CPUC Avoided Cost Workshop

1. CPUC Avoided Cost Workshop T&D Avoided Cost

2. T&D Comment Areas • “Adopted T&D Costs, not a uniform methodology” • Are time and location differences worth the effort? • Need for $/kW-yr capacity cost • Avoided cost only if DSM/CEE reductions are reliable • Generic T&D costs should not be used

3. Goals for the T&D Methodology • Disaggregate information by area and time to facilitate detailed analyses where appropriate • Use publicly available data, or information that can be easily provided by utilities • Transparent method • Easily updated (not necessarily on an annual basis) • Working group deliberated on several alternative approaches for methodology • Conclusion was that results were similar across several approaches (Present Worth, DTIM, TIM)

4. PW Method is Based on Deferral of Investments Base Plan • Load decrease delays investment need • PV value of deferral is PV(base plan) - PV(change plan) Load Capability Area Loads Investment PV = $7.93M BuildYear Year Shifted Plan Load Capability Load Change Investment PV = $7.35M Change Year

5. PG&E’s Electricity T&D: Comparison of Methods • Annualized MCs fell within a tight band using the DTIM, TIM or PW methods • MCs varied significantly by planning division. • Transmission MCs on a system average basis only 1999$/ kW-yr NOTE: Results exclude new business primary distribution marginal costs, which are borne by the customer and therefore not avoidable by the utility.

6. SCE Electric Distribution: Comparison of Methods • Under RCN, rural distribution has a high value because $14.5MM of investment for 20MW of new capacity • Transmission avoided costs exclude economic projects 2004$/ kW-yr

7. SDG&E Electric T&D: Comparison of Methods • When E3 calculated distribution marginal costs using 2002-2007 data, the 3 methods yielded similar results • Transmission: Although SDG&E uses embedded costs, it has clarified which investments are demand-related

8. Extrapolation of T&D Avoided Cost Estimates • PG&E: Retain cost differentials • SCE: Blended Long Term Forecast Approach (shown below) Transition Long Run Rural 2001 EE Values

9. SDG&E SCE PG&E $77.76 $36.00 $70.00 $21.00 $38.00 $5.00 $5.00 T&D Avoided Costs by Planning Division

10. Recommendation: Methods • “Use adopted T&D marginal costs, not a uniform methodology” • PW, DTIM, and TIM all produce comparable results, so using adopted values based on these methods would be fine --- provided that the adopted values retain the area differentiation • RCN can produce very different results, and should not be used. • “Are time and location differences worth the effort?” • Location does reveal significant cost differences for PG&E as well as SCE’s Rural area. Other SCE areas are less clear.

11. Allocation of T&D Based on Temperature by Climate Zone Drives Drives T&D Capacity Cost Loads Temperature Load Information Missing or Difficult to Obtain in Many Areas T&D Capacity Cost Temperature Use temperature as a proxy for load, and as the basis for allocating costs to hours of the year.

12. Summer PeakLoad vs. Temperature Fresno Similar analysis done on 33 PG&E areas as part of CEC Title 24 development Yellow 8am to 10pm

13. Example Results for PG&E Stockton

14. (From working group presentations) PG&E: Allocation by TOU Period • Low avoided costs in Oakland climate zone allocated much more evenly across TOU periods due to temperate weather Oakland on-peak is about half of Fresno.

15. Recommendation: Hourly Costs • Need for $/kW-yr capacity cost • Not needed if hourly costs are used, but could be more accurate when costs are averaged into TOU periods. • Caution must be exercised, however, to avoid overestimating capacity reductions. • Are time and location differences worth the effort? • Time difference can be dramatic in comparing coastal and inland areas.

16. Recommendation: Other T&D Issues • Avoided cost only if DSM/CEE reductions are reliable • Two aspects to this issue: • “Do you expect the reduction when you need it?” This is addressed by the hourly costs (or hourly peak allocation factors) • “What happens if the reduction is not there when you need it?” This is probably not an issue for DSM because of the high diversity of DSM reductions. This can be an issue for other proceedings, in which case the avoided cost should be de-rated. • Generic T&D costs should not be used • Do not see a need for individual studies for DSM program evaluation.

17. Gas T&D Findings

18. Gas Results are Simpler Than Electric • Results are by IOU, not sub-area • Hourly allocations are not needed because of the natural storage capability of gas pipe. • Allocation of costs to winter peak months (November through March) when peak loads occur • Results are shown by customer class to reflect the usage pattern differences of the classes. Results can also be provided at a system average level

19. Gas T&D Avoided Costs • Gas T&D annual average avoided costs can vary widely by utility, with PG&E having the highest costs • Results significantly above California 2001 energy efficiency values (about $0.03/therm)

20. No Gas Storage Costs in these Avoided Cost Estimates • Need for inventory expansions to support future growth driven by: • Growth in core demand for firm withdrawal as core peak day demand rises • Varying attractiveness of storage depending on summer/winter price differentials and the national storage market • To a considerable extent, storage and backbone transmission capacity are substitutes • The appropriateness of including storage will depend upon the extent to which peak capacity requirements are driving the need for the project.

21. Gas T&D Costs Allocated to Winter Season • Aggregate throughput by utility by summer and winter seasons. Allocate marginal costs to winter months when peak loads occur Winter Summer Winter

22. Winter Allocations by Utility