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Mozambique Regional Transmission Backbone Project (“CESUL”):

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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 1

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
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: : 6.5% - 7.9% (IMF estimates) : 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
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
No. Scenario: CESUL capacity CESUL transmission alternative Reference 0 MW Not applicable (new 400kV line Songo-Matambo-Inchope + reinforcement in south required) 1 CBNB 1,245 MW Single circuit 400 kV line (4 x Tern) with 550 kV equipment rating, 70% series compensation 2 MPNK 1,500 MW Double circuit 400 kV line (4 x Tern) with 550 kV equipment rating, 50% series compensation 3 MPNK + CBNB 2,745 MW Single circuit 400 kV line (4 x Tern) with 550 kV equipment rating, 50% series compensation, plus Bi-pole DC line (4 x Martin), 2,650 MW capacity 4 Add. Hydro Energy 3,536 MW Same as Scenario 3 (2nd bi-pole may be required if all generation projects implemented early) 5 Extended Hydro 4,486 MW Scenario 3 plus 2nd bi-pole (5,300 MW capacity) 6 Large Hydro & Coal 7,545 MW Scenario 3 plus 2nd bi-pole to Maputo and 3rd bi-pole terminated in South Africa 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)

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 energisation and 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 MW Stage 2: 1,325 MW

32 CESUL connections to Mozambique power system
Connection to load centres and consumers along CESUL HVAC transmission line route Connection to ‘regional’ power systems Voltage levels Transmission lines Transformer capacity Matambo 400/220 kV - 2 x 250 MVA Inchope 220 kV in-out 1 x 400 MVA Vilanculos 400/110 kV External project (not CESUL) 1 x 125 MVA Chibuto 110/33 kV External project (not CESUL) 1 x 40 MVA Moamba 400/275 kV 275/110 kV 1 x 500 MVA 1 x 63 MVA

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 HVAC - Cost Components 400 kV Foreign Local
USD (‘000) Local Total USD (‘000) HVAC Transmission Line 81% 79 672 19% HVAC Substations 92% 29 281 8% Compensation (2% of line) 0% 8 386 100% Engineering & Owner's Cost (10%) 47 120 60% 31 413 40% 78 533 Physical Contingencies (10%) 62 826 80% 15 707 20% Total HVAC Phase 1 83% 17%

35 Phase 1 HVDC costing HVDC - Cost Components Foreign Local Total
Stage 1, ± 500 kV 1325 MW Foreign USD (‘000) Local USD(‘000) Total HVDC Transmission Line 81% 72 308 19% HVDC Stations 92% 25 625 8% Compensation (2% of line) 0% 7 611 100% Engineering & Owner's Cost (10%) 42 053 60% 28 035 40% 70 088 Physical Contingencies (10%) 56 070 80% 14 018 20% Total HVDC: Stage 1 of Phase 1 83% 17% HVDC - Cost Components Stage 2, Additional 1325 MW Foreign USD (‘000) Local Total USD (‘000) HVDC Stations 92% 21 280 8% Engineering & Owner's Cost (10%) 15 960 60% 10 640 40% 26 600 Physical Contingencies (10%) 23 940 90% 2 660 10% Total HVDC: Stage 2 of Phase 1 89% 34 580 11%

36 CESUL Phase 1 – total investment costs
Summary CESUL Phase 1: 400 kV 900 MW HVAC Transmission and ± 500 kV 2,650 MW HVDC Transmission USD (’000) Total HVAC Phase 1 Total HVDC Stage 1 of Phase 1 Total HVAC + HVDC Stage 1 of Phase 1 Total HVDC Stage 2 of Phase 1 Total CESUL Phase 1 (excl. IDC, Financing costs/fees and Price Contingencies) Interest During Construction (IDC) & Financing Costs / Fees (est.) Price Contingency (10% of Project Costs excl. IDC & fees) Total Phase 1 Funding Requirement

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
Total Economic Value (Generation + CESUL) - in USD million Scenario 1 Scenario 2 Scenario 3 Phase 1 Scenario 3 Phase 1 Stage 1 only Total Economic NPV (at 10% economic discount rate) 132 1 565 1 962 1 416 CESUL Project Economic Feasibility Results Scenario 1 Scenario 2 Scenario 3 Phase 1 Scenario 3 Phase 1 Stage 1 only Project IRR 12.5 % 12.7 % 12.6 % NPV (USD 10% 184 268 402 332 Break even tariff (USc/kWh) 4.60 2.35 2.56 2.89 Note: IRR and NPV calculations are based on financial transmission tariff

41 Economic feasibility – results (cont.)
Sensitivities – Economic Unit costs (USc/kWh) – MPNK Scenario 2 Scenario 3 Phase 1 Scenario 3 Phase 1 Stage 1 only Construction cost + 20% 7.30 7.41 7.73 Construction cost + 10% 6.94 7.06 7.38 Base case (unit cost at SA border) 6.58 6.71 7.03 Construction cost - 10% 6.22 6.35 6.68 Construction cost - 20% 5.86 6.00 6.33 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 Sensitivities – Economic Unit costs (USc/kWh) – CBNB Scenario 1 Scenario 3 Phase 1 Construction cost + 40% 10.37 8.01 Construction cost + 30% 10.13 7.78 Construction cost + 20% 9.89 7.54 Construction cost + 10% 9.65 7.31 Base case (unit cost at SA border) 9.41 7.07 Construction cost - 10% 9.17 6.84 Construction cost - 20% 8.93 6.60

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
MUSD NPV Scenario 1 Scenario 2 Scenario 3 Phase 1 Scenario 3 Phase 1 Stage 1 only Total Financial NPV -39 293 389 200 Total Government take 216 793 897 826 CESUL Project Financial Results Scenario 1 Scenario 2 Scenario 3 Phase 1 Scenario 3 Phase 1 Stage 1 only Project IRR 13.0% 13.1% Equity IRR 16.0% Break-even transmission tariff (USc/kWh) 5.78 2.95 3.26 3.64

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 Sensitivities Financial Unit costs (USc/kWh) – MPNK Scenario 2 Scenario 3 Phase 1 Scenario 3 Phase 1 Stage 1 only Construction cost + 20% 9.74 9.94 10.31 Construction cost + 10% 9.25 9.45 9.82 Base case (Unit cost at SA border) 8.75 8.96 9.33 Construction cost - 10% 8.25 8.47 8.85 Construction cost - 20% 7.75 7.98 8.36 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 Sensitivities Financial Unit costs (USc/kWh) – CBNB Scenario 1 Scenario 3 Construction cost + 40% 12.34 9.46 Construction cost + 30% 12.05 9.17 Construction cost + 20% 11.76 8.89 Construction cost + 10% 11.47 8.60 Base case (Unit cost at SA border) 11.18 8.32 Construction cost - 10% 10.89 8.03 Construction cost - 20% 10.60 7.75

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 close MPNK – 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

51 Skills and training requirements
Management of CESUL Transmission Company Maintenance Management System Training Staff of new Dispatch Centres Operator training Maintenance engineers and technicians: hardware, software and communication equipment training HVDC and SVC Staff Project engineers, operation managers, control and protection specialists Engineers responsible for HVDC and SVC control and protection Technicians maintaining HVDC and SVC equipment Operators for HVDC link, remote and local control Maintenance staff of CESUL Transmission Company Maintenance engineers and technicians: fault tracing and preventive maintenance of HVAC substations, as well as live-line maintenance Key staff should be in place and be trained during Project construction phase Complementary external maintenance support by suppliers is recommended

52 Control centre requirements
New Control Centres Generation and load growth in North/Central area System expansion, load growth and interface with SAPP in South area Hence, two (2) new National Control Centres are proposed Location New NCC in (or near) Maputo SS New SNCC in (or near) Matambo SS Each CC equally equipped to be able to act as full back-up for the other Existing Maputo RCC gradually transformed to Distribution CC for Maputo area Manning Operation, each centre continuously manned with: One chief operator and two assistant operators Maintenance, each centre manned with: One chief and two assistant SCADA maintenance engineers (in SNCC two assistant only) plus two telecom technicians

53 CESUL Feasibility Study – Conclusions & Recommendations

54 CESUL Feasibility Study – Conclusions
CESUL is found to be technically and economically viable Recommended Phase 1 design is a combined HVAC (400 kV) and HVDC (500 kV bi-pole) solution with high reliability, at a total cost of US$2,119m (funding requirement of ~US$2,780m), providing a transmission capacity >3,000 MW HVAC solution will ensure interconnection of central and southern parts of national grid, allowing for economic & social development along line route Phase 1 solution is considered economically and financially robust, based on large- scale export of hydropower to South Africa, with significant revenue to GoM Phase 1 facilitates implementation of MPNK and CBNB, with both projects found to be economically and financially viable in combination with CESUL solution HVDC portion of CESUL Phase 1 can be implemented in two stages, allowing for staggered realisation of MPNK and CBNB if required (with MPNK assumed to be the first major hydropower development) Phase 1 implementation is expected to take 59 months (of which 42 months construction time) Financing requirements for CESUL Phase 1 are significant, with need for close coordination of generation and transmission developments to manage commercial and timing risks CESUL can be expanded by adding 2nd bi-pole with capacity of 2,650 MW

55 CESUL – Recommendations and Next Steps
Based on a targeted commercial operations date for MPNK by 2017, CESUL project preparation work has to commence early 2012 by progressing design, procurement and contracting arrangements In parallel, recommended legal, financial and commercial structures and arrangements need to be finalised Financial close of CESUL should be targeted for mid-2013 (to align with generation project timeframes) Early confirmation of CESUL equity sponsors (in addition to EDM) will be key to successful development Timely and coordinated engagement with South Africa (Government and Eskom) will also be essential Consideration may be given to creation of a Mozambique Joint Coordination Committee for CESUL and associated hydropower projects

56 Obrigado / Thank you for your attention!
com energia construimos futuro………

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