2019 Integrated Resource Plan Stakeholder Workshop #3

Transcription

1 2019 Integrated Resource Plan Stakeholder Workshop #3 Updated Slide Deck February 19, 2019 February 21, 2019 I&M Main Office 110 East Wayne Street Fort Wayne, IN 46802

2 TO ACCESS THIS EVENT: 1. Go to: 2. Choose to Enter as a Guest and type your name in the space provided. Then click on Enter Room 3. You will then be prompted to enter your EXTERNAL direct dial phone number: After entering your external # beginning with a 1 (ex ), hit the "Call My Phone" button If you have trouble with this connection, you can dial into the audio conference by using the following dial-in numbers. I&M Internal: Toll Free: Passcode: # 2

3 GROUND RULES Ground Rules Everyone will be heard and have the opportunity to contribute Please be respectful of all opinions and/or proposals Stick to the time allotted Housekeeping Safety emergency exits Restroom locations Lunch logistics Please silence phones and if you must take a call, please step outside the room to do so 3

4 I&M s Key Priorities for the 2019 IRP Stakeholder Engagement Continuous Improvement of IRP Processes Continued DSM/EE Advancement/Deployment Continued Renewables Deployment Continued Support for CHP and DG Opportunities Understanding of Rockport Disposition Options Develop a reasonable preferred resource plan that balances multiple factors such as cost effectiveness, reliability, portfolio risk and uncertainty to meet the future energy and capacity needs of I&M s customers Develop an IRP that meets the requirements of 170 IAC 4-7 (IURC draft proposed rule) and MCL 460.6t(4) 4

5 Goals for Today Today s Goals: Discuss IRP Portfolios, Scenarios, Sensitivities & Initial Model Results Discuss Stakeholder Feedback Discuss Current IRP Inputs 5

6 Updated Stakeholder Process Meeting Date Topic February 15, Northeast Indiana Innovation 2018 IRP Kick-off Meeting - Stakeholder Process & Center Scenario Discussion 3211 Stellhorn Road Fort Wayne, IN April 11, 2018 Barnes & Thornburg 11 S. Meridian St. Indianapolis, IN February 21, 2019 I&M Main Office 110 East Main St. Ft. Wayne, IN March 22, 2019 Minnetrista Gathering Place 1200 N. Minnetrista Pkwy. Muncie, IN Considerations for Modeling DSM in the 2018 IRP & Update on the IRP Updated Inputs, Portfolios, Scenarios & Initial Modeling Results Modeling Results, Preferred Portfolio Discussion & Final Inputs 6

7 Stakeholder Comments I&M continues to maintain a comment form on its webpage Please submit comments by February 27, 2019, so I&M will have time to consider your input before the final stakeholder meeting on March 22, 2019 Specifically, I&M welcomes comments on: Fundamental Commodity Forecast Pricing Assumptions Load Forecast Cost of Technology Options DSM/Energy Efficiency assumptions Sensitivity cases Portfolios to Consider Other I&M will continue to post stakeholder meeting minutes and comments received through the website 7 DRAFT: Results published for I&M s Indiana IRP 3 rd Stakeholder Meeting: February 13, 2019

8 Opening Remarks Today s Agenda Stakeholder Feedback Summary IRP Portfolios, Scenarios, Sensitivities & Initial Model Results Stakeholder Feedback IRP Inputs Review Load Forecasting Fundamental Commodity Forecasting DSM/EE Assumptions Cost of Resource/Technology Options Next Steps 8

9 Opening Remarks Today s Agenda Stakeholder Feedback Summary IRP Portfolios, Scenarios, Sensitivities & Initial Model Results Stakeholder Discussion IRP Inputs Review Load Forecasting Fundamental Commodity Forecasting DSM/EE Assumptions Cost of Resource/Technology Options Next Steps 9

10 Opening Remarks Today s Agenda Stakeholder Feedback Summary IRP Portfolios, Scenarios, Sensitivities & Initial Model Results Stakeholder Discussion IRP Inputs Review Load Forecasting Fundamental Commodity Forecasting DSM/EE Assumptions Cost of Resource/Technology Options Next Steps 10

11 Stakeholder Feedback Summary The Company has provided and posted responses to Stakeholder comments on its IRP website Some on-going discussions include: DSM/EE Modeling Carbon-free & increased DSM/EE Scenario Lower Renewable Cost Sensitivity Short-term versus Long-Term Capacity Replacement Reporting of Emission data Quantify Rockport Options The model continues to be available to stakeholders and two training session has been conducted with further sessions planned. You can continue to submit concerns at the following website: 11

12 Opening Remarks Today s Agenda Stakeholder Feedback Summary IRP Portfolios, Scenarios, Sensitivities & Initial Model Results Stakeholder Discussion IRP Inputs Review Load Forecasting Fundamental Commodity Forecasting DSM/EE Assumptions Cost of Resource/Technology Options Next Steps 12

13 Portfolio Assumptions I&M Going In Capacity Position (MW) Upcoming Key Milestones & IRP Planning Assumptions: 2022 Rockport 2 Lease Expires 2028 Rockport 1 Retires 2034 Cook 1 Retires 2037 Cook 2 Retires The Company is Short capacity beginning in 2022, which will provide an opportunity to invest in alternative renewable and supply- & demand-side resources in the future 13

14 Portfolio Assumptions I&M Going In Energy Position Upcoming Key Milestones & IRP Planning Assumptions: 2022 Rockport 2 Lease Expires 2028 Rockport 1 Retires 2034 Cook 1 Retires 2037 Cook 2 Retires Currently, the Company is Long energy through 2028, after this, new resources that provide both economic energy and capacity will have an increasing importance to the Company and its future resource mix 14

15 Initial Scenarios & Portfolios Considered Initially, the Company has considered 21 different scenarios of varying commodity pricing conditions, load conditions and existing and future resource conditions. Today s Presentation is a high level overview of these results and an opportunity to get stakeholder feedback. Group 2 A - Status Quo cases, except 7A and Group 4 cases are included in these additional slides. Type Group 1 Commodity Pricing Scenarios Group 2 & 2A Rockport Scenarios Group 3 IRP Scenarios Group 4 Load Scenarios Group 5 EE Scenarios Name Commodity Pricing Conditions Load Conditions 1. Base Mid Base 2. High Band High Band Base 3. Low Band Low Band Base 4. Status Quo No Carbon Base 5. Case 5 & 5A (RP1 Retires 12/2028; RP2 No Lease Ext.) 6. Case 6 & 6A (RP1 FGD 1/2026 & Retires 12/2044; RP2 No Lease Ext.) 7. Case 7 & 7A (RP1 FGD 1/2029 & Retires 12/2044; RP2 No Lease Ext.) 8. Case 8 &8A (RP1 Retires 1/2025; RP2 Lease Extended, FGD 1/2029, & Retires 12/2048) Mid/Status Quo (A) Mid/Status Quo (A) Mid/Status Quo (A) Mid/Status Quo (A) Base Base Base Base 9. Transitional Mid Base Year Peaking Mid Base Year Peaking Mid Base 12. High Renewables Mid Base 13. Low Load Mid Low 14. High Load Mid High 15. Low Load Low Band Low 16. High Load High Band High 17. EE Decrement Method Mid Base Updated Slide 15

16 Summary of Analyses Comparing the Base Optimized Portfolio (Case 1), Transitional Portfolio (Case 9), and High Renewables Portfolio (Case 12): o Cumulative Present Worth Cost (CPW) of these portfolios through 2048 is roughly the same. o High Renewables Portfolio post-2048 costs ( end-effects ) are lower than Base and Transitional portfolios. o Near term cost of High Renewables Portfolio are high relative to Base and Transitional portfolios. o High Renewables Portfolio has higher energy position (MWH generated vs. I&M Load) than other 2 portfolios. o High Renewables Portfolio reduces CO 2 relative to all other portfolios. 16

17 Summary of Analyses 17

18 Indicative Cost Difference (%) Vs Base Plan (Case 1) Compared to Case 1, High Renewable (Case 12) has higher costs through 2030, while Transitional Plan (Case 9) is close to or slightly lower cost than the optimal plan (Case 1). Updated Slide 18

19 Summary of Analyses Component Detailed System Revenue and Cost Summary Load Cost Fuel Costs Emission Costs Existing System FOM + OGC (Incremental) Fixed + Variable + Lease Costs (Incremental) Capital + Renewable + VVO Program Costs Contract (Revenue)/Cost Less: Market Revenue GRAND TOTAL, Net Utility Costs (Cost over/under) Case 1 Base Optimal Case 1- Base - RP1 Retires 1/29 & RP2 No Lease Extension Cumulative Present Worth $000 (2019$) Utility CPW ,835,307 5,506, , ,228 1,888,759 5,541,135 (84,139) 18,983,560 8,800,938 CPW of End Effects beyond ,946,039 TOTAL Utility Cost, Net CPW (2019$) 11,746,978 Case 9 - Transitional Cumulative Present Worth $000 (2019$) Utility CPW ,835,307 5,254, , ,228 1,916,736 5,735,221 (84,139) 18,937,868 8,793,238 (7,701) CPW of End Effects beyond ,991,693 45,654 TOTAL Utility Cost, Net CPW (2019$) 11,784,931 37,953 Case 12- High Renewables Cumulative Present Worth $000 (2019$) Utility CPW ,835,307 2,447, , ,228 2,172,908 9,342,149 (84,139) 19,515,953 8,803,974 3,036 CPW of End Effects beyond ,456,049 (489,990) TOTAL Utility Cost, Net CPW (2019$) 11,260,023 (486,954) 19

20 Preliminary Preferred Plan Considerations Primarily considering Case 9* optimization results with the following additions: Include 100MW of Storage by 2030 Include Micro/Mini-Grid deployment, up to 100MW, by 2030 Include Residential Energy Efficiency & Demand Response * Case 9 includes 1,700MW of Solar by 2031, 2,100MW of Wind by 2033 and 1,100MW of NGCC in 2028 Updated Slide 20

21 Group 1 Optimization Summary Optimized portfolios were created by the Plexos model under 4 pricing scenarios. Developing optimized plans under different pricing scenarios provides insight into how resources provide benefits under various commodity price futures. Changes in commodity prices did not result in a significant difference in the amount of EE, Market Purchases, or Natural Gas generation. Renewables are selected in all scenarios, but more wind selected in Base and High Band scenarios. Solar resources fully subscribed at 1,700MW by 2038 in all scenarios. 21

22 Group 1 Capacity Additions CC & STMP Cumulative Capacity Additions - MW Combined Heat and Power, Energy Storage, Demand Response & Combustion Turbine resources were not selected by the model in the Base, High, Low, or Status Quo optimizations. * The description of Short-Term Market Purchase is included in the inputs discussion. acity will have an increasing importance to the Company and its future resource mix 22

23 Group 1 Capacity Additions Wind & Solar Cumulative Capacity Additions - MW 23

24 Group 1 Capacity Additions EE & VVO Cumulative Capacity Additions - MW 24

25 DSM/Energy Efficiency Group 1 Results Discussion Cases within Group 1 produced similar results Cumulative Non-Degraded Energy Efficiency results Case 1 Case 1 Bundles Selected Residential Water Heating Residential Behavioral Commercial VFD Com. Building Management System Commercial HVAC Commercial Outdoor Lighting Commercial Indoor Lighting Industrial Measures Updated Slide 25

26 Group 1 Emissions Total System CO2 Emissions in Tons (000s) Total System CO2 Emissions in lb/mwh Case 1 Case 2 Case 3 Case 4 Case 1 Case 2 Case 3 Case ,488 12,518 9,559 12, ,616 12,969 11,855 12, ,514 12,797 11,638 12, ,768 12,645 12,369 12, ,044 12,938 6,860 6, ,043 7,589 7,459 7, ,581 7,557 7,413 7, ,555 7,499 6,467 6, ,579 6,539 6,488 6, ,463 7,796 8,312 8, ,378 7,743 3,254 3, ,392 2,758 3,275 3, ,297 2,655 3,139 3, ,381 2,705 3,232 3, ,408 2,764 3,316 3, ,632 4,516 4,505 4, ,690 4,574 4,616 4, ,629 4,489 4,621 4, ,388 6,109 6,352 6, ,723 6,451 6,650 6, In 2038, CO 2 emissions are approximately 50% of 2019 expected values. SO 2 and NOx reductions are forecasted to be over 90% for the existing resources 26

27 Group 2 Scenarios Overview Group 2 (Rockport Scenarios) Base 5. Case 5 Rockport Unit 1 (RP1) Retires EOY 2028 & Rockport Unit 2 (RP2) No Lease Extension 6. Case 6 RP1 installs FGD in Jan. 2026, retires EOY 2044 & Rockport Unit 2 (RP2) No Lease Extension 7. Case 7 RP1 installs FGD in Jan. 2029, retires EOY 2044 & Rockport Unit 2 (RP2) No Lease Extension 8. Case 8 RP1 Retires EOY 2025 & RP2 Lease Extended + FGD in Jan. 2029, retires EOY

28 Group 2 Optimization Summary The Rockport portfolios considered support the Company s current Case 1 planning assumptions for Rockport In all Rockport portfolios considered, Short-Term Market Purchases, Natural Gas Combined Cycle and Renewable resources provide economic capacity and energy at lower costs under Base Commodity pricing The Company continues to analyze these portfolios under Status Quo Commodity pricing and will provide these results at the next Stakeholder meeting 28

29 Group 2 Capacity Additions STMP & CC Cumulative Capacity Additions - MW 29

30 Group 2 Capacity Additions Wind & Solar Cumulative Capacity Additions - MW 30

31 Group 2 Capacity Additions EE & VVO Cumulative Capacity Additions - MW 31

32 Group 2 Emissions Total System CO2 Emissions in Tons (000s) Total System CO2 Emissions in lb/mwh Case 5 Case 6 Case 7 Case 8 Case 5 Case 6 Case 7 Case ,488 12,488 12,488 12, ,616 12,616 12,616 12, ,514 12,514 12,514 12, ,768 12,768 12,768 12, ,044 6,974 7,000 12, ,043 7,606 7,608 12, ,581 7,005 7,625 13, ,555 9,947 6,583 9, ,579 10,547 6,571 9, ,463 9,597 6,564 7, ,378 10,360 10,341 9, ,392 9,715 9,717 9, ,297 10,401 10,501 9, ,381 9,644 9,652 8, ,408 10,472 10,456 9, ,632 11,211 11,209 10, ,690 11,840 11,847 11, ,629 10,367 10,372 10, ,388 13,532 13,609 12, ,723 12,929 12,858 11, In 2038, Case 5 CO 2 emissions are approximately 50% of 2019 expected values. SO 2 is reduced 97% in Case 5 and ~80% in Cases 6, 7 & 8. NOx is reduced 92% in Case 5 and ~75%in Cases 6, 7 & 8. 32

33 Group 2 Scenarios - Economic Comparison Detailed System Revenue and Cost Summary Component Load Cost Fuel Costs Emission Costs Existing System FOM + OGC (Incremental) Fixed + Variable + Lease Costs (Incremental) Capital + Renewable + VVO Program Costs Contract (Revenue)/Cost Less: Market Revenue GRAND TOTAL, Net Utility Costs (Cost over/under) Case 1 Base Optimal Case 5 - RP1 Retires 1/29 & RP2 No Lease Extension Cumulative Present Worth $000 (2019$) Utility CPW ,835,307 5,506, , ,228 1,888,759 5,541,135 (84,139) 18,983,560 8,800,938 CPW of End Effects beyond ,946,039 TOTAL Utility Cost, Net CPW (2019$) 11,746,978 Case 6- RP1 FGD 1/26 & RP2 No Lease Extension Cumulative Present Worth $000 (2019$) Utility CPW ,835,307 5,096,878 1,620, ,168 1,827,324 5,989,263 (84,140) 19,819,347 9,001, ,541 CPW of End Effects beyond ,056, ,477 TOTAL Utility Cost, Net CPW (2019$) 12,057, ,018 Case 7- RP1 FGD 1/29 & RP2 No Lease Extension Cumulative Present Worth $000 (2019$) Utility CPW ,835,307 5,059,258 1,526, ,764 1,819,194 5,846,487 (84,140) 19,609,586 8,957, ,580 CPW of End Effects beyond ,090, ,573 TOTAL Utility Cost, Net CPW (2019$) 12,048, ,152 Case 8- RP1 Retires & RP2 Least Extended + 1/29 FGD Cumulative Present Worth $000 (2019$) Utility CPW ,835,307 5,662,733 1,738, ,142 2,880,991 6,034,649 (84,139) 20,800,760 9,899,791 1,098,853 CPW of End Effects beyond ,869,733 (76,306) TOTAL Utility Cost, Net CPW (2019$) 12,769,524 1,022,546 33

34 Group 2A Scenarios Overview Group 2A (Rockport Scenarios) Status Quo Case 5A - Rockport Unit 1 (RP1) Retires EOY 2028 & Rockport Unit 2 (RP2) No Lease Extension Case 6A - RP1 installs FGD in Jan. 2026, retires EOY 2044 & Rockport Unit 2 (RP2) No Lease Extension Case 7A - RP1 installs FGD in Jan. 2029, retires EOY 2044 & Rockport Unit 2 (RP2) No Lease Extension Case 8A - RP1 Retires EOY 2025 & RP2 Lease Extended + FGD in Jan. 2029, retires EOY 2048 Updated Slide 34

35 Group 2A Optimization Summary Case 5A, Optimized Status Quo, selects more CC capacity than Cases 6A and 8A that include a scrubbed Rockport unit All of these cases have very similar Wind, Solar and DSM capacity builds Emissions are lowest in Case 5A due to the assumed retirement of both Rockport units Case 5A has the lowest CPW when compared to Cases 6A and 8A Results for Case 7A are currently under development Updated Slide 35

36 Group 2A Capacity Additions STMP & CC Cumulative Capacity Additions - MW Updated Slide 36

37 Group 2A Capacity Additions Wind & Solar Cumulative Capacity Additions - MW Updated Slide 37

38 Group 2A Capacity Additions EE & VVO Cumulative Capacity Additions - MW Updated Slide 38

39 Group 2A Emissions Total System CO2 Emissions in Tons (000s) Total System CO2 Emissions in lb/mwh Case 5A Case 6A Case 8A Case 5A Case 6A Case 8A ,325 12,300 11, ,569 12,553 12, ,468 12,469 12, ,702 12,735 12, ,946 7,453 12, ,567 7,570 12, ,510 6,959 12, ,527 9,278 9, ,537 9,472 9, ,205 9,034 7, ,139 9,311 8, ,205 9,431 8, ,117 10,188 9, ,207 9,508 8, ,279 10,329 9, ,417 10,981 10, ,550 11,745 11, ,565 10,326 10, ,212 13,404 12, ,425 12,706 11, Updated Slide 39

40 Group 2A Scenarios - Economic Comparison Detailed System Revenue and Cost Summary Load Cost Fuel Costs Emission Costs Existing System FOM + OGC (Incremental) Fixed + Variable + Lease Costs (Incremental) Capital + Renewable + VVO Program Costs Contract (Revenue)/Cost Less: Market Revenue GRAND TOTAL, Net Utility Costs Case 5A - RP1 Retires 1/29 & RP2 No Lease Extension Cumulative Present Worth $000 (2019$) Utility CPW ,151,819 5,333, , ,228 1,881,861 4,319,538 (17,755) 15,431,072 8,805,538 CPW of End Effects beyond ,883,443 TOTAL Utility Cost, Net CPW (2019$) 11,688,981 (Cost over/under) Case 4 Status Quo Optimal Case 6A - RP1 FGD 1/26 & RP2 No Lease Extension Cumulative Present Worth $000 (2019$) Utility CPW ,151,819 5,628, , ,168 1,803,788 4,671,926 (16,467) 16,016,297 9,278, ,727 CPW of End Effects beyond ,987, ,592 TOTAL Utility Cost, Net CPW (2019$) 12,265, ,319 Case 8A - RP1 Retires & RP2 Least Extended + 1/29 FGD + 1/39 Retires Cumulative Present Worth $000 (2019$) Utility CPW ,151,819 6,350, , ,142 2,845,521 4,604,560 (16,468) 16,954,370 10,122,963 1,317,425 CPW of End Effects beyond ,843,768 (39,674) TOTAL Utility Cost, Net CPW (2019$) 12,966,731 1,277,751 Updated Slide 40

41 Group 3 Scenarios Overview Group 3 Scenarios (Case 1 Assumptions) 9. Transitional Portfolio Meet energy demand through economically selected resources including universal solar, wind, storage and DSM/EE programs CT capacity & Short-Term Market Purchase (STMP) made available beginning in 2022, NGCC beginning in Year Peaking Plan from Rockport 2 Lease end-date Meet energy demand through economically selected resources including universal solar, wind, storage and DSM/EE programs CT capacity & STMP made available beginning in 2022, NGCC beginning in Year Peaking Plan from Rockport 2 Lease end-date Meet energy demand through economically selected resources including universal solar, wind, storage and DSM/EE programs CT capacity & STMP made available beginning in 2022, NGCC beginning in High Renewables Plan Double Wind & Solar + Peaking Plan 2 times Wind potential at 4,200 MW 2 times Solar potential at 3,400 MW CT capacity & STMP available for conventional supply-side options 41

42 Group 3 Optimization Summary Resource selection for Group 3 scenarios remains relatively consistent, except where the timing of NGCC resources were varied. Renewables selection is consistent across this Group, except for the High Renewables portfolio that allows for double the amounts of wind and solar resources to be selected. DSM resource selection is consistent across the entire Group. Significant CO 2 reductions are observed in this Group, with the highest in the High Renewables portfolio. Increased cost for delaying the Combined Cycle are significant past The High Renewables portfolio receives significant financial benefits due to favorable economics in the end-effects period, this is due to ever increasing market energy prices and renewables having a fixed production cost. 42

43 Group 3 Capacity Additions STMP, CC, & CT Cumulative Capacity Additions - MW 43

44 Group 3 Capacity Additions Wind & Solar Cumulative Capacity Additions - MW 44

45 Group 3 Capacity Additions EE & VVO Cumulative Capacity Additions - MW 45

46 Group 3 Emissions Total System CO2 Emissions in Tons (000s) Total System CO2 Emissions in lb/mwh Case 9 Case 10 Case 11 Case 12 Case 9 Case 10 Case 11 Case ,488 12,488 12,488 12, ,616 12,616 12,616 12, ,514 12,514 12,514 12, ,768 12,768 12,768 12, ,044 7,051 7,051 7, ,043 7,050 7,050 7, ,006 7,015 7,015 7, ,987 5,996 5,996 5, ,996 6,004 6,004 6, ,829 5,953 5,953 5, , , , , , ,632 2, ,690 2, ,629 2, ,388 5,203 3, ,723 5,475 3,569 1, In 2038, CO 2 emissions are approximately 50% of 2019 expected values for the Case 9 portfolio, while Cases 10, 11 & 12 reduce CO 2 emissions further. SO 2 and NOx reductions for the existing fleet are forecasted to be over 90% of 2019 values. 46

47 Group 3 Scenarios - Economic Comparison Detailed System Revenue and Cost Summary Component Load Cost Fuel Costs Emission Costs Existing System FOM + OGC (Incremental) Fixed + Variable + Lease Costs (Incremental) Capital + Renewable + VVO Program Costs Contract (Revenue)/Cost Less: Market Revenue GRAND TOTAL, Net Utility Costs (Cost over/under) Case 1 Base Optimal Case 1- Base - RP1 Retires 1/29 & RP2 No Lease Extension Cumulative Present Worth $000 (2019$) Utility CPW ,835,307 5,506, , ,228 1,888,759 5,541,135 (84,139) 18,983,560 8,800,938 CPW of End Effects beyond ,946,039 TOTAL Utility Cost, Net CPW (2019$) 11,746,978 Case 9 - Transitional Cumulative Present Worth $000 (2019$) Utility CPW ,835,307 5,254, , ,228 1,916,736 5,735,221 (84,139) 18,937,868 8,793,238 (7,701) CPW of End Effects beyond ,991,693 45,654 TOTAL Utility Cost, Net CPW (2019$) 11,784,931 37,953 Case Year Peaking Plan, CC in 2034 Cumulative Present Worth $000 (2019$) Utility CPW ,835,307 4,036, , ,228 1,917,051 5,729,612 (84,139) 17,000,624 9,314, ,679 CPW of End Effects beyond ,082, ,590 TOTAL Utility Cost, Net CPW (2019$) 12,397, ,269 Case Year Peaking Plan, CC in 2037 Cumulative Present Worth $000 (2019$) Utility CPW ,835,307 3,380, , ,228 1,938,783 5,841,391 (84,139) 16,113,644 9,569, ,908 CPW of End Effects beyond ,214, ,212 TOTAL Utility Cost, Net CPW (2019$) 12,784,098 1,037,120 Case 12- High Renewables Cumulative Present Worth $000 (2019$) Utility CPW ,835,307 2,447, , ,228 2,172,908 9,342,149 (84,139) 19,515,953 8,803,974 3,036 CPW of End Effects beyond ,456,049 (489,990) TOTAL Utility Cost, Net CPW (2019$) 11,260,023 (486,954) 47

48 Group 4 Optimization Summary The following Group 4 slides, compare the various Group 4 cases to the appropriate Group 1 cases Updated Slide 48

49 Groups 1 & 4 (Base Commodity Pricing) Capacity Additions STMP & CC Cumulative Capacity Additions - MW Updated Slide 49

50 Groups 1 & 4 (Base Commodity Pricing) Capacity Additions Wind & Solar Cumulative Capacity Additions - MW Updated Slide 50

51 Groups 1 & 4 (Base Commodity Pricing) Capacity Additions EE & VVO Cumulative Capacity Additions - MW Updated Slide 51

52 Groups 1 & 4 (Low Commodity Pricing) Capacity Additions STMP & CC Cumulative Capacity Additions - MW Updated Slide 52

53 Groups 1 & 4 (Low Commodity Pricing) Capacity Additions Wind & Solar Cumulative Capacity Additions - MW Updated Slide 53

54 Groups 1 & 4 (Low Commodity Pricing) Capacity Additions EE & VVO Cumulative Capacity Additions - MW Updated Slide 54

55 Groups 1 & 4 (High Commodity Pricing) Capacity Additions STMP & CC Cumulative Capacity Additions - MW Updated Slide 55

56 Groups 1 & 4 (High Commodity Pricing) Capacity Additions Wind & Solar Cumulative Capacity Additions - MW Updated Slide 56

57 Groups 1 & 4 (High Commodity Pricing) Capacity Additions EE & VVO Cumulative Capacity Additions - MW Updated Slide 57

58 EE Degradation (Value of Load Reduction) Model Results Case Plan Cost CPW ($000) Avoided Capacity & Energy Cost CPW over Case 1 ($000) Annual Levelized Avoided Cost ($000) Case 1 - No Decrement to Customer Energy 11,867,769 NA NA Case 1A - Decrement to Residential Load % 11,844,666 (23,103) (4,440) Case 1B - Decrement to Industrial Load % 11,802,903 (64,866) (7,211) Case 1C - Decrement to Commercial Load - 0.5% 11,773,846 (93,923) (9,401) The Avoided Cost CPW dollar values do not include cost to achieve the Decrement levels Results provide insight into the magnitude of DSM program costs that may be justified to reach these Decrement levels 58

59 Today s Agenda Opening Remarks Stakeholder Feedback Summary IRP Portfolios, Scenarios, Sensitivities & Initial Model Results Stakeholder Discussion & Feedback IRP Inputs Review Load Forecasting Next Steps 59

60 Today s Agenda Opening Remarks Stakeholder Feedback Review IRP Portfolios, Scenarios, Sensitivities & Initial Model Results IRP Inputs Review Load Forecasting Next Steps 60

61 I&M Load Forecast Summary I&M s load has been relatively flat over the past decade and is not expected to grow over the next decade. Compound Growth Rates Peak Historical 10-Yr ( ) -0.1% Forecast 10-Yr ( ) -0.4% Energy Historical 10-Yr ( ) -0.3% Forecast 10-Yr ( ) -0.5% 61

62 Economic Outlook. Source: Moody s Analytics Gross Regional Product for the I&M service territory is expected to grow in line with the US over the next decade. However, growth in population and non-farm employment are expected to lag the US. 62

63 Load Growth by Jurisdiction I&M Long Term Sales Growth Rates by Jurisdiction 0.5% 0.0% -0.5% -1.0% -1.5% -2.0% -2.5% -3.0% -3.5% -4.0% -4.5% 0.2% 0.0% -0.2% -0.1% -0.6% Historical 10-Yr ( ) Forecast 10-Yr ( ) -3.9% IN Retail MI Retail Wholesale There are a number of wholesale contracts that are expiring in the next couple of years that are not expected to renew (-308 MW in total). Partially offsetting the decline in wholesale load are a number of announced Industrial expansions in IN and MI (+15 MW in total). 63

64 . Annual GWh Sales 9,000 8,000 7,000 6,000 5,000 4,000 3,000 2,000 1,000 0 Residential Industrial Retail Load Growth by Class I&M GWh Sales (Weather Normalized History & Forecast) Commercial Historical ( ) Forecast ( ) Residential -0.8% 0.0% Commercial -0.7% 0.1% Industrial 0.4% 0.3% The Residential and Commercial class sales are expected to be essentially flat over the next decade while Industrial sales are expected to see modest growth. 64

65 Adjustments for DSM Programs The load forecast was adjusted for company sponsored DSM/EE programs that are in the current plan filed with the Commission (through 2020). Long term DSM/EE amounts are optimized in the IRP modeling (using Plexos). 65

66 I&M Load Forecast Scenarios Based on stakeholder request, an extreme weather scenario was developed assuming cooling degree days increase by 2% per year. The Extreme Weather scenario was within the High and Low Economic scenario boundaries that are evaluated in the IRP modeling. 66

67 Today s Agenda Opening Remarks Stakeholder Feedback Review IRP Portfolios, Scenarios, Sensitivities & Initial Model Results IRP Inputs Review Fundamental Commodity Forecasting Next Steps 67

68 Fundamentals Forecast Process: Forecast requires iterative solution to satisfy all constraints Input Aurora Run Output Fuel Forecast Load Forecast Emissions Forecast LT Capacity Expansion Yearly Runs (8760 hrs dispatch) Generate Reports Emission Constraints Fuel Burn Market Price Capital Costs Existing Unit Modifications Recycle 68

69 Fundamentals Forecast Process: 30 Year Normal Weather vs Actual Weather 69

70 Analysis and Insight The Long-Term Forecast. The centerpiece is the Reference ( Base ) Case, it contains: o Objective input assumptions and output analysis. o Fuel sensitivities used to portray cause-and-effect and provide regulatory bounding of power prices. o Benchmarking to the EIA and other retained consultancies. Scenarios Collaborative scenarios o Distributed as a supplement to the Reference ( Base ) Case. o Highlights internal concerns and observations that deviate from sensitivities in that contributing/concurring factors must harmonize. 70

71 Fundamentals Fundamental Forecast 2018H2: Base Fundamental Forecast High, Low and Status Quo Carbon Burden Effective 2028 Future Considerations: Natural Gas Fundamentals Evolving State of Carbon Mitigation 71

72 Commodity Prices (2018 Forecast Nominal $) (Prices are not location specific but reflect trading hubs) 72 DRAFT: Results published for I&M s Indiana IRP 3 rd Stakeholder Meeting: February 13, 2019

73 Commodity Prices (2018 Forecast Nominal $) (Prices are not location specific but reflect trading hubs) 73 DRAFT: Results published for I&M s Indiana IRP 3 rd Stakeholder Meeting: February 13, 2019

74 Scenarios & Sensitivities Scenarios encapsulate future states in a way that all input variables are simultaneously plausible. Examples include o low growth or o boom economy Sensitivities change a single variable so that its impact within a scenario can be understood. Examples include: o carbon tax, o high gas prices, o low gas prices Sensitivities are not the basis for portfolio construction. 74

75 Today s Agenda Opening Remarks Stakeholder Feedback Review IRP Portfolios, Scenarios, Sensitivities & Initial Model Results IRP Inputs Review DSM/EE Inputs Next Steps 75

76 Residential Commercial / Industrial Planning assumptions for I&M IRP development Energy Efficiency Bundle AP = Achievable Potential LCOE ($/MWh) Installed Cost ($/kwh) Yearly Potential Savings (MWh) Yearly Potential Savings (MWh) Yearly Potential Savings (MWh) Yearly Potential Savings (MWh) R - HVAC Equipment - AP $88.01 $0.60 8,759 10,256 11,790 12, Air Source Heat Pump, Geothermal Heat Pump, Ductless Minisplits, R - HVAC Equipment - HAP $ $0.90 1,777 1,956 1,799 1, Central AC Maintenance, CAC Maintenance, Wifi Thermostats R - Building Shell - AP $ $1.65 1,516 1,623 1,786 1, High Efficiency Windows, Reflective Film-Windows, Insulation R - Building Shell - HAP $ $ Sealing R - Appliances - AP $45.17 $0.26 4,520 4,720 4,969 5, Air Purifier, Dehumidifier, Refrigerator/freezer recycling R - Appliances - HAP $67.75 $0.40 2,238 2,004 1,689 1, R - Water Heating - AP $34.41 $0.24 6,340 7,232 6,226 5, Heat Pump Water Heater, Pipe Insulation, Low Flow Showerhead R - Water Heating - HP $51.62 $0.35 3,225 3,304 2,184 1, R - Lighting - AP $88.21 $ ,954 1, Screw-In Lighting to LED (interior and exterior, speciality) R - Lighting - HP $ $ , R - Behavioral - AP $ $ ,500 28,500 28,500 28, Enhanced Bill Presentation Achievable Potential Sum 49,634 52,331 55,225 54,928 High Achievable Potential Sum 4,711 4,575 4,014 3,398 Bundle LCOE ($/MWh) Installed Cost ($/kwh) Yearly Potential Savings (MWh) Yearly Potential Savings (MWh) Yearly Potential Savings (MWh) Yearly Potential Savings (MWh) Bundle Life Bundle Life C - VFD - AP $6.88 $0.06 5,411 5,748 6,484 6, C - VFD - HAP $10.31 $0.09 2,599 2,444 2,150 2, C - INDUSTRIAL MEASURES - AP $15.55 $0.11 6,417 5,688 4,636 4, C - INDUSTRIAL MEASURES - HAP $23.32 $0.16 2,624 2,003 1, C - HVAC & REFRIGERATION - AP $10.62 $ ,216 9,875 9,757 9, C - HVAC & REFRIGERATION - HAP $15.93 $0.15 3,921 3,407 2,278 1, C - COMMERCIAL OUTDOOR LIGHTING - AP $11.89 $0.10 3,093 3,463 2,688 2, C - COMMERCIAL OUTDOOR LIGHTING - HAP $17.84 $0.15 1,109 1, C - COMMERCIAL INDOOR LIGHTING - AP $11.95 $ ,482 22,707 19,885 17, C - COMMERCIAL INDOOR LIGHTING - HAP $17.93 $0.15 5,707 6,936 4,674 3, C - BUILDING MANAGEMENT SYSTEM - AP $28.25 $0.19 4,036 4,253 4,606 4, C - BUILDING MANAGEMENT SYSTEM - HAP $42.37 $0.29 1,770 1,608 1,380 1, Achievable Potential Sum 49,656 51,733 48,056 45,609 High Achievable Potential Sum 17,729 17,785 12,579 10,822 DRAFT: Results published for I&M s Indiana IRP 3 rd Stakeholder Meeting: February 13, 2019 Measures Measures Ventilation VSC, Pumping System VSD, Compressed Air VSD Retrocomission, Fan System Flow optimization, Pumping system optimization, Water heat upgrade, insulation wall cavity Water Cooled Chiller, Chilled Water Reset, Air Cooled Chiller, Ventilation upgrade, HVAC economizer Screw-in, High-Bay Fixtures, Interior Lighting - Occupancy Sensors, Linear Lighting Screw-in, High-Bay Fixtures, Interior Lighting - Occupancy Sensors, Linear Lighting Ventilation - Demand Controlled, RTU - Advanced Controls, Process - Timers and Controls, Compressed Air - Leak Management Program, HAP = High Achievable Potential; EE bundles are made available as resource options 76

77 DSM/Energy Efficiency Demand Response Resources: The Company s DR resources are based on a BYOT Residential program and the Commercial program is a EIS light interface with existing customer equipment Four blocks of each DR resource can be selected per year Sector Participants Demand Savings (kw) Energy Savings (kwh) Enrollment/ Installation Cost Total First Year Cost Ongoing Annual Cost Service Life (Years) Residential 3,375 3, ,540 $1,932,250 $1,971,408 $89, Sector Participants Demand Savings (kw) Energy Savings (kwh) Enrollment/ Installation Cost Total First Year Cost Ongoing Annual Cost Service Life (Years) Commercial ,647 $468,963 $507,138 $214, DRAFT: Results published for I&M s Indiana IRP 3 rd Stakeholder Meeting: February 13, 2019

78 DSM/Energy Efficiency Volt VAR Optimization Resources: I&M has 70 MW of demand reduction potential from VVO; 18 station buses with 46 distribution circuits operating with 6 buses and 19 circuits planned in 2019 Tranche No. of Circuits Capital Investment Annual O&M Demand Reduction (kw) Energy Reduction (MWh) 1 32 $10,688,000 $320,640 8,066 33, $10,688,000 $320,640 6,443 26, $11,022,000 $330,660 6,185 25, $11,022,000 $330,660 5,701 23, $11,022,000 $330,660 5,413 22, $11,022,000 $330,660 5,115 21, $11,022,000 $330,660 4,793 19, $11,022,000 $330,660 4,574 18, $11,022,000 $330,660 4,397 18, $11,022,000 $330,660 4,223 17, $11,022,000 $330,660 4,004 16, $11,022,000 $330,660 3,668 15, $11,022,000 $330,660 3,264 13, $10,688,000 $320,640 2,549 10, $10,688,000 $320,640 1,733 7,137 One Tranche of VVO may be selected per year, based on planning and implementation constraints 78 DRAFT: Results published for I&M s Indiana IRP 3 rd Stakeholder Meeting: February 13, 2019

79 Today s Agenda Opening Remarks Stakeholder Feedback Review IRP Portfolios, Scenarios, Sensitivities & Initial Model Results IRP Inputs Review Resource Options Next Steps 79

80 IRP Inputs and Assumptions Supply Side Resource Costs Nuclear Coal with 90% Carbon Capture Natural Gas Combined Cycle with & without Carbon Capture (NGCC) Natural Gas Simple Cycle (CT) Short-Term Market Purchase (STMP) Wind Solar Storage Combined Heat & Power 80

81 IRP Inputs and Assumptions AEP System New Generation Technologies Key Supply-Side Resource Option Assumptions (a)(b)(c) Installed Full Load Fuel Variable Fixed Capacity Capability (MW) (d) Cost (c,e) Heat Rate Cost O&M O&M Factor LCOE (f) Type Std. ISO Summer Winter ($/kw) (HHV,Btu/kWh) ($/MBtu) ($/MWh) ($/kw-yr) (%) ($/MWh) Base Load Nuclear 1,610 1,560 1,690 7,900 10, Pulv. Coal with Carbon Capture (PRB) ,200 12, Combined Cycle (1X1 "J" Class) ,000 6, Combined Cycle (2X1 "J" Class) 1,080 1,410 1, , Combined Cycle (2X1 "H" Class) 1,150 1,490 1, , Peaking Combustion Turbine (2 - "E" Class) (g) ,200 11, Combustion Turbine (2 - "F" Class, w/evap coolers) (g) , Aero-Derivative (2 - Small Machines) (g,h) ,400 9, Recip Engine Farm ,300 8, Battery ,900 87% (i) Notes: (a) Installed cost, capability and heat rate numbers have been rounded (b) All costs in 2018 dollars, except as noted. (c) $/kw costs are based on summer capability (d) All Capabilities are at 1,000 feet above sea level (e) Total Plant Investment Cost w/afudc (AEP-East rate of 5.5%,site rating $/kw) (f) Levelized cost of energy based on capacity factors shown in table (g) Includes Dual Fuel capability and SCR environmental installation (h) Includes Black Start capability (i) Denotes efficiency, (w/ power electronics) Combined Heat and Power resource is assumed to be 15MW, with a full load net heat rate of ~4,800 Btu/kWh and an installed cost of ~$2,100/kW Stakeholder requested, AEPSC Generation Engineering developed a Class V estimate for a NGCC with Carbon Capture resource: Highlights include: Overnight Installed cost: $2,050/kW; Full Load Heat Rate: 81 7,600 Btu/kWh; Controlled CO2 rate: 11.7 lb./mmbtu

82 IRP Inputs and Assumptions Short-Term Market Purchase A one-year capacity purchase with no associated energy Up to 1,000MW may be selected in any year Pricing based on Fundamental Commodity Forecast Scenario 82

83 Wind Resources for the IRP IRP Inputs and Assumptions Source: AEP Based on Bloomberg New Energy Finance H US Renewable Energy Market Outlook Installed Cost based on Bloomberg New Energy Finance s H Renewable Energy Market Outlook Two Tranches Available as a Modeling Constraint Tranche A & Tranche B both reflect impact of the Production Tax Credit 300MW of Wind Available per year; 150MW for each Tranche, with a maximum build over the planning period of 2,100MW; NOTE: For the 3 rd Stakeholder meeting modeling, the max build was mistakenly set to 3,300MW, this will be corrected to 2,100MW going forward Expected Capacity Factor: 40.5% for Tranche A & 35% for Tranche B 83

84 Solar Resources for the IRP IRP Inputs and Assumptions Source: AEP Based on Bloomberg New Energy Finance H US Renewable Energy Market Outlook Two Tranches Available as a Modeling Constraint Tier 1 and Tier 2 Pricing with Normalized Investment Tax Credit impact 300MW of Solar Available per year; 150MW at Tier 1 & 150MW at Tier 2, with a maximum build over the planning period of 1,700MW Expected Capacity Factor ~24.4%, from Single Axis Tracking system For a 2021 Commercial Operation Date ~LCOE $62 to $68/MWh 84

85 IRP Inputs and Assumptions Energy Storage 10MW/40MWh Resource Based on Lithium Ion technology, Energy Product Cost Estimates based on Internal Estimates and information from EPRI and Storage Suppliers 85

86 IRP Inputs and Assumptions Forecast is based on PJM s November 27, 2018 Distributed Solar Forecast 86

87 Today s Agenda Opening Remarks Stakeholder Feedback Review IRP Portfolios, Scenarios, Sensitivities & Initial Model Results IRP Inputs Review Resource Options Next Steps 87

88 Final Steps to Filing I&M s IRP on May 1, 2019 Today - Stakeholder Meeting #3, February 21, 2019 Discuss stakeholder feedback on IRP inputs, scenarios, sensitivities, portfolios and initial modeling results Stakeholders provide final comments on inputs, scenarios and portfolios by February 27, 2019 Following today, I&M will begin final modeling and develop its preliminary preferred plan I&M will discuss the final modeling results and draft preferred plan with stakeholders on March 22, 2019 at Stakeholder Meeting #4. Collect stakeholder feedback on final modeling and draft preferred plan Following meeting #4, I&M will finalize modeling and preferred resource plan and prepare final report for filing on May 1, 2019 DRAFT: Results published for I&M s Indiana IRP 3 rd Stakeholder Meeting: February 13,

89 Updated Stakeholder Process Meeting Date Topic February 15, Northeast Indiana Innovation 2018 IRP Kick-off Meeting - Stakeholder Process & Center Scenario Discussion 3211 Stellhorn Road Fort Wayne, IN April 11, 2018 Barnes & Thornburg 11 S. Meridian St. Indianapolis, IN February 21, 2019 I&M Main Office 110 East Main St. Ft. Wayne, IN March 22, 2019 Minnetrista Gathering Place 1200 N. Minnetrista Pkwy. Muncie, IN Considerations for Modeling DSM in the 2018 IRP & Update on the IRP Updated Inputs, Portfolios, Scenarios & Initial Modeling Results Modeling Results, Preferred Portfolio Discussion & Final Inputs 89

90 Appendix 90

91 Group 1 Short-Term Market Purchase* Short-Term Market Purchase Firm Capacity (MW) Difference Over Case 1 Case 1 Case 2 Case 3 Case 4 Case 1 Case 2 Case 3 Case (400) (300) (350) (50) Note: Combined Heat and Power, Energy Storage, Demand Response & Combustion Turbine resources were not selected by the model in the Base, High, Low, or Status Quo optimizations. * The description of Short-Term Market Purchase in included in the inputs discussion. 91

92 Group 1 Combined Cycle Combined-Cycle Firm Capacity (MW) Difference Over Case 1 Case 1 Case 2 Case 3 Case 4 Case 1 Case 2 Case 3 Case ,492 1,119 1,492 1,492 0 (373) ,492 1,119 1,492 1,492 0 (373) ,492 1,119 1,492 1,492 0 (373) ,492 1,119 1,492 1,492 0 (373) ,492 1,119 1,492 1,492 0 (373) ,492 1,119 1,492 1,492 0 (373) ,238 2,238 2,238 2, ,238 2,238 2,238 2, ,238 2,238 2,238 2, ,357 3,357 3,357 3, ,357 3,357 3,357 3,

93 Group 1 Commercial EE Commercial EE Firm Capacity (MW) Difference Over Case 1 Case 1 Case 2 Case 3 Case 4 Case 1 Case 2 Case 3 Case (1) (1) (1) (1) (2) (1) (2) (3) (2) (3) (5) (3) (4) (6) (4) (1) (4) (1) (0) (2) (1) (1) (0) (0) (1) (1) (1) (1) (1)

94 Group 1 Residential EE Residential EE Firm Capacity (MW) Difference Over Case 1 Case 1 Case 2 Case 3 Case 4 Case 1 Case 2 Case 3 Case (2) (2) (7) (10) (4) (2) (2) (1) (1) 1 (1) (1) (1) (1) (1) (6) (6) (0) (8)

95 Group 1 Utility Solar Utility Solar Nameplate Capacity (MW) Difference Over Case 1 Case 1 Case 2 Case 3 Case 4 Case 1 Case 2 Case 3 Case (50) (99) (149) (99) (149) (99) (149) (99) , (149) (99) ,094 1, (149) (99) ,243 1,691 1,094 1, (149) (99) ,393 1,691 1,243 1, (149) (99) ,542 1,691 1,393 1, (149) (99) ,691 1,691 1,542 1, (149) (99) ,691 1,691 1,691 1, ,691 1,691 1,691 1, ,691 1,691 1,691 1, ,691 1,691 1,691 1,

96 Group 1 Wind Wind Nameplate Capacity (MW) Difference Over Case 1 Case 1 Case 2 Case 3 Case 4 Case 1 Case 2 Case 3 Case (150) (150) (300) (300) (450) (450) ,050 1, (450) (600) ,200 1, (450) (750) ,350 1, (450) (900) ,500 1,500 1, (450) (1,050) ,650 1,650 1, (450) (1,050) ,800 1,800 1, (450) (1,050) ,950 1,950 1, (450) (1,050) ,100 2,100 1,650 1, (450) (1,050) ,250 2,250 1,800 1, (450) (1,050) ,400 2,400 1,950 1, (450) (1,050) ,550 2,550 2,100 1, (450) (1,050) ,700 2,700 2,250 1, (450) (1,050) ,850 2,850 2,400 1, (450) (1,050) 96

97 Group 1 VVO VVO Firm Capacity (MW) Difference Over Case 1 Case 1 Case 2 Case 3 Case 4 Case 1 Case 2 Case 3 Case

98 Group 2 Short-Term Market Purchase Short-Term Market Purchase Firm Capacity (MW) Difference over Case 5 Case 5 Case 6 Case 7 Case 8 Case 5 Case 6 Case 7 Case (500) (300) (300) (450)

99 Group 2 Combined Cycle Combined-Cycle Firm Capacity (MW) Difference over Case 5 Case 5 Case 6 Case 7 Case 8 Case 5 Case 6 Case 7 Case (373) (373) (373) , (1,119) (1,119) (1,492) , (1,119) (1,119) (1,492) , (1,119) (1,119) (1,492) , (1,119) (1,119) (1,492) , (1,119) (1,119) (1,492) , (1,119) (1,119) (1,492) ,238 1,119 1,119 1,119 0 (1,119) (1,119) (1,119) ,238 1,119 1,119 1,119 0 (1,119) (1,119) (1,119) ,238 1,119 1,119 1,119 0 (1,119) (1,119) (1,119) ,357 2,238 2,238 2,238 0 (1,119) (1,119) (1,119) ,357 2,238 2,238 2,238 0 (1,119) (1,119) (1,119) 99

100 Group 2 Commercial EE Commercial EE Firm Capacity (MW) Difference over Case 5 Case 5 Case 6 Case 7 Case 8 Case 5 Case 6 Case 7 Case (1) (1) (1) (2) (2) (1) (3) (3) (1) (3) (3) (2) (5) (5) (2) (4) (4) (2) (2) (1) (1) (1) (1) (0) (0)