May 30, Advice Letter 3444-E

Transcription

1 STATE OF CALIFORNIA Edmund G. Brown Jr., Governor PUBLIC UTILITIES COMMISSION 505 VAN NESS AVENUE SAN FRANCISCO, CA May 30, 2017 Advice Letter 3444-E Russell G. Worden Director, State Regulatory Operations Southern California Edison Company 8631 Rush Street Rosemead, CA SUBJECT: SCE's Price Trigger to the Capacity Bidding Program and the Methodology to Determine the Price Trigger Developed in Conjunction with PG&E and SDG&E Pursuant to OP 29 of Decision Dear Mr. Worden: Advice Letter 3444-E is effective as of May 25, 2017, per Resolution E-4819 Ordering Paragraphs. Sincerely, Edward Randolph Director, Energy Division

2 ADVICE LETTER (AL) SUSPENSION NOTICE ENERGY DIVISION Utility Name: Southern California Edison Utility Number/Type: U 338-E Advice Letter Number(s) 3444-E Date AL(s) Filed) August 1, 2016 Utility Contact Person: Darrah Morgan Utility Phone No.: (626) Date Utility Notified: September 1, 2016 [x ] ed to: Darrah.Morgan@sce.com, AdviceTariffManager@sce.com, Karyn.Gansecki@sce.com ED Staff Contact: Dorris Chow ED Staff Dorris.Chow@cpuc.ca.gov ED Staff Phone No.: (415) [X] INITIAL SUSPENSION (up to 120 DAYS from the expiration of the initial review period) This is to notify that the above-indicated AL is suspended for up to 120 days beginning September 1, 2016 for the following reason(s) below. If the AL requires a Commission resolution and the Commission s deliberation on the resolution prepared by Energy Division extends beyond the expiration of the initial suspension period, the advice letter will be automatically suspended for up to 180 days beyond the initial suspension period. [ ] A Commission Resolution is Required to Dispose of the Advice Letter [ ] Advice Letter Requests a Commission Order [X] Advice Letter Requires Staff Review The expected duration of initial suspension period is 120 days [ X] FURTHER SUSPENSION (up to 180 DAYS beyond initial suspension period) The AL requires a Commission resolution and the Commission s deliberation on the resolution prepared by Energy Division has extended beyond the expiration of the initial suspension period. The advice letter is suspended for up to 180 days beyond the initial suspension period. If you have any questions regarding this matter, please contact Dorris Chow at Dorris.Chow@cpuc.ca.gov. cc: EDTariffUnit * Note: reference Decision D , dated February 21, 2002, and Rule 7.5 in appendix A of D.O

3 Russell G. Worden Managing Director, State Regulatory Operations August 1, 2016 ADVICE 3444-E (U 338-E) PUBLIC UTILITIES COMMISSION OF THE STATE OF CALIFORNIA ENERGY DIVISION SUBJECT: Southern California Edison Company s Price Trigger to the Capacity Bidding Program and the Methodology to Determine the Price Trigger Developed in Conjunction with Pacific Gas and Electric Company and San Diego Gas & Electric Company Pursuant to Ordering Paragraph 29 of Decision In compliance with the California Public Utilities Commission (Commission or CPUC) Decision (D.) , Ordering Paragraph (OP) 29, Southern California Edison Company (SCE) hereby submits the methodology developed by SCE, Pacific Gas and Electric Company (PG&E), and San Diego Gas & Electric Company (SDG&E) (the investor-owned utilities, or IOUs) to determine a price trigger for the Capacity Bidding Program (CBP). SCE also includes in this advice filing its specific price trigger proposal for its CBP Day-Ahead (DA) and Day-Of (DO) products and submits the following changes to its tariffs. The revised tariffs are listed on Attachment A and are attached hereto. I. PURPOSE The purpose of this advice filing is to provide SCE s methodology in determining a price trigger for each utilities CBP in compliance with D SCE submits the proposed price trigger for SCE s CBP-DA and CBP-DO products for Commission approval. This filing also modifies Schedule CBP as further explained below. II. BACKGROUND On August 24, 2006, the Commission issued Resolution E-4009 directing the IOUs to use a 15 Million British Thermal Units per megawatt-hour (MMBTU/MWh) heat rate trigger for the California Power Authority Demand Reserves Partnership (CPA DRP). P.O. Box Rush Street Rosemead, California (626) Fax (626)

4 (U 338-E) August 1, 2016 On October 19, 2006, the Commission issued Resolution E-4020 authorizing the IOUs to implement a CBP to replace CPA DRP, with the same 15 MMBTU/MWh heat rate trigger. On June 2, 2006 and October 30, 2006, SCE submitted Advice 2010-E and 2010-E-A, respectively, providing tariffs, contracts, and budget funding requirements for implementation of its CBP. On December 29, 2006, the Commission approved SCE Advice 2010-E and 2010-E-A with an effective date of October 19, In September 2013, the Commission initiated Rulemaking (R.) to enhance the role of Demand Response (DR) in meeting the state s resource planning needs and operational requirements. Under this Rulemaking, the Commission also confirmed its intent to prioritize the competitive bidding of DR into the California Independent System Operator s (CAISO) wholesale market. In June 2015, SCE began the integration of its DR portfolio and has thus far integrated over 1,100 megawatts (MW) of DR into the CAISO market. On September 15, 2015, Assigned Commissioner Florio and Administrative Law Judge (ALJ) Hymes issued a Ruling outlining expectations for the utilities 2017 DR Bridge filing. In response to this Ruling, SCE proposed program changes to improve DR program reliability and effectiveness, with the goal of developing more robust DR resources for the CAISO wholesale market and for future resource planning needs. SCE s proposal was largely based upon lessons learned from its 2015 integration efforts. SCE s 2017 program proposals were approved, with modifications, by the Commission in D III. PRICE TRIGGER METHODOLOGY AND SCE S PRICE TRIGGER PROPOSAL In compliance with OP 29 of D , the IOUs collaborated to develop a methodology to determine an energy price trigger for each utility s CBP. SCE has developed an opportunity cost methodology to derive an economic price trigger that maximizes the average hourly energy value (AHEV) as defined by the following equation: = max (, ) # h h Where is the settled locational marginal price in the Day Ahead Market (DAM) or Real Time Market (RTM) for a utility s specific Sub-Load Aggregation Point (SLAP) for an hour t in which dispatch occurred, is the 15 MMBTU/MWh heat rate price for the day containing the hour t, and is the trigger price for products in that market.

5 (U 338-E) August 1, 2016 The ideal trigger price for SCE s CBP evaluates all of SCE s SLAPs while maximizing the AHEV for the program s available hours and maintaining the maximum number of economic events per month at or below five. 1 The current 15 MMBTU/MWh thermal heat rate calculates into a $/MWh energy price as follows: =15 ( + ) where is the 15 MMBTU/MWh price in $/MWh, is the settled Southern California Gas Company s city gate price (in $/MMBTU) for the trading day containing hour t, and is the product of the settled price per metric ton of CO2 equivalent for the trading day containing hour t and a conversion factor of metric tons of CO2 equivalent per MMBTU of natural gas. Based upon SCE s 2015 DR market integration experience, SCE determined that a bid price solely based upon the 15 MMBTU/MWh heat rate, did not maximize the AHEV of the resource. When the 15 MMBTU/MWh heat rate trigger was originally adopted, gas prices were typically $6-10/MMBTU, which equated to an energy price of approximately $90/MWh. With current gas prices, including the GHG compliance adder (usually $0.60- $0.70/MMBTU), a 15 MMBTU/MWh resource may be awarded in the DAM at around $60/MWh or less, which does not maximize the resource s AHEV. To address this issue, an explicit price component will be added to the CBP heat rate trigger. Combined, the energy price and heat rate triggers will apply to SCE s CBP Day-Ahead (CBP-DA) and Day-Of (CBP-DO) products, but each product will have a different energy price that will be based upon the highest AHEV. SCE elects to have one energy price for each product (e.g., an energy price for CBP-DA and an energy price for CBP-DO), rather than establish an energy price by product by SLAP (e.g., an energy price for CBP-DA SLAP_SCEW, an energy price for CBP-DO SLAP_SCEW, an energy price for CBP-DA SLAP_SCEN, an energy price for CBP-DO SLAP_SCEN, etc.). Due to differences between the DAM and RTM, it is not appropriate to utilize the same price trigger for CBP-DA and CBP-DO. 2 In determining a price trigger, the resource should maximize the difference between the amount paid to program participants, such as aggregators, for the energy they provide and the settled market price. SCE analyzed settled prices and found that RTM prices may vary significantly and can have greater volatility than DAM prices. SCE analyzed 2014 and 2015 hourly price intervals between 1:00 p.m. and 7:00 p.m. 3 for non-holiday weekdays for all of SCE s SLAPs and Default Load Aggregation Points (DLAP). While the mean for hourly prices for the DAM and 1 In compliance with D , SCE intends to file an advice letter later in 2016 to limit the number of economic events to five per month. 2 In compliance with D , SCE intends to file an advice letter later in 2016 to change the notification time for its CBP-DO product from 60-minutes to 20-minutes. 3 In compliance with D , SCE intends to file an advice letter later in 2016 to modify the CBP available hours from 11:00 a.m. to 7:00 p.m. to 1:00 p.m. to 7:00 p.m.

6 (U 338-E) August 1, 2016 RTM differed by less than two percent, the variances differed dramatically between the DAM and RTM, as shown in Table 1. Table 1: Statistics for Settled Locational Marginal Prices (LMP), SLAP and DLAP, Jan 2014 Dec 2015, Non-Holiday Weekdays, between 1:00 p.m. and 7:00 p.m. Market Statistic SCEC 4 SCEN 4 SCEW 4 SCHD 4 SCLD 4 SCNW 4 Day- Ahead Market Real- Time Market Min $3.14 $2.20 $3.35 $1.35 ($2.35) $2.28 Max $ $ $ $ $ $ Mean $47.01 $51.57 $49.97 $45.16 $45.35 $45.77 Variance , Min ($278.27) ($290.99) ($281.77) ($263.17) ($270.74) ($284.86) Max $ $1, $ $ $ $ Mean $47.63 $51.10 $51.14 $45.00 $44.75 $46.29 Variance 3, , , , , , While the number of hours with settled DLAP_SCE prices indicating the dispatch of a 15 MMBTU/MWh resource was nearly identical between the two markets (167 hours for the DAM versus 166 hours for the RTM), the average settled prices during those hours were $60.69 and $ for the DAM and RTM, respectively. At the DLAP_SCE level, the DAM did not reach the latter price at any point in 2015, even outside of CBP s available program hours. For this reason, a common energy price for CBP for the DAM and RTM is not appropriate. For each SLAP, the number of hours with settled LMPs indicating the dispatch of a 15 MMBTU/MWh thermal resource the current CBP trigger was considerably higher for the RTM than for the DAM in 2014, but was nearly identical between the two markets in The RTM prices for such hours greatly exceeded those in the DAM in each year, as demonstrated in Table 2. 4 SCE s Sub-Load Aggregation Points (SLAPs) are as follows: SCEC = SCE Central; SCEN = SCE North; SCEW = SCE West; SCHD = SCE High Desert; SCLD = SCE Low Desert; SCNW = SCE Northwest.

7 (U 338-E) August 1, 2016 Table 2: Number of Hours with LMP At or Above 15 MMBTU/MWh Heat Rate Price and Average LMPs for Non-Holiday Weekdays, between 1:00 p.m. and 7:00 p.m. Year Market Statistic SCEC SCEN SCEW SCHD SCLD SCNW DAM RTM DAM RTM Hours Avg. LMP $83.63 $ $84.50 $85.57 $85.72 $80.52 Hours Avg. LMP $ $ $ $ $ $ Hours Avg. LMP $61.07 $62.68 $62.01 $61.84 $61.89 $60.88 Hours Avg. LMP $ $ $ $ $ $ In D , the Commission approved SCE s CBP modifications, including limiting economic events to no more than five per month for each product-slap combination. 5 Per the agreed upon methodology, the ideal trigger price for a given SLAP would maximize the AHEV for the resource while keeping the maximum number of economic events per month at or below the limit of five. Prior analysis of CBP dispatches using DLAP prices for CBP in the DAM, identified a price range of $60-90/MWh that would result in a number of events allowed under the tariff while still capturing the highest-priced events. SCE identified and analyzed $60, $65, $70, $75, $80, and $90 (in $/MWh) to determine the appropriate DAM trigger price for SCE s CBP-DA product. Table 3 below provides the results of: (1) the maximum number of events per month, (2) average number of events per month, (3) average number of hours per month, and (4) the AHEV for each price by SLAP. 5 D also adopts SCE s proposal to replace the 1-4, 2-6, and 4-8 Hour options for both CBP-DA and CBP-DO with a single 1-6 Hour option for both notices, while leaving unchanged the current limit of 30 hours per month of dispatch.

8 (U 338-E) August 1, 2016 Table 3: Event Analysis Based Upon Settled DAM Prices for Non-Holiday Weekdays, between 1:00 p.m. and 7:00 p.m. for January 2014 through June 2016 (maximum AHEVs for each SLAP in bold, chosen trigger price highlighted) Trigger Price Max # Events/ Month SLAP_SCEC (Central) SLAP_SCEN (North) SLAP_SCEW (West) Avg. # Avg. # AHEV Max # Avg. # Avg. # AHEV Max # Avg. # Avg. # Events/ Hours/ Events/ Events/ Hours/ Events/ Events/ Hours/ Month Month AHEV $ $ $ $10.08 $ $ $ $9.86 $ $ $ $9.66 $ $ $ $9.05 $ $ $ $9.23 $ $ $ $7.05 Trigger Price SLAP_SCHD (High Desert) SLAP_SCLD (Low Desert) SLAP_SCNW (Northwest) Avg. # Avg. # AHEV Max # Avg. # Avg. # AHEV Max # Avg. # Avg. # Events/ Hours/ Events/ Events/ Hours/ Events/ Events/ Hours/ Month Month Max # Events/ Month AHEV $ $ $ $10.10 $ $ $ $10.14 $ $ $ $9.65 $ $ $ $8.25 $ $ $ $7.87 $ $ $ $6.88 The large numbers in the Max # of Events/Month column for every SLAP and all trigger prices below $90 reflect a period of unusually high DAM prices in November 2014, 6 as well as a period of extremely high DAM prices in June 2014 in SLAP_SCEN. 7 The agreed upon methodology would identify and select an economic price trigger that maximizes the AHEV. Therefore, based upon Table 3 and the highest AHEVs (either the highest or second-highest for all SLAPs except SCEN) the DAM economic price trigger for CBP products would be around $65/MWh. Prior analysis of CBP-DO dispatches, using DLAP prices in the RTM, identified a range of $ /MWh for the RTM trigger price as the range that would result in a reasonable number of events while still capturing the highest-priced events or AHEV. The following trigger prices (in $/MWh) were analyzed: $100, $120, $140, $150, $160, $180, and $200. Tables 4, 5, 6, and 7 below provides the results of (1) the maximum number of events per month, (2) average number of events per month, (3) average number of hours per month, and (4) the AHEV for each price by SLAP for 1-hour, 6 Merchant generators serving SCE load had an unusually large number of scheduled maintenance outages during early evening hours in November For non-holiday weekdays in HE14-19 in July 2014, the average hourly LMP in SLAP_SCEN was $151.95; during all other months in the period January 2014 December 2015, it was $47.02.

9 (U 338-E) August 1, hour, 3-hour, and 4-hour events, respectively. All values for event counts and hours are rounded to the nearest integer. As such, average hour counts may not equal the product of the average event count shown and the event length. Table 4: 1-Hour Event Analysis Based Upon Settled RTM Prices for Non-Holiday Weekdays, between 1:00 p.m. and 7:00 p.m. for January 2014 through May 2016 (maximum AHEVs for each SLAP in bold, chosen trigger price highlighted) Trigger Price Max # Events/ Month SLAP_SCEC (Central) SLAP_SCEN (North) SLAP_SCEW (West) Avg. # Avg. # AHEV Max # Avg. # Avg. # AHEV Max # Avg. # Avg. # Events/ Hours/ Events/ Events/ Hours/ Events/ Events/ Hours/ Month Month AHEV $ $ $ $89.89 $ $ $ $94.55 $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ Trigger Price SLAP_SCHD (High Desert) SLAP_SCLD (Low Desert) SLAP_SCNW (Northwest) Avg. # Avg. # AHEV Max # Avg. # Avg. # AHEV Max # Avg. # Avg. # Events/ Hours/ Events/ Events/ Hours/ Events/ Events/ Hours/ Month Month Max # Events/ Month AHEV $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $149.93

10 (U 338-E) August 1, 2016 Table 5: 2-Hour Event Analysis Based Upon Settled RTM Prices for Non-Holiday Weekdays, between 1:00 p.m. and 7:00 p.m. for January 2014 through May 2016 (maximum AHEVs for each SLAP in bold, chosen trigger price highlighted) Trigger Price Max # Events/ Month SLAP_SCEC (Central) SLAP_SCEN (North) SLAP_SCEW (West) Avg. # Avg. # AHEV Max # Avg. # Avg. # AHEV Max # Avg. # Avg. # Events/ Hours/ Events/ Events/ Hours/ Events/ Events/ Hours/ Month Month AHEV $ $ $ $57.65 $ $ $ $49.76 $ $ $ $50.34 $ $ $ $56.10 $ $ $ $57.42 $ $ $ $52.19 $ $ $ $49.75 Trigger Price SLAP_SCHD (High Desert) SLAP_SCLD (Low Desert) SLAP_SCNW (Northwest) Avg. # Avg. # AHEV Max # Avg. # Avg. # AHEV Max # Avg. # Avg. # Events/ Hours/ Events/ Events/ Hours/ Events/ Events/ Hours/ Month Month Max # Events/ Month AHEV $ $ $ $71.28 $ $ $ $62.49 $ $ $ $53.95 $ $ $ $58.33 $ $ $ $59.75 $ $ $ $58.75 $ $ $ $53.71

11 (U 338-E) August 1, 2016 Table 6: 3-Hour Event Analysis Based Upon Settled RTM Prices for Non-Holiday Weekdays, between 1:00 p.m. and 7:00 p.m. for January 2014 through May 2016 (maximum AHEVs for each SLAP in bold, chosen trigger price highlighted) Trigger Price Max # Events/ Month SLAP_SCEC (Central) SLAP_SCEN (North) SLAP_SCEW (West) Avg. # Avg. # AHEV Max # Avg. # Avg. # AHEV Max # Avg. # Avg. # Events/ Hours/ Events/ Events/ Hours/ Events/ Events/ Hours/ Month Month AHEV $ $ $ $36.59 $ $ $ $29.13 $ $ $ $23.59 $ $ $ $24.77 $ $ $ $26.93 $ $ $ $17.48 $ $ $ $13.01 Trigger Price SLAP_SCHD (High Desert) SLAP_SCLD (Low Desert) SLAP_SCNW (Northwest) Avg. # Avg. # AHEV Max # Avg. # Avg. # AHEV Max # Avg. # Avg. # Events/ Hours/ Events/ Events/ Hours/ Events/ Events/ Hours/ Month Month Max # Events/ Month AHEV $ $ $ $48.36 $ $ $ $39.06 $ $ $ $24.22 $ $ $ $26.48 $ $ $ $28.47 $ $ $ $22.75 $ $ $ $11.54 Table 7: 4-Hour Event Analysis Based Upon Settled RTM Prices for Non-Holiday Weekdays, between 1:00 p.m. and 7:00 p.m. for January 2014 through May 2016 (maximum AHEVs for each SLAP in bold, chosen trigger price highlighted) Trigger Price Max # Events/ Month SLAP_SCEC (Central) SLAP_SCEN (North) SLAP_SCEW (West) Avg. # Avg. # AHEV Max # Avg. # Avg. # AHEV Max # Avg. # Avg. # Events/ Hours/ Events/ Events/ Hours/ Events/ Events/ Hours/ Month Month AHEV $ $ $ $25.51 $ $ $ $16.91 $ $ $ $13.75 $ $ $ $12.76 $ $ $ $12.84 $ $ $ ($4.03) $ ($15.62) $ ($14.00)

12 (U 338-E) August 1, 2016 Trigger Price SLAP_SCHD (High Desert) SLAP_SCLD (Low Desert) SLAP_SCNW (Northwest) Avg. # Avg. # AHEV Max # Avg. # Avg. # AHEV Max # Avg. # Avg. # Events/ Hours/ Events/ Events/ Hours/ Events/ Events/ Hours/ Month Month Max # Events/ Month AHEV $ $ $ $36.52 $ $ $ $26.11 $ $ $ $16.48 $ $ $ $15.75 $ $ $ $15.30 $ ($8.18) ($3.01) ($3.62) $ ($12.43) ($7.30) ($13.11) For any given trigger price, the shorter the bid length, the higher the AHEV of events, as there are fewer dispatches during hours that do not meet the trigger price criterion. However, the shorter bid lengths result in fewer hours of economic dispatch, reducing the value of the capacity provided by the program. SCE anticipates that most months will have either two- or three-hour bids, resulting in a maximum of either ten or fifteen hours of economic dispatch. While the $100 and $120 trigger prices generally have higher AHEVs, at these prices the resource would have more than five economic events, which is prohibited per tariff parameters. To ensure the number of events does not exceed five and that the resource receives the highest value, an economic trigger price of $160 would offer the highest AHEV for both two- and three-hour events for the majority of the SLAPs. SCE does not intend to have different trigger prices for each SLAP. Therefore, SCE proposes that its CBP resources bid into the DAM and RTM have an economic price trigger of at least $65/MWh and $160/MWh, respectively, in addition to the 15 MMBTU/MWh heat rate trigger. All other tariff trigger criteria will remain the same. IV. ALIGNMENT OF SCE S PROPOSED APPROACH WITH THOSE OF THE OTHER IOUS Upon issuance of the Decision, the IOUs collaborated to reach as much consensus as possible on the CBP price trigger within the allotted 45-day period. While the meetings were productive and much alignment was gained, there were some areas where the IOUs are still not aligned. These are detailed below. A. Areas of Alignment Between the IOUs: As a result of the collaboration between the IOUs, several areas of alignment can be incorporated into each IOUs methodology. Those are: 1. All three IOUs agreed that it would be best to start by estimating the number of event hours that would result from a given trigger and select a trigger that keeps the expected number of economic events hours below the program maximums, minus a small set-aside for reliability. This is known as an opportunity cost analysis (OCA). Using an opportunity cost

13 (U 338-E) August 1, 2016 price trigger methodology relies on targeting a pre-specified number of events per month and all three IOUs have agreed to use this approach. 2. The higher of the trigger price and existing heat rate trigger should be the minimum possible bid price. 3. Therefore, there would be no hard triggers proposed. 4. Any price methodology shall set a minimum price of the Net Benefits Test (NBT), pursuant to D , OP Each IOU will present a specific value for both day-ahead and/or day-of price triggers. B. Areas of Difference: Although considerable progress was made at creating a common methodology, it was not possible to design a single identical methodology. This was due to differences between the IOUs respective CBP program parameters. Thus differences between the methodologies proposed by the IOUs remained at the conclusion of the 45 days given for this effort. Those differences, as SCE understands them (while SCE does not speak on behalf of PG&E and SDG&E) are as follows: 1. SCE used an Average Energy Hourly Value (AHEV) methodology, which is an opportunity cost analysis that maximizes the value of called CBP events while remaining under the event cap. 2. There was no consensus among the IOUs on the treatment of sub Load Aggregation Points (SubLAPs). SCE and PG&E are applying a single trigger price for all their respective SubLAPs but are performing an overlaying short-term opportunity cost analysis for each SubLAP that will reflect conditions such as transmission congestion that are specific to each SubLAP. This is necessary due to the high number of SubLAPs within their service areas. SDG&E is not performing an overlaying analysis as SDG&E only has one SubLAP. 3. Use of the price trigger for both the day-ahead option and the day-of option. PG&E does not expect to bid its CBP into the real-time market until the 2018 season, and has not yet determined how it will model the day-of option price trigger. For 2017, PG&E expects to use the day-ahead price trigger as it will be a load-modifying resource DR program, and reserves the right to select a different trigger for its day-of product for the 2018 season. SCE and SDG&E have specified a specific day-of price trigger that differs from their day-ahead price triggers in their respective advice letters. Through the IOU meetings, the IOUs learned that each utility s Commissionapproved 2017 CBP program has a different monthly maximum number of events and different event lengths. PG&E has a maximum of 30 hours per month, SCE has a maximum of 30 hours per month and a maximum of 5

14 (U 338-E) August 1, 2016 economically-dispatched events per month, and SDG&E has a maximum number of event hours that differs by month but is 30 hours per month on average. In addition, SDG&E offers a 2-6 hour product whereas PG&E offers both a 1-4 hour product, a 2-6 hour product and a 4 8 hour product. In 2017 SCE will offer only a single 1-6 hour product. These basic differences in the program designs between the IOUs will naturally result in difference between the target number of hours and events on which to base a common trigger price methodology. C. Areas that IOUs May Be Able Agree On If Given More Time: Given those very program differences, it is unlikely that having more time to collaborate would necessarily result in any more of a single price trigger methodology being reached by all three IOUs. There might be further agreement, given more time, on issues related to schedule and the format to be used to update price triggers. Each IOU agreed that a process should be established to regularly update the price triggers via advice letters, though the date at which this occurs and the format (supplemental advice letter versus regular advice letter) was not agreed to. V. PROPOSED TARIFF LANGUAGE Schedule CBP is modified to reflect the change to the CBP Event trigger in Special Condition as follows: CBP Event Triggers. A CBP Event is triggered only when both of the following criteria are met: a. The economic criterion that a 15,000 Btu/kWh heat rate thermal resource is or should be dispatched. This criterion may be caused by any one of the following conditions: 1) High temperatures; or 2) Resource limitations; or 3) A generating unit outage; or 4) Transmission constraints; or 5) CAISO Alert or Warning Notice; or 6) SCE system emergency; and b. An energy price is set at (1) $0.065/kWh or above for the Day-Ahead market, or (2) $0.16/kWh or above for the Real-Time market. Given the variations expected in wholesale market prices over time, SCE proposes that its proposal should allow for yearly updates, if necessary, via a Tier 1 advice letter by no later than March 1 of each year to allow for Commission approval by the beginning of the summer season on May 1, or via DR program applications, bridge-funding proposals, or equivalent mechanisms. The updated triggers would still be designed to

15 (U 338-E) August 1, 2016 result in a CPUC-approved maximum number of events per month but would be updated with more current price information. No cost information is required for this advice filing. This Advice Letter will not increase any rate or charge, cause the withdrawal of service, or conflict with any other schedule or rule. TIER DESIGNATION Pursuant to D , OP 29, this advice letter is submitted with a Tier 3 designation. EFFECTIVE DATE This Advice Letter will be effective upon Commission resolution. NOTICE Anyone wishing to protest this Advice Letter may do so by letter via U.S. Mail, facsimile, or electronically, any of which must be received no later than August 21, Protest should be submitted to: CPUC Energy Division ED Tariff Unit 505 Van Ness Avenue, 4th Floor San Francisco, California Facsimile: (415) EDTariffUnit@cpuc.ca.gov Copies of protests also should be mailed to the attention of the Director, Energy Division, Room 4004 (same address above). In addition, protests and all other correspondence regarding this Advice Letter shall be sent to either via or U.S. mail (and by facsimile, if possible) at the address shown below on the same date it is mailed or delivered to the Commission:

16 (U 338-E) August 1, 2016 Russell G. Worden Managing Director, State Regulatory Operations Southern California Edison Company 8631 Rush Street Rosemead, California Telephone: (626) Facsimile: (626) AdviceTariffManager@sce.com Michael R. Hoover Director, State Regulatory Affairs c/o Karyn Gansecki Southern California Edison Company 601 Van Ness Avenue, Suite 2030 San Francisco, California Facsimile: (415) Karyn.Gansecki@sce.com There are no restrictions on who may file a protest, but the protest shall set forth specifically the grounds upon which it is based and must be received by the deadline shown above. In accordance with General Rule 4 of GO 96-B, SCE is serving copies of this Advice Letter to the interested parties on the attached GO 96-B and R service lists. Address change requests to the GO 96-B service list should be directed by electronic mail to AdviceTariffManager@sce.com or at (626) For changes to all other service lists, please contact the Commission s Process Office at (415) or by electronic mail at Process_Office@cpuc.ca.gov. Further, in accordance with Public Utilities Code Section 491, notice to the public is hereby given by filing and keeping this Advice Letter at SCE s corporate headquarters. To view other SCE advice letters filed with the Commission, log on to SCE s web site at For questions, please contact Nathanael Gonzalez at (626) or by electronic mail at Nathanael.Gonzalez@sce.com. Southern California Edison Company RGW:ng:cm Enclosures /s/ Russell G. Worden Russell G. Worden

17 CALIFORNIA PUBLIC UTILITIES COMMISSION ADVICE LETTER FILING SUMMARY ENERGY UTILITY MUST BE COMPLETED BY UTILITY (Attach additional pages as needed) Company name/cpuc Utility No.: Southern California Edison Company (U 338-E) Utility type: Contact Person: Darrah Morgan ELC GAS Phone #: (626) PLC HEAT WATER Disposition Notice to: EXPLANATION OF UTILITY TYPE ELC = Electric GAS = Gas PLC = Pipeline HEAT = Heat WATER = Water (Date Filed/ Received Stamp by CPUC) Advice Letter (AL) #: 3444-E Tier Designation: 1 Subject of AL: Southern California Edison Company s Price Trigger to the Capacity Bidding Program and the Methodology to Determine the Price Trigger Developed in Conjunction with Pacific Gas and Electric Company and San Diego Gas & Electric Company s Pursuant to Ordering Paragraph 29 of Decision Keywords (choose from CPUC listing): Compliance AL filing type: Monthly Quarterly Annual One-Time Other If AL filed in compliance with a Commission order, indicate relevant Decision/Resolution #: Decision Does AL replace a withdrawn or rejected AL? If so, identify the prior AL: Summarize differences between the AL and the prior withdrawn or rejected AL: Confidential treatment requested? Yes No If yes, specification of confidential information: Confidential information will be made available to appropriate parties who execute a nondisclosure agreement. Name and contact information to request nondisclosure agreement/access to confidential information: Resolution Required? Yes No Requested effective date: Upon Commission Approval Estimated system annual revenue effect: (%): Estimated system average rate effect (%): No. of tariff sheets: -3- When rates are affected by AL, include attachment in AL showing average rate effects on customer classes (residential, small commercial, large C/I, agricultural, lighting). Tariff schedules affected: Service affected and changes proposed 1 : See Attachment A Pending advice letters that revise the same tariff sheets: None 1 Discuss in AL if more space is needed.

18 Protests and all other correspondence regarding this AL are due no later than 20 days after the date of this filing, unless otherwise authorized by the Commission, and shall be sent to: CPUC, Energy Division Attention: Tariff Unit 505 Van Ness Avenue San Francisco, California Russell G. Worden Managing Director, State Regulatory Operations Southern California Edison Company 8631 Rush Street Rosemead, California Telephone: (626) Facsimile: (626) Michael R. Hoover Director, State Regulatory Affairs c/o Karyn Gansecki Southern California Edison Company 601 Van Ness Avenue, Suite 2030 San Francisco, California Facsimile: (415)

19 Public Utilities Commission 3444-E Attachment A Cal. P.U.C. Sheet No. Title of Sheet Cancelling Cal. P.U.C. Sheet No. Revised E Schedule CBP Revised E* Revised E Table of Contents Revised E Revised E Table of Contents Revised E 1

20 Southern California Edison Revised Cal. PUC Sheet No E Rosemead, California (U 338-E) Cancelling Original Cal. PUC Sheet No E* Schedule CBP Sheet 3 CAPACITY BIDDING PROGRAM SPECIAL CONDITIONS (Continued) (Continued) 1. Definitions (Continued) g. Key Factors in Payment Calculations 1. Capacity Nomination = The amount of energy nominated per hour 2. Recorded Reduction = Sum of aggregated customer Energy Baselines or Adjusted Energy Baseline (see Special Condition 12) per SLAP Sum of Recorded kw per SLAP 3. Shortfall Energy = Capacity Nomination Recorded Reduction 4. Shortfall Penalty = (Shortfall Energy) * CAISO hourly energy price for DLAP 5. Delivered Energy Payment = Recorded Reduction * daily SCE city gate gas price * heat rate factor of 15,000 Btu/kWh 6. Energy Payment = Delivered Energy Payment Shortfall Penalty 2. Agreements. Aggregators must execute all applicable Agreements prior to participation under this Schedule. Necessary Agreements may include Capacity Bidding Program Aggregator Agreement (Form ), Aggregator Add Form (Form ), and Aggregator Remove Form (Form ). Aggregators must be in full compliance with all terms of the Aggregator Agreement to participate in Schedule CBP. 3. Assignment to SLAP: SCE will assign each CBP customer to a Sub-Load Aggregation Point (SLAP). The CBP customer s assigned SLAP may change over time. SCE will notify the Aggregator of any change to SLAP assignment. The effective date of the SLAP change will occur on the first day of the following calendar month. 4. CBP Events. CBP Events may be triggered on any weekday between the hours of 11 a.m. to 7 p.m., Monday through Friday, excluding holidays. A CBP Event can be scheduled on a Day-Of basis and on a Day-Ahead basis on any weekday except holidays. CBP Event Triggers. A CBP Event is triggered only when both of the following criteria are met. a. The economic criterion that a 15,000 Btu/kWh heat rate thermal resource is or should be dispatched. This criterion may be caused by any one of the following conditions: 1) High temperatures; or 2) Resource limitations; or 3) A generating unit outage; or 4) Transmission constraints; or 5) CAISO Alert or Warning Notice; or 6) SCE system emergency; and b. An energy price is set at (1)$0.065/kWh or above for the Day-Ahead market, or (2) $0.16/kWh or above for the Real-Time market. 5. CBP Test Events. Up to three (3) CBP Test Events may be called within each SLAP in each calendar year (see Special Condition 6 Event Limits). All notification protocols, as well as all applicable credits and penalties, will apply during CBP Test Events. A CBP Test Event can be scheduled on a Day-Of basis and on a Day-Ahead basis on any weekday except holidays. (T) (T) (T) (T) (N) (N) (Continued) (To be inserted by utility) Issued by (To be inserted by Cal. PUC) Advice 3444-E Caroline Choi Date Filed Aug 1, 2016 Decision Senior Vice President Effective May 25, H17 Resolution E-4819

21 Southern California Edison Revised Cal. PUC Sheet No E Rosemead, California (U 338-E) Cancelling Revised Cal. PUC Sheet No E TABLE OF CONTENTS Sheet 1 Cal. P.U.C. Sheet No. TITLE PAGE E TABLE OF CONTENTS - RATE SCHEDULES E E TABLE OF CONTENTS - LIST OF CONTRACTS AND DEVIATIONS E TABLE OF CONTENTS - RULES E TABLE OF CONTENTS-INDEX OF COMMUNITIES, MAPS, BOUNDARY DESCRIPTIONS E TABLE OF CONTENTS - SAMPLE FORMS E E (T) (T) PRELIMINARY STATEMENT: A. Territory Served E B. Description of Service E C. Procedure to Obtain Service E D. Establishment of Credit and Deposits E E. General E F. Symbols E G. Gross Revenue Sharing Mechanism E E H. Baseline Service E I. Charge Ready Program Balancing Account E J. Not In Use... -E K. Nuclear Decommissioning Adjustment Mechanism E L. Purchase Agreement Administrative Costs Balancing Account E M. Income Tax Component of Contributions E N. Memorandum Accounts E E E E E E E E O. California Alternate Rates for Energy (CARE) Adjustment Clause E E P. Optional Pricing Adjustment Clause (OPAC) E (Continued) (To be inserted by utility) Issued by (To be inserted by Cal. PUC) Advice 3444-E Caroline Choi Date Filed Aug 1, 2016 Decision Senior Vice President Effective May 25, H8 Resolution E-4819

22 Southern California Edison Revised Cal. PUC Sheet No E Rosemead, California (U 338-E) Cancelling Revised Cal. PUC Sheet No E TABLE OF CONTENTS Sheet 8 (Continued) RATE SCHEDULES (Continued) Schedule No. Title of Sheet Cal. P.U.C. Sheet No. OTHER BG-NEM Experimental Biogas Net Energy Metering E E BioMAT Bioenergy Market Adjustment Tariff E E BSC-IMO Bundled Service Customer-Interval Meter Ownership E CBP Capacity Bidding Program E E CCA-CRS Community Choice Aggregation Cost Responsibility Surcharge E E CCA-INFO Community Choice Aggregation-Information Fees E E CCA-SF Community Choice Aggregation Service Fees E E CC-DSF Customer Choice - Discretionary Service Fees E E CGDL-CRS Customer Generation Departing Load Cost Responsibility Surcharge E E CHP Combined Heat and Power Excess Energy Purchase E E CPP Critical Peak Pricing E CREST California Renewable Energy Small Tariff E DA-CRS Direct Access Cost Responsibility Surcharge E E E DAEBSC-CRS Direct Access Eligible Bundled Service Customers-Cost Responsibility Surcharge E DA-LRATC Direct Access Local Resource Adequacy Transfer Credit E DA-RCSC Direct Access Revenue Cycle Services Credits E E DBP Demand Bidding Program E DL-NBC Departing Load - Nonbypassable Charges E DRP-SF Demand Response Provider Service Fees E E EITE Emissions-Intensive and Trade-Exposed Customer Greenhouse... Gas Allowance Revenue Provisions E ESP-DSF Energy Service Provider - Discretionary Service Fees E E ESP-NDSF Energy Service Provider - Non Discretionary Service Fees E FC-NEM Fuel Cell Electrical Generating Facility NEM & Interconnection Agreement E GMS Generation Municipal Surcharge E GTSR-CR Green Tariff Shared Renewables Community Renewables E E GTSR-GR Green Tariff Shared Renewables Green Rate E E (T) (Continued) (To be inserted by utility) Issued by (To be inserted by Cal. PUC) Advice 3444-E Caroline Choi Date Filed Aug 1, 2016 Decision Senior Vice President Effective May 25, H12 Resolution E-4819