1. 2015 California Statewide Critical Peak Pricing Evaluation DRMEC Spring 2016 Load Impact Evaluation Workshop San Francisco, California May, 2016 Prepared by: Eric Bell Marshall Blundell

2. Program Description  Critical Peak Pricing (CPP) is an electric rate in which a utility charges a higher price for consumption of electricity during peak hours on selected days, referred to as critical peak days or event days −Typically, CPP hours coincide with the utility’s peak demand—SDG&E’s events last from 11 AM to 6 PM while PG&E’s and SCE’s last from 2 to 6 PM −The higher price during peak hours on critical event days is designed to encourage reductions in demand and reflects the fact that electric demand during those hours drives a substantial portion of electric infrastructure costs −Each utility typically calls event days 5 to 15 times a year based on their system conditions when demand is high and supply is short −System load patterns across utilities are not always coincidental, particularly between Northern and Southern California −Comparisons of impacts between the utilities should be made with caution −September 9 and September 10 events were common to all utilities 2

3. Program Description  CPP is the default rate for large customers, and is offered to small and medium customers on a voluntary basis −PG&E began defaulting small and medium business (SMB) customers onto CPP in 2014— defaulting will continue in large batches each November through 2016 −SDG&E will begin to default their SMB customers onto CPP in 2016, and SCE will begin to default their SMB customers onto CPP starting in 2018  CPP enrollment 1 by utility and customer size  Hours of Availability and Actual Use 3 Utility Large >200 kW Medium 20 kW to 199 kW Small <20 kW PG&E1,83523,541136,843 SCE2,587529532 SDG&E82635823 1 Enrollment from average event day in 2015. Utility Hours of Availability Hours of Actual Use No. of Available Dispatches No. of Actual Dispatches PG&E60 15 SCE60481512 SDG&E12635185

4. Hours of Availability and Actual Use Utility Hours of Availability Hours of Actual Use No. of Available Dispatches No. of Actual Dispatches PG&E60 15 SCE60481512 SDG&E12635185 4

5. Ex Post Methodology 5

6. Methodology for large default customers consistent across utilities  Large C&I Customers: −Used matched control groups with difference-in-differences panel regressions −Yields unbiased results for average event −Matches evaluated using out-of-sample testing −Load impacts for customers that are large or idiosyncratic for which matching was not successful were estimated using individual customer regressions (very few)  Default SMB Customers (PG&E only) −Methodology same as above but all customers successfully matched −Homogeneous population and availability of large control group facilitated finding similar control group counterparts for all customers −SCE and SDG&E do not yet have default SMB customers 6

7. PG&E Ex Post Results Large C&I Customers 7

8. PG&E’s average load reduction for large C&I customers was 5.3%, or 30 MW across the 15 event days in June-September 2015 8

9. Event Summary  PDP was called for 15 events in 2015, compared to 10 in 2014  Most events were clustered into groups of sequential event days  Significant differences between 2014 and 2015 −2014: 7 out of the 10 events were in July −2015: events were distributed more evenly from June through September 9

10. 10 2014 vs 2015 Comparison: Persistent Customers  Year over year impacts similar for persistent customers in first 9 events of 2015  Later season events show smaller impacts, significantly lowering the average event impact  2015 impacts: 29.8 MW, 14.24 kW per customer (5.3%) −Persistent Customers (1,500 Accounts): 27.6 MW, 18.4 kW per customer (7%) −Non-Persistent Customers (593 Accounts): 2.2 MW, 3.7 kW per customer (1.6%)  2014 impacts: 41 MW, 23.2 kW per customer (8.1%)

11. PG&E detailed event load impacts- Large C&I 11 Average event temperature shown for event hours 2-6 PM and for single hour for utility and system peak hour. Event DateDay of WeekAccounts Avg. Customer Reference Load Avg. Customer Load w/ DR Impact Aggregate Impact % Reduction Avg. Event Temp. Daily Max. Temp. (kW) (MW)(%)(°F) 6/12/2015Fri2,107248.4238.69.820.73.9%88.2101.8 6/25/2015Thu2,103256.2245.011.123.44.4%91.3105.0 6/26/2015Fri2,105250.3237.013.327.95.3%88.5107.0 6/30/2015Tue2,106266.0248.617.336.56.5%93.9106.5 7/1/2015Wed2,106262.7239.123.649.79.0%87.9102.0 7/28/2015Tue2,091264.3245.319.039.87.2%93.1102.0 7/29/2015Wed2,092262.7245.816.935.36.4%92.3107.5 7/30/2015Thu2,091258.3240.118.238.07.0%87.7103.0 8/17/2015Mon2,089277.5261.715.833.15.7%93.0108.0 8/18/2015Tue2,089264.3254.99.419.63.6%86.9104.0 8/27/2015Thu2,083272.3263.88.517.73.1%92.8103.5 8/28/2015Fri2,082275.9264.911.023.04.0%93.5106.0 9/9/2015Wed2,083283.9271.312.726.44.5%96.1104.0 9/10/2015Thu2,084283.6269.214.430.05.1%94.6105.0 9/11/2015Fri2,084271.7259.212.526.14.6%91.2101.0 Avg. Event2,093266.5252.214.229.85.3%91.4103.7 Utility System Peak Hr.2,084277.3263.413.934.05.0%94.8105.0 Statewide System Peak Hr.2,106248.9232.716.129.06.5%94.0106.5  Utility system peak hour: 34 MW (June 30, HE18)  Statewide system peak hour: 29 MW (September 10, HE17)  Average event hour: 29.8 MW

12. PG&E Ex Post Results SMB Customers 12

13. PG&E’s average load reduction for SMB customers was 0.8%, or 5.8 MW across the 15 event days in June-September 2015 13

14. PG&E detailed event load impacts- SMB Customers 14 Average event temperature shown for event hours 2-6 PM and for single hour for utility and system peak hour Event DateDay of WeekAccounts Avg. Customer Reference Load Avg. Customer Load w/ DR Impact Aggregate Impact % Reduction Avg. Event Temp. Daily Max. Temp. (kW) (MW)(%)(°F) 6/12/2015Fri152,3994.74.80.0-7.4-1.0%90.190.8 6/25/2015Thu150,8995.05.10.0-4.7-0.6%92.592.9 6/26/2015Fri150,8174.84.9-0.1-9.7-1.3%90.190.8 6/30/2015Tue150,6875.2 0.00.50.1%95.496.0 7/1/2015Wed150,5405.04.90.06.20.8%89.389.7 7/28/2015Tue148,9985.1 0.06.80.9%94.494.9 7/29/2015Wed148,9215.2 0.0-7.2-0.9%94.194.6 7/30/2015Thu148,8515.04.90.17.91.1%89.289.8 8/17/2015Mon147,8835.2 0.01.40.2%94.495.2 8/18/2015Tue147,8125.0 0.0-1.7-0.2%87.588.1 8/27/2015Thu147,4365.35.20.113.71.8%93.594.5 8/28/2015Fri147,3585.35.20.115.22.0%94.095.6 9/9/2015Wed146,4895.55.30.226.53.3%96.997.6 9/10/2015Thu146,3735.55.30.119.52.4%95.796.2 9/11/2015Fri146,2805.15.00.118.62.5%92.293.2 Avg. Event148,7825.1 0.05.80.8%92.693.2 Utility System Peak Hr.146,3735.45.30.1-0.92.5%96.096.2 Statewide System Peak Hr.150,6874.7 0.020.2-0.1%95.796.0  Utility system peak hour: -0.9 MW (June 30, HE18)  Statewide system peak hour: 20.2 MW (September 10, HE17)  Average event hour: 5.8 MW

15. PG&E Ex Post Results All Customers 15

16. PG&E detailed event load impacts- All Customers 16 Average event temperature shown for event hours 2-6 PM and for single hour for utility and system peak hour. Event DateDay of WeekAccounts Avg. Customer Reference Load Avg. Customer Load w/ DR Impact Aggregate Impact % Reduction Avg. Event Temp. Daily Max. Temp. (kW) (MW)(%)(°F) 6/12/2015Fri165,8007.87.70.116.31.3%89.9101.8 6/25/2015Thu164,2448.28.10.122.81.7%92.2105.0 6/26/2015Fri164,1618.07.80.121.31.6%89.9107.0 6/30/2015Tue164,0288.68.30.341.73.0%95.2106.5 7/1/2015Wed163,8848.37.90.459.34.4%89.1102.0 7/28/2015Tue162,4268.48.10.349.93.6%94.3102.0 7/29/2015Wed162,3498.58.30.231.02.2%93.9107.5 7/30/2015Thu162,2828.38.00.349.33.7%89.0103.0 8/17/2015Mon161,3518.88.50.237.52.6%94.2108.0 8/18/2015Tue161,2788.38.20.120.61.5%87.2104.0 8/27/2015Thu160,9268.78.50.234.02.4%93.3103.5 8/28/2015Fri160,8608.88.50.340.92.9%93.9106.0 9/9/2015Wed160,0329.18.80.456.13.8%96.8104.0 9/10/2015Thu159,9189.18.80.352.43.6%95.5105.0 9/11/2015Fri159,8298.68.30.346.93.4%92.1101.0 Avg. Event162,2248.58.30.238.72.8%92.4103.7 Utility System Peak Hr.159,9189.08.70.336.83.6%95.8105.0 Statewide System Peak Hr.164,0287.87.60.251.92.9%95.5106.5  Utility system peak hour: 36.8 MW (June 30, HE18)  Statewide system peak hour: 51.9 MW (September 10, HE17)  Average event hour: 38.7 MW

17. SCE Ex Post Results Large C&I Customers 17

18. SCE’s average load reduction was 5.0%, or 29 MW across the 12 event days in July-September 2015 18

19. SCE detailed event load impacts- Large C&I 19 Average event temperature shown for event hours 2-6 PM and for single hour for utility and system peak hour. Event DateDay of WeekAccounts Avg. Customer Reference Load Avg. Customer Load w/ DR Impact Aggregate Impact % Reduction Avg. Event Temp. Daily Max. Temp. (kW) (MW)(%)(°F) 7/1/2015Wed.2,690208.8195.413.536.36.5%82.898.4 7/2/2015Thu.2,692202.5194.18.422.74.2%84.8100.1 7/28/2015Tue.2,679208.8199.29.525.54.6%85.397.0 7/29/2015Wed.2,676212.8204.68.221.83.8%85.8104.5 8/3/2015Mon.2,667214.6200.713.937.06.5%85.093.1 8/6/2015Thu.2,667212.2198.613.636.46.4%83.391.2 8/14/2015Fri.2,669216.2205.710.528.04.8%94.7102.9 8/17/2015Mon.2,669219.9209.610.327.44.7%85.1105.4 8/18/2015Tue.2,667216.4206.310.126.84.7%83.7100.4 9/9/2015Wed.2,684236.5223.213.335.65.6%93.0102.5 9/10/2015Thu.2,684240.0230.79.325.03.9%93.4102.0 9/21/2015Mon.2,682218.2208.79.525.44.3%80.799.9 Avg. Event2,677217.2206.410.829.05.0%86.598.1 Utility System Peak Hr.-------- Statewide System Peak Hr.2,684233.0224.28.823.63.8%93.6102.0  Utility system peak hour: 0 MW (No event called)  Statewide system peak hour: 23.6 MW (September 10, HE17)  Average event hour: 29 MW

20. SDG&E Ex Post Results Large C&I Customers 20

21. SDG&E’s average load reduction was 8.3%, or 25 MW across the 5 event days in August-September 2015 21

22. SDG&E detailed event load impacts- Large C&I 22 Average event temperature shown for event hours 2-6 PM and for single hour for utility and system peak hour. Event DateDay of WeekAccounts Avg. Customer Reference Load Avg. Customer Load w/ DR Average Customer Aggregate Impact % Reduction Avg. Event Temp. Daily Maximum Temp. Impact (kW) (MW)%°F 8/27/2015Thu1,207240.6223.117.521.17.3%88.593.1 8/28/2015Fri1,206240.8219.521.325.78.8%91.294.3 9/9/2015Wed1,209270.7241.029.735.911.0%94.6103.0 9/10/2015Thu1,209267.4244.622.827.58.5%92.698.0 9/11/2015Fri1,208245.8232.213.516.45.5%87.395.0 Avg. Event1,207253.1232.121.025.38.3%90.897.3 Utility System Peak Hr.1,209265.2235.529.735.911.2%92.6103.0 Statewide System Peak Hr.1,209251.8230.121.726.38.6%91.698.0  Utility system peak hour: 35.9 MW (September 9, HE16)  Statewide system peak hour: 26.3 MW (September 10, HE17)  Average event hour: 25.3 MW

23. Ex Ante Methodology 23

24. Ex ante estimates relied on available historical data  The steps involved in the analysis are as follows: 1.Calculate Percent Impacts A.Large Default Customers- Use 2015 ex post results for large default customers to calculate percent impacts for each hour on the average event day; -SCE and SDG&E also used 2014 results for large default customers enrolled in the program for both years; -Segmented by geographic area (LCA/Transmission Planning Area) B.PG&E SMB Customers- Calculate percent reductions across the ex post event hours for the average event; -PG&E SMB results used for projected SMB impacts at SCE and SDG&E; 2.Model reference load as a function of temperature, by geographic area; 3.Apply reference load model to ex ante weather conditions; 4.Combine percent impacts and reference load for each set of ex ante conditions to get kW impacts for the average customer; and 5.Multiply average customer impacts by ex ante enrollment. 24

25. PG&E Ex Ante Results 25

26. PG&E Enrollment Projections by Size, Forecast Year and Month Note: 2015 values are actual from the average event; 2016 and beyond are forecasted.  Due to additional large customers that are scheduled to be defaulted onto CPP, PG&E projects that large C&I CPP enrollment will grow to 3,109 by November 2017 and will then remain essentially flat  For medium and small customers, customers with at least 24 months of experience on TOU will be defaulted in November 2016 and 2017 26 SizeYearJan.Feb.Mar.Apr.MayJun.Jul.Aug.Sep.Oct.Nov.Dec. Large: Greater than 200 kW 20151,826 20162,123 2,483 2,776 20172,776 3,011 3,109 20263,150 3,154 3,155 Medium: 20 kW to 199.99 kW 201521,347 33,118 201633,118 58,283 201758,283 64,334 202669,474 69,960 Small: Less than 20 kW 2015125,191 184,027 2016184,027 234,332 2017234,332 260,751 2026287,981 289,952 All Customers 2015148,364 219,268 2016219,268 219,628 295,391 2017295,391 295,627 328,194 2026360,605 360,609 363,067

27. PG&E Ex Ante Impacts: August 1-in-2 PG&E Weather  Ex ante impacts use RA window of 1-6 PM, yielding slightly lower impacts and percent reductions than program operating hours  On the average ex post event day, all customers yielded: − Avg. load impact of 0.2 kW, similar to ex ante impact of 0.2 kW −Aggregate load impact of 39 MW, smaller than ex ante 2017 impact of 54 MW, with difference due to higher future enrollment 27 Demand SizeYear Enrollment Forecast Avg. Load Impact (kW) Aggregate Load Impact (MW) Percent Impact (%) Greater than 200 kW 20172,91014.241.35.00% 20263,05314.143.14.96% Medium: 20 kW to 199.99 kW 201758,2590.210.80.73% 202669,4500.213.00.73% Small: Less than 20 kW 2017234,3200.02.00.39% 2026287,9680.02.40.39% All Customers 2017295,4890.254.21.92% 2026360,4710.258.51.80%

28. Comparison of 2015 PG&E ex ante year estimates to prior year estimates  Large: −Percent reductions lower in 2015, reflecting ex post performance −Enrollment slightly higher  SMB: −Realized percent reductions are lower than previously assumed 1 −Enrollment is higher in 2015  Net effect is 35% reduction for August 2017 28 Demand Size Weather Year Year Accounts Reference Loads (MW) Percent Reductions Aggregate Impacts (MW) 2014 Estimates 2015 Estimates 2014 Estimates 2015 Estimates 2014 Estimates 2015 Estimates 2014 Load Impact (MW) 2015 Load Impact (MW) Large: Greater than 200kW 1-in-1020172,6243,01171.845.28.1%5.0%71.845.2 1-in-220172,6243,01164.843.97.7%5.0%64.843.9 Medium: 20 kW to 199.99 kW 1-in-10201737,57958,28314.011.61.2%0.7%14.011.6 1-in-2201737,57958,28313.110.91.2%0.7%13.110.9 Small: Less than 20kW 1-in-102017203,973234,33210.52.21.6%0.4%10.52.2 1-in-22017203,973234,3329.52.01.6%0.4%9.52.0 All Customers 1-in-102017244,176295,62796.259.03.5%1.9%96.259.0 1-in-22017244,176295,62787.456.83.4%2.0%87.456.8 1 Prior assumptions were based off the PG&E Early Enrollment Pilot percentage load impacts, and scaled down by approximately two-thirds to account for customer self selection bias. Customer self selection appears to strongly influence event performance.

29. SCE Ex Ante Results 29

30. SCE enrollment projections by size, forecast year and month  SCE projects that large C&I CPP enrollment will grow by 0.73% per year to approximately 2,813 customers by December 2026.  SMB customers on a TOU rate will be defaulted onto CPP in April 2018. 30 SizeYearJan.Feb.Mar.Apr.MayJun.Jul.Aug.Sep.Oct.Nov.Dec. Large: Greater than 200 kW 20152,677 20162,718 20172,738 20262,813 Medium: 20 kW to 199.99 kW 2015000000000000 2016000000000000 2017000000000000 202613,918 Small: Less than 20 kW 2015000000000000 2016000000000000 2017000000000000 202686,082 All Customers 20152,677 20162,718 20172,738 2026102,813 Note: 2015 values are actual from the average event; 2016 and beyond are forecasted.

31. SCE ex ante impacts: August 1-in-2 SCE weather  Ex ante impacts use RA window of 1-6 PM, yielding slightly lower impacts and percent reductions than program operating hours.  On average, ex post event day, large customers yielded: − Avg. load impact of 10.8 kW, similar to ex ante impact of 10.2 kW in 2017 −Aggregate load impact of 29 MW, similar to ex ante impact of 28 MW in 2017 31 Demand SizeYear Enrollment Forecast Avg. Load Impact (kW) Aggregate Load Impact (MW) Percent Impact (%) Greater than 200 kW 20172,73810.227.94.44% 20262,81310.228.64.44% Medium: 20 kW to 199.99 kW 20170--- 202613,9180.23.30.73% Small: Less than 20 kW 20170--- 202686,0820.00.80.39% All Customers 20172,73810.227.94.44% 2026102,8130.332.72.53%

32. Comparison of 2015 SCE ex ante year estimates to prior year estimates  Large C&I: −Percent reductions in 2015 are 30% higher: 2014 estimates exhibited a negative relationship with temperature, and so percent impacts under ex ante conditions were relatively low −2015 enrollment forecast is about 6% higher than in 2014 −Net effect in 2016 year forecast: −38% higher than last year’s forecast for 1-in-10 weather conditions −29% higher than last year’s forecast for 1-in-2 weather conditions  SMB default was delayed a year from 2017 to 2018 32 Demand Size Weather Year Year Accounts Reference Loads (MW) Percent Reductions Aggregate Impacts (MW) 2014 Estimates 2015 Estimates 2014 Estimates 2015 Estimates 2014 Estimates 2015 Estimates 2014 Load Impact (MW) 2015 Load Impact (MW) Large: Greater than 200kW 1-in-1020172,6572,738642.5642.43.3%4.4%21.128.5 1-in-220172,6572,738624.8628.33.5%4.4%22.127.9 Medium: 20 kW to 199.99 kW 1-in-10201734,79501,143.3-1.2%-13.6- 1-in-2201734,79501,095.3-1.2%-13.0- Small: Less than 20kW 1-in-102017215,2050511.6-1.6%-8.1- 1-in-22017215,2050482.8-1.6%-7.6- All Customers 1-in-102017252,6572,7382,297.4642.41.9%4.4%42.828.5 1-in-22017252,6572,7382,202.9628.31.9%4.4%42.827.9

33. SDG&E Ex Ante Results 33

34. SDG&E enrollment projections by size, forecast year and month  Large C&I forecast simply reflects the expected growth of SDG&E large customer population  In March 2016, medium C&I customers with at least 24 months of experience on TOU rate will be defaulted onto CPP 34 SizeYearJan.Feb.Mar.Apr.MayJun.Jul.Aug.Sep.Oct.Nov.Dec. Large: Greater than 200 kW 20151,207 20161,2631,2641,2651,2661,2671,2681,2701,2711,2721,2731,2741,275 20171,2761,2771,278 1,2791,2801,2811,2821,283 1,2841,285 20261,4101,4111,4131,4141,4151,4171,4181,4191,4211,4221,4241,425 Medium: 20 kW to 199.99 kW 2015000000000000 201619,308 201717,276 202616,260 Small: Less than 20 kW 2015------------ 2016------------ 2017------------ 2026------------ All Customers 20151,207 201620,57120,57220,57320,57420,57520,57620,57820,57920,58020,58120,58220,583 201718,55218,55318,554 18,55518,55618,55718,55818,559 18,56018,561 202617,67017,67117,67317,67417,67517,67717,67817,67917,68117,68217,68417,685 Note: 2015 values are actual from the average event; 2016 and beyond are forecasted.

35. SDG&E ex ante impacts: August 1-in-2 SDG&E weather  Ex ante impacts use RA window of 1-6 PM, which is shorter than SDG&E’s CPP program window of 11AM – 6PM  On average, the ex post event day, large customers yielded: − Avg. load impact of 21 kW, higher than ex ante impact of 17.4 kW in 2017 −Aggregate load impact of 25 MW, higher than ex ante aggregate impact of 22 MW in 2017 −Smaller ex ante impacts due to higher ex post temperatures (avg. event day mean17 was 83.2, while mean17 for 1-in-2 event day SDG&E weather was 72.5)—this is a very significant difference in temperature that strongly influences the results 35 Demand SizeYear Enrollment Forecast Avg. Load Impact (kW) Aggregate Load Impact (MW) Percent Impact (%) Greater than 200 kW 20171,28217.422.37.71% 20261,41917.424.67.69% Medium: 20 kW to 199.99 kW 201717,2760.35.20.92% 202616,2600.34.90.92% Small: Less than 20 kW 2017---- 2026---- All Customers 201718,5581.527.53.22% 202617,6791.729.53.47%

36. Comparison of 2015 SDG&E ex ante year estimates to prior year estimates  Large: −Accounts, percent reductions similar across years −Reference loads lower in 2015 so impacts are slightly lower.  SMB: −Realized percent reductions are lower than previously assumed −Enrollment is higher in 2015  Net effect is 18% reduction in load impacts for August 2017 1-in-2 year weather 36 Demand Size Weather Year Year AccountsReference Loads (MW)Percent Reductions Aggregate Impacts (MW) 2014 Estimates 2015 Estimates 2014 Estimates 2015 Estimates 2014 Estimates 2015 Estimates 2014 Load Impact (MW) 2015 Load Impact (MW) Large: Greater than 200kW 1-in-1020171,2831,282326.6304.68.4%8.3%27.525.3 1-in-220171,2831,282312.3289.37.9%7.7%24.822.3 Medium: 20 kW to 199.99 kW 1-in-1020178,05017,276458.0605.02.0%0.9%9.25.6 1-in-220178,05017,276431.0565.12.0%0.9%8.65.2 Small: Less than 20kW 1-in-102017-------- 1-in-22017-------- All Customers 1-in-1020179,33318,5587859104.7%3.4%36.630.9 1-in-220179,33318,5587438544.5%3.2%33.427.5

37. Conclusions and Recommendations  Ex post and ex ante impacts for SCE and SDG&E were generally comparable to prior years for large existing customers  PG&E experienced significant changes in the population of customers, and in the number and timing of events −First wave of default SMB customers at PG&E, influx of additional large default customers −PG&E also increased the number of events from 10 in 2014 to 15 in 2015 −Lower performance in later events is possibly due to a combination of seasonality for certain industries, and event fatigue  Recommendations −Compare the performance of the newly defaulted SMB customers in 2016 to customers defaulted in 2015 to determine if the inconsistent early event performance was seasonal, industry related, or perhaps related to learning or awareness −Consider developing an experimental design to vary the number and timing of event dispatches across customers for the 2016 event season to learn more about the effects of seasonality and possible event fatigue 37

38. Nexant, Inc. 101 Montgomery St., 15th Floor San Francisco, CA 94104 415-777-0707 For comments or questions, contact: Eric Bell Managing Consultant ebell@nexant.com ebell@nexant.com Marshall Blundell Consultant mblundell@nexant.com mblundell@nexant.com 38