Puget Sound Energy’s Use of RTF Analytical Tools for DSM Valuation

1. Puget Sound Energy’s Use of RTF Analytical Tools for DSM Valuation Jim Lazar March 4, 2003

2. Use of RTF Approaches As Part of Rate Case Settlement • May, 2002 -- Agreement on DSM Valuation Methods • Use PSE marginal costs of G, T, and D • Use RTF Load Factors by Measure • June, 2002 --Agreement on Inverted Rate Design That Was Based, in Part, On RTF Load Factors • December, 2002 -- Revised T&D Values

3. May, 2002: Agreement on DSM Valuation Methods • PSE historical -- Generic energy cost; losses only dist cost. • Staff Position: Distribution not “marginal” but large generation capacity costs • Public Counsel Position: Dist marginal, gen capacity costs in Aurora energy values • Agreement: RTF load shape and load factors, $8 gen cap, $28.65 Transmission, $24.95 distribution (vs. $3 and $20 for RTF generic T&D analysis)

4. Original Basis of $24.95/kw Distribution Capacity Cost • Take all capacity-related distribution investment, and divide by load growth • Typical of marginal cost study approaches (I.e., OPUC) • Criticism: not all of the cost is avoidable if capacity not needed • Fixed cost component for new business • Replacements of existing components

5. Settlement Approved in June, 2002 • Did not file DSM changes until September. • Worked with PSE to emulate RTF Methodology

6. Post-Settlement Commitments • PSE to develop DSM Supply Portfolio • Separate collaborative • Work due in August • TOU Evaluation • Needed G, T, and D avoided costs

7. Original Filed Avoided Costs • Filed in September, 2002 • Currently in Effect • Subject to future modification.

8. October - December, 2002 Meetings on G, T, and D • $8 generation capacity cost • Found to be redundant to Aurora, and eliminated • $28.65 trans -- not modified -- BPA rate is “avoidable” for PSE • Distribution cost extensively discussed • What’s really related to “capacity” vs. growth in customers and replacements

9. Resolutions from December 2002 Distribution Cost Analysis • Cost of extending system to serve new business removed. It is addressed separately in the line extension policy. • Replacements of existing elements removed -- does not change capacity of system • Result: $24.95/kw dropped to $6.67/kw • Combined T+D is now $35.32/kw

10. Potential Revisions Based on New Capacity Values • Not yet filed or in effect. • Probably will include revised Aurora results if/when filed • Significant Reductions in avoided capacity costs reflected.

11. What will it mean for DSM Avoided Cost? • Substitute zero for generation in spreadsheet • Substitute $35.32 for T&D in spreadsheet

12. Bottom Line -- Payment Limits for DSM Programs • Higher levels are currently in effect. • Lower levels will reflect new (higher) Aurora energy costs, so they are only a guesstimate. • Much higher than “old system” for long-lived peak-coincident savings.

13. What’s Next • New Aurora Results with (probably) higher energy costs • New Conservation Supply Curves Being Developed. • Eventually, a new DSM filing, probably with lower cost limits, but broader applicability to new supply curve.