1. Study Results High EE/DG/DR Study This slide deck contains results from the 2011 TEPPC Study Program. This study shows the results of an increase of EE/DG/DR policy and it impact on the interconnection.

2. 2 2022 PC4 – High EE, DSM, DG Central Question: What impact do aggressive EE, DSM, and DG policies have on transmission and capacity needs relative to the 2022 Common Case? Assumptions Loads – decreased to reflect the assumption that “all cost-effective EE potential” is achieved throughout the West Transmission System – None Generation – o DG resources increased based on ‘interconnection potential’ of distributed PV and ‘technical potential’ of distributed CHP as estimated by E3 (link to E3 report)link o RPS resources adjusted for lower loads due to EE and behind-the-meter DG, and for increased PV DG o DSM increased based on LBNL analysis of demand response potential estimated using an updated FERC DR Potential Estimates model LinkLink to all SPSC input provided for this case

3. 3 1)Perform EE load adjustments; + 2) Add DG resources, adjust RPS; + 3) Add DR and “tune” Study Execution Build and run study in steps… PC4 Results in similar order…

4. Summary of Aggressive EE Load Adjustments

5. 5 Incremental DG (PV and CHP) modeled in the Common Case was first removed from the total potential DG estimates developed for PC4 Incremental DG added to 2022 PC4 was scaled up for avoided transmission and distribution system losses o 6% for all areas except CA, 7% for CA (consistent with assumptions used to develop RPS requirements) DG was distributed proportionally (to load) amongst largest area load busses Distributed Generation Modeling Approach Common Case DG Potential DG Losses, 6% Distributed proportionally

6. 6 The following categories of distributed solar PV were modeled o Residential rooftop – modeled using NREL rooftop solar profiles (fixed tilt of 20º) o Commercial rooftop – modeling using solar profiles developed by E3 using PVWatts o Ground-mounted – modeled using NREL single-axis tracking solar profiles Distributed CHP was modeled as follows: o Flat output o Heat rate = 6,000 Btu/kWh o Capacity factor = 85% Distributed Generation Modeling Approach, continued All DG has behind-the-meter (BTM) and wholesale component (50/50 split)

7. 7 2022 Incremental Distributed PV in PC1 and PC4 – Big Picture WECC total ~ 25,000 MW

8. 8 2022 Incremental Distributed CHP in PC1 and PC4 – Big Picture WECC total ~ 9,900 MW

9. 9 High EE and High DG Impacts to RPS Requirements Top 3 % change in Red

10. 10 Planned/future RPS resources removed as needed to meet adjusted RPS targets o After EE load adjustments o Again, after high DG adjustments Ran out of planned/future resources to remove during the high DG adjustments o Increased PV counts towards RPS o Behind-the-meter PV and CHP reduces retail sales, hence reduces RPS targets Overbuild of RPS Resources State RPS Requirement (GWh) RPS Energy in Dataset (GWh) % Over Requirement Arizona5,6556,68918% Nevada4,3488,912105% Utah4,7544,8883%

11. 11 Interruptible DR Bus assignment assumptions: o Based on generator size o Based on bus size (real load) Modeling technique – high cost CT o ~20 dispatch hours per year o 4-6 hours per dispatch, 4-5 times per year o Min down time: 4 hours o Min up time: 3 hours o Modify heat rate (MMBtu/MWh) Monthly availability specified DR Modeling Approach More info Economic DR Bus assignment assumptions: o Based on generator size o Based on bus size (real load) Modeling technique - fixed-shape transaction (i.e. like wind) 50-80 dispatch hours per year Hours per dispatch, frequency – varies LBNL uses area loads and load weighted LMPs to calculate dispatch Monthly availability specified

12. 12 DR Modeling Implementation PC4 w/ EE and DG Add Economic DR Add Interruptible DR Results to LBNL Run study Tune Interruptible DR Run study Check results Yes OK? No Run study PC4 Done! Note: Same process for PC1

13. DR Capacity chart

15. 15 Interruptible DR Energy Dispatch by Month

16. 16 Economic DR Energy Dispatch by Month

17. 17 Total DR Energy Dispatch by Month

18. 18 Total DR Average Hourly Dispatch (PC4)

19. 19 Takeaways Combined cycle - lower loads, CA/AB Cogen/Solar - study assumptions Wind - RPS impacts from study Dump – lower loads, BC hydro PC4 Generation Results

20. Changes in Total Annual Generation

21. Production Cost Summary Category 2022 PC1 Common Case 2022 PC4 High EE-DG-DR DifferenceDiff % Dump Energy397,1041,515,2661,118,162281.579% Emergency Energy2,6761,372(1,305)-48.742% CO 2 Emissions (MMetricTons) 359310(49)-13.680% CO 2 Adder ($/metric ton)0.000 Variable Production Cost (thermal units excl DSM) CO 2 Adder (Total M$)0000.000% Other Variable Costs (M$)14,85111,902(2,949)-19.858% Total Var. Prod. Cost (M$)14,85111,902(2,949)-19.858%

22. 22 Changes in Generation by State

23. 23 Annual Generation Difference by Energy Type

24. 24 Transmission Expansion Results – Changes in Dump Energy by State Path 3 congested?

25. 25 Takeaways NW/CAN to CA - inexpensive NW resource free to meet CA load. COI and Path 3 congested as a result. Path 8 utilization Path 26 utilization PC4 Transmission Results

26. 26 Comparison with PC1 Largest IncreaseU99Largest IncreaseU90 P29 Intermountain-Gonder 230 kV27.65%P66 COI45.49% P03 Northwest-British Columbia26.67%P03 Northwest-British Columbia33.95% P66 COI25.21%P29 Intermountain-Gonder 230 kV32.05% P27 Intermountain Power Project DC Line17.40%P27 Intermountain Power Project DC Line20.68% P45 SDG&E-CFE10.00%P25 PacifiCorp/PG&E 115 kV Interconnection18.77% Largest DecreaseU99Largest DecreaseU90 P26 Northern-Southern California-9.58%P08 Montana to Northwest-17.42% P08 Montana to Northwest-9.30%P26 Northern-Southern California-11.86% P01 Alberta-British Columbia-5.67%P60 Inyo-Control 115 kV Tie-11.32% P60 Inyo-Control 115 kV Tie-5.03%P22 Southwest of Four Corners-9.16% P61 Lugo-Victorville 500 kV Line-4.36%P01 Alberta-British Columbia-6.48%

27. 27 Transmission Expansion Results – Changes in Path Utilization P45 SDG&E-CFE* P29 Intermountain-Gonder* P26 Northern- Southern California* P03 Northwest-British Columbia* P66 COI NamePC4 U99PC1 U99Change P45 SDG&E-CFE44.38%34.38%10.00% P03 Northwest-British Columbia42.93%16.27%26.66% P29 Intermountain-Gonder 230 kV41.77%14.12%27.65% P66 COI29.99%4.78%25.21% P27 Intermountain Power Project DC Line24.12%6.72%17.40% UtilizationMax Inc.Max Dec. U75P66 (51.74%)P11 (-28.30%) U90P66 (45.49%)P16 (-17.42%) U99P29 (27.65%)P26 (-9.58%) Table 1 Five most congested paths Table 2 Greatest change in path utilization p66 coi p29 intermountain-go p26 northern-southern P16 idaho-sierra p11 west of crossover P08 Montana - Northwest* P16 Idaho-Sierra * P11 West of Crossover P27 Intermountain Power Project DC Line

28. 28 Changes in Generation by State

30. Questions or thoughts on this study?

31. 31 Hourly region to region transfers Additional Material

32. 32 P45 SDG&E-CFE Hourly Flow BackBack to presentation

33. 33 P27 Intermountain Power Project DC Line Hourly Flow BackBack to presentation

34. 34 P03 Northwest-British Columbia Hourly Flow BackBack to presentation

35. 35 P66 COI Hourly Flow BackBack to presentation

36. 36 P29 Intermountain-Gonder 230 kV Hourly Flow BackBack to presentation

37. 37 Transmission Expansion Results – Changes in Un-utilized Generation

38. 38 Changes in Energy by Region

39. 39 WECC Peak Impact