AVOIDED COST OF TRANSMISSION AND DISTRIBUTION WORKSHOP

1. AVOIDED COST OF TRANSMISSION AND DISTRIBUTION WORKSHOP July 18, 2019 Energy Division

2. Introduction and Overview of Staff Proposal 10:00-10:30

3. Workshop Objectives • Present and discuss staff white paper on methodologies to calculate the avoided cost of transmission and distribution, and to support parties in preparation of reply comments to the June 13, 2019 Ruling • To discuss the appropriate locational granularity to include in the avoided cost calculator • Consider application of proposed methods to various use cases

4. Agenda 10:00-10:30 Introduction and Overview on Staff Proposal 10:30-12:30 ED Staff Proposed Methodology for Unspecified Distribution Deferral 12:30-1:30 Lunch 1:30-3:00 Discussion on Unspecified Transmission Methodology 3:00-4:00 Application of methodology to Use Cases

5. Clarifying Key Concepts in Staff White Paper: Use Cases * The third use case identified in D.17-09-026 is expected to provide the inputs for the avoided cost calculator, which informs the non-RFO forms of DER procurement, including NEM tariffs, EE and DR portfolio budgets.

6. Clarifying Key Concepts in Staff White Paper: Counterfactual v. Trajectory Forecasts • The chart below is the CEC demand forecast—the red, downward sloping curve reflects the “trajectory forecast” • Counterfactual forecast—load forecast with DERs removed • Different demand trajectories will produce very different avoided T&D values Cumulative impacts of DERs on demand forecast Forecast simplified for illustrative purposes. Actual counterfactual forecast must be adjusted for Codes and Standards and peak shift, and impact of EVs is included in forecast but not shown on this chart

7. Clarifying Key Concepts in Staff White Paper: Specified v. Unspecified Deferral Specified Deferral Value Unspecified Deferral Use Cases: Inform long-term DER programs and policies via avoided cost calculator Potentially establish location-specific tariffs Provide T&D impacts of DERs to IRP modeling for meeting GHG targets Avoided cost calculation: Reflects the deferred Dx costs that result from DER growth that is embedded in the forecast due to existing programs and tariffs Calculation must use a counterfactual forecast Use Cases: • Identify circuit-specific, DER procurement opportunities based on near term needs • Evaluate DER proposals for short-term Dx deferral projects via DIDF Avoided cost calculation: • Reflects deferral opportunities under trajectory stress conditions defined by IEPR forecast • Is limited to the circuits with DIDF candidate deferral projects selected for competitive solicitation

8. Opening Comments on White Paper and Next Steps for Development of Values

9. Staff Proposed Next Steps to Adoption of New Values for ACC

10. ED Staff Proposed Methodology for Unspecified Distribution Deferral 10:30-12:30

11. Session Agenda

12. Methodology Overview Part 1: Estimate the distribution capacity that is deferred by DERs (Q) • Calculate counterfactual forecast—by “removing” forecasted DER installations from IEPR demand forecast • Calculate capacity overload for counterfactual forecast—Loading of distribution circuit can be derived from ratio of forecasted load and circuit capacity • Estimate the percentage of distribution capacity overloads that lead to deferred distribution upgrades* Part II: Estimate the value of deferring distribution system upgrades (P) • Calculate the marginal cost of the deferred distribution upgrades, based on DDOR and/or GRC data • Detailed description of methodology is included in the appendix to this presentation • *This step will not be needed because the 2019 GNA will provide the capacity distribution upgrades

13. Limitations to the Preliminary Analysis The following issues need to be addressed in order to implement proposed methodology • Completeness of the 2019 GNA: Will 2019 GNA be complete enough? • Amount and location of no-cost transfers • DER production shapes • Removal of naturally occurring EE savings: Is it really significant enough to merit this step? • 5-year versus 20-year forecasting horizon, • Current load forecast trajectory: What impact would growth of electrification have on the calculations? • Are some of the circuits deferred that are listed in the upgrades? • Definition and construction of marginal cost (i.e. “P”) • Other adjustments needed to the analysis?

14. Discussion of Dx Methodological Questions Topic 1: GNA Data Topic 2: DER Data What DER production loads shapes should be used and how should they be applied? What are the data sources for each technology? Does the GNA data represent all the distribution upgrades that are being deferred by DERs? Topic 3: Forecasts Topic 4: Definition of “P” How is P calculated? Should the DDOR data or the GRC be the basis of P? Should the GNA forecast horizon be extended? If DERs useful life is at least 20 years, should the capacity deferred be multiplied by 4?

15. Results of Preliminary Analysis DERS caused 21 MW of deferred distribution capacity, equal 1.2% of the total 1,700 MW DER growth that is forecasted to occur during this time period . Overview of Results from PG&E Preliminary Analysis NOTE: These are PRELIMINARY results, and should not be interpreted to represent the actual deferral value of DERs, a full analysis is needed, they just provide an indication of the scale of DER impacts

16. Discussion of Feasibility of Implementation and Implications of Preliminary Results E3 to provide initial thoughts on the feasibility of implementing the analysis based on the adjustments raised by parties, and how they may impact the results.

17. LUNCH 12:30-1:30 pm

18. Unspecified Transmission Avoided Costs 1:30-3:00 pm

19. Factors Complicating Avoided Tx Calculation Factors complicating calculation of Avoided Tx value: • Generation and Tx can serve as substitutes in the ACC. • Avoided cost of Tx is highly specific to the individual transmission project. • Additionally, local RA value is subject to many additional factors so determining the avoided cost of Tx overlaps with avoided cost of generation. • Tx capacity constraints are not as clearly defined as Dx capacity constraints. • Tx required to meet “N-1 contingency” which varies by location and depends on the shifting loading capacities of other neighboring circuits. • Tx reliability standards are established and regulated at the national level, and the solutions are often “lumpier” than those for Dx reliability and are implemented through several separate processes. • Tx solutions are developed to address economic and policy objectives as well as more specific reliability objectives. • Transmission needs are planned for a 50-year asset. • Tx solutions are typically harder to site and permit than Dx solutions, primarily because Tx assets are larger in scale. • Tx solutions are subject to longer-term planning horizons than Dx planning. • Tx planning is more defined by long-term population growth and generation requirements. • The ratio of Tx need to typical DER size is much larger than the ratio of Dx need to typical DER size.

20. External Presentations • Tom Beach, SEIA • Aram Shumavon, Kevala

21. Recommendations for Use Cases 3:00-4:00

22. Recommended Methodologies for Estimating Deferral Values Source: Administrative Law Judge’s Amended Ruling Requesting Comments On The Energy Division White Paper On Avoided Costs And Locational Granularity Of Transmission And Distribution Deferral Values. June 13, 2019

23. Recommended Applications to Granularities to DER Use Cases

24. Considerations of the ACC Calculator Tool for Use Case 3 • Original objective: to incorporate locational value into Avoided Cost Calculator to inform NEM and EE with locational values. However: • Locational values change with feeder reconfigurations • ACC tool is updated on annual basis • ACC tool is used to make broad policy decisions for NEM and EE/DR budgets • Thus, Staff recommends that the ACC tool is maintained on a service territory level

25. Discussion of outcomes of deferral analysis to date, and implications for next steps • Specified deferral capacity appears to be low—is limited to the projects that that result in successful contracts with DERs • Unspecified deferral capacity appears to be low—PG&E preliminary analysis suggests that 2-4% of DER capacity may result in unspecified distribution deferral • Load growth from electrification may increase needs for upgrades, and thus deferral opportunities • Could the GNA analysis inform additional long-term deferral opportunities?

26. ATTACHMENTS

27. Proposed Unspecified Dx Methodology • Calculate the Counterfactual Forecast Sample Circuit-level Calculation of Counterfactual Forecast Source: Sample set of circuits from PG&E’s 2018 GNA

28. Proposed Unspecified Dx Methodology • Calculate capacity overload for counterfactual forecast Capacity Overload for Sample Circuits in Counterfactual Forecast

29. Proposed Unspecified Dx Methodology 3. Estimate the percentage of distribution capacity overloads that lead to deferred distribution upgrades Capacity Overload for Sample Circuits in Counterfactual Forecast