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Economic Transmission Projects

Economic Transmission Projects

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Economic Transmission Projects

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  1. Economic Transmission Projects George Bartlett Director, Transmission Operations Entergy Transmission Planning Summit New Orleans, LA July 8, 2004

  2. Topics • Issues & Challenges in Transmission Planning • Internal Studies Performed to Date • Proposed Future Plan

  3. Merchant Generation in Entergy Area by State State MW # of IOAs AR 7,790 7 MS 6,328 10 LA 8,190 17 TX2,975 6 TOTAL 25,283 40 Merchant generating facilities with filed IOAs Merchant generating facilities that have filed IOAs and completed construction (19,000 MW)

  4. Energy Mix for Entergy for 2003 Issue Source: GOL/AFC/WPP Technical Conference presentations (http://www.entergy.com/transmission)

  5. Composition of Purchases for 2003 Not reflected in long-term planning model Source: GOL/AFC/WPP Technical Conference presentations (http://www.entergy.com/transmission)

  6. Composition of Short-Term Purchases Reflected only in short-term monthly operations model Source: GOL/AFC/WPP Technical Conference presentations (http://www.entergy.com/transmission)

  7. Summary of Issues in Entergy System • Generation to load ratio will be ~2:1 by 2005. • Uncertainty in planning for future system due to short-term purchases. • Loop flow due to various tie lines. • Incentive to invest in bulk transmission system

  8. Internal Studies Performed to Date • Bulk Power Study (2002) • Identified transmission projects to accommodate point to point transmission requests on Entergy system. • Ten projects, including at least 800 miles of 500 kV lines and three autotransformers, are required to move ~9,300 MW to Entergy’s border and to embedded load. • Total transmission expansion cost is ~$1.9 Billion (i.e., $205/kW) • LPSC Phase II Transmission Study (2003)

  9. LPSC Phase II Transmission Study: A cost-benefit analysis verified the effectiveness of transmission expansion alternatives • Examined transmission expansion alternatives • Aimed at alleviating internal and external interface limitations • Considered 13,800 MW of merchant capacity available by summer 2004 along with Entergy owned units to serve native load • 81 potential constraints identified for 2003-2012 simulation period in PROMOD

  10. Southhaven ANO Uprate Hot Springs Little Rock Southaven GT Pine Bluff Hot Springs County AREC Coop Batesville Expansion Hempstead County Crossroads Panda Union Attala Choctaw Transmission Area Ouchita Power Amite South Silver Creek Perryville Central North Arkansas WOTAB Sterlington Power Hinds Energy Facility Warren Power Project Evangeline Project Smith County Cottonwood Tenaska Frontier Big Cajun I Expansion Calcasieu Exxon Baton Rouge BASF Beaumont Shell Geismar Carville Acadia Sabine River PPG Riverside Occidental Taft AEP/Dow Chemical Port Arthur Sabine Bayer-Cogen Waterford (ELA) Bayou Cove Generation Locations

  11. LPSC Phase II Transmission Study:Top Four Areas for Potential Benefits 2 Import into Entergy from SPP 3 Northeast AR Area Western Import Import into Entergy from Southern/TVA 4 East/ Northeast Import 1 Amite South Import

  12. LPSC Phase II Transmission Study:Transmission Projects Detail Set A Detail Set B Detail Set C

  13. Set A Projects: Amite South • Construct a new 230 kV line from Panama to Dutch Bayou • Rebuild 230 kV line from Coly to Vignes • Rebuild 230 kV line from Conway to Bagatelle Estimated project cost: $45 million << Back

  14. Set B Projects: East Area • Set A Projects, Plus: • McAdams autotransformer to improve Entergy’s import capability from the east Estimated project cost: $53 million total << Back

  15. Set C Projects: Miscellaneous • Set A and Set B Projects, Plus: • Rebuild 115 kV line from Couch to McNeil • Upgrade 230 kV line from PPG to Rose Bluff • 500/115 kV autotransformer at Sterlington Estimated project cost: $78 million total

  16. Upper Bound Cost/Benefit Study Results $260.5 $127.6 $290.3 $147.2 $310.9 $170.6 Lower Bound

  17. UpperandLowerBounds • Upper Bound Assumes • Increases in transfer capability constant throughout study • No additional transmission expansion projects • Lower Bound Assumes • Transfer capabilities reduced throughout study period • No additional transmission expansion projects

  18. Limitation of LPSC Phase II Study • Could not examine voltage constraints • PROMOD IV output based on DC solution methodology • Unable to monitor all transmission constraints • Footprint of the detailed model is limited to Entergy only • Changes in external system dispatch that may impact various internal constraints were not considered • Must-run unit requirements and import/export limits could not be changed dynamically based on the system condition in PROMOD IV

  19. Summary of LPSC Phase II Study • North Arkansas area constraint • City of Jonesboro committed to fund third line (ISES-Newport) • In Service Date: By Summer 2005 • Import from Western area • OG&E committed to install a 500/161 kV auto at Ft. Smith • In Service Date: By December 2004 • Company committed to proceed with the projects identified in Set A • (Amite South improvement plan) • At present, projects are in scoping/engineering phase • Projected In Service Date: Summer 2007 • Projects in Sets B and C to be reviewed through planning process • Company identified Sterlington 500/115 kV auto as RMR issue and committed to install additional auto by year end 2005.

  20. Proposed Future Plan Reliability planning • Continue to determine reliability projects based on traditional planning models and software (PSS/E, MUST) • Verify the need of those proposed reliability projects that might be impacted by a change in unit commitment by looking at market-based dispatch. • Use indicators like congestion hours, production cost or load payment to compare/prioritize proposed projects. • Prioritize those projects that have both reliability and economic impact.

  21. Proposed Future Plan (Cont.) Economic Planning • Identify potential bottlenecks on the system using historical operational constraints (TLRs, flowgates, etc.) • Determine cost-effective solutions that would increase the transmission throughput • Coordinate this effort with neighboring utilities to address any seams issues. • Encourage participant funding for the market-driven economic projects

  22. Questions?