Mozambique Regional Transmission Backbone Project (“CESUL”): Technical & Economic Feasibility Study

1. Mozambique Regional Transmission Backbone Project (“CESUL”): Technical & Economic Feasibility Study Presentation of Feasibility Study Report CESUL Launch Workshop Centro de Conferências Joaquim Chissano Maputo, 24 November 2011

2. Presentation outline Feasibility study objective & goals Feasibility study highlights Power market assessment Mozambique generation options considered CESUL technical feasibility Economic & financial feasibility CESUL project timelines Institutional and operational arrangements Conclusions & Recommendations

3. Feasibility Study objective & goals Objective: • Provide technical and economic determination of least cost option for transfer of 3,100 MW north-south in Mozambique CESUL Project Goals: • Contribute to Mozambique’s economic and social development through facilitating improved access to electricity by: • Interconnecting the Mozambique power systems north-south, i.e. creating a Backbone Transmission System • Supply electricity at affordable prices to load centres and consumers along the transmission system corridor • Facilitate realisation of Mozambique’s large power development potential, with particular focus on hydropower, for domestic and industrial use and bulk export of cost-competitive renewable energy to South Africa and Southern Africa

4. Feasibility Study scope of work Review and update all information in previous studies and undertake: • Load forecasts (Mozambique / Southern Africa region) • Regional generation expansion scenarios (for Mozambique candidate projects) • Power system studies • Minimum one (1) AC link north-south as a premise for acceptability of any alternative • Determination of substation locations • Line routes – HVAC and HVDC (incl. electrode locations) • Preliminary engineering designs (lines & substations) and costing • Project packaging and implementation programme • Operational and control centre requirements, including organisation & training • Economic and financial feasibility analysis • Liaise with CESUL ESIA/RPF Consultant (separately appointed) The CESUL Feasibility Study builds on previous pre-feasibility study (2008) by Vattenfall Power Consultants and subsequent technical Optimisation Study (2009)

5. Feasibility Study deliverables The Technical and Economic Feasibility Study report consists of the following documents: • Volume I-A: Main Report • Volume I-B: Appendices to Main Report • Volume II: Economic Impact Study (still being completed) • Volume III-A: Preliminary Design Report – HVAC and HVDC Transmission Lines • Volume III-B: Preliminary Design Report – HVAC and HVDC Substations • Volume IV: Line Route Report – HVDC Line • Volume V: Line Route Report – HVAC Line

6. Key challenges encountered • Challenges to successful realisation of CESUL and the associated large (hydropower) generation developments include: • Project size and remoteness / distances involved • Technical requirements (to ensure high availability & reliability) • Cost competitiveness compared to alternative regional options • Amount of financing and commercial frameworks required • Integrated nature of generation and transmission developments, requiring alignment of stakeholder interests and high degree of coordination • Other key considerations include: • Devising transmission solutions in support of initial generation developments while facilitating long-term expansion to tap Mozambique’s energy potential • Ensuring sustainability and tangible benefits to local (Mozambican) economy from recommended technical and economic solutions • Minimising environmental & social impacts through line route selection • Dynamic and iterative nature of planning, analysis, structuring and financing

7. Findings and Conclusions • Feasibility Study confirms technical viability of combined HVAC and HVDC transmission backbone solution for 3,100 MW (and more) power transfer capability • CESUL Phase 1 investment costs (excl. financing costs and IDC) are estimated at US$ 2,119 million (of which US$ 1,800 million for Stage 1) • Phase 1 financing requirement of ~US$2,780 million incl. IDC & price contingency • Economic viability of combined hydropower and transmission backbone is robust • Financial viability and competitiveness of delivering electricity at Mozambique / South Africa border in southern Mozambique appears promising • Timely realisation of Mphanda Nkuwa project is key to commence CESUL development • Realising Cahora Bassa North Bank will allow complete CESUL Phase 1 development • Cost of debt financing to be tested with market participants • HVAC solution will ensure interconnection of Mozambique’s national transmission grid, with increased access to electricity along line route • HVDC portion of transmission backbone is scalable – for initial CESUL Phase 1 solution and beyond • Due to magnitude of project costs, a staged Phase 1 realisation should be considered • CESUL development needs to continue without delay from early 2012 to align with planned timeframe for commissioning of hydropower project(s)

8. Recommended CESUL Phase 1 solution CESUL Phase 1 includes combined HVAC & HVDC solution HVAC solution includes: 1,340 km 400 kV AC line for 900 MW continuous power transfer at 400 kV, but with 550 kV design of equipment 50% series compensation of AC line HVDC solution (Phase 1) includes: 1,275 km ±500 kV DC bipolar transmission line and converter stations with 2,650 MW capacity 90 km transmission lines to Cataxa and Maputo electrodes Implementation of HVDC solution is proposed staged: Stage 1: ±500 kV DC line with 1,325 MW converter capacity Stage 2: Additional 1,325 MW converter capacity Project is proposed packaged and tendered as a limited number of contracts (indicatively 7) Timeframe to implement Phase 1 / Stage 1 is 59 months: Design, tendering and contracting period: 17 months Construction period: 42 months

9. CESUL Feasibility Study – Power Market Assessment

10. Mozambique demand forecast - recent electricity demand growth trajectory (excluding Mozal)

11. Mozambique demand forecast(cont. I) • Forecast period is 2010 – 2030: • Energy supplied (before losses) (in GWh) and Peak demand (MW) • Natural growth + Large consumer demand • Medium forecast = base case (+ high and low forecast) • General electricity demand drivers: • Annual GDP growth: • 2010 - 2015: 6.5% - 7.9% (IMF estimates) • 2016 - 2030: initially 7.0%, tapering off to 4.0% • GDP elasticity: 1.2, tapering off to 1.1 (except large loads) • Electricity tariffs – current tariffs do not cover costs: • 7% real increase assumed over next 5 years • Assumptions applied will contribute to dampen future demand growth • Large user loads: • Defined as > 5 MW initial loads, identified based on information from EdM, Ministry, developers and consultant estimates • Cost-reflective tariffs assumed, with consequences for energy intensive projects that rely on low tariffs (e.g. Mozal expansion) • Uncertainty with respect to loads and timing dealt with by estimating probability and applying loads to medium forecast, high forecast and low forecast respectively

12. Mozambique demand forecast (cont. II) –Base Case national demand forecast (GWh)

13. Mozambique demand forecast(cont. III) Peak Demand – Base Case, High and Low forecasts (MW) Base Case forecast – natural growth and large loads (MW)

14. Southern African power demand SAPP power demand and supply: Importance of South Africa’s IRP2010 South Africa approved an IRP2010 in April 2011, being a 20-year indicative generation expansion plan Strong focus on clean, renewable energy Plan assumes 2,600 MW of hydropower import, mainly from Mozambique, to commence in 2022 (earlier if possible) Preference is for base load / mid-merit energy (not peaking) IRP2010 includes long-term indicative electricity price forecast Forecast average cost of new (base-load) generation is >10.0 USc/kWh Represents benchmark for Mozambique hydropower at South Africa border Actual price will however be subject to commercial negotiations • Southern Africa needs additional generation capacity – quickly! • Current reserve margins are insufficient • South Africa is by far the dominant market

15. CESUL Feasibility Study – Mozambique Generation Options and Regional Generation Expansion Scenarios

16. Generation Option Assessment – Mozambique candidate generation projects Potential generation projects were reviewed, focused on hydropower, coal, gas-fired projects Gas-fired plant with a total capacity of up to 600 MW are assumed built in Southern Mozambique, as well as 100 MW of local generation injected into Tete part of system Based on regional market assessment, hydropower projects are considered priority: Mphanda Nkuwa (“MPNK”) 1,500 MW base-load / mid-merit plant 8,600 GWh of annual energy (850 MW firm power) Feasibility study complete / Concession Agreement exists Cahora Bassa North Bank (“CBNB”) 1,245 MW estimated mid-merit/peaking capacity 2,983 GWh of gross annual energy (but only 854 GWh increase in overall Cahora Bassa annual energy) Studies ongoing / data & information to be firmed up

17. Generation Scenarios and associated Transmission Solutions Candidate generation projects and associated transmission alternatives were studied through scenarios, with grid injection of 600 MW gas-fired generation in south and 100 MW generation in Tete common to all scenarios

18. Regional generation expansion modelling • Southern Africa needs ~1,500 MW of additional (base-load) capacity per annum • Future generation and transmission developments in Mozambique will depend on competitiveness of Mozambique projects compared to alternative regional projects • Cost characteristics for Mozambique and regional generation projects were developed and analysed • January 2011 used as reference year for prices and cost estimates • Investment, (fixed and variable) O&M costs, and fuel costs considered • Analysis covered thermal (coal and gas-fired) and renewable generation projects (including hydropower, wind and solar) • Cost data were sourced from EPRI, Nexant and Consultant’s own data bases • Particular focus on generation expansion as envisaged by South Africa’s IRP2010 • Generation expansion simulations were undertaken to demonstrate economic viability of large-scale power export from Mozambique • Total generation costs, including energy not served (“ENS”) and spinning reserve costs, as well as generation related transmission costs (including losses) considered • Mozambique options substituted for ‘generic’ options in IRP2010 • Overall NVP of total generation costs in regional generation simulations was calculated, using feasibility study Generation Scenarios 1 to 6 as previously presented

19. Generation expansion scenario results • Some observations: • All generation scenarios with inclusion of Mozambique hydropower projects appear merited • Despite significant transmission costs, both MPNK and CBNB are economically viable projects • While Scenario 4 shows the highest potential saving, this scenario may trigger additional investments in transmission infrastructure at an early stage • On balance, therefore, Scenario 3 (MPNK and CBNB) appears to be most robust, with scope for future expansion by additional hydropower resource developments

20. CESUL Feasibility Study – Technical Feasibility Assessment

21. Planning methodology & criteria • Transmission • Planning assumptions document prepared and discussed with Eskom (ref. “Memorandum of Transmission Planning Assumptions”) • Complies in general with South Africa’s Grid Code • Deterministic N-1 planning criteria, but with agreement that up to 2,000 MW of generation can be tripped in Tete area for an outage of a line on CESUL transmission backbone (effectively a “N-½ criteria”) • Will normally not affect customers in South Africa due to size of South Africa system • Series compensation facilities and Static VAr Compensators (SVC) along AC backbone planned with redundancy • All transmission alternatives considered include at least one 400 kV AC line from Tete area to Maputo, to provide supply to areas in between • Recognised that wheeling capacity through Zimbabwe may be limited • Generation characteristics recognised • Production profiles • Forced and Scheduled outages • Minimum 15% reserve requirement for South Africa, with maximum 19% import share (of peak load)

22. Transmission system studies undertaken • Load flow, voltage stability and losses • Simulation of normal ‘steady state’ operation • Contingency analyses • Transient and dynamic stability • Fault levels • Sub-synchronous resonance studies • Switching studies • Optimisation of conductor configuration • Optimisation of reactive power compensation facilities: • Line and bus shunt reactors • AC line series compensation • Static VAr Compensation (SVC)

23. Transmission system studies (cont.) • Key assumptions: • Generation at Benga and Moatize developed basically to cover own demand, with 100 MW surplus generation sold to EdM • HVDC Songo - Apollo transfer capacity of 1,920 MW • SAPP grid support during contingencies • Wheeling via Zimbabwe attempted kept at low level as full capacity of interconnection Songo - Bindura may not be available in future • Under normal operations, wheeling may possibly be avoided once CESUL HVDC line is in service • Comparison of alternatives based on unit cost estimates • Detailed cost estimates based on supplier quotations developed for recommended CESUL scheme • CESUL O&M costs estimated at 2.0% p.a. • Marginal cost of losses priced at 6.0 USc/kWh (for equivalent capacity and energy cost)

24. Transmission solutions considered HVDC 500 kV and 600 kV bi-pole schemes - bi-pole lines 800 kV mono-pole Phase 1 2nd 800 kV mono-pole in Phase 2, forming bi-pole with DC in Phase 1 HVAC 400 kV operation (but heavier equipment design) Quadruple line configuration to limit reactance Compact line / expanded bundle design considered for high transfer levels Series compensation up to 70% to achieve transient stability Line and bus shunts to handle energization / load rejection SVCs for voltage & stability control measures Intermediate substations required for voltage control combined with supply to local area Both HVAC and HVDC technology solutions were examined in the Feasibility Study, under a number of design considerations

25. Transmission studies – considerations • Characteristics of existing transmission system • Defining a base case (without CESUL backbone) • Specific technical challenges (line lengths, fault levels, compensation, energization) • Substation locations (AC + DC) • Interaction with HVDC system Songo – Apollo (RSA) • Integration with neighbouring SAPP countries and wheeling over SAPP networks • System expansion in Southern Mozambique • Interfacing with Motraco system • New Master Power Controller (MPC)

26. Line routings (HVDC and HVAC) Key considerations: General Utilize existing and planned "energy" corridors (transmission lines, roads, railways) Minimise social and environmental impact Access and maintenance conditions Utilise reliable low cost design Least cost HVAC Line Routing Support for development of Mozambique Interconnection of EDM grid Selection of substations considering reactive compensation requirements HVDC Line Routing Bulk power transfer (aligned to generation scenarios) Minimise social and environmental impact Utilise reliable low cost design

27. Conclusions from transmission studies For AC line(s), the following is noted: • Distance from Tete to Maputo (~1,340 km along chosen route) presents technical challenges: • Voltage control (for energisationand normal and contingency operation) • Transient and dynamic stability • (Note: 53 km of 400 kV line Songo – Cataxa will be required, not currently defined as part of CESUL Phase 1) • Low reactance is required, implying: • Four bundle conductor configuration • Compact line design with expanded bundle would be required for high transfers (>1,400 MW) • Low reactance leads to high capacitance, causing: • Higher switching surges • Increased insulation level • Higher investment costs

28. Conclusions from transmission studies (cont. I) • AC line requires extensive reactive power control for energisation and voltage regulation during normal and contingency operation: • Long line - must be split in sections • Intermediate substations at Inchope, Vilanculos and Chibuto are required and will feed into local grids • Line shunt reactors required at either end of each line section in combination with switched bus shunt reactors • Large SVCs required at intermediate substations, with two units at each of Inchope and Vilanculos to maintain operability during outages of SVCs • New substation proposed at Moamba to act as feeding point for Maputo area (and suitable connection point for gas-fired plant and potential future 3rd 400 kV line to South Africa)

29. Conclusions from transmission studies (cont. II) For DC line(s) the following is noted: • 500 kV HVDC bi-pole solution with bi-pole DC line estimated to present least-cost solution for CESUL DC link • 600 kV HVDC bi-pole and 800 kV mono-pole also evaluated, but considered to imply slightly higher overall costs • Bi-pole solution will provide higher overall availability (than mono-pole), although loss of 500 kV bi-pole will require tripping of generation as for a 800 kV mono-pole solution • 500 kV bi-pole solution will also limit environmental impacts through reduced width of right-of-way, lower line towers (about 3.5 m lower) and less time of operation with electrodes

30. CESUL Phase 1 – combined HVAC / HVDC solution HVAC operated at 400 kV (equipment designed for 550 kV) – 900 MW transfer capacity HVDC operated at ±500 kV – 2,650 MW transfer capacity, implemented in two stages , each with 1,325 MW converter capacity

31. Staged implementation of HVDC for CESUL Phase 1 Stage 1: 1,325 MWStage 2: 1,325 MW

32. CESUL connections to Mozambique power system

33. CESUL Project cost estimates • General approach • Unit costs used for comparison, drawn from Consultant’s databases and external cost statistics (e.g. CIGRE) • Supplier quotations used for actual Project costing and economic/financial analysis, based on EPC delivery, "CIF to port“ • Project costing includes Engineering & Owner’s Costs and Contingencies (added to suppliers’ EPC cost quotations): • Engineering & Owners Cost: 10% of EPC quotations • Considered conservative • Physical Contingencies: 10% of EPC quotations • Price Contingencies: not included in Project cost estimates • 10% price contingency on EPC quotations recommended included when finalising Project financing requirements • Relocation / compensation payments: • Included in Project costs with value equal to 2% of estimated transmission line cost (HVAC and HVDC) • CESUL RPF Report recommendations will be used in Final Report, with latest indication is 3% of transmission line costs

34. Phase 1 HVAC costing

35. Phase 1 HVDC costing

36. CESUL Phase 1 – total investment costs

37. CESUL Feasibility Study – Economic & Financial Feasibility

38. Economic feasibility – objective & approach • Objective of economic analysis: • Establish least-cost Project option (for each generation scenario) • Ensure that benefits of least-cost Project option exceeds Project costs • Demonstrate that Project represents efficient use of scarce economic resources • Approach: • Project benefits and costs are compared to a situation without the Project • Analysis is based on discounted cash flow (“DCF”) modelling • Required Internal Rate of Return (“IRR”) of 10% in real terms (equal to assumed economic opportunity cost of capital) • Calculation of Economic IRR (“EIRR”), Net Present Value (“NPV)” and Economic Unit Energy Cost (“EUEC”) of electricity generated and transported • Analysis focused primarily on assessment of Generation Scenarios 1, 2 and 3: • Scenario 1: CBNB only (1,245 MW) • Scenario 2: MPNK only (1,500 MW) • Scenario 3: MPNK + CBNB (1,500 MW + 1,245 MW), with CBNB implemented 2 years after MPNK • Scenario 3: MPNK only + Stage 1 of CESUL Phase 1 only

39. Economic feasibility – assumptions • Main assumptions: • 45 years Project life • All power from MPNK and CBNB assumed contractually transmitted over CESUL infrastructure • Transmission losses assumed as 4.5% in recommended alternative • Electricity valued at 10.5 USc/kWh at SA border • Equal to estimated alternative cost of base-load supply (assuming Combined Cycle Gas-Fired plant using imported LNG) • Operating costs of CESUL infrastructure: 2.0% p.a. of investment • Energy transmitted from: • MPNK: 8,548 GWh/year • CBNB: 2,983 GWh/year • Total net increase of production at Cahora Bassa complex is 854 GWh/year, including a decrease at CBSB of 2,129 GWh/year • Loss of generation at CBSB takes place at night, and such lost generation is priced at 2.6 USc/kWh (assumed as variable cost of coal-fired plant)

40. Economic feasibility - results Note: IRR and NPV calculations are based on financial transmission tariff

41. Economic feasibility – results (cont.) • MPNK + CESUL are economic viable and robust solution • With MPNK only, cost ‘penalty’ of developing CESUL with combined HVAC and HVDC has marginal impact only • Staged CESUL Phase 1 development is viable solution • CBNB + CESUL represent an economic viable solution based on HVAC transmission solution • CBNB economics improve substantially when developed with MPNK and ‘complete’ CESUL solution (HVAC + HVDC) • CBNB economics appear robust in combination with MPNK, based on recommended CESUL Phase 1

42. Financial viability – objective & approach • Objective of financial analysis: • Takes the view of prospective investors in CESUL • Establishes whether investors can be expected to achieve a satisfactory equity return • Approach: • Project financial income and costs are compared to situation without the Project • Analysis is based on discounted cash flow (“DCF”) modelling • Required USD based equity IRR of 16% after tax in nominal terms for CESUL, 17% for generation investments • Calculation of Project and Equity IRR, NPV and Financial Unit Energy Cost (“FUEC”) of electricity generated and transported • Same Generation scenarios as in Economic Analysis, i.e. Scenarios 1 to 3, including alternative with Scenario 3 Stage 1 only

43. Financial viability – assumptions • Main assumptions: • 30 years concession period • Electricity selling price set at 10.5 USc/kWh at SA border • Based on estimated alternative cost of base-load supply (assuming Combined Cycle Gas-Fired plant using imported LNG) • 10% of MPNK (and CBNB) energy sold with 40% discount to EdM (as per term of Concession for MPNK) • 70/30% debt/equity ratio assumed • 8.0% - 8.5% interest rate on USD loans (including margin) • Debt financing assumptions to be tested and confirmed by CESUL Financial Adviser • VAT and excise duty exemptions assumed for Generation and CESUL • No income tax incentives assumed for CESUL • Tax regime for Generation projects assumed as per MPNK Concession

44. Financial viability - results

45. Financial viability – results (cont.) • MPNK + CESUL is a financially viable and robust solution • Cost ‘penalty’ of CESUL with combined HVAC and HVDC solution has marginal impact only • Staged CESUL Phase 1 development is viable • CBNB financial viability uncertain based on CESUL HVAC solution • CBNB viability improves when developed with MPNK and ‘complete’ CESUL solution with HVAC + HVDC • CBNB financial viability appears robust in combination with MPNK, based on recommended CESUL Phase 1 solution

46. CESUL Feasibility Study – Project Timelines

47. Implementing CESUL – key steps • Key Project development activities • Appoint Consultant for Design, Specifications & Tender documents - Feb 2012 • Commencement of Procurement process - Mar 2012 • Approved tender evaluation - Mid Apr 2013 • Approved contracts - Jun 2013 • Financial Close of Project – Jul 2013 • Construction of Project Facilities • Commencement of OHTL Construction Contracts – Mid Jul 2013 • Commencement of Converter Stations Construction Contract – Mid Jul 2013 • Commencement of Substation Construction Contracts – Nov 2013 • Taking-Over of Project Facilities – Jan 2017 • Assumed timeline for associated IPP projects • Financial closeMPNK – Mid-2013 • Commissioning of MPNK – 2nd half of 2017 • Commissioning CBNB~ earliest mid-2017 (but could be later)

48. CESUL Phase 1 – Indicative Project Programme

49. CESUL Feasibility Study – Institutional & Operational Aspects

50. Envisaged organisation of CESUL • CESUL Project size, technical nature and complexity, as well as the very large financing requirements, are all factors indicating that CESUL should be established as a Special Purpose Vehicle (“SPV”) • SPV model and recommended structure will be developed by CESUL Financial & Legal Advisors • EDM is expected to be lead Sponsor • Additional equity participation may be sought from credible international investors with relevant skills, experience and financial strength • Organisation structure, staffing and training programme for CESUL SPV should be clarified early to mitigate against operational risks • CESUL SPV will be granted long-term Concession under Mozambique law • Terms and conditions of the Concession need to be confirmed, including a Transmission / Wheeling charge methodology supportive of limited recourse project financing structures (part of mandate of Financial & Legal Adviser) • Relationships to EDM (as National Power Transmission Grid Manager), HCB, Motraco and other stakeholders must be clarified and formalised to ensure timely implementation of CESUL