ISTEP · 2010-02-18 · ISTEP 2009 . I. Executive Summary On November 17, 2006 the ICT initiated...

ISTEP

ICT Strategic Transmission Expansion Plan

2009 Report

Rev. 0

ICT Planning

Revision Issue Date Description of Revision 0 2/17/10 Posted on Oasis

ISTEP 2009

Table of Contents Table of Contents........................................................................................................................................1 I. Executive Summary ...........................................................................................................................2 II. Background.........................................................................................................................................3 III. Objectives ...........................................................................................................................................5

A. Improving Load-Serving Capability ..................................................................................................5 B. Improving Transfer Capability ..........................................................................................................5 C. Improving Deliverability to Load Pockets/Load Centers ..................................................................5 D. Relieving Constraining Flowgates....................................................................................................5

IV. Models and Assumptions .............................................................................................................6 A. Engineering Models Assumptions....................................................................................................6 B. Economic Assessment Models Assumptions ..................................................................................6

V. Study Results......................................................................................................................................9 A. South Central Arkansas/Northeast Louisiana Constraint ................................................................9 B. Central Arkansas Constraint ..........................................................................................................13 C. Lake Charles 230 kV Loop.............................................................................................................16 D. Baton Rouge/South Mississippi Constraint....................................................................................19 E. Jackson Area .................................................................................................................................22

VI. Summary.......................................................................................................................................25 VII. Appendix A ...................................................................................................................................26 VIII. Appendix B ...................................................................................................................................28 IX. Appendix C ...................................................................................................................................29 X. Appendix D ...................................................................................................................................30 XI. Appendix E ...................................................................................................................................31 XII. Appendix F....................................................................................................................................32 XIII. Appendix G ...................................................................................................................................33

1

ISTEP 2009

I. Executive Summary On November 17, 2006 the ICT initiated its duties laid out in Attachment A of the ICT Agreement and further defined in Attachments S and T of Entergy’s OATT. Annually, the ICT has developed the ICT Strategic Expansion Plan (ISTEP) recognizing that a long-term analysis is needed to encourage transmission expansion on the Entergy transmission system beyond the three-year window provided by Attachment T. Section 3.2 of Attachment T states:

The ICT will assess whether a proposed upgrade should be considered a Base Plan Upgrade or Supplemental Upgrade. For purposes of this Section 3.2, the ICT will consider only upgrades in the then-current Base Plan for which construction is to be initiated within the next 3 years.

The Attachment S language, relocated to Attachment K due to modifications imposed by FERC Order 890, provides additional guidance in the development of transmission expansion projects. Another duty of the ICT, as outlined in Section 14 of Entergy’s proposed Attachment K, is that of identifying potential economic upgrades. Section 14 of Attachment K states:

The ICT will identify such upgrades based on screening criteria, which may include considerations such as frequent transmission loading relief events, frequently constrained flowgates in the Available Flowgate Capability process or the Weekly Procurement Process (WPP), flowgates with high congestion costs as identified in the WPP process, and commonly invoked must-run operating guides.

A primary purpose of this Plan is to promote EHV expansion on the Entergy transmission system by identifying problem areas and developing long-term strategic solutions. The projects identified in the ISTEP are proposed outside the scope of the ICT Base Plan. The expectation is that such facility upgrades will provide enhanced reliability and economic benefits to Entergy transmission system users. The ISTEP is not an evaluation Entergy Transmission System compliance with NERC Transmission Planning Standards, which allow for the use of operating guides, redispatch, breaker operation, or other mitigation plans. These mitigation plans have not been taken into account in this analysis.

2

ISTEP 2009 II. Background The following ten ISTEP 2009 projects were proposed with each consisting of one or more transmission system upgrades.

1. Proposed Projects a. Lake Charles 230 kV Loop (relieve 138 kV flowgate NELLC_NELLCB) b. Relieve Waterford-Little Gypsy 230 kV flowgate (WATGYP_WATGP) c. NW Texarkana-Fulton-El Dorado 345 kV d. Increase AMRN-EES interface e. Baton Rouge/South Mississippi constraint f. South Central Arkansas/Northeast Louisiana constraints g. Central Arkansas Constraint h. SOCO/SMEPA Interface Improvement i. Western Region j. Jackson Area

These projects were grouped by geographic area, and focused on creating new, higher-voltage transmission in order to address system expansion and performance needs on the Entergy Transmission System, as opposed to upgrading the underlying lower-voltage systems. Subsequent to the publication of the ISTEP 2009 report, the ICT requested the stakeholders provide the ICT with a priority ranking for the ISTEP 2009 projects. Based on the stakeholders’ rankings, along with the ICT’s knowledge of the Entergy transmission system, a final ranking was developed. On April 22, 2009, the ICT issued the top five (5) projects for further study as follows:

2. Selected Projects for Further Study a. South Central Arkansas/Northeast Louisiana constraint b. Central Arkansas Constraint c. Lake Charles 230 kV Loop d. Baton Rouge/South Mississippi constraint e. Jackson Area

3

ISTEP 2009 ISTEP 2009 study results are the subject of this report.

4

ISTEP 2009

III. Objectives The ISTEP 2009 was created with several key objectives driving the projects that compose the Plan. Those objectives are: improving load-serving capability, improving transfer capability, improving deliverability to load pockets/load centers, and relieving constraining flowgates. These objectives combine in order to provide a more robust transmission system that is capable of both reliable service and the economic delivery of power across the transmission system. Each objective is discussed in further detail below.

A. Improving Load-Serving Capability The ISTEP 2009 projects are designed to enhance the transmission system by improving its ability to serve load. The upgrades accomplish this task by providing increased voltage, increased thermal capacity, and additional paths from the generation to the load.

B. Improving Transfer Capability The Entergy Transmission System interfaces with 19 control areas, including both SERC and SPP members. The ISTEP includes projects that improve the ability to move power.

C. Improving Deliverability to Load Pockets/Load Centers The Entergy transmission system has several recognized load pockets. These are areas of high load, with limited local generation, and are dependent upon transmission lines in order to move power into the area. One focus of ISTEP 2009 is to increase the import capability into these load pockets.

D. Relieving Constraining Flowgates Under certain system conditions, flowgates can become constrained during real-time operations. When this occurs, the ICT will institute congestion management procedures, often in the form of Transmission Loading Relief (TLR). TLR procedures have a number of levels and can result in the curtailment of non-firm and/or firm transmission service. In addition to the operational issues, there are a number of flowgates that frequently constrain the sale of transmission service. The ISTEP 2009 includes upgrades that are intended to address some of the current most constraining flowgates from both a TLR and a transmission service perspective.

5

ISTEP 2009

IV. Models and Assumptions A. Engineering Models Assumptions

The 2017 summer model was used as the starting point for ISTEP 2009 studies. Several additional dispatch scenarios were modeled in order to simulate system conditions that could cause a flowgate to overload under contingency. The following Projects from 2009-2011 Entergy Construction Plan Rev 2 were added to the 2017 summer model to obtain the ISTEP 2009 base case powerflow model. See appendix A.

B. Economic Assessment Models Assumptions Economic modeling, simulations, and results were developed using GridView, by ABB Inc. In general, GridView is a database-driven software package that uses a linear programming approach for economic simulation of electric power systems. Its application is for generation and transmission expansion planning, market simulation, and production cost modeling. GridView uses a Security Constrained Unit Commitment and Economic Dispatch (SCUC&ED) to simulate the most economic generation dispatch while observing system security constraints. Significant effort was required in gathering detailed data and ensuring that correct information was used as input data for the simulation software. Among the inputs, requirements, and outputs were:

1. Input Power Flow Case As previously discussed, all approved and proposed projects from the Entergy 2009-2011 Final Construction Plan Rev 2 were added to the 2017 summer power flow model. The resulting power flow model raw data was used as one input for the economic simulations.

6

ISTEP 2009

2. Load Area Definitions The GridView model areas are defined as follows:

a. Entergy 1. Entergy Arkansas 2. Entergy Mississippi 3. Entergy Louisiana South 4. Entergy Louisiana North 5. Entergy NOPSI 6. Entergy Gulf States 7. Entergy Texas

b. Entities Operating within Entergy Footprint 1. LAGN (Louisiana Generating) 2. WMUC (City of West Memphis, AR) 3. CNWY (City of Conway, AR) 4. BUBA (City of Benton, AR) 5. PUPP (Union Power Partners Generating Station) 6. DERS (City of Ruston, LA) 7. DENL (City of North Little Rock, AR) 8. CELE (Central Louisiana Electric Company (CLECO)) 9. LAFA (City of Lafayette, LA) 10. LEPA (Louisiana Energy and Power Authority) 11. SWPA (Southwestern Power Administration)

c. Entergy Tier 1 1. SOCO (Southern Company) 2. TVA (Tennessee Valley Authority) 3. SMEPA (South Mississippi Electric Power Association) 4. AECC (Arkansas Electric Cooperative Corporation) 5. AMMO (Ameren Missouri Utility) 6. AECI (Associated Electric Cooperative, Inc) 7. BCA (Batesville Generating Station) 8. SPP (Southwest Power Pool)

7

ISTEP 2009

3. Other Input and Assumptions Other system characteristics and assumptions used as input are as follows:

a. Generators 1. All generation resources for all areas were modeled in detail. 2. Generation data was gathered from the ICT, Entergy, RDI Platts, and

ABB. 3. Merchant generator costs include a $3/MWh surcharge (added to the

O&M). 4. Fuel costs were gathered from the Energy Information Association (EIA). 5. Generation RMR operating guides were not included in models.

b. Transmission 1. All transmission elements were modeled in detail. 2. Selected flowgates and interfaces were monitored. 3. Hurdle rates were $10/MWh to/from SOCO, SPP, and TVA. 4. WOTAB limits were not enforced. 5. Operating Guides were not included in models.

c. Loads 1. 8760 hour load profiles were used for all areas. 2. 2017 forecast was obtained from FERC filings and power flow case.

4. Output The simulation provides output data such as production costs, production profit, load payment, bus Location Marginal Price (LMP), and congestion costs. Primary output of interest for this study is congestion cost. Congestion occurs when a transmission element’s thermal limit is exceeded, forcing redispatch of system generation to maintain the limit. The congestion cost is the cost of redispatch of more expensive generation. More precisely, the congestion cost for a transmission line is defined as:

Congestion Cost = Shadow price x Flow,

where shadow price ($/MW) is defined as the production cost savings should the thermal limit of the element be raised 1MW. It should be noted that congestion costs are only incurred during any hour where the MW power flow reaches the constraint limit. If the MW flow is less than the limit, there is no congestion or congestion cost.

8

ISTEP 2009 V. Study Results All project cost estimates provided in this section of the report should be considered high-level planning estimates.

A. South Central Arkansas/Northeast Louisiana Constraint

1. Engineering Analysis Project cost estimates are high-level planning estimates. This project addresses the north to south flows on the Entergy system, specifically looking at the four flowgates shown below for the 2008 curtailment hours.

Map Reference

Description Non-Firm Curtailment

(MWh)

Firm Curtailment

(MWh) 1 Sheridan – El Dorado 500 kV

FTLO Etta – McNeil 500 kV (SHRELD_HSPET)

73,010 25,199

2 White Bluff – Sheridan 500 kV FTLO

Mabelvale – Sheridan 500kV (WHBSHE_MABEL)

32,084 0

3 Mabelvale – Sheridan 500 kV FTLO

White Bluff – Sheridan 500kV(MABSH_WBSH)

14,096 0

4 White Bluff – Keo 500 kV FTLOSheridan – Mabelvale 500 FTLO (WBKEO_SHMAB)

443 0

9

ISTEP 2009 Locations of Monitored flowgates for projects A

The long term model was not sufficient to replicate the flowgate overload. The flowgate overloaded during off-peak periods of the peak loading season. The TLR curtailment was called at 2am. The July 6, 2008 operational horizon model was used to replicate the overload. The generation, load, and transactions were used in the model simulation. Upgrades were developed to eliminate flowgate issues and are shown below.

10

ISTEP 2009 The solution set consists of upgrades to terminal equipment limited flowgates as shown below:

• Sheridan-Eldorado 500kV from 1732 to 2598 MVA • White Bluff – Sheridan 500 kV from 1732 to 2598 MVA • Mabelvale – Sheridan500 kV from 1732 to 2598 MVA • Sheridan - Magnet Cove 500kV from 1732 to 2598 MVA • Magnet Cove – Hot Springs EHV 500kV from 1732 to 2598 MVA

A detailed description of the solution set upgrades are shown below.

Description Existing Line

Rating

1st Limiting Element

ICT Cost Estimate

2nd Limiting Element

ICT Cost Estimate

Sheridan – El Dorado 500 FTLO Hot Springs – Etta

500 SHRELD_HSPET

(1)

1732MVA (2000A)

Sheridan CT ratio ~2000A

El Dorado switch & line

trap all ~2000A

Replace CT $225,000 Replace Switch & Line Trap $700,000

($925,000)

Sheridan 4 switches ~2500A

Sheridan line trap ~2500A

Replace 4 Switches and

Line Trap ($1,300,000)

White Bluff – Sheridan 500 FTLO

Sheridan – Mabelvale 500

WHBSHE_MABEL (2)

1732MVA (2000A)

CT @ Sheridan ~2000A

Upgrade CT $225,000

5 Switches @ White Bluff

~2500A

Replace 5 Switches

$1,000,000

Mabelvale – Sheridan 500 FTLO

White Bluff – Sheridan 500

MABSHE_WBSH (3)

1732MVA (2000A)

Mabevale 4 Switches & Line Trap--

2000A

Replace 4 Switches and Line

Trap $500,000

($1,300,000)

Sheridan Line trap ~2500A Sheridan 4 Switches ~2500A

Replace 4 Switches and

Line Trap ($1,300,000)

Sheridan-Magnet Cove FTLO

Sheridan-El Dorado 500

1732MVA (2000A)

n/a n/a

Line Trap @ Sheridan ~2500A

Switch @ Sheridan ~2500A

Upgrade switch and line

trap @ Sheridan

$1,120,000

Magnet Cove-Hot Springs EHV 500

1732MVA (2000A)

Hot Springs CT ~ 2000A

Replace CT @ Hot Springs

$225,000

n/a n/a

South Central Arkansas/Northeast Louisiana upgrades and costs

11

ISTEP 2009

2. Economic Assessment Subsequent to the powerflow analysis, an economic assessment was performed to determine the economic viability of the selected upgrades. The upgrades listed above have an estimated cost of $7.4 million dollars.

a. Transmission Congestion The loadings on the flowgates in the Arkansas area were monitored during the security constrained unit commitment and economic dispatch (SCUC&ED). The resulting congestion costs and congestion hours for 2017 are shown in the table below. The flowgate that is shaded in grey was not initially one of the constraints being monitored for this project.

White Bluff-Sheridan 500kV FTLO Mabelvale-Sheridan 500kV (WHBSHE_MABEL) 8Sherid 8WH BLF 457 30 0 0

White Bluff-Sheridan 500kV FTLO Mabelvale-Wrightsville 500kV (SHEWHB_MABWR) 8Sherid 8WH BLF 166 10 0 0Sheridan-El Dorado 500kV

FTLO Hot Springs-Etta 500kV (SHRELD_HSPET) 8ELDEHV 8Sherid 0 0 0 0

Mabelvale-Sheridan 500kV FTLO White Bluff-Sheridan

500kV (MABSH_WBSH) 8Sherid 8Mabel 0 0 0 0

Change Case

Contingency From_Bus_Name To_Bus_NameCongestion Cost

(K$)Congestion Hours (Hrs)

Congestion Hours (Hrs)

Base Case

Congestion Cost (K$)

Project 1

2017 SC AR/NE LA Congestion

b. System-wide Results and Benefits The upgraded model was compared to the base case to determine the yearly cost savings due to reductions in congestion costs as shown in the table below.

Upgrade

Cost Estimate

Total Congestion

Cost

Congestion Cost Reduction From

Base Case

$ $ $ 2017 Base Case 523.3 M

SC AR/ NE LA 7.4 M 522.3 M 1 M

Upgrade Benefits

12

ISTEP 2009

B. Central Arkansas Constraint

1. Engineering Analysis This project addresses the south to north flows on the Entergy system, specifically looking at the flowgate for the 2008 curtailment hours shown below.

Map Reference


(MWh)

Firm Curtailment

(MWh) 1 Sheridan – Mabelvale 500

kV FTLO White Bluff – Keo 500 kV

(SHRMAB_KEO)

18,729 4,324

Location of the Monitored flowgate for projects B The long term model was not sufficient to replicate the flowgate overload. The flowgate overloaded during off-peak periods of the off-peak loading season. The TLR curtailment was called at 6pm. The December 21, 2008 operational horizon model was used to replicate the overload. The generation, load, and transactions were used in the model

13

ISTEP 2009 simulation. Upgrades were developed to eliminate flowgate issues and are shown below.

Central Arkansas Upgrades The solution set consists of upgrades to a terminal equipment limited flowgate and detailed descriptions of the upgrades are shown below:

• Mabelvale – Sheridan 500 kV from 1732 to 2598 MVA

Description Line Rating

1st Limiting Element

ICT Cost Estimate

2nd Limiting Element

ICT Cost Estimate

Sheridan – Mabelvale 500 FTLO White Bluff – Keo 500 SHRMAB_KEO

1732MVA (2000A)

Mabelvale 5 Switches & Line Trap—2000A

Replace 5 Switches & Line Trap $1,500,000

Sheridan 4 Switches & Line Trap ~2500A

Replace 4 Switches & Line Trap $1,300,000

Central Arkansas upgrades and costs

14

ISTEP 2009


a. Transmission Congestion The loading on the flowgate in the Arkansas area was monitored during the security constrained unit commitment and economic dispatch (SCUC&ED). The resulting congestion costs and congestion hours for 2017 are shown in the table below. The upgrade did not affect any flowgates for this project.

Sheridan-Mabelvale 500kV FTLO White Bluff-Keo 500kV

(SHRMAB_KEO) 8Sherid 8Mabel 0 0 0 0

Project Base Case Change Case



Congestion Cost (K$) Congestion

Hours (Hrs)

2017 Central Arkansas Congestion

b. System-Wide Results and Benefits The upgrade mitigated the TLR issue but was not required in the congestion cost analysis because there was no congestion in the gridview base case due to the SCUC&ED.

Upgrade Cost

Estimate

Total Congestion

Cost


Base Case

$ $ $ 2017 Base Case 523.3 M

Central Arkansas 2.8 M 522.3 M 0

Upgrade Benefits

15

ISTEP 2009

C. Lake Charles 230 kV Loop

1. Engineering Analysis This project looks specifically at the NELLC_NELLCB flowgate for the 2008 curtailment hours shown below.


(MWh)

Firm Curtailment

(MWh) Nelson – Lake Charles Bulk #1

FTLO Nelson – Lake Charles Bulk #2

(NELLC_NELLCB)

363 0

The long term model was not sufficient to replicate the flowgate overload. The flowgate overloaded during off-peak periods of the off-peak loading season. The TLR curtailment was called at 6:25pm. The October 29, 2008 operational horizon model was used to replicate the overload. The generation, load, and transactions were used in the model simulation. Additionally, the Nelson-Richard 500kV transmission line was out of service. Upgrades were developed to eliminate flowgate issues and are shown below.

ckt 1

Lake Charles Upgrades

16

ISTEP 2009 The solution set consists of terminal equipment at the Nelson and Lake Charles substations along with a rebuild of circuit 1 from Nelson to Lake Charles Bulk increasing the rating on this the line from 159 MVA to 382 MVA. The detailed descriptions of these upgrades are shown in the following table.

Description Line Rating

Limiting Element ICT Cost Estimate

Nelson Switch, CT, & Line Trap – 1200A

Replace Switch, CT, & Line Trap $87,500 (382MVA)~1600A

Lake Charles BulkBreaker, Switch, CT, & Line Trap – 1200A

Replace Breaker, Switch, CT, & Line Trap $222,500 (382MVA)~1600A

Nelson-Lake Charles Bulk 138kV #1 FTLO Nelson-Lake Charles Bulk 138kV #2 (NELLC_NELLCB)

159MVA (665A)

Nelson-Lake Charles ckt 1 Transmission Line – 665A

Rebuild Transmission Line 11.54 miles $6,231,600 (382MVA)~1600A

Lake Charles upgrades and costs

2. Economic Assessment Subsequent to the powerflow analysis, an economic assessment was performed to determine the economic viability of the selected upgrades. The selected upgrades listed above have an estimated cost of $6.5 million dollars.

a. Transmission Congestion The loading on the flowgate in the Lake Charles area was monitored during the security constrained unit commitment and economic dispatch (SCUC&ED). The resulting congestion costs and congestion hours for 2017 are shown in the table below.

Nelson-Lake Charles Bulk #1 flto Nelson-Lake Charles Bulk

#2 (NELLC_NELLCB) 4Nelson 4LC Bulk 1 2 0 0

Project Base Case Change Case




Hours (Hrs)

2017 Lake Charles Congestion

17

ISTEP 2009


Upgrade Cost

Estimate

Total Congestion

Cost


Base Case

$ $ $ 2017 Base Case 523.3 M

Lake Charles 6.5 M 522.8 M 0.5 M

Upgrade Benefits

18

ISTEP 2009

D. Baton Rouge/South Mississippi Constraint

1. Engineering Analysis No specific flowgate was monitored for this project. The project was to increase the central to south flows into the Amite South area. A 2014 winter powerflow model was used because north to south flows were observed in the winter cases but not in the summer cases. System upgrades were developed to increase transfers into this area. The upgrades identified to increase transfer capability are:

1. New 500/230kV Substation on the Daniel – McKnight 500kV Line 2. Amite – Bogalusa 115kV: Increase operating voltage from 115kV to

230kV A. Tie the Amite – Chicken Farm 115kV to the 230kV bus at Amite B. Tie the Franklinton – Bogalusa 115kV to the 230kV bus at

Bogalusa 3. Upgrade Florence – Florence SS – Star 115kV

The upgrades increased central to south transfer capability by 400MW. Location of Upgrades for project D

19

ISTEP 2009 Detailed descriptions of these upgrades are shown in the following table.

Description Existing Line

Rating

New Line Rating

Upgrade Description ICT Cost Estimate

New 500/230kV Tap

N/A 1200MVA Tap the Daniel – McKnight 500kV Line. Create a New 500/230kV Substation with a 500/230kV Transformer

$32,000,000

Amite – New 230kV Bus – Chicken Farm 230kV

(159MVA) ~798A

(883MVA) ~2217A

Loop in and out Amite – Chicken Farm 115kV to the new 230kV Bus. Move the Amite – Chicken Farm Line from the 115kV side of Amite to the 230kV Side. Upgrade the Amite – New230kV – Chicken Farm to 230kV and Upgrade Conductor.

$10,000,000

Convert Chicken Farm – Bogalusa 115kV to 230kV operation

(159MVA ) ~798A

(570MVA) ~1431A

Convert Chicken Farm – Bogalusa 115kV to 230kV and upgrade Conductor. Move the Franklinton – Bogalusa 115kV line from the 115kV side of Bogalusa to the 230kV side.

$35,000,000

Florence – Florence SS - Star 115kV

(161MVA) ~805A

( 260MVA)~1305A

Upgrade Transmission Line 7 miles

$5,000,000 Included in Entergy 2010-2012 Construction Plan (Approved)

Baton Rouge/South Mississippi Upgrades and costs


20

ISTEP 2009

a. Transmission Congestion The loading on the flowgates in the Baton Rouge/South Mississippi area were monitored during the security constrained unit commitment and economic dispatch (SCUC&ED). The resulting congestion costs and congestion hours for 2017 are shown in the table below. The upgrades had positive and negative effects on congestion costs and congestion hours as shown below.

2017 Baton Rouge/South Mississippi Congestion

Slidel-French Branch 230

Wilbert-LA Station 138 V kFTLO Webre-Wells

500kV(LASWIL_WEBWL) 4Wilbt 4LA Sta 357 26 26 2Addis-Tiger 230kV FTLO Dow

(ADDTIG_CHTAI)

Meter-Air Liquid Tap 230kV A.A.C.-Licar 230kV FTLO 6Addis 6Tiger 829 447 685 308

500kV(AACLIC_WATXF) Willow Glen-Waterford

6AAC 6Licar 3837 685 1853 497

kV 500kV(SLIFB_DANMCK) FTLO Daniel-McKnight

6FRNBRA 6Slidel 157000 5717 219000 6612

Bagatelle-Sunshine 230kV FTLO Willow Glen-Waterford 500kV (BAGSUN_WGWAT) 6BGATEL 6Sunshn 1527 138 2118 215

Negative Base Case Change Case




Hours (Hrs)

Project 4- Positive Base Case Change Case




Hours (Hrs)


Upgrade Cost

Estimate

Total Congestion

Cost


Base Case

$ $ $ 2017 Base Case 523.3 M

Baton Rouge/S. Miss 82.6 M 578.9 M -54.7 M

Upgrade Benefits

21

ISTEP 2009

E. Jackson Area

1. Engineering Analysis

This project looks specifically at the MCADXF_LAKOV flowgate for the 2008 curtailment hours shown below.

Description Non-Firm curtailment

(MWh)

Firm Curtailment

(MWh) McAdams 500/230 FTLO McAdams-Lakeover 500

(MCADXF_LAKOV)

172,445 15,070

North to South flows caused by low generation levels in Texas and DSG have been observed. The long term model was not sufficient to replicate the flowgate overload. The flowgate overloaded during off-peak periods of the off-peak loading season. The TLR curtailment was called at 11:44am. The February 22, 2008 operational horizon model was used to replicate the overload. The generation, load, and transactions were used in the model simulation. Additionally, the McKnight-Daniel 500kV transmission line was out of service. Upgrades were developed to eliminate flowgate issues and are shown below.

2nd Auto

To Lakeover

LINE

Jackson Area Upgrades

22

ISTEP 2009 The solution set consists of upgrades to the McAdams-Pickens 230kV line and adding a second McAdams Auto. The detailed descriptions of these upgrades are shown in the following table. Description Existing

Line Rating

New Line Rating

Upgraded Description ICT Cost Estimate

McAdams 500/230 ftlo McAdams-Lakeover 500 (MCADXF_LAKOV)

560MVA 1175MVA Add 2ND McAdams Auto Move Autotransformer from Hartburg, expand McAdams substation

$15,000,000 Included in Entergy 2010-2012 Construction Plan

McAdams-Pickens 230kV Transmission Line

463MVA 883MVA Upgrade Transmission Line Rebuild Transmission Line 16.3 miles

$20,375,000 Included in Entergy 2010-2012 Construction Plan

Jackson Area Upgrades and costs


a. Transmission Congestion The loading on the flowgate in the Jackson area was monitored during the security constrained unit commitment and economic dispatch (SCUC&ED). The resulting congestion costs and congestion hours for 2017 are shown in the table below. The proposed upgrades eliminated all the congestion costs and congestion hours on this flowgate.

Project 5 Base Case Change Case

Contingency From_Bus_Name To_Bus_Name Congestion

Cost (k$) Congestion Hours (Hrs)

Congestion Cost (k$)

Congestion Hours (Hrs)

Mcadams 500/230 XF FTLO Mcadams-

Lakeover (MCADXF_LAKOV) 8Mcadam 6Mcadam 119000 4230 0 0

2017 Jackson Area Congestion

23

ISTEP 2009


Upgrade

Cost Estimate

Total Congestion

Cost


Base Case

$ $ $ 2017 Base Case 523.3 M

Jackson Area 35.3 M 401.8 M 121.5 M

Upgrade Benefits

24

ISTEP 2009 VI. Summary Powerflow and economic analysis was performed on the five projects selected for ISTEP 2009. As shown below, only the Jackson Area project demonstrated a significant congestion cost reduction but all projects provided benefits in terms of relieving constrained flowgates.

Upgrade Cost

Estimate

Congestion Cost

Reduction From Base

Other Benefits

Case

$ $ __________ 2017 Base Case

SC AR\NE LA 7.4 M 1 M Flowgate

Relief

Central AR 2.8 M 0 Flowgate

Relief

Lake Charles 6.5 M 0.5 M Flowgate

Relief

Baton Rouge/S. Miss82.6 M - 54.7 M

400 MW transfer increase

Jackson Area 35.3 M 121.5 M Flowgate

Relief The end result of the 2009 ISTEP study is a high-level engineering and economic assessment of specific upgrades which may have an economic benefit to users of Entergy’s transmission system. Parties, including Entergy, that are interested in pursuing these projects further will want to undertake additional studies on their own to fine-tune the assumptions made by the ICT to their individual situations, and to verify and determine what, if any, economic benefit would accrue to them. The ICT expects that, a party wishing to proceed with construction of an upgrade, would approach the ICT to engage in a joint process with Entergy to determine a more precise cost estimate and timeline for construction of the upgrades and to execute an agreement to do so.

25

ISTEP 2009 VII. Appendix A Construction Plan Projects Reconductor Conway West-Donaghey Reconductor Donaghey-Conway South Danville Substation Upgrade SMEPA Upgrades Sarepta Project Hamlet Project Warren East cap bank New Osage Creek-Grandview line New Holland Bottoms substation Upgrade ANO-Russellville North Upgrade Russellville East-Russellville South Upgrade Hot Springs-Bismark Upgrade Bismarck-Alpine Upgrade Alpine-Amity Winn Cap bank Carter and Elton cap banks New Youngsville Substation Upgrade Alchem-Monochem Acadiana Area Improvement Project Phase 1 Acadiana Area Improvement Project Phase 2 Acadia cap bank New Loblolly-Hammond line Amite South Import Improvement Phase 3 Southeast LA Coastal Improvement Plan Phase 1 Destrehan Project Waterford 4 Project Upgrade Bogalusa-Adams Creek No. 2 Southeast LA Coastal Improvement Plan Phase 2 Ouachita Transmission Service Upgrades Upgrade Indianola-Greenwood Magee Substation Upgrade Hornlake-TH Allen Grenada/Winona/Greenwood Area Improvement Phase 1 Grenada/Winona/Greenwood Area Improvement Phase 2 Natchez cap bank Liberty-Gloster Upgrade Sheco Jacinto upgrade Western Region Reliability Improvement Plan Phase 3 Upgrade Tamina-Cedar Hill Newton Bulk Project Beaumont Improvement Plan College Station Upgrade

26

ISTEP 2009 Fawil Upgrade TVA Affected System Upgrades Westar Transmission Service Upgrades Grand Gulf Uprate Project

27

ISTEP 2009

VIII. Appendix B Base

Contingency Congestion_Cost

(K$) Congestion Hours

(Hrs) SLIFB_DANMCK_ENT 157271.4688 5717 MCADXF_LAKOV_ENT 119322.3516 4230 BRKBET_VLPIT_ENT 80198.21094 5551 TUPTAP_VLPIT_ENT 30776.03125 2720 SAGMEL_ISDEL_ENT 26591.93945 2105 LCHTOL_GRICR_ENT 22314.76563 1568 RNGXF_SARLW_ENT 16217.31738 758

RUSDAR_ANOFS_ENT 12556.83496 897 MORGL_ARKMAB_ENT 11226.19824 92 JONHE_JONJOS_ENT 9198.216797 121

COULEW_SARLW_ENT 8633.235352 1026 COWCO_COWSA_ENT 5669.639648 4080 LEWPAT_GRICR_ENT 5390.089844 525 MAIPMA_DHSW_ENT 4051.85083 434 AACLIC_WATXF_ENT 3837.047607 685

TBOGRN_WEBWL_ENT 3716.976074 452 BAGSUN_WGWAT_ENT 1526.677246 138 SGAAC_CLYVIG_ENT 1303.127319 304 SABPN_SABLI_ENT 1162.487061 437 ADDTIG_CHTAI_ENT 829.1850586 447

WHBSHE_MABEL_ENT 457.4632263 30 LASWIL_WEBWL_ENT 356.9605408 26 DELTAL_BAXPV_ENT 174.9844818 18

SHEWHB_MABWR_ENT 166.4007874 10 CLDXF_CLKMON_ENT 128.8901062 106 MABXF1_MAXF2_ENT 43.42552567 2 WILLVB_WEBWL_ENT 35.69363022 7 CHKDYB_SABCH_ENT 33.62300873 3 DARDAM_FTARK_ENT 32.64833069 3 MDCPNB_SABXF_ENT 20.37644386 12 LASTHM_WEBWL_ENT 12.41702843 4 GEOHEL_SACHI_ENT 12.36042786 1

WATGYP_WATGP_ENT 9.232548714 1 SABOILL_HAMP_ENT 3.409685373 1

ORSAB_COWSAB_ENT 1.830832005 2 NELLC_NELLCB_ENT 0.799525857 2

28

ISTEP 2009 IX. Appendix C

Lake Charles








SHEWHB_MABWR_ENT 99.37937927 8 CLDXF_CLKMON_ENT 149.6707764 99 MABXF1_MAXF2_ENT 76.16452026 3 WILLVB_WEBWL_ENT 2.678840876 1 CHKDYB_SABCH_ENT 8.80547905 2 DARDAM_FTARK_ENT 45.49410629 4 MDCPNB_SABXF_ENT 20.37644386 12 LASTHM_WEBWL_ENT 12.41702843 4 GEOHEL_SACHI_ENT 0 0

WATGYP_WATGP_ENT 0 0 SABOILL_HAMP_ENT 0 0

ORSAB_COWSAB_ENT 2.62673974 4 NELLC_NELLCB_ENT 0 0

NECSB_NECCAR_ENT 0.116497166 1

29

ISTEP 2009 X. Appendix D

SC AR/NE LA







WHBSHE_MABEL_ENT 0 0 LASWIL_WEBWL_ENT 345.1220093 25 DELTAL_BAXPV_ENT 386.6655273 22

SHEWHB_MABWR_ENT 0 0 CLDXF_CLKMON_ENT 145.9757385 97 MABXF1_MAXF2_ENT 24.79810715 1 WILLVB_WEBWL_ENT 40.43993378 8 CHKDYB_SABCH_ENT 24.87057877 3 DARDAM_FTARK_ENT 42.73742294 4 MDCPNB_SABXF_ENT 20.37644577 12 LASTHM_WEBWL_ENT 12.41702843 4 GEOHEL_SACHI_ENT 12.7189827 1


ORSAB_COWSAB_ENT 0 0 NELLC_NELLCB_ENT 0.788661897 2

NECSB_NECCAR_ENT 3.263381004 2

30

ISTEP 2009 XI. Appendix E

Central AR








SHEWHB_MABWR_ENT 166.4007874 10 CLDXF_CLKMON_ENT 128.8901062 106 MABXF1_MAXF2_ENT 43.42552567 2 WILLVB_WEBWL_ENT 35.69363022 7 CHKDYB_SABCH_ENT 33.62300873 3 DARDAM_FTARK_ENT 32.64833069 3 MDCPNB_SABXF_ENT 20.37644386 12 LASTHM_WEBWL_ENT 12.41702843 4 GEOHEL_SACHI_ENT 12.36042786 1



31

ISTEP 2009 XII. Appendix F

Jackson Area



(Hrs) SLIFB_DANMCK_ENT 157997.3906 5753 MCADXF_LAKOV_ENT 0 0 BRKBET_VLPIT_ENT 69265.625 5247 TUPTAP_VLPIT_ENT 32539.73242 2817 SAGMEL_ISDEL_ENT 26675.88867 2163 LCHTOL_GRICR_ENT 28046.24023 1850 RNGXF_SARLW_ENT 16254.12988 767





SHEWHB_MABWR_ENT 2118.295654 143 CLDXF_CLKMON_ENT 127.6216888 70 MABXF1_MAXF2_ENT 133.4440613 7 WILLVB_WEBWL_ENT 0 0 CHKDYB_SABCH_ENT 0 0 DARDAM_FTARK_ENT 227.7005615 27 MDCPNB_SABXF_ENT 7.824978352 2 LASTHM_WEBWL_ENT 6.668644428 1 GEOHEL_SACHI_ENT 0 0

WATGYP_WATGP_ENT 0 0 SABOILL_HAMP_ENT 3.66674757 2


NECSB_NECCAR_ENT 8.118628502 1 LAKXF_RABLO_ENT 838.8543091 69

GYPFAV_FSMIC_ENT 20.70750809 2

32

ISTEP 2009

33

XIII. Appendix G Baton Rouge/South Mississippi








SHEWHB_MABWR_ENT 104.7087021 10 CLDXF_CLKMON_ENT 154.5186615 82 MABXF1_MAXF2_ENT 48.91047668 3 WILLVB_WEBWL_ENT 11.68251324 2 CHKDYB_SABCH_ENT 11.23652458 1 DARDAM_FTARK_ENT 77.639328 6 MDCPNB_SABXF_ENT 27.55877113 12 LASTHM_WEBWL_ENT 0 0 GEOHEL_SACHI_ENT 0 0

WATGYP_WATGP_ENT 0 0 SABOILL_HAMP_ENT 1.193843126 1

ORSAB_COWSAB_ENT 0 0 NELLC_NELLCB_ENT 27.26673889 4

NECSB_NECCAR_ENT 6.971916199 2 LAKXF_RABLO_ENT 0 0

GYPFAV_FSMIC_ENT 11.52247143 1

ISTEP · 2010-02-18 · ISTEP 2009 . I. Executive Summary On November 17, 2006 the ICT initiated...

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Transcript of ISTEP · 2010-02-18 · ISTEP 2009 . I. Executive Summary On November 17, 2006 the ICT initiated...