1. 1 Energy Division Workshops: LTPP Planning Standards (Part 1) & Procurement Rulebook June 11, 2010 Workshop R.10-05-006, Tracks 1, 2, & 3

2. 2 Energy Division Staff Proposal on LTPP Planning Standards Part 1 June 11, 2010 Workshop R.10-05-006, Tracks 1 & 2 Nathaniel Skinner & Rebecca Lee CPUC Energy Division

3. 3 Workshop Objectives Help participants understand the purpose of the Planning Standards (Part 1) Facilitate helpful comments on Staff Proposals: –June 21 –June 28, Replies Separate workshops will be held for: –Planning Standards (Part 2): RPS –Planning Standards (Part 3): EE

4. 4 Agenda Planning Standard Goals Standardized L&R Tables Portfolio Evaluation Criteria Scenarios Base Case Assumptions Sensitivity Analysis

5. 5 Planning Standards Goals For a core set of analyses –Internally consistent system plans –Easily comparable To produce for the Scoping Memo –Finalized planning standards –Finalized L&R Table Templates –Full descriptions of required scenarios

6. 6 Guiding Principles Assumptions should –Take a realistic view of policy-driven resource achievements to ensure electric reliability and track progress toward resource policy goals –Reflect behavior of market participants

7. 7 Resource Plans should –Be informed by an open and transparent process –Consider whether significant new investments in transmission and flexible resources would be needed to reliably integrate and deliver new resources to loads Guiding Principles

8. 8 Resource scenarios should provide useful information Resource portfolios should be substantially unique from each other Guiding Principles

9. 9 Who does the analysis? May 28 th 2010 Planning Standard Ruling requires the three largest IOUs (PG&E, SCE, SDG&E) to be responsible for the system plans for their individual service areas Other LSEs are encouraged to actively participate Note: The system resource plans prepared by the IOUs with specific Commission guidance are not IOU proposals

10. 10 Planning Standards (Part 1)

11. 11 Background In R.08-02-007, the Commission considered proposals to standardize the IOUs’ resource planning practices, assumptions, and analytical techniques July 1, 2009 Staff Proposal contained specific recommendations Based on the record in R.08-02-007, Staff proposes that the IOUs’ filing of system resource plans (Track I), and bundled LTPPs (Track II) should be based on a limited set of planning standards

12. 12 Standardized L&R Tables Purposes –To help improve comparability across plans –To create summaries of the “managed forecasts” used for the LTPP Developed by ED and the IOUs –Supported by other parties to R.08-02-007 Staff anticipates templates will be finalized in the Scoping Memos for Tracks 1 and 2

13. 13 Load & Resources Tables for System Resource Planning Attachment 1

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15. 15

16. 16 Load & Resources Tables for Bundled LTPP Filings Attachment 3

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18. 18

19. 19 Portfolio Evaluation Criteria

20. 20 Table 1: Required Evaluation Criteria for Resource Plans (Attachment 2, pp. 3-4) Table 5: Required Evaluation Criteria for Bundled LTPPs (Attachment 4, pp. 2-3) Portfolio Evaluation Criteria

21. 21 Cost Criteria - PVRR Present Value Revenue Requirement –All costs required to meet service area demand that are expected to enter into rates –Total utility revenue requirements summed for each year and discounted back to base year dollars using an appropriate discount rate –Must include CO2 allowance cost forecast –Shall be calculated over a minimum of 20 years

22. 22 Cost Criteria – Utility Average Rate Calculated for each year as the revenue requirement of each portfolio divided by total sales in that year Present value of the utility average rate shall also be calculated –PVRR / present value of total sales

23. 23 Cost Criteria - TRC Total Resource Cost (customer and utility) –Used to include the costs of customer contributions in addition to utility support –Customer and utility costs should be calculated for all utility- sector programs administered by the Commission –Includes EE, DR, CSI, CHP, and others Excludes incentives the utility pays to the customer Not necessary to calculate programs administered outside of utility programs such as building codes and standards Note: This criterion is only used for system plans

24. 24 Risk Criteria Robust scenario analysis for system plans –ED RPS scenarios –Proposed alternative scenarios Robust sensitivity analysis TEVaR for bundled plans

25. 25 Risk Criteria – RPS Scenarios Staff Draft Report expected week of June 14 th Presented in workshop on June 18 th Comments on RPS Scenarios due July 9th Replies on RPS Scenarios due July 16 th Note: These criteria are only used for system plans

26. 26 Risk Criteria – Alternate Scenarios IOUs or other parties may propose for the Commission to consider Anticipated that the Assigned Commissioner will determine a reasonable minimum set of scenarios for the Scoping Memo based on parties’ comments Must be consistent with Guiding Principles Note: This criterion is only used for system plans

27. 27 Risk Criteria - Sensitivities System –Sensitivities conducted only on the Base Case scenario –Assumed that resource portfolio and dispatch will not change –Discussion of required sensitivities is later in the presentation Bundled –Risk metrics shall measure the sensitivity of each portfolio’s average cost to changes in key cost parameters –IOUs shall also continue to calculate formal risk metrics, such as TEVaR

28. 28 GHG Emissions Total GHG Emissions Average, per ton Cost of GHG Emissions Abatement Qualitative assessment of Long-Term GHG Implications

29. 29 GHG – Total Emissions Resource plans shall report the total GHG emissions associated with each portfolio during each year of the planning horizon

30. 30 GHG – Average Abatement Cost Abatement costs are compared against meeting all future resource needs with only new natural gas fired resources –Used for benchmarking purposes only Average, per ton cost of CO2 emissions reductions relative to the all gas case –Calculated based on change in PVRR of the portfolios versus the “all gas” portfolio Discounted to present day values

31. 31 GHG – Long-Term Implications Qualitative assessment of each portfolio’s impacts on the state achieving long-term GHG goals –80% below 1990 levels by 2050 –Potential impact of portfolio choice to influence long- term technology transformation –Not intended to be highly specific and quantitative in nature –Interested in parties’ perspective as to which technologies hold the most promise for long-term benefits

32. 32 Required Base Case Portfolio Assumptions

33. 33 Common Assumptions System & Bundled Load Forecast Energy Efficiency Demand Response Peak Capacity Value Planning Reserve Margin

34. 34 Assumptions - Load Forecast Most recent IEPR 1-in-2 base case load forecast System only: –Local RA needs assessments use 1-in-10 load forecast Bundled only: –1-in-2 load forecast, including CEC assumptions about departing load

35. 35 Assumptions - EE Committed EE –Embedded utility EE program savings in the most recent IEPR base case load forecast Uncommitted EE –Levels of EE savings that are incremental to the most recent IEPR base case load forecast –Will be covered more fully in Planning Standards (Part 3) Workshop on June 25 th Data Sources Include –California Energy Demand 2009 –CEC Committee Report on Incremental Impacts of Energy Efficiency –Itron Consultant Report on Incremental Impacts of Energy Efficiency –CPUC EE Goals (D.08-07-047)

36. 36 Assumptions – DR Provided in the form of ex-ante annual load impact forecasts for 2011-2020 Use the August Monthly System Peak Load Day under a 1-in-2 weather condition If estimates are significantly revised between the Scoping Memo and the utilities’ filed resource plans (est. Q1 2011), parties will be able to comment on revised estimates

37. 37 Assumptions – DR IOUs propose forecasted Demand Response load impacts based on April 1 st Load Impact Report Compliance Filing, pursuant to D.08-04-050, OP 4 which –Reflect current DR program plans (2009-2011) –DR programs approved through other proceedings –Other anticipated DR programs/resources anticipated, such as Automated Metering Infrastructure (AMI) systems

38. 38 Assumptions – Peak Capacity Net Qualifying Capacity values per the RA proceeding

39. 39 Assumptions – PRM Planning Reserve Margin will be 15%-17% of peak demand, or as modified in R.08- 04-012

40. 40 Assumptions System Only Customer-side DG Resource Additions and Retirements

41. 41 System Assumptions – DG Customer-side DG, including CSI, are assumed to be the embedded levels of self-generation in the most recent IEPR base case load forecast

42. 42 System Assumptions - Resources IOUs will propose assumptions on resource additions, totals will be listed in L&R Tables –Specify which additions and retirements are assumed –Known/High Probability Additions Contract in place, permitted, and under construction “Other” fields should include contracted resources that have not yet begun construction The Scoping Memo will specify an approach for plant retirements consistent with OTC policy

43. 43 Common Cost Variable Assumptions

44. 44 Cost Assumptions For System and Bundled Plans Renewable Resource Availability / Cost New Generation Tax and Financing Cost Traditional Transmission & Distribution Cost Renewables Transmission Cost Conventional and Other Resource Cost Natural Gas Price Carbon Price GHG Policy Assumption (Compliance Cost) Generic Renewable Resource Cost System Bundled

45. 45 Renewable Resource Availability and Cost Will be proposed by Staff in the forthcoming Draft RPS Planning Standards Will be presented and discussed in the June 18 th 2010 Workshop Data sources include –RETI –Energy Division RPS Contract Database –E3 Assessment of REC Availability

46. 46 New Generation Tax and Financing Cost For new renewable generation, Staff will propose tax and financing cost assumptions in the forthcoming Draft RPS Planning Standards For non-renewable generation, IOUs propose tax and financing assumptions for CPUC consideration

47. 47 Traditional T&D Cost Assumptions In R.04-04-025, the CPUC adopted the E3 Avoid Cost Methodology for calculating the avoided cost. (D.05-04- 024) The methodology calculates avoided electric T&D cost (differentiated by hour, utility, planning area, and climate zones)

48. 48 Renewables Transmission Cost For transmission to access new renewable resources, ED staff will propose transmission cost assumptions in the forthcoming Draft RPS Planning Standards

49. 49 Cost Assumptions From Market Price Referent (MPR) MPR includes cost methods and inputs to calculate –Non-fuel cost assumptions for conventional resources –Natural gas price forecast –Carbon price (estimated GHG compliance cost) MPR is currently employed to assess the cost reasonableness of renewable contracts. MPR represents the “all-in” cost to own and operate a baseload combined cycle gas turbine power plant over various time periods

50. 50 Generic Non-Fuel Cost Assumption from MPR

51. 51 MPR Natural Gas Price Forecast (D.08-10-026)

52. 52 Carbon Price from 2009 MPR (Res E-4298) CO 2 Conversion201220152020 MPR GHG compliance cost in short tons (nominal$ / CO 2 ton) $10.44/ CO 2 ton $24.35/ CO 2 ton $43.52/ CO 2 ton Conversion to Metric Ton (nominal$ /MT CO 2 ) $11.51/ MT CO 2 $26.84/ MT CO 2 $47.97/ MT CO 2

53. 53 Sensitivity of Portfolio Cost Natural gas price Carbon price Need determination Generation resource technology cost (system planning)

54. 54 Sensitivities We are seeking comments and/or alternative proposals on what sensitivity values should be established in the Scoping Memo –High and Low values

55. 55 Thank you! For Additional Information: www.cpuc.ca.gov/PUC/energy/Procurement/LTPP/LTPP2010

56. 56 Extra Slides

57. 57 Attachment 1 – L&R Table Notes Notes by Line Number: 1 System peak demand represents peak demand in CAISO's control area, North of Path 26 (NP26) or South of Path 26 (SP26). This includes the PG&E service area and participating publicly owned utilities in the NP26 region served by the CAISO. 2 Service area peak demand represents the peak demand in the PG&E service area, independent of LSE providing service. Service area peak demand includes bundled and direct access (DA) customer peak demand, and excludes publicly owned utility (POU) peak. 7 Resources included here match the CEC's most recent resource assessment from [date and document source]. 10 System resource additions that have a contract in place, have been permitted, and have construction well under way. 12 System resource additions resources that have a contract, but have not yet begun construction. 13 System resource additions resources that have a contract, but have not yet begun construction. 14 Sum of all imports and exports into service area. 19 Service Area Portion of System Resources = Total System Resources *( Service Area Demand/System Demand) 20 Available Planning Reserve = Service Area Resources - Service Area Demand (not adjusted to account for the difference between firm and non-firm imports) 21 Available Planning Reserve = Available Planning Reserve/Service Area Demand 22 Service Area Demand * 15% 23 Service Area Demand * 17% 24 Line 20 + (adjusted for firm imports by adding 15% of Line 16) - Line 22 25 Line 20 + (adjusted for firm imports by adding 17% of Line 16) - Line 23

58. 58 Attachment 1 – L&R Table Notes for SDG&E NOTES (by Line number): 1 Based on CEC's 2009 IEPR 1-in-2 peak demand, which embeds self-served load and committed EE. 6 Resources included here match the CEC's most recent resource assessment from [date and document source]. 9 System Resource additions that meet predetermined criteria. 13 Sum of all imports and exports into service area. 18 Available Planning Reserve = Service Area Resources - Service Area Demand (not adjusted to account for the difference between firm and non-firm imports) 19 Available Planning Reserve = Available Planning Reserve/Service Area Demand 20 Service Area Demand * 15% 21 Service Area Demand * 17% 22 Line 19 + (adjusted for firm imports by adding 15% of Line 15) - Line 21 23 Line 19 + (adjusted for firm imports by adding 17% of Line 15) - Line 22