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South Carolina Regional Transmission PlanningSouth Carolina Regional Transmission PlanningSouth Carolina Regional Transmission PlanningSouth Carolina Regional Transmission Planning

Stakeholder MeetingStakeholder MeetingStakeholder MeetingStakeholder Meeting

Hilton Garden Inn Hilton Garden Inn –– Charleston AirportCharleston Airport

Charleston SCCharleston SCCharleston, SCCharleston, SC

September 8, 2011September 8, 2011

Purpose and Goals for Today’s MeetingPurpose and Goals for Today’s Meeting

• Review Initial Results of Reliability Assessments• Local Area • SERC • Multi-Party Local Area SERC Multi Party• Inter-regional • ERAG

• Discuss Proposed Changes to Expansion PlansDiscuss Proposed Changes to Expansion Plans• Discuss Alternative Solutions from Stakeholders• Present Information on FERC Order 1000Present Information on FERC Order 1000

2

1 R li bilit Stakeholder

Reliability1 - Reliability Planning Kick-off

MeetingsReliabilityPlanning

2 - Reliability Studies

4 - Economic Transfer Studies -

Initial ResultsStudies -Initial Results

3 - Economic Transfers Selected

Economic Transfers

4

SelectedTransfers

Transmission Expansion Drivers:Transmission Expansion Drivers:– Criteria Testing

• NERC Reliability Standards• Internal Planning Guidelines• Internal Planning Guidelines

– Customer Needs• Distribution & Industrialst but o & dust a• Wholesale (cooperative & municipal)• Network• Firm PTP

– Generator Interconnection NeedsActual system performance (poor performance)– Actual system performance (poor performance)

5

Reliability Planning Study ActivitiesReliability Planning Study Activities

SCE&GSCE&GSCE&GSCE&G

Joe HoodJoe Hood

6

NERC TPL StandardsNERC TPL StandardsNERC TPL StandardsNERC TPL StandardsTable 1Table 1

7

SCE&G Internal Planning CriteriaSCE&G Internal Planning CriteriaEvent resulting in the

l f i l t Voltage limit Thermal li itloss of a single component Voltage limit limit

Generator 95.0% 100%Transformer 95.0% 100%Transmission line 95.0% 100%Underground cable 95.0% 100%Capacitor bank 95.0% 100%

Event resulting in the lossof two or more components Voltage limit Thermal

limitOne bus segment 95.0% 100%Two bus segments (one bus tie breaker failure) 92.5% 100%Multiple circuits on a same structure 95.0% 100%All ti i l t 95 0% 100%All generation in any one plant 95.0% 100%Generator+ Transmission Line or Underground Cable 92.5% 100%Generator + Generator 92.5% 100%Generator + Transformer 92.5% 100%Generator + Capacitor bank 92.5% 100%Transformer + Transformer 92.5% 100%Transformer + Transmission Line or Underground Cable 92.5% 100%Transformer + Switch 92.5% 100%Transformer + Capacitor bank 92.5% 100%Transmission line + Transmission line 92.5% 100%Transmission line + Underground cable 92.5% 100%Transmission line + Capacitor bank 92.5% 100%Transmission line Capacitor bank 92.5% 100%Capacitor bank + Underground cable 92.5% 100%

8

Modeling AssumptionsModeling Assumptions

Basecase Development:– SCE&G Area: Detailed Data from Model Database ‐ Including Most Current Transmission Expansion Plan p

– SERC Region: Latest 2011 SeriesReduced Long Term Study Group Models

– North America: 2010 Series MMWG Models (Electrically Equivalenced)

9

Modeling AssumptionsModeling Assumptions• Dispersed Substation Load Forecast

– Summer/Winter Peak, Off‐Peak and Seasonal Load Levels• Existing Generation• Existing Generation

– Input from Generation Maintenance Schedule• Generation Additions

f l– Input from Generation Expansion Plan• Transmission Additions

– Input from Planners and Engineering• Firm Transmission Service

– Input from OASIS, Coordinate with Neighbors• Neighboring Transmission Systems Modeled• Neighboring Transmission Systems Modeled

10

Reliability Study ProcedureReliability Study Procedure

Analysis Tools:Siemens PSS/E Power– Siemens PSS/E Power Systems Simulator

– PowerWorld Simulator– PowerWorld Simulator– Automation Programs (Python NET)(Python, .NET)

11

Reliability Study ProcedureReliability Study ProcedureStartStart • Run all NERC TPL Category A, B and C

contingencies, and selected D contingencies for each iteration and

Run Criteria Screening

each seasonal/loading condition (~100,000 contingencies per iteration)

• Violations may initiate transmission

Violations ?

Create/Change Project or

Create/Change Procedure and

YesYes

expansion studies or require operating procedures depending on probability and severity of problem

Update Model

E dE d

NoNo

Initiate Detailed EndEnd Alternative Studies

12

Santee Cooper Local Reliability StudiesSantee Cooper Local Reliability Studies

•• Planning CriteriaPlanning Criteria•• Reliability Study ProcedureReliability Study Procedure

Willi G ithWilli G ith


William GaitherWilliam Gaither

Planning CriteriaPlanning Criteria

• Santee Cooper Internal Planning CriteriaD t d i 1987– Documented in 1987

– Last revised in September, 2007

• North American Electric Reliability Corporation (NERC) TPL Standards

SCPSA Internal Planning CriteriaSCPSA Internal Planning Criteria

Event Description Voltage limit

Delivery Point Bus normal operating conditions 92 5% to 102 5%Delivery Point Bus, normal operating conditions 92.5% to 102.5%Delivery Point Bus, emergency operating conditions 90.0% to 104.0%Transmission lines, within continuous rating during normal operationsTransmission lines, within emergency rating during contingency eventsTransformers, within its max. 55 degree C rating during normal operationsTransformers, within 107 % of its max. 65 degree C rating during contingency eventscontingency events

NERC TPL StandardsNERC TPL StandardsTable 1Table 1

Reliability Study ProcedureReliability Study Procedure• Power Flow Models

– Updated loads from current corporate load forecast, Central supplied load forecast, industrial loads

– Detailed data including the most current transmission expansion planexpansion plan

– Transmission associated with new generation– SERC Region: 2011 Series Reduced LTSG Modelsg– North America: 2011 Series MMWG Models (Electrically

Equivalenced)


• Analysis Tools– Siemens/PTI PSS/E Power Systems Simulator– Python Automation Programs– Microsoft Access and Excel

Reliability Study ProcedureReliability Study Procedure• Contingencies Tested:• Contingencies Tested:

– All Single Transmission Line Outages at 230 kV, 115 kV, and 69 kV– All Single Transformer Outages

All Si l B O t– All Single Bus Outages– All Single Generator Unit Outages– Selected Combinations of 2 Transmission Line Outages

S l t d C bi ti f 2 T f O t– Selected Combinations of 2 Transformer Outages– Selected Combinations of 2 Generator Unit Outages– Selected Combinations of 1 Transmission Line Outage and 1 Transformer Outage

S C f O G O– Selected Combinations of 1 Transmission Line Outage and 1 Generator Unit Outage– Selected Combinations of 1 Transformer Outage and 1 Generator Unit Outage


• Review results of tested contingencies• Identify contingencies that fail to meet planning criteriay g p g• Recommend project to correct facility not meeting criteria• Test recommended project against planning criteriap j g p g• If recommended project meets criteria add to transmission plan• If recommended project does not meet criteria, develop

alternative project and re-test until planning criteria met• Develop transmission plan based on recommended projects

CTPCA Future Year AssessmentsCTPCA Future Year Assessments

Kale FordKale Ford

CTPCA PurposeCTPCA Purpose• Collection of agreements developed concurrently by the

Principals and Planning Representatives of multiple two-Principals and Planning Representatives of multiple twoparty Interchange Agreements

• Establishes a forum for coordinating certain transmission planning and assessment activities among the specific parties associated with the CTPCA

CTPCA PurposeCTPCA PurposeInterchange Agreements associated with the CTPCA

Duke Energy Corporation (“Duke”) and Progress Energy Carolinas (“PEC”)gy p ( ) g gy ( )Duke Energy Corporation (“Duke”) and South Carolina Electric & Gas Company (“SCE&G”)Duke Energy Corporation (“Duke”) and South Carolina Public Service Authority (“SCPSA”)Progress Energy Carolinas (“PEC”) and South Carolina Electric & Gas Company (“SCE&G”)g gy ( ) p y ( )Progress Energy Carolinas (“PEC”) and South Carolina Public Service Authority (“SCPSA”)South Carolina Electric & Gas Company (“SCE&G”) and South Carolina Public Service Authority

(“SCPSA”)

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CTPCA Power Flow Study GroupCTPCA Power Flow Study Group

• Duke Energy Carolinas (“Duke”)

• Progress Energy Carolinas (“Progress”)

• South Carolina Electric & Gas (“SCEG”)

• South Carolina Public Service Authority (“SCPSA”)

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CTPCA Studies CTPCA Studies PurposePurpose

• Assess the existing transmission expansion plans of Duke, Progress, SCEG, and SCPSA to ensure that the plans are simultaneously

PurposePurpose

feasible. • Identify any potential joint solutions which would improve the

simultaneous feasibility of the Participant companies’ transmission simultaneous feasibility of the Participant companies transmission expansion plans.

• The Power Flow Study Group (“PFSG“) will perform the technical analysis outlined in this study scope under the guidance and direction of the Steering Committee (“SC”).

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CTPCA StudiesCTPCA StudiesScopeScopeScopeScope

• NERC Reliability Standards, SERC Requirements, and individual company study criteria.p y y

• Cases are developed with detailed internal models with current transmission expansion plans from each participating company.

• Generation down cases are developed from starting point cases with internal generation redispatch and Transmission Reserve Margin (TRM) import(s) implemented.po t(s) p e e ted

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CTPCA Studies CTPCA Studies Scope (continued)Scope (continued)Scope (continued)Scope (continued)

• Study results are obtained by use of PTI's MUST and PSS/E programs.y y p g• Report on thermal loading(s) above 90% and voltage(s) violating

individual company criteria• 2014/21 Summer Study report, Spring 2011 (2010 Study)• 2015/18 Summer Study report draft, Fall/Winter 2011 (2011 Study)

Results are currently being compiled-Results are currently being compiled

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CTPCA 2014/21 Summer Study CTPCA 2014/21 Summer Study Element Contingency Year Potential PotentialElement Contingency Year Issue Solution

McIntosh-Jasper Tap115 kV Line

(Southern/SCE&G)

Cross 3 GdJasper-Yemassee

230 kV Line 2014 Loading

(100.6 %) Jasper-Okatie-Yemassee

230 kV Line

Cross 3 GdLyles-Williams St115 kV Line

Cross 3 GdLyles-Edenwood


(104.3 %) Line Upgrade

Georgia Pacific Tap Cliffside 6 Gm

Saluda-Georgia Pacific 2014/21 HighVoltage Transformer Tap Changes

Tap 115 kV Line Voltage

McIntosh-Jasper Tap115 kV Line

(Southern/SCE&G)

Belews Creek 1 GmMcIntosh-Purrysburg

230 kV Line (Southern/SCPSA)

2021 Loading(118.8 %)

SCE&G and Southern Company are jointly investigating

(Sout e /SC S )

Summerville230/115 kV 2

Cross 3 GdSummerville230/115 kV 1

2021 Loading(100.1 %)

Upgrade Transformer to 336 MVA and leave 224 MVA as in-service

spare

Parr Winnsboro Pineland North Point Loading Winnsboro or BlythewoodParr-Winnsboro115 kV Line

Pineland-North Point115 kV Line 2021 Loading

(100.4 %) Winnsboro or Blythewood

Substation

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McIntosh-Jasper 115 kVLyles-Williams Street 115 kVGeorgia Pacific Tap 115 kVGeorgia Pacific Tap 115 kVSummerville 230/115 kVParr-Winnsboro115 kV

CTPCA 2014/21 Summer Study CTPCA 2014/21 Summer Study Element Contingency Year Potential PotentialElement Contingency Year Issue Solution

Arcadia-Parkersville115 kV Line

Brunswick 2 Gd (TRM) Perry Road-Campfield

230 kV Line2014 Loading

(91.8 %)

Bucksville 230-115 kV Sub. [2015]Winyah-Bucksville 230 kV [2016]

Bucksville-Garden City 115 kV [2017][2017]

Winyah-Campfield230 kV Line

Brunswick 1 Gd (TRM)Winyah-Hemingway

230 kV Line2014 Loading

(96.9 %)


Bucksville-Garden City 115 kV [2017]

Georgetown-Campfield3 115 kV Line

McGuire 1 or 2 GmWinyah-Campfield


(115.2 %)


Bucksville-Garden City 115 kV[2017]

B i k 1 2 Gd Bucksville 230-115 kV Sub. [2015]

Georgetown-Winyah 1115 kV Line

Brunswick 1 or 2 Gd(TRM)

Georgetown-Winyah 2115 kV Line

2021 Loading (93.0 %)

uc sv e 30 5 V Sub. [ 0 5]Winyah-Bucksville 230 kV Line

[2016]Bucksville-Garden City 115 kV Line

[2017]

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Arcadia-Parkersville115 kVWinyah-Campfield 230 kVGeorgetown-Campfield 3 115 kVGeorgetown Campfield 3 115 kVGeorgetown-Winyah 1 115 kV

CTPCA StudiesCTPCA Studies

Questions?Questions?Questions?Questions?

41

SERC Future Year AssessmentsSERC Future Year AssessmentsLong Term Study Group (LTSG)Long Term Study Group (LTSG)Long Term Study Group (LTSG)Long Term Study Group (LTSG)

42

SERC LTSG 2017 Summer StudySERC LTSG 2017 Summer StudyPurposePurposePurposePurpose

• Analysis of the performance of the members’ transmission y psystems that identifies limits to power transfers occurring non-simultaneously among the SERC members.

• Analysis of the performance of the members’ transmission systems under normal conditions and loss of a single elementsystems under normal conditions and loss of a single element.

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SERC LTSG 2017 Summer StudySERC LTSG 2017 Summer StudyScopeScopeScopeScope

• Assess the strength of the SERC interconnected network by d t i i it bilit t t t fdetermining its ability to support power transfers.

• NERC Reliability Standards and SERC Requirements• NERC Reliability Standards and SERC Requirements.

• Case is developed by the SERC LTSG Modeling GroupCase is developed by the SERC LTSG Modeling Group.

44

SERC LTSG 2017 Summer StudySERC LTSG 2017 Summer StudyScope (continued)Scope (continued)Scope (continued)Scope (continued)

• Study results are obtained by use of PTI's MUST and PSS/E programs.

Id tif Si ifi t F iliti d t f l i • Identify Significant Facilities under transfer analysis.

St d sched led to be completed December 2011• Study scheduled to be completed December 2011

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SERC LTSG 2017 Summer StudySERC LTSG 2017 Summer StudySi ifi t F ilitiSi ifi t F ilitiSignificant FacilitiesSignificant Facilities

• If the facility is a hard limit to a transfer

• The level at which it limits a transfer compared to the test level

• The response of the facility to the transfer

• The number of different transfers/companies impacted

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SERC LTSG 2017 Summer StudySERC LTSG 2017 Summer StudySi ifi t F iliti ( ti d)Si ifi t F iliti ( ti d)Significant Facilities (continued)Significant Facilities (continued)

• If the facility requires the use of an operating guide

• If the outage of the facility results in the overload of numerous j t i i l tmajor transmission elements

If an act al TLR has been called on the facilit• If an actual TLR has been called on the facility

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SERC LTSG 2017 Summer StudySERC LTSG 2017 Summer StudyV i bl F tV i bl F tVariable FactorsVariable Factors

• Load forecasts and generation availability

• Anticipated drought conditions in the SERC area

• Geographic distribution of load and generation

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SERC LTSG 2017 Summer StudySERC LTSG 2017 Summer StudyV i bl F t ( ti d)V i bl F t ( ti d)Variable Factors (continued)Variable Factors (continued)

• Transmission system configuration

• Simultaneous inter-system power transfers

• Operation based on regional requirements to respect additional contingenciesadditional contingencies

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2017 LTSG Summer Reliability Study2017 LTSG Summer Reliability StudyPreliminary ResultsPreliminary ResultsPreliminary ResultsPreliminary Results

Element Contingency PotentialIssue

PotentialSolution

McIntosh PurrysburgSRS-Canadys 230 kV

McIntosh-Purrysburg 230 kV (open McIntosh-

Jasper Tap 115 kV)

FCITC Importlimit Evaluating

L i t L l 115 kV P i VCS S b 2 FCITC Export R d tLexington-Lyles 115 kV Pomaria-VCS Sub 2 pLimit Reconductor

McIntosh-Purrysburg 230 kV None NITC Import

Limit Evaluating230 kV Limit

50

Lexington-Lyles 115 kVSRS-Canadys 230 kV

McIntosh-Purrysburg 230 kV

SERC LTSG StudySERC LTSG Study

Q ti ?Q ti ?Questions?Questions?

51

ERAG Future Year AssessmentsERAG Future Year Assessments

Phil KleckleyPhil Kleckley

SERC EastSERC East--RFCRFC--NPCCNPCC• SERC East

VACAR (Duke, DVP, PEC, SCE&G, SCPSA)Central (TVA, EON U.S., EKPC, BREC)

• Reliability First Corporation y pPJM (Pennsylvania, New Jersey, Maryland)MISO (Midwest Independent System Operator)( p y p )

SERC EastSERC East--RFCRFC--NPCCNPCC(CONT.)(CONT.)

• Northeast Power Coordinating CouncilNortheast United StatesSoutheast Canada

SERC EastSERC East--RFCRFC--NPCC NPCC LongLong--Term StudiesTerm Studies

• Analysis of interregional system performance during regional and sub-regional power transfers

• Study of normal and contingency conditions• Effects of selected multiple outages and simultaneous p g

transfers on system performance


• Identify transfer limits from and to each study regiony y g• Transfer limits are not ATC or TTC as required in FERC

Orders 888 and 889 and posted on OASIS• Results are conditional, not absolute or optimal• Identify facilities having thermal or selected y g

voltage/reactive limits for regional and sub-regional transfers


• FCITC - First Contingency Incremental Transfer Capability g y p yis the incremental transfer capability above the transfers modeled in the base case

• FCTTC - First Contingency Total Transfer Capability is the algebraic sum of the FCITC and the base case region-to-

i t fregion transfer


• Analysis of FCITCs for simultaneous transfers among, or through study areas

• FCITCs and FCTTCs for non-simultaneous transfers• Appraisals for PJM, Midwest ISO, SERC East and NPCC pp , ,

study areas


FCITC values are based on the prediction of many factors that could change in daily operation of the power system


Reliability Assessment AssumptionsReliability Assessment AssumptionsReliability Assessment AssumptionsReliability Assessment Assumptions

• Load forecasts and generation availability• Load forecasts and generation availability• Geographic distribution of load and generation• Transmission system configuration• Transmission system configuration


Reliability Assessment AssumptionsReliability Assessment Assumptionsy py p

• Simultaneous inter-system power transfersSimultaneous inter system power transfers• Regional operational requirements for contingencies• Phase Angle Regulator control settings• Phase Angle Regulator control settings

SERC EastSERC East--RFCRFC--NPCC NPCC 2021 Summer Long Term Study2021 Summer Long Term Study

ScopeScopeScopeScope• Due November 2011• Develop 2021 summer base case with all scheduled firm • Develop 2021 summer base case with all scheduled firm

capacity backed transactions• Determine thermal regional and sub-regional FCITCs• Determine thermal regional and sub-regional FCITCs• Determine FCTTCs for regional and sub-regional transfers

SERC EastSERC East--RFCRFC--NPCC NPCC SSScopeScope

• Reliability Analysis for selected transfers occurringsimultaneously among, or through the SERN regions

• Identify Limiting facilities for non-simultaneous emergencytransfers among MISO SERC East expanded PJM and NPCCtransfers among MISO, SERC East, expanded PJM and NPCC

• Appraisals for the PJM, MISO ,SERC East and NPCC study areas• The FCITCs reported in the study are based on simulatedThe FCITCs reported in the study are based on simulated

system operation

SERC EastSERC East--RFCRFC--NPCCNPCCInterregional Transmission S stemInterregional Transmission S stemInterregional Transmission SystemInterregional Transmission System

Reliability AssessmentsReliability Assessments

Questions?Questions?

MultiMulti--Party StudiesParty Studies

59

SCE&G/Santee Cooper/SouthernSCE&G/Santee Cooper/SouthernInterface AssessmentInterface AssessmentInterface AssessmentInterface Assessment

William GaitherWilliam Gaither

Study Scope•• A multiA multi--party assessmentparty assessment

•• Conducted under multiple twoConducted under multiple two--party Interchange Agreementsparty Interchange Agreementspp p y g gp y g g–– Southern Company and South Carolina Electric & GasSouthern Company and South Carolina Electric & Gas–– Southern Company and South Carolina Public Service AuthoritySouthern Company and South Carolina Public Service Authority–– South Carolina Electric & Gas and South Carolina Public Service AuthoritySouth Carolina Electric & Gas and South Carolina Public Service Authority

•• Identify potential transfer limits across these interfaces:Identify potential transfer limits across these interfaces:–– Southern Balancing Authority Southern Balancing Authority -- South Carolina Electric & GasSouth Carolina Electric & Gas

S th B l i A th it S th B l i A th it S t CS t C–– Southern Balancing Authority Southern Balancing Authority –– Santee CooperSantee Cooper–– South Carolina Electric & Gas South Carolina Electric & Gas –– Santee CooperSantee Cooper

Study timeframe Study timeframe longlong term planning horizon (2016term planning horizon (2016 2020)2020)•• Study timeframe Study timeframe –– longlong--term planning horizon (2016term planning horizon (2016--2020)2020)

Study Results

•• Development of operating guide SO1Development of operating guide SO1•• SO1 operating guide SO1 operating guide –– for the loss of the McIntoshfor the loss of the McIntosh--Purrysburg Purrysburg

230 kV tie, open the McIntosh230 kV tie, open the McIntosh--Jasper Tap 115 kV tieJasper Tap 115 kV tie

•• SO1 utilized in the current SERC LTSG study of 2017 SummerSO1 utilized in the current SERC LTSG study of 2017 Summer

Proposed Changes toTransmission Expansion PlanTransmission Expansion Plan

SCE&GSCE&G

Joe Hood

63

SCE&G Recently Completed Transmission Projectsy p j

Pepperhill – Robert Bosch 115kV Line Upgradepp pg

Lake Murray – McMeekin 115kV Line Upgrade

Lake Murray – Saluda Hydro 115kV Line UpgradeLake Murray – Saluda Hydro 115kV Line Upgrade

Saluda Hydro – McMeekin 115kV Line Upgrade

Saluda River 230kV Transmission Project

• Adds a new 230/115kV Substation

d b k d• Located between Lake Murray and Downtown

Columbia near the Saluda River

• Allows the following costly projects to be canceled:

• Denny Terrace Add 3rd Autotransformer

• Lake Murray Add 3rd Autotransformer

Greater Columbia Area

Saluda River 230kV Transmission

Charleston Peninsula Area Improvement Projects

• Consolidates and Changes the Scope of the following Projects:

• Accabee – Charlotte St 115kV Line Upgrade to Double Circuit• Accabee – Charlotte St 115kV Line Upgrade to Double Circuit

• Faber Place – Accabee 115kV Line Upgrade

Add th F ll i P j t• Adds the Following Projects:

• Upgrade Hagood – Bee St 115kV Line to B‐795 ACSR

• Construct Faber Place – Hagood 115kV Line #2

• Retires Aging Accabee 115kV Substation

Charleston Peninsula Area Improvement

Postponed Projects

• Lake Murray 2nd Autotransformer 12/31/2012 5/1/2013

• Belvedere – Church Ck 115kV Upgrade 12/31/2012 5/1/2014

• Yemassee – Burton #2 115kV Upgrade 5/1/2013 5/1/2014

• Pepperhill – Summerville 230kV Line 5/1/2013 5/1/2014

• Okatie 230kV Substation 5/1/2014 5/1/2015Okatie 230kV Substation 5/1/2014 5/1/2015

V.C. Summer Unit #2 Related Projects

• Denny Terrace ‐ Lyles 230kV Line Upgrade 12/31/2015• Lake Murray ‐McMeekin 115kV Line Upgrade 12/31/2015y pg• Lake Murray ‐ Saluda 115kV Line Upgrade 12/31/2015• Saluda ‐McMeekin 115kV Line Upgrade 12/31/2015• VCS2 ‐ Lake Murray #2 230kV Line Construct 12/31/2015y / /• VCS2 ‐Winnsboro ‐ Killian 230kV Line Construct 12/31/2015

V.C. Summer Unit #3 Related ProjectsV.C. Summer Unit #3 Related Projects

• Saluda ‐ Duke 115kV Tielines Upgrade 12/31/2018• St George 230kV Switching Station Construct 12/31/2018• St George ‐ Canadys 230kV Line Upgrade 12/31/2018• St George ‐ Summerville 230kV Line Upgrade 12/31/2018• VCS Sub #2 ‐ St George 230kV Double Circuit Construct 12/31/2018

Proposed Changes toTransmission Expansion PlanTransmission Expansion Plan

Santee CooperSantee Cooper

William Gaither

74

Transmission NetworkC l t d P j tCompleted Projects

• Carnes Crossroads-Cane Bay Tap Double Circuit 115 kV• Cane Bay 115 kV Tap Line• Cane Bay 115 kV Tap Line• Lake Ridge 115 kV Tap Line• Red Dam 115 kV Tap LineRed Dam 115 kV Tap Line• Bennettsville City-Mohawk 69 kV Line

Transmission NetworkPlanned Projects

• Arcadia-Garden City #2 115 kV Line 12/2011• Carolina Forest 230-115 kV Substation 06/2012• Carolina Forest-Dunes #2 115 kV Line 06/2012• Fold Hemingway-Marion 230 kV Line into Lake City 06/2012• Orangeburg 230-115 kV Substation 12/2012• Pomaria 230-69 kV Substation 06/2013• Pomaria 230-69 kV Substation 06/2013• Bucksville 230-115 kV Substation 06/2015 06/2014• Winyah-Bucksville 230 kV Line 06/2016 06/2015• Bucksville-Garden City 115 kV Line 06/2017 06/2016• Transmission Plans Associated with VCS #2 (2016) and VCS #3 (2019)

Grand Strand Area

Myrtle Beach Area

• Issues:– Large load center served from remote resources

Ti htl i t t d t i i t– Tightly-integrated transmission system– Numerous contingencies impact “source” lines into the area– Line loadings projected to exceed their normal rating– Line loadings projected to exceed their normal rating

Arcadia-Garden City #2 115 kV Line

• Problem:– Contingency:

O t f C fi ld P R d 230 kV Li• Outage of Campfield-Perry Road 230 kV Line• Severe or extreme events in the Myrtle Beach Area

– Result:• Arcadia-Litchfield 115 kV line section may overloady

– Base case loading projected to exceed normal rating in 2012

• Solution:Arcadia-Garden City #2 115 kV Line

– Rebuild the existing Garden City-Arcadia 115 kV Line as a do ble circ it linea double circuit line

• Benefit:Benefit:– Provide another source into

southern portion of Myrtle Beach area.

• Solution:

Carolina Forest 230/115 kV Substation

– Construct the Carolina Forest 230/115 kV Substation

– Construct 115 kV line from

CarolinaForest

Construct 115 kV line from Carolina Forest to Dunes 115-12 kV Substation

• Benefits:• Benefits:– Provide another bulk source into

the central part of Myrtle BeachR li d d P – Relieve dependency on Perry Road and Myrtle Beach Substations

Fold Hemingway-Marion 230 kV into Lake City

Orangeburg-St. George-Varnville 69 kV System

Orangeburg 230/115 kV

SubSub

Pomaria 230-69 kV Substation

MarionBucksville Transmission Projects

Fold Hemingway-Red Bluff

Lake CityConway

Carolina Forest 230-115 kV Substation

Fold HemingwayMarion 230 kV Line

into Lake City

Bucksville 230-115 kV S b t ti

DunesPerry Road

Kingstree

Hemingway

ykV Substation

Garden City

Winyah-Bucksville 230 kV Line

Arcadia

Campfield

Georgetown

Arcadia-Garden City 115 kV Line #2

Winyah

VC Summer #2 Transmission Plan (ISD 2016)

Richburg 69 kV Sw StaFlat Creek 230-69 kV Sub.

Richburg 69 kV Sw. Sta.

Winnsboro 69 kV Sw. Sta.VC Summer Nuclear Plant Camden 230-69 kV Sub.

Pomaria 69 kV Sw Sta

Lugoff 230-69 kV Sub.

Pomaria 69 kV Sw. Sta.Blythewood 230-115-69 kV Sub.


Richburg 230 69 kV SubFlat Creek 230-69 kV Sub.

Richburg 230-69 kV Sub.

Winnsboro 230-69 kV Sub.VC Summer Nuclear Plant Camden 230-69 kV Sub.

Pomaria 230 69 kV Sub

Lugoff 230-69 kV Sub.

Pomaria 230-69 kV Sub.Blythewood 230-115-69 kV Sub.

VCS #2 Transmission Projects

• Winnsboro 230-69 kV Substation 09/2013• VCS-Winnsboro 230 kV Line 11/2013CS sbo o 30 e / 0 3• Richburg 230-69 kV Substation 06/2014• Winnsboro-Richburg 230 kV Line 08/2014• Richburg Flat Creek 230 kV Line 10/2015• Richburg-Flat Creek 230 kV Line 10/2015

VC Summer Nuclear


Pomaria 69 kV SS

Newberry 230-69 kV Sub.

Blythewood 230-69 kV Sub.

Sandy Run 115 kV SS

Orangeburg 115-69 kV Sub.

Bamberg 69 kV SS

St George 115 69 kV

Varnville 230 115 69 kV Sub

Sycamore 69 kV SS St. George 115-69 kV Sub.

Yemassee 230 kV SS

Varnville 230-115-69 kV Sub.

VCS-Pomaria 230 kV LineVC Summer Nuclear


Blythewood 230-69 kV Sub.Pomaria 230-69 kV Sub.

Pomaria-Sandy Run 230 kV LineNewberry 230-69 kV Sub.

Sandy Run 230-115 kV Sub.

Pomaria-Sandy Run 230 kV Line

Orangeburg 230-115-69 kV Sub.

Sandy Run-Orangeburg 230 kV Line

Bamberg 69 kV SS

St. George 230-115 kV Sub.

Orangeburg-St. George 230 kV Line

St George 115 69 kVSycamore 69 kV SS

Varnville 230 115 69 kV Sub

St. George-Varnville 230 kV Line

St. George 115-69 kV Sub.

Varnville 230-115-69 kV Sub.

Yemassee 230 kV SS

VCS #3 Transmission Projects

• VCS-Pomaria #2 230 kV Line 05/2014• Sandy Run 230-115 kV Substation 04/2016

P i S d R 230 kV Li 05/2016• Pomaria-Sandy Run 230 kV Line 05/2016• Sandy Run-Orangeburg 230 kV Line 05/2017• St. George 230-115 kV Substation 04/2018• Varnville 230-115 kV Substation 05/2019• St. George-Varnville 230 kV Line 06/2019

Stakeholder Input andStakeholder Input andppAlternative Discussion OnAlternative Discussion On

Proposed Changes toProposed Changes toProposed Changes toProposed Changes toTransmission Expansion PlansTransmission Expansion Plans

92

FERC Order 1000FERC Order 1000FERC Order 1000FERC Order 1000

Transmission Planning and Cost AllocationTransmission Planning and Cost AllocationTransmission Planning and Cost AllocationTransmission Planning and Cost Allocation

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FERC Order 1000FERC Order 1000

• Planning Requirementsg• Cost Allocation Requirements

N i b t D l R i t• Non-incumbent Developer Requirements• Compliancep

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Planning RequirementsPlanning Requirements• Public utility transmission providers are required to

participate in a regional transmission planning processparticipate in a regional transmission planning process• Local and regional transmission planning processes

id i i d d i b bli must consider transmission needs driven by public policy

• Public utility transmission providers in each pair of neighboring transmission planning regions must coordinate to determine if more efficient or cost effective solutions are available

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Regional PlanningRegional Planning

• Each transmission planning region must produce a p g g pregional transmission plan reflecting solutions that meet the region’s needs more efficiently or costg yeffectively

• Stakeholders must have an opportunity to participate Stakeholders must have an opportunity to participate in identifying and evaluating potential solutions to regional needsregional needs

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Interregional CoordinationInterregional Coordination

• Each pair of neighboring transmission planning p g g p gregions must:– Share information regarding the respective needs of each region and

potential solutions to those needs– Identify and jointly evaluate interregional transmission facilities that

may be more efficient or cost effective to those regional needsmay be more efficient or cost-effective to those regional needs

• Interregional transmission facilities are those that are located in two or more neighboring transmission located in two or more neighboring transmission planning regions

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Cost Allocation RequirementsCost Allocation Requirements

• Regional transmission planning process must have a g p g pregional cost allocation method for a new transmission facility selected in the regional transmission plan for y g ppurposes of cost allocation

• Neighboring transmission planning regions must have a Neighboring transmission planning regions must have a common interregional cost allocation method for a new interregional transmission facility that the regions selectinterregional transmission facility that the regions select

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NonNon--incumbent Developersincumbent Developers

• Rule promotes competition in regional transmission planning processes

• Rule requires the development of a not unduly q p ydiscriminatory regional process for transmission project submission, evaluation, and selectionp j , ,

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ComplianceCompliance

• Each transmission provider is required to make a p qcompliance filing within twelve months of the effective date of the Final Rule (October 2012)( )

• The compliance filings for interregional transmission coordination and interregional cost allocation must be coordination and interregional cost allocation must be filed within eighteen months of the effective date (April 2013)2013)

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SCRTP SCRTP -- Next MeetingNext Meeting

• Discuss Alternative Solution AnalysesSCRTP St k h ld G ill d l t 5 • SCRTP Stakeholder Group will propose and select 5 intra-regional economic transfers for study

• Proposed inter regional economic transfers will be • Proposed inter-regional economic transfers will be advanced to the SIRPP

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South Carolina Regional Transmission PlanningSouth Carolina Regional Transmission PlanningSouth Carolina Regional Transmission PlanningSouth Carolina Regional Transmission Planning

Stakeholder MeetingStakeholder MeetingStakeholder MeetingStakeholder Meeting

Hilton Garden Inn Hilton Garden Inn –– Charleston AirportCharleston Airport

Charleston SCCharleston SCCharleston, SCCharleston, SC

September 8, 2011September 8, 2011

south carolina regional transmission planning stakeholder ... · pdf filesouth carolina...

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