George BartlettDirector, Transmission Operations

Economic Transmission ProjectsEconomic Transmission Projects

Entergy Transmission Planning Summit

New Orleans, LA

July 8, 2004

22

TopicsTopics

Issues & Challenges in Transmission Planning Internal Studies Performed to DateProposed Future Plan

33

Merchant Generation in Entergy Area by State

State MW # of IOAsAR 7,790 7MS 6,328 10LA 8,190 17TX 2,975 6TOTAL 25,283 40

Merchant generating facilities with filed IOAs

Merchant generating facilities that have filed IOAs and completed construction (19,000 MW)

44

Energy Mix for Entergy for 2003Energy Mix for Entergy for 2003

Source: GOL/AFC/WPP Technical Conference presentations (http://www.entergy.com/transmission)

Issue

55

Composition of Purchases for 2003Composition of Purchases for 2003

Not reflected in long-term planning model

Source: GOL/AFC/WPP Technical Conference presentations (http://www.entergy.com/transmission)

66

Composition of Short-Term PurchasesComposition of Short-Term Purchases

Source: GOL/AFC/WPP Technical Conference presentations (http://www.entergy.com/transmission)

Reflected only in short-termmonthly operations model

77

Summary of Issues in Entergy SystemSummary 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

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Internal Studies Performed to DateInternal 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)

LPSC Phase II Transmission Study:LPSC Phase II Transmission Study:A cost-benefit analysis verified the effectiveness A cost-benefit analysis verified the effectiveness

of transmission expansion alternativesof 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

Generation LocationsGeneration Locations

Occidental Taft

Waterford (ELA)

CarvilleShell Geismar

Exxon Baton RougeBig Cajun I Expansion

Hinds Energy Facility

Attala

Choctaw

AEP/Dow Chemical

Evangeline Project

Cottonwood

AcadiaPPG Riverside

Ouchita Power

Sterlington Power

Perryville

Panda Union

Hempstead County Batesville Expansion

Southhaven

Southaven GT

Crossroads

ANO Uprate

AREC Coop

Pine Bluff

Little RockHot Springs

Hot Springs County

Tenaska Frontier

Sabine River

Beaumont

Port Arthur Sabine Bayer-Cogen

Calcasieu

Warren Power Project

Transmission Area Amite South

Bayou Cove

Smith County

Silver Creek

BASF

Central North Arkansas WOTAB

1111

Oklahoma

Texas

Louisiana

Arkansas

Mississippi Alabama

TennesseeNORTH ARKANSAS

CENTRAL

WOTAB

AMITE SOUTH

East/Northeast

Import

Northeast AR Area Import intoImport into

Entergy from Entergy from Southern/TVASouthern/TVA

WesternImport

Import intoImport intoEntergy Entergy from SPPfrom SPP

Amite SouthImport

33 22

44

11

LPSC Phase II Transmission Study:LPSC Phase II Transmission Study:Top Four Areas for Potential BenefitsTop Four Areas for Potential Benefits

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LPSC Phase II Transmission Study:LPSC Phase II Transmission Study:Transmission ProjectsTransmission Projects

No Examined Transmission Projects State Expected Benefit (Location)

1 Construct new line from Panama to Dutch Bayou

LA

Improve Amite-South interface.(Between Baton Rouge and New Orleans

within the Company’s industrial corridor)2 Rebuild 230 kV line from Coly to

VignesLA

3 Rebuild 230 kV line from Conway to Bagatelle

LA

4 500/230 kV autotransformer at McAdams

MS Relieve congestion in Entergy’s central region. (Near Entergy-TVA border in central Mississippi near of Jackson)

5 Rebuild 115 kV line from Couch to McNeil

AR Relieve identified constraint.(Near Arkansas-Louisiana border)

6 Upgrade 230 kV line from PPG to Rose Bluff

LA Relieve identified constraint.(Near Louisiana-Texas border in Lake Charles area)

7 500/115 kV autotransformer at Sterlington

LA Improve North-South Interface(North Louisiana near city of Monroe)

Detail Set A

Detail Set B

Detail Set C

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Set A Projects: Amite SouthSet A Projects: Amite SouthConstruct a new 230 kV line from Panama to Dutch BayouRebuild 230 kV line from Coly to Vignes Rebuild 230 kV line from Conway to Bagatelle

Estimated project cost: $45 million<< Back

1414

Set B Projects: East AreaSet 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

1515

Set C Projects: MiscellaneousSet C Projects: Miscellaneous

Set A and Set B Projects, Plus:Rebuild 115 kV line from Couch to McNeilUpgrade 230 kV line from PPG to Rose Bluff500/115 kV autotransformer at Sterlington

Estimated project cost: $78 million total

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Cost/Benefit Study ResultsCost/Benefit Study Results

CaseCase20 Year NPV of 20 Year NPV of Savings ($MM)Savings ($MM)

Set A Set A

Set BSet B

Set CSet C

$260.5$127.6

Upper Bound Lower

Bound

$170.6

$147.2

$310.9

$290.3

UpperUpper andand LowerLower BoundsBounds

• 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

Limitation of LPSC Phase II StudyLimitation 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

Summary of LPSC Phase II StudySummary 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.

2020

Proposed Future PlanProposed Future PlanReliability 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.

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Proposed Future Plan (Cont.)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

Questions?Questions?