Public Disclosure Authorized Variable Renewable Energy Integration and Planning Results of Task 1: Dispatch Diagnosis & Task 2: Demand & Generation Forecast Analysis Public Disclosure Authorized Stakeholder Dissemination Event Islamabad, April 4, 2019 Public Disclosure Authorized x Confidential Public Restricted Internal A company of Public Disclosure Authorized
OVERVIEW Task 1 Dispatch Diagnosis Chapter 1 Presentation of results and open discussion Task 2 Demand and Generation Forecast Analysis Chapter 2 Presentation of results and open discussion 2
Comparison Approach Task 1 versus Task 2 Background: Task 1 and 3 follow different approaches due to different base and purpose VRE Modelling, Task Outcome input optimization For both generation profiles PLEXOS with existing and - Dispatch observing constraints / costs committed system Task 1: Fixed wind and Least-(variable) cost to serve - Technical and commercial constraints Dispatch PV shares demand for one year (2017, 2022) - Implications for variable costs of overall (5, 10, 14 GW…) system → variable cost reduction due to Analysis No: capex, expansion transmission (2017 & 2022) VRE Task 3: Cost assumptions Least-(all) cost for demand of 22 - Expansion paths generation sources Expansion Expansion years - Focus: VRE shares → optimal (least-cost) expansion with Exercise constraints All capex, transmission (up to 2040) (e.g. annual (but only links between zones) given assumptions for given scenarios** Expansion all sources (candidates) limits)* within limits* * Reducing complex regulatory/market frame for VRE to a set of parameters **Note: A fully fledged master plan would consider many more scenarios / sets of assumptions 3
Task 1: Dispatch Diagnosis Task 1: Dispatch Diagnosis Chapter 1 Presentation of results and open discussion ▪ Results of Dispatch Simulation ▪ Results of Scenario Analysis ▪ Dispatch Constraints for the Integration of VRE 4
Comparison of Energy Mixes Base Case (2.5 GW wind, 1.3 GW PV) 10 GW Case (5 GW Wind, 5 GW PV) Energy Mix Energy Mix PV, 1.3% PV, 4.8% STs, 6.6% STs, 6.4% Wind, 4.3% Wind, 8.3% Bagasse, 4.0% Bagasse, 3.6% CCGTs, 29.8% HPPs, 24.9% CCGTs, 32.7% HPPs, 24.8% CC DGUs, 0.0% Coal PPs, 17.5% CC DGUs, 0.1% DGUs, 0.0% Coal PPs, 13.5% DGUs, 0.0% Nuclear, 8.7% Total generation: 172.8 TWh Nuclear, 8.7% Total generation: 172.8 TWh 5
Dispatch Comparison: Winter Base Case (2.5 GW wind, 1.3 GW PV) 10 GW Case (5 GW Wind, 5 GW PV) Bagasse Coal PPs Nuclear CCGTs OCGTs STs Gas engines HPP VRE CC DGUs 6
Dispatch Comparison: Summer Base Case (2.5 GW wind, 1.3 GW PV) 10 GW Case (5 GW Wind, 5 GW PV) Bagasse Coal PPs Nuclear CCGTs OCGTs STs Gas engines HPP VRE CC DGUs 7
Reserves Overview Secondary Primary Contingency Reserve Reserve Reserve e e • 30 sec • 15 sec • 10 sec Response: • 30 min e e • 30 min • 30 sec e • 5 min • scheduled Duration: • • • • • • • • • • 1/3 largest unit • • • 1/3 largest unit • • • Largest unit • Capacity: • • • • • • • • • • • • • • 200 MW • • 200 MW 600 MW • • • • • • • • • • • • • • • Requirement will pass to 367 MW (1,100 MW), when Karachi Coastal Nuclear will be online by the end of 2021 8
Reserve Constraints: Secondary Reserve Secondary Reserve Requirement 500 450 400 Reserve Requirement [MW] 350 300 250 200 150 100 50 0 1 6 11 16 21 26 31 36 41 46 51 56 61 66 71 76 81 86 91 96 101 106 111 116 121 126 131 136 hour SecRes SecRes_SizInc SecRes_Wind SecRes_PV Secondary ResReq = ( 1 3 𝑇𝑗𝑨𝑗𝑜 _ 𝐽𝑜𝑑𝑗𝑒𝑓𝑜𝑢 ) 2 + 𝑋𝑗𝑜𝑒 _ 𝑆𝑓𝑡𝑆𝑓𝑟 𝑡𝑓𝑑−𝑛𝑗𝑜 ² + 𝑄𝑊 _ 𝑆𝑓𝑡𝑆𝑓𝑟 𝑡𝑓𝑑−𝑛𝑗𝑜 ² 9
Reserve Constraints: Contingency Reserve Contingency Reserve Requirement 1400 1200 Reserve Requirement [MW] 1000 800 600 400 200 0 1 6 11 16 21 26 31 36 41 46 51 56 61 66 71 76 81 86 91 96 101 106 111 116 121 126 131 136 hour ContRes ContRes_SizInc ContRes_Wind ContRes_PV Contingency ResReq = 𝑇𝑗𝑨𝑗𝑜 _ 𝐽𝑜𝑑𝑗𝑒𝑓𝑜𝑢 2 + 𝑋𝑗𝑜𝑒 _ 𝑆𝑓𝑡𝑆𝑓𝑟 𝑆𝑓𝑣𝑚𝑏𝑢𝑗𝑝𝑜 ² + 𝑄𝑊 _ 𝑆𝑓𝑡𝑆𝑓𝑟 𝑆𝑓𝑣𝑚𝑏𝑢𝑗𝑝𝑜 ² 10
Reserve Constraints: Primary Reserve Shortfall Shortfall Provision No large change between Base Case and 10 GW Case 11
Reserve Constraints: Primary Reserve Provisioning Bagasse Coal PPs Nuclear CCGTs OCGTs STs Gas engines HPP VRE CC DGUs No large change between Base Case and 10 GW Case 12
Reserve Constraints: Secondary Reserve Base Case Shortfall 2.5 GW Wind 1.3 GW PV Shortfall Provision 10 GW Case Provision 5.0 GW Wind 5.0 GW PV 13
Reserve Constraints: Fuel Contracts Variable Generation Costs [MUSD] Category with Fuel without Fuel difference Contracts Contracts STs 2,119.1 2,137.4 18.3 0.9% CC DGUs 20.5 21.2 0.7 3.5% DGUs 4.9 5.3 0.4 8.7% Gas engines 0.1 0.1 0.0 3.0% CCGTs 4,822.6 4,615.5 -207.1 -4.3% Nuclear 134.2 134.2 0.0 0.0% Coal PPs 1,516.5 1,588.4 71.9 4.7% 8,617.9 8,502.2 TOTAL -115.7 -1.3% Simulations for 2022 have shown that without fuel contracts the around 116 MUSD could be saved. 14
Task 1: Dispatch Diagnosis Task 1: Dispatch Diagnosis Chapter 1 Presentation of results and open discussion ▪ Results of Dispatch Simulation ▪ Results of Scenario Analysis ▪ Dispatch Constraints for the Integration of VRE 15
Scenario Analysis: Analysed Cases Installed Capacity [MW] Cases PV Wind Total VRE Base 1,286 2,450 3,736 3 GW each 3,000 3,000 6,000 5 GW each 5,000 5,000 10,000 7 GW each 7,000 7,000 14,000 9 GW each 9,000 9,000 18,000 11 GW each 11,000 11,000 22,000 Bagasse capacity: 1,300 MW within all cases 16
Scenario Analysis: Energy Mix Energy Mix per scenario 200,000 HPPs 180,000 STs 160,000 Generation [GWh] Nuclear 140,000 Coal PPs 120,000 CCGTs 100,000 CC DGUs 80,000 DGUs 60,000 PV 40,000 20,000 Wind 0 Bagasse Base 3 GW each 5 GW each 7 GW each 9 GW each 11 GW each 17
Scenario Analysis: Generation per Scenario Generation per scenario 60,000 50,000 Generation [GWh] 40,000 30,000 20,000 10,000 0 STs CCGTs CC DGUs DGUs Nuclear Coal PPs HPPs VRE of which of which Bagasse Wind PV Base 3 GW each 5 GW each 7 GW each 9 GW each 11 GW each 18
Scenario Analysis: VRE share and Curtailment Potential & Actual VRE share in energy mix 35.0% Potential VRE share 30.0% Actual VRE share 25.0% Share of VRE [%] Potential VRE share 20.0% VRE Generation & Curtailment per Scenario Actual VRE share 15.0% 60,000 30.0% Generation/Curtailment [GWh] 10.0% 50,000 25.0% Curtailment Rate [%] 5.0% 40,000 20.0% 0.0% 30,000 15.0% 0 5,000 10,000 15,000 20,000 25,000 Installed VRE capacity [MW] 20,000 10.0% 10,000 5.0% Same curtailment for wind and PV 0 0.0% Base 3 GW each 5 GW each 7 GW each 9 GW each 11 GW each VRE Generation VRE Curtailment Curtaiment Rate 19
Scenario Analysis: Variable Generation Cost Variable Generation Costs [MUSD] Category Base 5 GW each difference STs 2,119.1 2,095.5 -23.5 -1.1% CC DGUs 20.5 2.9 -17.6 -86.0% DGUs 4.9 0.6 -4.3 -86.8% Gas engines 0.1 0.0 -0.1 -100.0% CCGTs 4,822.6 4,544.0 -278.6 -5.8% Nuclear 134.2 134.0 -0.2 -0.2% Coal PPs 1,516.5 1,215.7 -300.9 -19.8% 8,617.9 7,992.6 TOTAL -625.3 -7.3% 20
Scenario Analysis: System Short Run Marginal Cost System Short-Run Marginal Cost (SRMC) 52.00 50.00 SRMC [USD/MWh] 48.00 46.00 44.00 42.00 40.00 0 5,000 10,000 15,000 20,000 25,000 Installed VRE [MW] ▪ Steep cost reduction for low VRE shares due to large savings of expensive thermal generation ▪ Declining cost reduction due to increased reserve requirements and curtailment 21
Task 1: Dispatch Diagnosis Task 1: Dispatch Diagnosis Chapter 1 Presentation of results and open discussion ▪ Results of Dispatch Simulation ▪ Results of Scenario Analysis ▪ Dispatch Constraints for the Integration of VRE 22
VRE Dispatch Constraints: Overview Commercial, Legal, Regulatory, Transmission Reserves Generation Policy • SCADA 3 • Primary • CCGTs • Take-Or-Pay Agreements • Capacity • Secondary • Coal Power limitations • Ramping • Contingency • Steam turbines • Reserves • Nuclear • Nuclear Power • Responsibilities • Bagasse • Hydro Power • Geographical • Policy • Combustion distribution framework: engines • NTDC <> DISCOs Federal <> • Bagasse Provincial legislation 23
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