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Transmission Expansion and Cost Allocations for FERC SPP-Entergy CBA

Transmission Expansion and Cost Allocations for FERC SPP-Entergy CBA. Background. FERC is funding a SPP-Entergy Corporation Cost Benefit Analysis (CBA) to evaluate the merits and costs of Entergy joining, or not joining, SPP (FERC SPP-Entergy CBA)

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Transmission Expansion and Cost Allocations for FERC SPP-Entergy CBA

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  1. Transmission Expansion and Cost Allocations for FERC SPP-Entergy CBA

  2. Background • FERC is funding a SPP-Entergy Corporation Cost Benefit Analysis (CBA) to evaluate the merits and costs of Entergy joining, or not joining, SPP (FERC SPP-Entergy CBA) • The FERC SPP-Entergy CBA provides a foundation for the APSC-directed Cost Benefit Analysis to evaluate the merits and costs of Entergy Arkansas, Inc. (EAI) joining, or not joining, SPP (APSC EAI CBA) • The APSC EAI CBA leverages models, data, and assumptions in the FERC SPP-Entergy CBA

  3. Background, cont. • “SPP Ready” costs - incremental investments required by Entergy (and EAI) to join SPP to meet SPP reliability requirements are zero • SPP has not identified any reliability issues, assuming completion of transmission expansion projects in the Entergy Construction Plan, including horizon projects. Note that focus for this conclusion has been end state, e.g., 2022. It is expected that Entergy will need to develop and SPP would approve mitigation plans so system needs are met given several projects will not be installed until after need date • Entergy transmission expansion plans are the same in all studies and scenarios

  4. Transmission Cost Allocation Notes • Study 1-All Regional Costs: Entergy and Cleco are exposed to regional recovery of SPP upgrades completed after March, 2006 coincident with first regional recovery in SPP. (Same approach used when Nebraska entities joined SPP in April 2009) • Study 2- Regional Costs after 1/1/13: Entergy and Cleco are only exposed to regional recovery of SPP upgrades needed after the proposed “bright line” date of January 1, 2013. (Prospective) • Study 3-Regional Costs (Excluding BP and PP) After 1/1/13: Entergy and Cleco, as in Study 2, are only exposed to regional recovery of SPP upgrades needed after the proposed “bright line” date of January 1, 2013. Additionally, Entergy and Cleco were not exposed to Balanced Portfolio or Priority Project regional recovery. (Modified Prospective) • For all Studies, SPP members are exposed to regional recovery of Entergy and Cleco projects beginning January 1, 2013

  5. Transmission Cost Allocation Notes, cont. • Differential results subtract Base Case Annual Transmission Revenue Requirement (ATRR) from Change Case ATRR; where: • Differential = Change Case – Base Case • Change Case: Entergy and Cleco join SPP and share in regional recovery. SPP traditional Transmission Owners also support Entergy and Cleco upgrades. • Base Case: Entergy and Cleco do not join SPP and therefore do not share in regional recovery. Entergy and Cleco fund their own upgrades without SPP Transmission Owner support.

  6. Methods • ATRR forecast was constructed for SPP Transmission Owners, Entergy, and Cleco incorporating several upgrade types with several simplifying assumptions, e.g., maintain MW-MIs & BP balancing transfers, 3% depreciation rate for all upgrades, etc. • Host zone Net Plant Carrying Charge was applied to each upgrade to develop total ATRR for each upgrade • Cost allocation was performed for each upgrade • Focus was reallocation of regional, not zonal, ATRRs and the differential amounts ($M) between the base and change case over the 2013-2020 period

  7. Key Inputs • Net Plant Carrying Charges • Entergy = 17.49% (self reported) • Cleco = 16.87% (self reported) • Load Ratio Shares • Entergy = 35.42% (calculated using ETR’s 2009 hourly loads) • Cleco = 3.21% (calculated using CLE’s 2009 hourly loads) • Entergy and Cleco upgrades self-supplied to SPP ITC • Project lists were posted 8/16 in zip file at http://www.spp.org/section.asp?group=1784&pageID=27.

  8. Key Inputs, cont.

  9. Study 1 – All Regional Costs

  10. Study 2 – Regional Costs After 1/1/13

  11. Study 3 – Regional Costs (Excluding BP and PP) After 1/1/13

  12. Concluding Remarks • Focus of these transmission cost allocation studies have been exclusively costs, not benefits • It should be noted that PP costs assume double circuit 345 kV, not 765 kV, projects in plains • End effects and depreciation are driving results for 2017 + • Results for 2020 will be extrapolated for 2021 and 2022 to complete 2013-2022 impacts

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