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

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

3. 3 Merchant Generation in Entergy Area by State StateMW# of IOAs AR 7,7907 MS 6,328 10 LA 8,190 17 TX 2,9756 TOTAL 25,28340 Merchant generating facilities with filed IOAs Merchant generating facilities that have filed IOAs and completed construction (19,000 MW)

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

5. 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. 6 Composition of Short-Term Purchases Source: GOL/AFC/WPP Technical Conference presentations (http://www.entergy.com/transmission) Reflected only in short-term monthly operations model

7. 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. 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. Generation Locations

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

12. 12 LPSC Phase II Transmission Study: Transmission Projects NoExamined Transmission ProjectsStateExpected Benefit (Location) 1Construct new line from Panama to Dutch Bayou LA Improve Amite-South interface. (Between Baton Rouge and New Orleans within the Company’s industrial corridor) 2Rebuild 230 kV line from Coly to Vignes LA 3Rebuild 230 kV line from Conway to Bagatelle LA 4500/230 kV autotransformer at McAdams MSRelieve congestion in Entergy’s central region. (Near Entergy-TVA border in central Mississippi near of Jackson) 5Rebuild 115 kV line from Couch to McNeil ARRelieve identified constraint. (Near Arkansas-Louisiana border) 6Upgrade 230 kV line from PPG to Rose Bluff LARelieve identified constraint. (Near Louisiana-Texas border in Lake Charles area) 7500/115 kV autotransformer at Sterlington LAImprove North-South Interface (North Louisiana near city of Monroe) Detail Set A Detail Set B Detail Set C

13. 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. 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. 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. 16 Cost/Benefit Study Results Case 20 Year NPV of Savings ($MM) Set A Set B Set C $260.5 $127.6 Upper Bound Lower Bound $170.6 $147.2 $310.9 $290.3

17. Upper and Lower Bounds 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. 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. 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?Questions?