 400 kV plus two bays 105 $53.4 9 Third circuit of Jordan (Amman each end 200 2030 North) – Syria (Dir Ali) 10 Lebanon (Ksara) – Syria (Dimas) HVAC OHTL 400 kV 42 $44.7 730 2024 11 Saudi Arabia – GCCIA Third 600MVA BtB HVDC link 0 $0.0 600 2025 Interconnection System 400 kV at Al-Fadhili 12 Kuwait – GCCIA Interconnection Third 650MVA Auto Trafo 0 $7.4 600 2025 System plus 4 L Trafo bays 13 Qatar – GCCIA Interconnection Existing 2*1900MVA 400kV 0 $18.0 1050 2025 System connections 14 UAE – GCCIA Interconnection System Existing 2*1400MVA GCC Grid Lines 0 $0.0 900 2025 15 Bahrain – GCCIA Interconnection System Existing 2*750MVA 400kV lines 0 $6.8 600 2025 PTO Proposed New Distance EPC Capacity Commission Technical Characteristics # Interconnection (km) US$M (MW) Year 16 Saudi Arabia (Medinah) – Egypt (Badr) OHTL HVDC to Tabuk; 20km 1,500 $2,500.0 3,000 2023 submarine cable over Gulf of Aqaba; HVAC OHTL 500kV to Badr City, Egypt in service 2024 17 Saudi Arabia (Jazan) – Yemen Jazan 380kV via HVDC BtB OHTL 581 $482.6 500 2025 (Saana/Tiaz/Aden) 400 kV 18 Tunisia (Bouchemma) – Libya (Melitia) 500 2023 19 Second Circuit of Tunisia HVAC OHTL 400kV plus switchbays 250 $125.1 500 2027 (Bouchemma) – Libya (Melitia) 20 Saudi Arabia (Qurayyat) – Jordan First Stage HVDC 3 Way Connect 165 $425.4 1,000 2027 (Qatranah) Saudi-Jordan-Iraq 21 Saudi Arabia (Hail) – Iraq (Karbala) Hail to Rafha to Arar, Saudi, 729 $683.8 1,000 2027 380kV OHTL and HVDC Arar, Saudi to Karbala, Iraq 22 Jordan (Amman East) – Iraq (Qa'im) Second Stage HVDC 3 Way 523 $390.0 500 2025 via Azraq NPS Connect Saudi-Jordan-Iraq 23 Saudi Arabia (Ras Abu Gamys) – HVDC line with Converters 688 $633.5 1,000 2027 Oman (Ibri IPP) both ends 24 Kuwait (Subiyah) – Iraq (Basra) AC Double circuit OHTL 400kV 122 $66.3 1,000 2027 25 Kuwait (Jahra) – Saudi Arabia 380kV OHTL from Rafha to 492 $611.8 1,000 2027 (Qaisumah/Rafha) Qaisumah, Saudi; to 400kV HVDC BtB at border Saudi-Kuwait-Iraq Note /1/: The capacity in MW corresponds to additional capacity for reinforcement projects and total capacity for new interconnection projects. 119 // APPENDIX H. TECHNICAL CHARACTERISTICS AND ESTIMATED PROJECT COST OF THE PROPOSED CROSS-BORDER TRANSMISSION LINES The WB modeling team investigated the power #2, the proposed 500kV line between Aswan trading options based on the use of existing (Egypt) and Sudan is expected to reinforce supplies transmission links, transmission lines under to existing 500/230kV substations en-route to construction or transmission interconnections Khartoum (Sudan): (i) at Wadi Halfa (Sudan), and planned for implementation before 2030. The table (ii) Merow (Sudan), where two existing 500kV provides a cross reference to power trade options lines terminate, before going on to Kabushiya (PTO) estimated costs of the interconnection and Khartoum (Sudan). There are large hydro projects outlined in this report. stations at Atbara and Merowe (Sudan) which would be used to complement power supplies to and from Aswan (Egypt). For the project #16, H.2. KSA-NORTHERN although it was proposed to build a HVDC line from Yanbu (KSA) to Aswan (Egypt), the option REGION PAN-ARAB of continuing with an HVDC line from Aswan to Khartoum was not considered. The HVDC line that COUNTRIES is under construction from Medinah (KSA) to Badr City (Egypt) was estimated in 2010 to cost $1.6 Even though the Algerian interconnections billion, but the current estimates to complete it are with Morocco are well developed, two 220kV between $2.1 and 2.5 billion: https://www.utilities- lines in operation in 1988 and one 400kV line me.com/news/13049-saudi-egypt-electric-grid- in operation in 2010, their use for cross-border link-reaches-implementation-phase. electricity trade has been limited to mutual aid Information relating to Egypt-Gaza Project (PTO and annual trade contracts. For the Algeria- #3) is taken from a 2018 ESMAP report (https:// Morocco project (PTO #1), the nominal capacity www.esmap.org/node/158108) on the status of of existing cross-border interconnections the existing link between Egypt and Gaza, which between Morocco and Algeria allows the quotes, “Interconnection line between Egypt maximum transfer capacity to be increased from and Gaza is a 220 kV double circuit OHTL with 400MW to 1000MW at no extra cost. 952 MVA thermal capacity in total and transfer For the Egypt and KSA projects (PTOs #2 and is limited to 150 MW”. This report indicates that #16), the costs are based on existing plans by a new backbone 220kV line would be needed the respective power companies. For the project throughout the length of Gaza to interconnect the Figure 48. Coastal Interconnections Note: All maps in this document are for illustration purposes of cross-border projects only and not intended to reflect any political boundaries. OCTOBER 2021 // 120 four main load centers and that an increase in there are seven countries that plan to synchronously power imports about 200km from Egypt to Gaza interconnect their power systems including: Algeria, is contingent on upgrading the existing 220kV Egypt, Libya, Morocco, Sudan, Tunisia, and Western network throughout the Sinai region, as well as Sahara. Morocco is connected to Spain and thus building a 40km 220kV line from Rafah (Egypt) to Algeria and Tunisia are now synchronized with Jabalia (Gaza). the European high-voltage transmission network. Although Tunisia and Libya were interconnected in For the Egypt-Jordan project (PTO #4), the 2002, the link is currently not operational because of information was retrieved from the MED-TSO stability issues that are still under study. Moreover, it project (https://www.med-tso.com/publications/ is likely that, because of the long distance involved, a pub3/11_EYJO_Detailed_Project_Description. HVDC or VFT interconnection will be required at one pdf ). The PTO #4 consists of a second or more locations to separate the Egyptian based interconnection between Jordan and Egypt to be 50Hz region from the Moroccan based 50Hz region. realized through a 13 km 400 kV, AC submarine cable. It is expected to increase the current The Egyptian system will be linked to KSA via the transfer capacity between the two countries multi-terminal ±500kV HVDC project capable of to reach 1100 MW, aiming to mitigate possible two-way 3000 MW power trading via 1250 km of overloads in the path of the interconnection. DC line and 16 km of HVDC cable under the Gulf of Aqaba. The HVDC line terminates at two 1500MW converters in Badr City in Egypt and via a 750MW H.3. KSA-EGYPT intermediate converter at Tabuk in KSA, and at a two 1500MW converters at El-Madinah and El MEDITERRANEAN Munawara in KSA. Two transition/switching stations (Nabq in Egypt and one on the eastern shore of the COASTAL Gulf of Aqaba in KSA) will also be constructed for connecting the overhead lines and subsea cable. INTERCONNECTIONS Other key projects in planning include the 30-km- long, 500 kV Giza North power interconnection; Power trade opportunities are proposed between the 28-km-long, 500 kV Samallout–Suez Gulf–Jebel Egypt and its Mediterranean neighbors Libya al-Zayt interconnection; and the 500-km-long, 500 and Tunisia. In the western region of North Africa 121 // APPENDIX H. TECHNICAL CHARACTERISTICS AND ESTIMATED PROJECT COST OF THE PROPOSED CROSS-BORDER TRANSMISSION LINES H.4. INCREASING GCCIA POWER TRADE CAPABILITY The GCC interconnection (PTO #11 – #15) comprises seven 400 kV substations connecting five countries through approximately 900 km 400 kV OHTL double Note: All maps in this document are for illustration purposes of cross-border circuit backbone line rated at 1900 MVA connecting projects only and not intended to reflect any political boundaries. the substations of Al-Zour (Kuwait) in the North to the substation of Silaa (UAE) in the South. Bahrain kV Sidi Krir–El Salloum transmission line including is connected to the 400 kV backbone through two a new 500kV interconnection with Libya in order to upgrade the existing 230kV interconnection with the Arab Maghreb countries. Geographical structure of the GCCIA system The estimated cost of providing a 1000MW connection between Egypt and Libya (PTO #6 and #7) is based on the EETC proposal to build a 500kV line from the 750 MW Sidi Krir Combined Cycle Power plant switchyard inland following the inland road parallel to the 220kV line along the coast. Because of the difficulties in synchronizing with the western states, it is assumed that this project will include a 100MW HVDC BtB station built at El- Salloum (Egypt) to interconnect with a 400kV line connected to Tobruk (Libya). An alternative project could be based on the use of a HVDC connection Note: All maps in this document are for illustration purposes of cross-border all the way to Tobruk with an intermediate terminal projects only and not intended to reflect any political boundaries. at Marsa Matru (Egypt) as the need arises to supply the local 220kV system. With the intermediate Topological structure of the GCCIA system station, the costs would be comparable with the 500kB BtB solution. The 400 kV and 220 kV transmission lines in Libya connect the main centers of Tripoli and Benghazi regions with loop designed transmission networks. The project to upgrade the existing 220kV line to El-Salloum will form part of the ELTAM transmission interconnector which connects the power markets of Egypt, Libya, Tunisia, Algeria and Mali. It will involve the reinforcement of the Libya part of the 210 km / 400 kV Libya to Tunisia (PTO #18 and #19) section from Abou Kamach (Libya) to the Tunisia border. OCTOBER 2021 // 122 submarine cables rated each at 715 MVA. Kuwait, Bahrain and Qatar interconnect to the GCCIA system through, respectively, 3x650 MVA, 3x325 MVA and 3x400 MVA transformers. Saudi Arabia is connected through BtB HVDC converters rated at 3x600 MW at the 400 kV substation of Al-Fadhili. The HVDC station, in addition to being designed for economic power exchanges, also enables Dynamic Reserve Power Sharing (DRPS) between the 60 Hz and 50 Hz systems that has been to date activated on several occasions following severe active power imbalances for mutual support between the 50 Hz and the 60 Hz systems. Kuwait’s transmission network is connected with that of Saudi Arabia’s via a 900km-long double-circuit 400 kV AC line through the Gulf Cooperation Council (GCC) interconnection project at Al-Fadhili. Kuwait is currently connected to the GCC grid at the Al Zour 400kV substation via three 275kV lines feeding back to the main load centers as shown on the diagram on the next page. However, Kuwait is reportedly building a new 400kV ring through the city area with three substations in Sulaibiya, Fintas, and Jabriya, all of which are rated 275/400kV as shown in the picture The proposed power system on the right-hand side below. A logical point for KSA to connect to this ring would be in the center of the ring at JBAR substation located near the the city or to north and south through the new Sulaibiya, Al-Jahra. 400kV grid. Although the project could also be used to facilitate a 400kV line to be built from the For PTOs #21, #24 and #25, the proposal for KSA to BtB facility to Nasirayah in Iraq, this is not included increase its renewable exports from Hail/ Rafha/ in the cost estimate below. Qaisumah directly to Kuwait could be achieved by extending KSA’s 380kV lines from Rafha to GCC interactions with Oman are in effect wheeled Qaisumah and thence to a proposed HVDC BtB through the UAE 400kV transmission network and facility at the location where the three borders across the border from Sweihan (UAE) to Mahda (KSA, Iraq, and Kuwait) meet. The associated 400kV in northern Oman. The existing Oman 220kV substation would provide a supply to a 400kV transmission system extends across the whole of line to the new 400/275KV Sulaibiya substation northern Oman and interconnects bulk consumers enabling KSA power to be evacuated directly to and generators of electricity. 123 // APPENDIX H. TECHNICAL CHARACTERISTICS AND ESTIMATED PROJECT COST OF THE PROPOSED CROSS-BORDER TRANSMISSION LINES KUWAIT KSA should be able to inject/wheel more power through Al-Fadhili. The extent to which this can be done can only be determined by load flow calculations that are beyond the scope of this analysis. If KSA injects more power at Al-Fadhili, GCC would probably have to build another 400kV line in parallel with the existing one. Note: All maps in this document are for illustration purposes of cross-border projects only and not intended to reflect any political boundaries. Currently the Ibri independent power project (IPP) is a 1,509MW gas-fired power plant being developed in the Ad-Dhahirah region of northern Oman. The project includes the construction of a 400/220kV grid station to facilitate the transmission of power generated by the Ibri power plant to the national grid. The grid station will include three 500MVA transformers (400/220kV), 19 400kV gas-insulated switchgears (GIS), ten 220kV GIS, and two 4.3km-long LILO of 220kV Ibri – Mahdah overhead line. It is difficult to get up-to-date connection details of the GCC interconnections with the member countries. While it is possible that more 400/230kV transformers could be added to the designated off-taking substations, the respective power companies would probably look for more diversification – e.g., by extending the 400kV lines to other substations in their domestic systems. The way in which they decide to evacuate the power within their system is beyond the scope of this type of cost estimation. As KSA and its Pan- Arab neighbors are increasingly intertwined with transmission interconnections, a more complex situation will arise requiring extensive load flow studies to determine the impact on adjacent transmission lines. For PTO #23, by injecting power into the GCC 400kV backbone at its ends (Kuwait and Oman), OCTOBER 2021 // 124 Oman Transmission System in 2014 (with GCC 400kV interconnection) Note: All maps in this document are for illustration purposes of cross-border projects only and not intended to reflect any political boundaries. 125 // APPENDIX H. TECHNICAL CHARACTERISTICS AND ESTIMATED PROJECT COST OF THE PROPOSED CROSS-BORDER TRANSMISSION LINES