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Energy Institute

Power System Planning in Pakistan Presented at REDC Electricity Market Professionals Program September 19, 2019. Energy Institute. Fiaz A. Chaudhry, Ph.D., P.Eng. Professor of Practice and Werner-Von Siemens Chair, EE Director, LUMS Enrgy Institute. Topics for Discussion.

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  1. Power System Planning in Pakistan Presented at REDC Electricity Market Professionals Program September 19, 2019 Energy Institute Fiaz A. Chaudhry, Ph.D., P.Eng. Professor of Practice and Werner-Von Siemens Chair, EE Director, LUMS Enrgy Institute

  2. Topics for Discussion Historical Perspective Planning Considerations Investment Requirements and Volume of Work Current State Assessment (2019-2025) Fuel Supply Assessment Way Forward Initiatives at LUMS Energy Institute

  3. Historical Perspective: Plans, Policies and Unbundling • National Power Plan (NPP 1994 - 2018) 1994 • Indigenous Fuel Focus (15,000 MW from Thar Coal) • Hydro Generation (Over 10,000 MW) • Bhikki, Balloki and HB Shah CCPP Sites (Gas pipeline from Central Asia) • 1994 IPP Policy 1994 • Procured 4,300 MW instead of 2,000 MW (Oil fired) • Surplus in generation from 1999 to 2004 (Circular Debt) • WAPDA was unbundled 1998 • Bad transition of Power Wing to 14 companies • New Companies didn’t perform (Remained under PEPCO’s Control) • Regulator’s (NEPRA) Role remained missing (Structural flaw) • Generation Deficit from 2006 to 2017 • No NTDC Plan (IGCEP) for 13 years • National Power System Expansion Plan (NPSEP) 2011 • Partially being followed

  4. Historical Perspective:

  5. Historical Perspective: Inefficient Structure of Power Sector NEPRA Ministry of Energy (Power Division) AEDB K-E (Vertically Integrated utility) PPIB Unbundled Power Wing of WAPDA IPPs CPPA BULK Power Consumers Other Consumers WAPDA HYDRO BULK Power Consumers DIST Central Dispatch Other Consumers GENCOs Thermal 4 Nos. DISCOS 10 Nos. NTDC TRAN Bulk Power Consumers Nuclear GEN Imports NEECA Provincial Boards Provision of Service Financial Flows

  6. Planning ConsiderationsParadigm Shift in Power System Traditional Utility • Generation • Transmission • Distribution Modern Utility • IPPs & Distributed Generation • Electric Vehicles • Information and Communication Technology • Grid Scale Batteries • Independent System and Market Operator (ISO, IMO) • Transmission Service Provider • DISCOs and Retailers

  7. Planning Considerations Planning and Procurement Process Planning Cycle Procurement Integrated Energy Plan (IEP) PPIB/AEDB/PPDB etc Technology Type Size Timing Location Procurement Plan Fuel Mix targets for energy sector Fuel Mix targets & Other Policy Options Run Procurement Process or Issue LOIs Electricity Policy Energy Forecast Indicative Generation Capacity Expansion Plan (IGCEP) (Grid Code PC 4) Demand & Energy Forecast Approval of NEPRA Long Term Forecast (Grid Code PC 4.2) Medium Term Forecast Transmission System Expansion Plan (Grid Code PC 4.1) Transmission Investment Plan (Grid Code PC 4.2)

  8. Generation Capacity Requirement Planning Considerations Daily Demand and Supply Profile Unrecovered Fixed Cost

  9. NTDC’s Load Duration Curve Example (2018-2019) Planning Considerations Generation Energy Requirement

  10. NTDC’s Demand and Supply Profile (June 2016 – March 2019) Planning Considerations NTDC System: Capacity and Energy Requirements Unrecovered Fixed Cost Base Load is about 8,000 MW

  11. Power System Development Planning Considerations Demand Side Supply Side • Base Load Generation • Technology, efficiency, least cost and highest reliability • Abundant fuel availability • Utilization assessment (must run) • Renewable energy penetration • Load Following Capability • Appropriate technology (water storage or fossil fuel) • High ramp rate • Low start-up costs • Short down time • Peaking Plants • Low CAPEX • Fast start and emergency response • Low duty cycle • Demand Side Management • Peak Shaving Opportunities • Interruptible Loads for Spinning Reserve • Off-Grid Supply Analysis • Remote area supply • Micro Grid for small communities • Net-Metering • Roof top Solar • Battery storage

  12. Planning Considerations Power System Development Key Objectives: • Available • Affordable • Reliable

  13. Meeting Key Objectives Power System Development Optimum Cost vs Adequate Reliability • Available(easily accessible, abundant and selection of appropriate technology) • Exploit Indigenous energy sources as much as possible to reduce fuel import bill • Adequate supply sources at appropriate locations Capability to meet variable load demand (Power and Energy) at all times • Affordable (cost effective generation technology, environment friendly and least T&D investment) • Least cost or optimum cost for generation resources • Least impact on environment • Correct transmission connection configurations requiring minimum T&D Investment and reducing T&D losses

  14. Meeting Key Objectives Power System Development Optimum Cost vs Adequate Reliability • Reliable (Integrated power system: Generation, Transmission and Distribution facilities) • Planning, design and implementation • Diversified energy sources to avoid dependency on particular fuel(s)/technology • Adequate redundancy of generation, transmission and distribution facilities to remain stable under forced outages (conforming to applicable performance standards) • Timely construction of facilities aligned with best utility practices • Operation of power system • Optimal generation dispatch and control • Respecting system reliability and security limits • Proactive Asset Management for maximum availability

  15. Power System DevelopmentLoad Demand Forecast (2019-2040) • Grid Connected Load Demand Forecast – Setting a Target • Medium term (8 to 10 years) • Long term (20 to 25 years) 201920252040 • Base Load (MW)8,600 11,200 28,000 • Peak Load (MW)27,26035,420 80,400 • Energy (GWh)149,400 202,500 458,000 128,000* Source: NTDC Load Forecast *CPPA-G expects maximum energy dispatch after forced load shedding due to high loss feeders

  16. Investment Requirements:Generation and Transmission Development (2015-2025) About $65 Billion CAPEX in Power Sector (2015 2025): A Serious Undertaking! Typical Unit Costs: Generation: $ 0.8 - 4 million / MW Over 90% imported material 2000 MVA 500 kV Substation: $ 100 million 750 MVA 220 kV Substation $ 40 million Over 90% imported material 500 kV Transmission Line: $ 0.5 million / km 220 kV Transmission Line: $ 0.3 million / km Over 65% imported material 4000 MW ±660 kV HVDC ML Line: $1.6 Billion G G L L G L Generation CAPEX: $50 Billion T & D CAPEX: $15 Billion

  17. Investment Requirements: Generation Development Plan (2019-2025) Year 2016 2018 2025 Installed Capacity (MW) 21,000 32,000 52,000

  18. Investment Requirements: Transmission Development Plan (2019-2025)

  19. Investment Requirements: Transmission Development Plan (2019-2025) Technological Challenges • FACTS Applications: • +450/-50 MVAR SVC at New KotLakhpat near completion • 50-60% Series compensation on Southern 500 kV lines • Shunt Compensation (3x200 MVAR SVCs) in Balochistan Area • HVDC Applications: • ±660 kV, 4000 MW HVDC Bipole Line from Matiari to Lahore (878 km) • CASA-1000 Project: ±500 kV, 1000 MW HVDC Bipole Line from TJK to PWR • 765 kV AC Technologies • 250 km long Dasu to Mansehra 765 kV Double Circuit Line • 765 kV Substation at Mansehra

  20. Current State Assessment (2019-2025) Demand and Supply Assessment Generation Capability vs Annual Peak Demand (MW) Generation Capability vs Annual Energy Demand (GWh) Monthly Surplus Capacity and Energy (%) Fuel-Wise Annual Generation Capability (GWh) Financial Impact Analysis: A few Examples Procurement of 4th RLNG 1263 MW Jhang (Trimmu) Plant High plant factor (Utilization) contracts: RLNG (66%) and Imported Coal ( 50%) Idle Capacity Payments Increasing Renewable Energy (RE) penetration to 15% or 20% by 2025 Volume of Capacity and Energy Payments 2019-2025 Operational Impact due to Higher Share of Base Load and Must Run Plants

  21. Notes: 1. Trimmu800 MW (2xGTs) will be available for dispatch in June-19 but was excluded from capability calculations in June-19 since the CoD of the plant is Nov-19 Data Source: NTDC, PPIB, AEDB, PPDB, Etc.. 2. Realistic demand assumes 2000 MW, 1500 MW, 1000 MW, 500 MW forced load shedding (high loss feeders) in 2019, 2020, 2021, 2022 respectively.

  22. Notes: 1. Trimmu800 MW (2xGTs) will be available for dispatch in June-19 but was excluded from capability calculations in June-19 since the CoD of the plant is Nov-19 Data Source: NTDC, PPIB, AEDB, PPDB, Etc.. 2. Realistic demand assumes 2000 MW, 1500 MW, 1000 MW, 500 MW average forced load shedding (high loss feeders) in 2019, 2020, 2021, and 2022, respectively.

  23. Monthly Peaks for Capacity and Energy are represented by the base line at X-axis

  24. Hydro Imp. Coal RLNG-N Nuclear Local Coal

  25. Example 1 - Capacity Decision:Procurement of 4th RLNG 1263 MW Jhang (Trimmu) Plant- Procured despite ban on imported fuel- Against recommendation of the Demand-Supply Analysis 2018-2025 report- 100,000 Million Rs annual financial commitment for 15 years (fuel supply agreement)- 7,000 Million Rs to 51,000 MRs annual savings from 2020 to 2025 that could have been realized if 4th RLNG would not have been procured Financial Impact Analysis: A few Examples

  26. Example 1: Procurement of 4th RLNG against Policy and Recommendations Two months operation only

  27. Example 1: Procurement of 4th RLNG against Policy and Recommendations Cumulative Total = 200 Billion Rupees Savings in 6 years

  28. Cumulative Total = 269 Billion Rupees Savings in 6 years

  29. Example 2 – Energy Decision:High plant factor (Utilization) contracts: RLNG (66%) and Imported Coal ( 50%)- 11,000 Million Rsto 69,000 Million Rs extra annual financial burden from 2019 to 2025 due to Must Run Contracts (out of Merit operation due to ‘Take or Pay’ contracts) - RLNG plants do not remain competitive beyond 2023 since when dispatched on Merit Order, their utilization reduces to under 30% -- 60% to 78% of annual energy demand from 2019 to 2025 is met by Must Run Plants Only, leaving a very limited space for energy dispatch under a competitive market model Financial Impact Analysis: A few Examples

  30. Example 2: Contracting RLNG (at 66%) and Imported Coal (at 50%) Projects Must Run RLNG and Imported Coal based power plants replace cheaper plants in the Merit Order resulting in higher energy payments. Cumulative Total (With Load Shedding) = 198 Billion Rupees Cumulative Total (Without Load Shedding) = 230 Billion Rupees

  31. Fuel-wise Plant Factors – Normal Energy Demand RLNG-N RLNG-N Note: Economic Merit Order (EMO) means the cheapest plant will be dispatched first

  32. Example 2: Contracting RLNG (at 66%) and Imported Coal (at 50%) Projects The increase in percentage of must run energy from committed generation projects leaves acute space for the development of competitive market.

  33. Example 3: Idle CapacityPlants dispatched at less than 1% Annual Plant Factor for Realistic Demand- Idle capacity increases from 4,700 MW to 7,900 MW from 2019 to 2025 under the realistic demand scenario that assumes forced load shedding of high loss feeders- Idle capacity payments increase from Rs 46 Billion to Rs 104 Billion from 2019 to 2025 Financial Impact Analysis: A few Examples

  34. Idle Capacity of Plants dispatched at less than 1% Annual Plant Factor for Realistic Demand Scenario Indicate excess generation capacities

  35. Idle Capacity Payments of Plants dispatched at less than 1% Annual Plant Factor for Realistic Demand Scenario Indicate additional financial burden that could have been saved through proper planning

  36. Example 4: Increasing RE Penetration to 15% or 20% by 2025Realistic Demand Scenario - Additional annual financial burden to the tune of Rs48 Billion and Rs 93 Billion in 2025 for 15% or 20% RE penetration, respectively - Share of Must Run plants increases from 78% to 85% in 2025 for 20% RE penetration Financial Impact Analysis: A few Examples

  37. Example 4: Increasing RE Penetration: from 10% to 15% or 20% Cumulative Total (15% RE) = 83 Billion Rupees Cumulative Total (20% RE) = 168 Billion Rupees

  38. Example 4: Increasing RE Penetration: from 10% to 15% or 20% Addition of More RE generation leads to very high share of Must Run energy Projects.

  39. Example 5: Volume of Capacity and Energy Payments 2019-2025Normal Demand Scenario - Capacity Payments increase from Rs854Billion to Rs1,800Billion (over 200% increase) - Capacity payment ratio in Tariff changes from 50% to 70% by 2025 - Energy payments for Must Run plants increase from Rs332 Billion to Rs526 Billion (over 158% increase) - Energy payments for Competitive Market decrease from Rs476 Billion to Rs232 Billion (becomes less than half) - Rs232 Billion volume of competitive market will shrink to only Rs 143 Billion for increasing RE penetration from 10% to 20% in 2025 Financial Impact Analysis: A few Examples

  40. Example 5: Volume of Capacity and Energy Payments 2019 - 2025

  41. Example 5: Energy Volume for Competitive Market 2019 - 2025 If additional renewable is added to meet 20% RE target in 2025, there is a further decrease in volume of competitive market. Total energy/variable prices shown above do not include the capacity charges associated with the generation projects.

  42. Example 6: Operational Impact due to Higher Share of Base Load and Must Run Plants:Normal Demand Scenario - Beyond Jan 2023, total energy demand can be met by Must Run and Base Load plants - Some of the Base Load plants will have to be curtailed in 2025 - Meaning selection of generation technology and commitment of high plant factors (50% for imported coal and 66% for RLNG) are arbitrary and not based on any analysis – Not optimal decision. Financial Impact Analysis: A few Examples

  43. Example 6: Higher Share of Base Load and Must Run Plants Beyond Jan 2023, very few peaking plants are in operation and total energy demand is mostly met by Must Run and Base Load plants. In addition to that, some of the base load plants will have to be curtailed.

  44. Example 7: Implications of Transmission Interconnection Decisions • 5 GW of Base Load Power Plants near the Load Centers were connected at 500 kV • 1320 MW coal and more than 3600 MW RLNG – All base load plants • Higher stress at 500 kV network • Over loading of 550/220 kV transformers at Gatti and Lahore • Furnace Oil plants are operated out of merit to mitigate overloading of 500/220 kV transformers • Financial Implications • Higher transmission infrastructure cost at 500 kV than at 220 kV • Higher Energy Cost due to out of merit operation of expensive FO plants • Reduced life of 500/220 kV Transformers • Inability to meet RLNG 66% Take or Pay plant factorsdue to reduced dispatch of RLNG plants • High RLNG demurrages due to low regasification rate to avoid high line pack • Future Implications • Most of the planned generation to be interconnected at 500 kV • More than 10 GW hydro generation from North • 4 GW of thermal power from South to be connected at 500 kV AC via HVDC • More Stress on 500 kV Network and 500/220 kV Transformers • May cause Underutilization of HVDC infrastructure

  45. Fuel Supply Assessment Fuel Supply Assessment (2019-2025) Generation Dispatch Situation 2019 – Normal Demand Generation Dispatch Situation 2019 – Low Demand Generation Dispatch Situation 2019 – High Demand RLNG Forecast Scenarios (2019) – Merit Order Operation RLNG Forecast (Sep 2019) after Curtailing Imported Coal Increase in Energy Payments as a Result of Power Curtailment (Sep 2019) Generation Dispatch Situation 2025 – Normal Demand Fuel-wise Plant Factors 2019-2025 – Normal Demand Fuel-wise Plant Factors 2019-2025 with 10 GW Distributed Generation Solar PV Installed

  46. Generation Dispatch Situation 2019 – Normal Demand

  47. Generation Dispatch Situation 2019 – Low Demand

  48. Generation Dispatch Situation 2019 – High Demand

  49. RLNG Forecast Scenarios (2019)

  50. RLNG Forecast (Sep 2019)After Curtailing Imported Coal

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