PUBLIC UTILITIES COMMISSION. June 5, Advice Letter 5193-E

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STATE OF CALIFORNIA PUBLIC UTILITIES COMMISSION 505 VAN NESS AVENUE SAN FRANCISCO, CA 94102-3298 EDMUND G. BROWN JR.

1 STATE OF CALIFORNIA PUBLIC UTILITIES COMMISSION 505 VAN NESS AVENUE SAN FRANCISCO, CA EDMUND G. BROWN JR., Governor June 5, 2018 Advice Letter 5193-E Erik Jacobson Director, Regulatory Relations Pacific Gas and Electric Company 77 Beale Street, Mail Code B10C P.O. Box San Francisco, CA SUBJECT: Revised Capacity Bidding Program (CBP) Price Trigger. Dear Mr. Jacobson: Advice Letter 5193-E is effective as of June 1, 2018 per Resolution E Sincerely, Edward Randolph Director, Energy Division

2 Erik Jacobson Director Regulatory Relations Pacific Gas and Electric Company 77 Beale St., Mail Code B13U P.O. Box San Francisco, CA Fax: December 1, 2017 Advice 5193-E (Pacific Gas and Electric Company ID U 39 E) Public Utilities Commission of the State of California Subject: Revised Capacity Bidding Program (CBP) Price Trigger Purpose Pacific Gas and Electric Company (PG&E) hereby submits this advice letter to the California Public Utilities Commission (Commission or CPUC) pursuant to Ordering Paragraph (OP) 2 of Resolution E-4819 to update its Capacity Bidding Program (CBP) price trigger for the 2018 demand response (DR) season. Background PG&E s CBP is a DR program for customers on a commercial, industrial, or agricultural electric rate schedule to enroll through a third-party aggregator or self-aggregation. The CBP offers a day-ahead (DA) option and a day-of (DO) option, along with several products that include event durations of 1-4 hours, 2-6 hours, and 4-8 hours. It operates from May 1 through October 31 of each year and all products have a maximum of 30 event hours per operating month. The CBP provides capacity payments based on the amount of load reduction committed for each month, and provides energy payments based on customers load reduction during events (include test events). The CBP has been in operation since Prior to 2017, PG&E could trigger a DA or DO CBP event for one or more of the California Independent System Operator (CAISO) Load Zones when: 1. PG&E s procurement stack is expected to require the dispatch of electric generation facilities with heat rates of 15,000 BTU/kWh or greater for the dayahead or real-time market (respective of the day-ahead option and the day-of option), 2. PG&E receives a market award or dispatch instruction from the CAISO for a Proxy Demand Resource bid, 1 The CBP was implemented per Decision (D.) and Resolution E-4020.

3 Advice 5193-E December 1, PG&E, in its sole opinion, forecasts that generation resources or electric system capacity may not be adequate, or 4. the forecasted temperature for a Load Zone exceeds the temperature threshold for the Load Zone. Under the E-CBP tariff, PG&E is also allowed the right to not call an event even when these thresholds have been reached and when, in PG&E s sole opinion, forecasts indicate that resources may be adequate. On February 1, 2016, Southern California Edison Company (SCE) submitted its bridge funding proposal for DR Programs for its 2017 Transition Year, proposing to add a price trigger to its CBP. On June 9, 2016, the Commission issued D supporting the addition of a price trigger, but also ordered SCE, PG&E, and San Diego Gas & Electric Company (SDG&E) (collectively, the IOUs) to collaborate to create a methodology to determine a price trigger for the CBP and submit the proposed price trigger and the associated methodology to Energy Division (via a Tier 3 advice letter) within 45 days of approval of the Decision. The IOUs agreed that the price trigger should be set using an opportunity cost methodology to target the highest-value events, which is based on a maximum of 5 economic events per month. PG&E submitted a proposed price trigger of $70/MWh for both its DA and DO options on August 1, 2016, based on its opportunity cost analysis. 2 The Commission approved the IOUs price triggers on May 25, 2017, and ordered the IOUs to update these price triggers and provide further analyses on various aspects of the proposed price trigger, or justify why the 2017 price trigger should be continued. 3 In Application (A.) , submitted on January 17, 2017, PG&E proposed several modifications to the CBP in 2018, which included the following: opening the program to residential aggregators to allow residential customer participation, eliminating the DO option, shifting the program hours from 11 a.m.-7 p.m. to 1 p.m. 9 p.m., reducing the number of event durations to 1-4 hour and 2-6 hour options, and offering new Elect and Elect+ options with customized bidding prices. 4 These modifications are pending CPUC approval, with the ALJ s proposed decision (PD) expected to be considered by the Commission on December 14, PG&E Advice 4887-E, pp. 3-6.This price trigger was proposed to work in conjunction with the existing heat rate trigger, such that both triggers must be met for a CBP dispatch to occur. 3 Resolution E-4819, p A , pp. 2-8 to A PD was issued on November 9, 2017, approving all of these enumerated changes, with one exception: the PD approves PG&E s proposal to shift the hours to 1 p.m.-9 p.m. as an optional measure but retains the 11 a.m.-7 p.m. hours as the default option. (See, [Proposed] Decision Adopting Demand Response Activities and Budgets for 2018 Through 2022 (A ), OP 24.)

4 Advice 5193-E December 1, 2017 PG&E provides the analysis ordered in the Resolution, as well as additional analysis to support modifications to PG&E s CBP triggers. Updated Analysis Using Commission-Specified Historical Time Periods Resolution E-4819 required PG&E to provide its price trigger based on consistent historical time periods (January 1, 2015 through December 31, 2016). Accordingly, PG&E updated its opportunity cost analysis, and proposes no other modifications to its model, 6 with the resultant price trigger remaining at $70/MWh. Analysis of the 2017 CBP Season Dispatches Using the Price Trigger Overall, PG&E s experience with the addition of a price trigger was very positive. By setting a clear minimum price to trigger the program, PG&E s program managers concluded that expectations of program dispatches were clear to aggregators because no complaints or questions about its CBP dispatches this season were received. Aggregators also seem to prefer the addition of the 5 event per month cap. That said, system conditions this DR season were markedly different from prior years: the frequency, duration, and magnitude of heat waves this year was notable, as reflected in higher CAISO day-ahead market prices over prior years. For instance, the maximum day-ahead locational marginal price (LMP) for the PG&E DLAP within the CBP operating hours was $ in 2015 and $ in 2016, but as high as $ in While the price trigger provided aggregators with transparency in dispatching the program based on a clear price, PG&E ultimately relied on short-term opportunity cost analysis to prevent exceeding the monthly event cap of 5 events and dispatched the program under the highest priced events representing the greatest economic value. 6 Page 4 of Advice 4887-E describes PG&E s opportunity cost model as follows: PG&E s opportunity cost analysis utilizes public, historical data from the CAISO Open Access Sametime Information System (OASIS) of hourly prices for the day-ahead market at the PG&E Default Load Aggregation Point (DLAP) [ ]. The model starts with isolating the prices for the days and hours during which the CBP program operates, and determines the minimum price needed to achieve 5 economic events during the CBP operating months. [Footnote omitted.] To allow for a range of event hours, PG&E used its model to identify the highest price each day, and identified the 5th highest value each month, such that the maximum value across the 6 months of the CBP season represents the price trigger for that year. [ ]The annual price trigger was averaged over the three years of the analysis, and rounded to the nearest $5 for simplicity, which all three IOUs agreed to. As mentioned in footnote 5, the A PD rejects PG&E s proposal to shift the CBP hours to later in the day. For this reason, PG&E presents its opportunity cost analysis using the current approved hours, 11 a.m.-7 p.m. Should PG&E be allowed to shift the program hours to correspond to grid needs at a later date, PG&E will then submit updated supplemental analysis that reflects the revised results. 7 Hourly LMP data (source: CAISO OASIS).

5 Advice 5193-E December 1, 2017 PG&E had high utilization of program hours in 2017 due to PG&E and CAISO system conditions; however, several instances occurred when a program was not dispatched even though the price trigger threshold had been met. As stated earlier, PG&E reserves the right to not call an event irrespective of the program thresholds, such as when forecasts indicate that resources may be adequate, because other non-price driven circumstances would prompt program managers to base dispatch decisions on qualitative assessments. For instance, PG&E avoids dispatching any DR program more than three consecutive days, due to customer fatigue. In addition, PG&E did not dispatch certain SubLAPs affected by the northern California wildfires as system conditions did not require it and customer response was expected to be limited. Other circumstances include instances where the price forecast available at the deadline to issue the DA event notification (3 p.m. for the prior business day) did not exceed the price trigger, but the official DA price exceeded the price trigger. For example, when the CAISO issues late day-ahead price reports, it prevents PG&E from dispatching DA CBP events with sufficient time for the 3:00 p.m. notification window. 8 A circumstance such as this one does not affect PG&E s ability to dispatch day-of. Table 1, below, reflects the CBP season total dispatches for both the DA and DO options. 8 PG&E proposed to extend the notification time to 4 p.m. and update the notification from the prior business day to the prior calendar day in its 2017 Transition Year Bridge Funding Proposal (filed February 1, 2016, in R , pp. 14, 28). The Commission approved this proposal in D , OP 23 and pp. 38, 56, and ordered PG&E to update its tariffs accordingly. However, PG&E s Advice 5055-E was suspended pending further review by Energy Division staff, and to date no formal disposition letter has been issued. Therefore, PG&E could not update its tariffs to reflect the later notification time. See Advice 5055-E, filed April 25, 2017, and Supplemental Advice 5055-E-A, filed July 12, 2017.

6 Advice 5193-E December 1, 2017 TABLE 1 CBP NUMBER OF HOURS AND EVENTS DISPATCHED, ANNUAL TOTAL(A) Line No. Load Zone Name Day-Ahead Day-Of Load Zone Hours Events Hours Events 1 Central Coast PGCC East Bay PGEB Fresno PGF Geysers PGFG Humboldt PGHB Kern PGKN North Bay PGNB North Coast PGNC North Valley PGNP Peninsula PGP South Bay PGSB San Francisco PGSF Sierra PGSI Stockton PGST ZP26 PGZP (A) The annual total reflects the full CBP season of events dispatched in May through October 2017, which includes May, prior to when the price trigger went into effect. Table 2 and Table 3, below, provide the SubLAP-specific dispatch results for the DA and DO options, respectively, between June and October, the months the price trigger was in effect. 9 In general, the price forecasts exceeded the price trigger later in the day, at the end of the program hour window, resulting in often time shorter dispatches in hour ending (HE) 18 and Resolution E-4819 was issued on May 25, 2017, so the price trigger went into effect in June.

7 Advice 5193-E December 1, 2017 TABLE 2 CBP DAY-AHEAD NUMBER OF HOURS AND EVENTS DISPATCHED BY SUBLAP June July August September October Line No. Load Zone Hours Events Hours Events Hours Events Hours Events Hours Events 1 PGCC PGEB PGF PGFG PGHB PGKN PGNB PGNC PGNP PGP PGSB PGSF PGSI PGST PGZP TABLE 3 CBP DAY-OF NUMBER OF HOURS AND EVENTS DISPATCHED BY SUBLAP Line No. June July August September October Load Zone Hours Events Hours Events Hours Events Hours Events Hours Events 1 PGCC PGEB PGF PGFG PGHB PGKN PGNB PGNC PGNP PGP PGSB PGSF PGSI PGST PGZP

8 Advice 5193-E December 1, 2017 PG&E s Preferred Price Trigger Due to the significant increase in CAISO LMPs in 2017, PG&E recommends a number of changes to the opportunity cost analysis to set a transparent, minimum price trigger that (1) better reflects changing market conditions, and (2) relies on short-term opportunity cost modeling. These changes include the following: 1) Utilize the most recent pricing data available to reflect current market conditions, which are more likely to impact next year s market conditions than data lagged by one and two years, 2) Increase the amount of history to offer stability to a minimum price trigger yearto-year and reflect the often-cyclical nature of markets, and 3) Apply a harmonic mean, as opposed to a simple arithmetic mean, to reduce the effect of outliers from 2017, while still capturing the significant and recent changes in market conditions. PG&E s preferred price trigger utilizes the same model to determine the minimum price needed to achieve 5 economic events during the CBP operating months in each year, from 2011 to 2017, and applies a harmonic mean across the 7 years. The resulting price trigger is $85/MWh. As stated above, the use of short-term opportunity cost analysis is necessary to ensure the CBP is dispatched for the highest priced events. In addition, due to low natural gas prices and the reduced reliance on natural gas power plants relative to renewable sources, PG&E proposes to eliminate the heat rate trigger. 10 Addition of a Day-Of Price Trigger On December 14, 2017, the Commission is expected to resolve PG&E s DR Program Application (A ). If the PD is approved as written, then the Commission would approve PG&E s proposal to eliminate the DO option. 11 For this reason, PG&E does not present a DO analysis in this advice letter, as this option will likely be eliminated. However, PG&E will file a supplemental advice letter proposing a DO price trigger if the Commission amends OP 24 thereby rejecting PG&E s proposal (i.e., creating a DO price trigger). 10 The heat rate trigger was based on implied heat rates, calculated using gas prices. Today, gas prices are significantly lower and fluctuations in gas prices have less influence on market conditions, and therefore, less reflect economic DR needs. 11 A PD, OP 24.

9 Advice 5193-E December 1, 2017 Conclusion PG&E requests that the Commission approve PG&E s preferred price trigger of $85/MWh, following the issuance of a final decision on PG&E s DR Program Application, which is expected to formalize the CBP hours. Should the Commission allow PG&E to shift the CBP hours to later in the day, PG&E would submit a supplemental advice letter to reflect modifications to the price trigger. In addition, PG&E requests the Commission allow PG&E to submit the final price trigger to its tariffs and remove the heat rate trigger via a Tier 1 advice letter. Protests Anyone wishing to protest this filing may do so by letter sent via U.S. mail, facsimile or , no later than December 21, 2016, which is 20 days after the date of this filing. Protests must be submitted to: CPUC Energy Division ED Tariff Unit 505 Van Ness Avenue, 4 th 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, at the address shown above. The protest shall also be sent to PG&E 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: Erik Jacobson Director, Regulatory Relations Pacific Gas and Electric Company 77 Beale Street, Mail Code B13U P.O. Box San Francisco, California Facsimile: (415) PGETariffs@pge.com Any person (including individuals, groups, or organizations) may protest or respond to an advice letter (General Order 96-B, Section 7.4). The protest shall contain the following information: specification of the advice letter protested; grounds for the protest; supporting factual information or legal argument; name, telephone number, postal address, and (where appropriate) address of the protestant; and statement that

10 Advice 5193-E December 1, 2017 the protest was sent to the utility no later than the day on which the protest was submitted to the reviewing Industry Division (General Order 96-B, Section 3.11). Effective Date Pursuant to General Order (GO) 96-B and Resolution E-4819, PG&E requests that the Commission issue a disposition letter approving this Tier 2 advice letter within 30 days, on or before January 2, Notice In accordance with General Order 96-B, Section IV, a copy of this advice letter is being sent electronically and via U.S. mail to parties shown on the attached list and the parties on the service list for R and A et al. Address changes to the General Order 96-B service list should be directed to PG&E at address PGETariffs@pge.com. For changes to any other service list, please contact the Commission s Process Office at (415) or at Process_Office@cpuc.ca.gov. Send all electronic approvals to PGETariffs@pge.com. Advice letter filings can also be accessed electronically at: /S/ Erik Jacobson Director, Regulatory Relations cc: Service List R and A et al

11 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. Pacific Gas and Electric Company (ID U39 E) Utility type: Contact Person: Yvonne Yang ELC GAS Phone #: (415) PLC HEAT WATER and EXPLANATION OF UTILITY TYPE ELC = Electric GAS = Gas PLC = Pipeline HEAT = Heat WATER = Water Advice Letter (AL) #: 5193-E Tier: 2 Subject of AL: Revised Capacity Bidding Program (CBP) Price Trigger Keywords (choose from CPUC listing): Compliance (Date Filed/ Received Stamp by CPUC) AL filing type: Monthly Quarterly Annual One-Time Other If AL filed in compliance with a Commission order, indicate relevant Decision/Resolution #: E-4819 Does AL replace a withdrawn or rejected AL? If so, identify the prior AL: No Summarize differences between the AL and the prior withdrawn or rejected AL: Is AL requesting confidential treatment? If so, what information is the utility seeking confidential treatment for: No Confidential information will be made available to those who have executed a nondisclosure agreement: N/A Name(s) and contact information of the person(s) who will provide the nondisclosure agreement and access to the confidential information: Resolution Required? Yes No Requested effective date: On or before January 2, 2018 Estimated system annual revenue effect (%): N/A Estimated system average rate effect (%): N/A No. of tariff sheets: N/A 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: N/A Service affected and changes proposed: N/A Pending advice letters that revise the same tariff sheets: N/A Protests, dispositions, 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: California Public Utilities Commission Energy Division EDTariffUnit 505 Van Ness Ave., 4 th Flr. San Francisco, CA EDTariffUnit@cpuc.ca.gov Pacific Gas and Electric Company Attn: Erik Jacobson Director, Regulatory Relations c/o Megan Lawson 77 Beale Street, Mail Code B13U P.O. Box San Francisco, CA PGETariffs@pge.com

12 PG&E Gas and Electric Advice Filing List General Order 96-B, Section IV AT&T Don Pickett & Associates, Inc. Office of Ratepayer Advocates Albion Power Company Douglass & Liddell OnGrid Solar Alcantar & Kahl LLP Downey & Brand Pacific Gas and Electric Company Anderson & Poole Ellison Schneider & Harris LLP Praxair Atlas ReFuel Energy Management Service Regulatory & Cogeneration Service, Inc. BART Evaluation + Strategy for Social SCD Energy Solutions Innovation Barkovich & Yap, Inc. G. A. Krause & Assoc. SCE Braun Blaising Smith Wynne P.C. GenOn Energy, Inc. SDG&E and SoCalGas CalCom Solar Goodin, MacBride, Squeri, Schlotz & SPURR Ritchie California Cotton Ginners & Growers Assn Green Charge Networks San Francisco Water Power and Sewer California Energy Commission Green Power Institute Seattle City Light California Public Utilities Commission Hanna & Morton Sempra Utilities California State Association of Counties ICF Southern California Edison Company Calpine International Power Technology Southern California Gas Company Casner, Steve Intestate Gas Services, Inc. Spark Energy Cenergy Power Kelly Group Sun Light & Power Center for Biological Diversity Ken Bohn Consulting Sunshine Design City of Palo Alto Leviton Manufacturing Co., Inc. Tecogen, Inc. City of San Jose Linde TerraVerde Renewable Partners Clean Power Research Los Angeles County Integrated Waste Tiger Natural Gas, Inc. Management Task Force Coast Economic Consulting Los Angeles Dept of Water & Power TransCanada Commercial Energy MRW & Associates Troutman Sanders LLP County of Tehama - Department of Public Manatt Phelps Phillips Utility Cost Management Works Crossborder Energy Marin Energy Authority Utility Power Solutions Crown Road Energy, LLC McKenna Long & Aldridge LLP Utility Specialists Davis Wright Tremaine LLP McKenzie & Associates Verizon Day Carter Murphy Modesto Irrigation District Water and Energy Consulting Defense Energy Support Center Morgan Stanley Wellhead Electric Company Dept of General Services NLine Energy, Inc. Western Manufactured Housing Communities Association (WMA) Division of Ratepayer Advocates NRG Solar Yep Energy

April 10, 2018 Advice Letter 3948-G. SUBJECT: Revisions to Appendix F to the 1997 California Production Interconnection and Operating Agreement

STATE OF CALIFORNIA PUBLIC UTILITIES COMMISSION 505 VAN NESS AVENUE SAN FRANCISCO, CA 94102-3298 EDMUND G. BROWN JR., Governor April 10, 2018 Advice Letter 3948-G Erik Jacobson Director, Regulatory Relations