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

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use of rtf approaches as part of rate case settlement
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
may 2002 agreement on dsm valuation methods
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)
original basis of 24 95 kw distribution capacity cost
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
settlement approved in june 2002
Settlement Approved in June, 2002
  • Did not file DSM changes until September.
  • Worked with PSE to emulate RTF Methodology
post settlement commitments
Post-Settlement Commitments
  • PSE to develop DSM Supply Portfolio
    • Separate collaborative
    • Work due in August
  • TOU Evaluation
    • Needed G, T, and D avoided costs
original filed avoided costs
Original Filed Avoided Costs
  • Filed in September, 2002
  • Currently in Effect
  • Subject to future modification.
october december 2002 meetings on g t and d
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
resolutions from december 2002 distribution cost analysis
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
potential revisions based on new capacity values
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.
what will it mean for dsm avoided cost
What will it mean for DSM Avoided Cost?
  • Substitute zero for generation in spreadsheet
  • Substitute $35.32 for T&D in spreadsheet
bottom line payment limits for dsm programs
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.
what s next
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.