VACAR-CTCA-SERC Studies This document includes the following studies: 1. VACAR Power Flow Working Group (PFWG) commissioned by the VACAR Planning Task Force- entitled “VACAR 2015 Summer Peak Reliability Study-Final” 2. VACAR Drought Working Group commissioned by the VACAR Operating Task Force – draft study entitled “VACAR Drought Study” 3. VACAR Stability Working Group commissioned by the VACAR Planning Task Force- draft study entitled “VACAR STABILITY STUDY OF PROJECTED 2008 LIGHT LOAD CONDITIONS” 4. VACAR Stability Working Group commissioned by the VACAR Planning Task Force- draft study entitled “VACAR STABILITY STUDY OF PROJECTED 2014/2015 WINTER PEAK LOAD CONDITIONS-Draft” 5. Coordinated Study Progress Energy Carolinas And South Carolina Public Service Authority: “PEC-SC_Red_Bluff_JointStudy_2010_Final- 2016 Summer Peak” 6. Carolinas Transmission Coordination Arrangement (CTCA): “2016 Summer Peak/Shoulder Reliability Study”
Transcript
VACAR-CTCA-SERC Studies This document includes the following studies:
1. VACAR Power Flow Working Group (PFWG) commissioned by the VACAR Planning Task
2. VACAR Drought Working Group commissioned by the VACAR Operating Task Force – draft study entitled “VACAR Drought Study”
3. VACAR Stability Working Group commissioned by the VACAR Planning Task Force- draft study entitled “VACAR STABILITY STUDY OF PROJECTED 2008 LIGHT LOAD CONDITIONS”
4. VACAR Stability Working Group commissioned by the VACAR Planning Task Force- draft study entitled “VACAR STABILITY STUDY OF PROJECTED 2014/2015 WINTER PEAK LOAD CONDITIONS-Draft”
5. Coordinated Study Progress Energy Carolinas And South Carolina Public Service Authority: “PEC-SC_Red_Bluff_JointStudy_2010_Final- 2016 Summer Peak”
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STUDY PARTICIPANTS
Prepared by: VACAR Power Flow Working Group (PFWG) Representative Company Joey West, Chair Progress Energy Carolinas Brian D. Moss Duke Energy Carolinas S. E. Shealy South Carolina Electric and Gas V.M. Abercrombie South Carolina Electric and Gas (Alternate) K.L. Ford South Carolina Electric and Gas (Alternate) William Gaither South Carolina Public Service Authority Mehdi Shakibafar Dominion Virginia Power Helen Stines Alcoa Power Generating, Inc. (APGI) - Yadkin Reviewed by: VACAR Planning Task Force (PTF) Representative Company A. Mark Byrd, Chair Progress Energy Carolinas Brian D. Moss Duke Energy Carolinas Phil Kleckley South Carolina Electric and Gas Jim Peterson South Carolina Public Service Authority Mehdi Shakibafar Dominion Virginia Power James Manning North Carolina Electric Membership Corporation Herb Nadler Southeastern Power Administration Rick Anderson Fayetteville Public Works Commission Jennifer Connors Alcoa Power Generating, Inc. (APGI) - Yadkin
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TABLE OF CONTENTS
I. EXECUTIVE SUMMARY .................................................................................................................................... 1 A. OVERVIEW ........................................................................................................................................................ 2 B. SUMMARY DIAGRAM ..................................................................................................................................... 3
II. INTRODUCTION ................................................................................................................................................. 4 A. INTRODUCTION ............................................................................................................................................... 5 B. STUDY PROCEDURE ....................................................................................................................................... 5
III. STUDY RESULTS ............................................................................................................................................... 6 A. SIGNIFICANT FACILITIES DISCUSSION ..................................................................................................... 7 B. INDIVIDUAL ASSESSMENTS ......................................................................................................................... 9
Progress Energy Carolinas - Carolina Power and Light (CPL) ........................................................................... 10 Duke Energy Carolinas (Duke) ........................................................................................................................... 21 South Carolina Public Service Authority (SCPSA) ............................................................................................. 35 Dominion Virginia Power (DVP) ........................................................................................................................ 41 APGI - Yadkin ..................................................................................................................................................... 46
IV. TRANSFER TABLES AND OPERATING GUIDES .................................................................................... 47 Table A. Progress Energy Carolinas Imports ......................................................................................................... 48 Table B. Duke Energy Carolinas Imports ............................................................................................................... 50 Table C. South Carolina Electric and Gas Imports ................................................................................................. 51 Table D. South Carolina Public Service Authority Imports ................................................................................... 52 Table E. Dominion Virginia Power Imports ........................................................................................................... 53 Table F. Operating Guides ..................................................................................................................................... 54
V. SUPPORTING DATA ......................................................................................................................................... 55 Exhibit A. Major Generation and Transmission Facility Changes ......................................................................... 56 Exhibit B. Generation Dispatch .............................................................................................................................. 61 Exhibit C. Detailed Interchange ............................................................................................................................. 74 Exhibit D. Outaged Facilities ................................................................................................................................. 81 Exhibit E. Transfer Capability Definitions ............................................................................................................. 95
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I. EXECUTIVE SUMMARY
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A. OVERVIEW The purpose of this study is to analyze the transfer capabilities among the Virginia-Carolinas (VACAR) companies and determine the effect of heavy parallel transfers on those transfer capabilities using the 2015 summer peak power flow model developed by the SERC Long Term Study Group (LTSG) in June 2008. Part 1 is an analysis of the capabilities of the transmission systems within VACAR by identifying limits and limiting conditions to power transfers between the transmission systems within VACAR. The NITC and FCITC import limits for each company, resulting from the transfer capability evaluation, can be found in the Incremental Transfer Capability Tables in Section IV. The following list provides a summary of the most significant facilities found to be limits to transfers in this study. Elimination of these facilities as transfer limits may require infrastructure upgrades or additional operating procedures. Details concerning these key facilities can be found in the significant facilities discussion in Section III. • Weatherspoon-Marion 115 kV Line (CPLE) • Wateree 100/115 kV Transformer (Duke/CPLE) • Parkwood 500/230 kV Transformers (Duke) • Belews Creek-Bob White 230 kV Lines (Duke) • Shiloh-Pisgah 230 kV Lines (Duke) • Bush River-Morris Switching Station 100 kV Black Line (Duke) • Antioch 500/230 kV Transformers (Duke) • Winyah-Campfield 230 kV Line (SCPSA) • Pee Dee-Marion 230 kV Line (SCPSA) • Tuckertown-High Rock 100 kV Line (Yadkin) Part 2 is an analysis of the effects of heavy North to South and South to North parallel transfers on the VACAR inter-company transfer capabilities. The parallel transfer evaluation was done by conducting a standard transfer capability analysis while simulating a North to South transfer of 4000 MW from PJM Mid-Atlantic (Pennsylvania-New Jersey-Maryland) to Florida Reliability Coordination Council (FRCC). The transfer was reversed to give a South to North transfer. The impacts of these parallel transfers vary widely from company to company. Detailed results can be found in Section III which includes graphical representations of each parallel transfer and its effect on each VACAR company’s import capabilities. Part 3 is an analysis of the effects of moderate West to East intra-PJM parallel transfers on the VACAR inter-company transfer capabilities. The parallel transfer evaluation was done by conducting a standard transfer capability analysis while simulating a West to East transfer of 3000 MW from PJM’s western most zones (AEP, Dayton, Northern Illinois/COMED) to PJM Mid-Atlantic. Detailed results can be found in Section III which includes graphical representations of the parallel transfer and its effect on each VACAR company’s import capabilities.
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B. SUMMARY DIAGRAM
VACAR TRANSFER CAPABILITY Projected 2015 Summer Peak
LEGEND: nnnn - Normal Incremental Transfer Capability (NITC in MW)
(nnnn) - First Contingency Incremental Transfer Capability (FCITC in MW)
200+ (200+)
Duke
CPLE
SCPSA
SCEG
DVP
CPLW
2000+(750)
1400+ (700)
1300 (450)
2000+ (2000+)
700+ (600)
700+ (600)
2000+ (2000+)
1400+ (1300)
2000+ (1400)
2000+ (2000+)
2000+ (1200)
1400+ (1400+)
2000+ (2000+)
2000+ (2000+)
2000+ (1200)
1400+ (1400+)
2000+ (2000+)
2000+ (1700)
2000+ (650)
1400+ (950)
1400+ (500)
Yadkin
200+ (200+)
1400+ (1100)
200+ (200+)
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II. INTRODUCTION
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A. INTRODUCTION
The VACAR Reliability Agreement requires that studies be conducted to assess the capability of the bulk power system to withstand various contingencies without suffering uncontrolled, cascading interruptions. As part of this activity, Progress Energy Carolinas (PEC), Duke Energy Carolinas (Duke), South Carolina Electric and Gas (SCEG), South Carolina Public Service Authority (SCPSA), Dominion Virginia Power (DVP) and Alcoa Power Generating, Inc. (Yadkin) have conducted this joint study to assess performance as required by the North American Electric Reliability Corporation (NERC) Reliability Standards for Transmission System Performance. This study is part of a continuing series of studies being made to accomplish the objectives of the VACAR Reliability Agreement. At the direction of the VACAR Planning Task Force, the primary purpose of this study is to analyze the transfer capabilities among the VACAR companies, identifying the limits to power transfers and the effects of heavy parallel transfers. This investigation was initiated in August 2008 as a part of the VACAR Power Flow Working Group’s normal schedule for conducting studies of future system performance. The power flow base case for this study was derived by incorporating each VACAR company’s updates to the power flow model developed by the SERC LTSG which was released in June 2008.
B. STUDY PROCEDURE This assignment is a three-part study to evaluate the performance of the VACAR members’ transmission systems for the projected 2015 summer peak load, using an updated version of the 2015 summer power flow model developed by the SERC LTSG in June 2008. The MUST software was used to complete the linear results. Part 1 is an analysis of the performance of the VACAR members’ transmission systems that identifies limits to power transfers among the VACAR companies. Part 2 is an analysis of the effects of heavy North to South and South to North parallel transfers on the VACAR inter-company transfer capabilities. Part 3 is an analysis of the effects of moderate West to East intra-PJM parallel transfers on the VACAR inter-company transfer capabilities.
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III. STUDY RESULTS
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A. SIGNIFICANT FACILITIES DISCUSSION The following is a list of significant facilities, as determined by the VACAR Power Flow Working Group representatives, and what generation, outages, transfers, and operating guides affect them. Factors which may be considered in determining whether a facility should be considered “significant” in regards to this study include: • 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 • If the facility requires the use of an operating guide • If the outage of the facility results in the overload of numerous major transmission elements Weatherspoon-Marion 115 kV Line (CPLE) This line limits SCPSA-CPLE and SCPSA-DVP transfers during various conditions and at low transfer levels. This is a line that is sensitive to planned area generation and should continue to be monitored in the future. Wateree 115/100 kV Transformer (CPLE/Duke) The updated 2015 summer peak power flow case was created with the Wateree 115/100 kV transformer out of service to prevent overloads in the Great Falls-Wateree-Elgin-Camden area. This is similar to past studies where the DK1 operating guide (opening of the Great Falls-Wateree line) was invoked in order to accommodate additional transfers. System loading under 2015 summer peak conditions is predicted to require pre-contingency opening of the CPLE/Duke tie at Wateree in order to avoid overloads in the area. Parkwood 500/230 kV Transformers (Duke) The outage of either parallel bank limits Duke-CPLE and Duke-DVP transfers. An ancillary equipment CT upgrade can eliminate the lower transfer limits caused by bank 6. The transfer limits caused by bank 5 are sufficiently high that there are no corrective actions planned at this time; however, Duke is evaluating future corrective actions. Belews Creek-Bob White 230 kV Lines (Duke) Either circuit of the double circuit line limits Duke-CPLE, Duke-SCEG, Duke-SCPSA, and Duke-DVP transfers for the outages of a Belews Creek-North Greensboro 230 kV line or the Pleasant Garden-Woodleaf 500 kV line. An ancillary equipment CT upgrade can eliminate these transfer limits. The limits are sufficiently high that there are no corrective actions planned at this time. Shiloh-Pisgah 230 kV Lines (Duke) The outage of either circuit of the double circuit line limits CPLE-CPLW and Duke-CPLW transfers. The limit is sufficiently high that there are no corrective actions planned. Duke and PEC are evaluating future corrective actions, including an ancillary equipment upgrade which would provide some additional line capacity. Potential PEC plans to serve the majority of the CPLW load from external resources would require a reconductor of these lines. Bush River-Morris Switching Station 100 kV Black Line (Duke) This line limits SCEG-Duke transfers for the outage of the parallel Bush River-Morris Switching Station White 230 kV line. An ancillary equipment CT upgrade can eliminate this transfer limit. The limit is sufficiently high that there are no corrective actions planned at this time.
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Antioch 500/230 kV Transformers (Duke) The outage of either parallel bank limits DVP-Duke transfers. The impedance difference between the banks causes the limit to be different for each bank. The transfer limits are sufficiently high that there are no corrective actions planned at this time; however, Duke is evaluating future corrective actions. Winyah-Campfield 230 kV Line (SCPSA) This line limits SCE&G-CPLE and SCE&G-DVP transfers during various conditions. The transfer limits are sufficiently high that there are no corrective actions planned at this time; however, SCPSA is evaluating future corrective actions. Pee Dee-Marion 230 kV Line (SCPSA) This line limits SCPSA-CPLE and SCPSA-Duke transfers during various conditions. This line is sensitive to planned generation at Pee Dee and will be monitored in the future. Tuckertown-High Rock 100 kV Line (Yadkin) This line limits Yadkin-CPLE, Yadkin-SCE&G, and Yadkin-Duke transfers during various conditions. The outage of various circuits in Duke’s northern region can limit Yadkin exports to Duke, CP&LE, and SCE&G. This line is very responsive to Yadkin and Duke’s generation when Duke’s generation in the northern region is off-line. An approved operating procedure (YD1) is available to eliminate this line as a limit to transfer.
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B. INDIVIDUAL ASSESSMENTS The following discussions center on each company’s adequacy of import and/or export transfer capabilities for the 2015 summer peak season.
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Progress Energy Carolinas - Carolina Power and Light (CPL) Carolina Power and Light (CPL) is now doing business as Progress Energy Carolinas, Inc. (PEC) This new name has begun to appear in reports and data. In this report, however, Carolina Power and Light transfer results related to its eastern and western control areas are noted using CPLE or CPLW. Transfer Capability CPLE NITC import capability exceeds test levels for CPLE imports from Duke, SCEG, DVP and Yadkin. NITC import capability for CPLE imports from SCPSA was limited to 1300 MW by SCPSA’s Pee Dee-Marion 230kV Line. Under assumed study conditions testing single contingency events, FCITC for a CPLE import from Duke is limited to 750 MW by Duke’s Parkwood 500/230 kV 6 transformer for the outage of the parallel transformer. Duke’s Belews Creek-Bob White Tap 230 kV lines limit the transfer at 1000 MW for an outage of the Duke’s Belews Creek-North Greensboro 230 kV line. Duke’s Belews Creek-Bob White 230 kV lines limit the transfer at 1100 MW for an outage of the Duke’s Woodleaf-Pleasant Garden 500 kV line. Duke’s Parkwood 500/230 kV 5 transformer also limits this transfer at 1400 MW for an outage of the parallel transformer. Under assumed study conditions testing single contingency events, FCITC for a CPLE import from SCEG is limited to 700 MW by SCPSA’s Winyah-Campfield 230 kV line for an outage of Winyah-Hemingway 230 kV. At 1100 MW SCPSA’s Pee Dee-Marion 230 kV line is the limit for an outage of Kingstree-Kingstree 230 kV line. At 1200 MW CPLE’s Marion-Whiteville 115 kV is the limit for an outage of CPLE’s Marion-Whiteville 230 kV line. Also at 1300 MW Duke’s Parkwood 500/230 kV 6 transformer for the outage of the parallel transformer is the limit. Under assumed study conditions testing single contingency events, FCITC for a CPLE import from SCPSA is limited to 450 MW by CPLE’s Marion-Weatherspoon 115 kV for an outage of CPLE’s Latta-Weatherspoon 230 kV line. At 700 MW the limit is again Marion-Weatherspoon 115 kV line for the outage of the Marion-Whiteville 230 kV line. The transfer is limited at 800 MW by SCPSA’s Pee Dee-Marion 230 kV line for the Kingstree-Kingstree 230 kV line. Also at 800 MW CPLE’s Marion-Weatherspoon 115 kV Line is the limit with the Bennettsville-Laurinburg 230 kV Line contingency. At 900 MW SCPSA’s Pee Dee-Marion 230 kV line is the limit for CPLE’s Kingstree-Florence 230 kV line contingency. At 1000 MW the limit is CPLE’s Marion-Whiteville 115 kV line for the Marion-Whiteville 230 kV contingency. Also limiting at 1200 MW is SCPSA’s Conway-4 Mile 115 kV line for the outage of SCPSA’s Pee Dee-Marion 230 kV line. Under assumed study conditions testing single contingency events, FCITC for a CPLE import from DVP is not limited by any facility up to the transfer test level of 2000 MW. Under assumed study conditions testing single contingency events, FCITC for a CPLE import from Yadkin is not limited by any facility up to the transfer test level of 200 MW. CPLW NITC import capability exceeds test levels for CPLW imports from CPLE and Duke up to the 700 MW test level. Under assumed study conditions testing single contingency events, FCITC for a CPLW import from CPLE is limited to 600 MW by Duke’s Shiloh-Pisgah 230 kV line for an outage of the parallel line.
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Under assumed study conditions testing single contingency events, FCITC for a CPLW import from Duke is limited to 600 MW by Duke’s Shiloh-Pisgah 230 kV line for an outage of the parallel line. A complete listing of the resulting CPLE and CPLW transfer capabilities is provided in Section IV. Parallel Transfers North-South (PJM Mid-Atlantic-FRCC) CPLE A North to South (PJM Mid-Atlantic to FRCC) transfer with a test level of 4000 MW was run in parallel with each of the five standard CPLE imports. The results illustrated remaining FCITC for CPLE imports from Duke, SCEG, SCPSA, DVP and Yadkin at the parallel transfer test level of 4000 MW. Import transfer capability from Duke is 750 MW for a 0 MW parallel transfer level (FCITC). The transfer limit then increases to 1100 MW at a parallel transfer level of 800 MW. This limit is due to an overload of the Parkwood 500/230 kV 6 transformer for an outage of the parallel Parkwood 500/230 kV 5 transformer. The transfer limit then increases to 1250 MW at a parallel transfer level of 4000 MW. This limit is due to an overload of the Belews Creek-Bob White Tap 230 kV lines for an outage of the Belews Creek-Noth Greensboro 230 kV line. Import transfer capability from SCEG is 700 MW for a 0 MW parallel transfer level (FCITC). The transfer limit increases to 2300 MW at a parallel transfer level of 4000 MW. This limit is due to an overload of Winyah-Campfield 230 kV line for an outage of Winyah-Hemingway 230 kV line. Import transfer capability from SCPSA is 450 MW for a 0 MW parallel transfer level (FCITC). The transfer limit increases to 1650 MW at a parallel transfer level of 4000 MW. This limit is due to an overload of Marion-Weatherspoon 115 kV for an outage of Latta-Weatherspoon 230 kV line. Import transfer capability from DVP is 2100 MW for a 0 MW parallel transfer level (FCITC). The transfer limit decreases to 900 MW at a parallel transfer level of 4000MW. This limit is due to an overload of the Everetts-Trowbridge 115 kV Line for the outage of the Everetts-Earleys 230 kV Line. Import transfer capability from Yadkin is 200 MW for a 0 MW parallel transfer level (FCITC). The transfer limit remains at 200 MW at a parallel transfer level of 4000 MW CPLW A North to South (PJM Mid-Atlantic to FRCC) transfer with a test level of 4000 MW was run in parallel with the two CPLW imports. The results illustrated remaining FCITC for CPLW imports from CPLE and Duke at the parallel transfer test level of 4000 MW. Import transfer capability from CPLE is 600 MW at 0 MW parallel transfer level (FCITC). The transfer increases to 700 MW for a parallel transfer level of 1700 MW. This limit is due to an overload of the Pisgah-Shiloh 230 kV 2/1 line for and outage of the parallel Pisgah-Shiloh 230 kV 1/2 line. The transfer limit then decreases to 0 MW at a parallel transfer level of 4000 MW. This limit is due to an overload of the Peach Valley-Riverview 230 kV 2/1 line for an outage of the parallel Peach Valley-Riverview 230 kV 1/2 line. Import transfer capability from Duke is 600 MW at 0 MW parallel transfer level (FCITC). The transfer limit increases to 650 MW for a parallel transfer level of 1600 MW. This limit is due to an overload of
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the Pisgah-Shiloh 230 kV 2/1 line for and outage of the Pisgah-Shiloh 230 kV 1/2 line. The transfer limit then decreases to 0 MW at a parallel transfer level of 4000 MW. This limit is due to an overload of the Peach Valley-Riverview 230 kV 2/1 line for an outage of the parallel Peach Valley-Riverview 230 kV 1/2 line. South-North (FRCC-PJM Mid-Atlantic) CPLE A South to North (FRCC to PJM Mid-Atlantic) transfer with a test level of 4000 MW was run in parallel with each of the five standard CPLE imports. The results illustrated that FCITC for CPLE imports from Duke, SCEG, SCPSA and Yadkin decline to zero under this parallel transfer. Import transfer capability from Duke is 750 MW for a 0 MW parallel transfer level (FCITC). The transfer limit then decreases to 0 MW at a parallel transfer level of 1700 MW. This limit is due to an overload of the Parkwood 500/230 kV 6 transformer for an outage of the parallel Parkwood 500/230 kV 5 transformer. Import transfer capability from SCEG is 700 MW for a 0 MW parallel transfer level (FCITC). The transfer limit then decreases to 0 MW at a parallel transfer level of 1600 MW. This limit is due to an overload of the Winyah-Campfield 230 kV line for an outage of Winyah-Hemingway 230 kV line. Import transfer capability from SCPSA is 450 MW for a 0 MW parallel transfer level (FCITC). The transfer limit then decreases to 0 MW at a parallel transfer level of 1500 MW. This limit is due to an overload of the Marion-Weatherspoon 115 kV for an outage of the Weatherspoon- Latta 230 kV line. Import transfer capability from DVP is 2100 MW for a 0 MW parallel transfer level (FCITC). The transfer limit then increases to 2800 MW at a parallel transfer level of 1300 MW. This limit is due to an overload of the Everetts-Trowbridge 115 kV Line for the outage of the Everetts-Earleys 230 kV Line. The transfer limit then decreases to 0 MW at a parallel transfer level of 3000 MW. This limit is due to an overload of the Marion-Pee Dee 230 kV line for an outage of the Kingstree-Kingstree 230kV line. Import transfer capability from Yadkin is 200 MW for a 0 MW parallel transfer level (FCITC). The transfer limit remains at 200 MW for a parallel transfer level of 1200 MW. This is due to overload of the High Rock-Tuckertown 100 kV line for the outage of the Pleasant Garden-Woodleaf 500 kV line. The transfer limit then decreases to 0 MW at a parallel transfer level of 1700 MW. This limit is due to an overload of the Parkwood 500/230 kV 6 transformer for an outage of the parallel Parkwood 500/230 kV 5 transformer. CPLW A South to North (FRCC to PJM Mid-Atlantic) transfer with a test level of 4000 MW was run in parallel with each of the two CPLW imports. The results illustrated that FCITC for CPLW imports from Duke, and CPLE decline to zero under this parallel transfer. Import transfer capability from CPLE is 600 MW test level for a 0 MW parallel transfer level (FCITC). The transfer limit then decreases to 500 MW at a parallel transfer level of 2100 MW. This limit is due to an overload of the Pisgah-Shiloh 230 kV 2/1 line for an outage of the parallel Pisgah-Shiloh 230 kV 1/2 line. The transfer limit then decreases to 100 MW at a parallel transfer level of 3600 MW. This limit is due to an overload of the Weatherspoon-Fayetteville Dupont 115 kV line for an outage of the Weatherspoon-Fayetteville 230 kV line. This particular loading issue is due primarily to a localized generation dispatch at Weatherspoon Plant. The limit then decreases to 0 MW at a parallel transfer level
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of 4000 MW. This limit is due to an overload of the Central-Shady Grove 230 kV Black/White line for and outage of the parallel Central-Shady Grove 230 kV White/Black line. Import transfer capability from Duke is 600 MW for a 0 MW parallel transfer level (FCITC). The transfer limit then decreases to 550 MW at a parallel transfer level of 900 MW. The transfer limit then decreases to 0 MW at a parallel transfer level of 1700 MW. This limit is due to an overload of the Parkwood 500/230 kV 6 transformer for an outage of the parallel Parkwood 500/230 kV 5 transformer. Intra-PJM West-East (PJM West-PJM Mid-Atlantic) CPLE A West to East intra-PJM (PJM West-PJM Mid-Atlantic) transfer with a test level of 3000 MW was run in parallel with each of the five standard CPLE imports. The results illustrated remaining FCITC for CPLE imports from Duke, SCEG, SCPSA, DVP, and Yadkin at the parallel transfer test level of 3000 MW. Import transfer capability from Duke is 750 MW for a 0 MW parallel transfer level (FCITC). The transfer limit then decreases to 250 MW at a parallel transfer level of 3000 MW. This limit is due to an overload of the Parkwood 500/230 kV 6 transformer for an outage of the parallel Parkwood 500/230 kV 5 transformer. Import transfer capability from SCEG is 700 MW for a 0 MW parallel transfer level (FCITC). The transfer limit decreases to 550 MW at a parallel transfer level of 2500 MW. This limit is due to an overload of the Winyah-Campfield 230 kV line for an outage of Winyah-Hemingway 230 kV line. The transfer limit decreases to 450 MW at a parallel transfer level of 3000 MW. This limit is due to an overload of the Parkwood 500/230 kV 6 transformer for an outage of the parallel Parkwood 500/230 kV 5 transformer. Import transfer capability from SCPSA is 450 MW test level for a 0 MW parallel transfer level (FCITC). The transfer limit decreases to 300 MW at a parallel transfer level of 3000 MW. This limit is due to an overload of the Marion-Weatherspoon 115 kV for an outage of the Weatherspoon- Latta 230 kV line. Import transfer capability from DVP is 2100 MW for a 0 MW parallel transfer level (FCITC). The transfer limit then decreases to 2000 MW at a parallel transfer level of 3000 MW. This limit is due to an overload of the Weatherspoon 230/115 kV transformer for an outage of the Weatherspoon-Marion 115 kV line. Import transfer capability from Yadkin is 200 MW for a 0 MW parallel transfer level (FCITC). The transfer limit remains at 200 MW at a parallel transfer level of 3000 MW. This is due to overload of the High Rock-Tuckertown 100 kV line for the outage of the Pleasant Garden-Woodleaf 500 kV line. CPLW A West to East intra-PJM (PJM West-PJM Mid-Atlantic) transfer with a test level of 3000 MW was run in parallel with each of the two CPLW imports. The results illustrated remaining FCITC for CPLW imports from CPLE and Duke at the parallel transfer test level of 3000 MW. Import transfer capability from CPLE is 600 MW for a 0 MW parallel transfer level (FCITC). The transfer limit increases to 650 MW at a parallel transfer level of 3000 MW. This limit is due to an overload of the Pisgah-Shiloh 230 kV 2/1 line for an outage of the parallel Pisgah-Shiloh 230 kV 1/2 line.
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Import transfer capability from Duke is 600 MW for a 0 MW parallel transfer level (FCITC). The transfer limit remains at 600 MW for a parallel transfer level of 2100 MW. This limit is due to an overload of the Pisgah-Shiloh 230 kV 2/1 line for an outage of the parallel Pisgah-Shiloh 230 kV 1/2 line. The transfer limit decreases to 400 MW at a parallel transfer level of 3000 MW. This limit is due to an overload of the Parkwood 500/230 kV 6 transformer for an outage of the parallel Parkwood 500/230 kV 5 transformer.
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Progress Energy Carolinas - Carolina Power and Light EastNorth to South Parallel Transfer
0
500
1000
1500
2000
2500
3000
0 500 1000 1500 2000 2500 3000 3500 4000 4500
Single Parallel transfer From PJM_MA_LOAD to FRCC_GEN
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Duke Energy Carolinas (Duke) Transfer Capability Imports Under normal operating conditions assumed for this investigation, no elements are reported as a limit to Duke import capability. For the network conditions represented in this study, NITC levels for Duke imports from CPLE, SCEG, SCPSA, DVP, and Yadkin all exceed their respective transfer test levels. Under assumed study conditions testing single contingency events, FCITC for a Duke import from CPLE is not limited by any facility up to the transfer test level of 2000 MW. Under assumed study conditions testing single contingency events, FCITC for a Duke import from SCEG is limited to 1300 MW by Duke’s Bush River-Morris Switching Station Black 100 kV line for an outage of Duke’s Bush River-Morris Switching Station White 100 kV line. This limit is a minor restriction on Duke’s import capability from SCEG. No other limits exist up to the 1400 MW test level. Under assumed study conditions testing single contingency events, FCITC for a Duke import from SCPSA is limited to 1100 MW by SCPSA’s Pee Dee-Marion 230 kV line for an outage of CPLE/SCPSA’s Kingstree-Kingstree 230 kV line. This limit is a minor restriction on Duke’s import capability from SCPSA. SCPSA’s Pee Dee-Marion 230 kV line is also the next limiting elements providing 1200 MW of import capability. Under assumed study conditions testing single contingency events, FCITC for a Duke import from DVP is limited to 1400 MW by Duke’s Antioch 500/230 kV transformer bank 2 for an outage of Duke’s parallel Antioch 500/230 kV transformer bank 1. This limit is a minor restriction on Duke’s import capability from DVP. Duke’s Antioch 500/230 kV transformer bank 1 is the next limiting elements providing 1700 MW of import capability. Under assumed study conditions testing single contingency events, FCITC for a Duke import from Yadkin is not limited by any facility up to the transfer test level of 200 MW. Exports Under normal operating conditions assumed for this investigation, no elements are reported as a limit to Duke export capability. For the network conditions represented in this study, NITC levels for Duke exports to CPLE, CPLW, SCEG, SCPSA, and DVP all exceed the respective transfer test levels. Under assumed study conditions testing single contingency events, FCITC for a Duke export to CPLE is limited to 700 MW by Duke’s Parkwood 500/230 kV transformer bank 6 for an outage of Duke’s parallel Parkwood 500/230 kV transformer bank 5. This limit is a significant restriction on Duke’s export capability to CPLE. Duke’s Belews Creek-Bob White Tap 230 kV lines are the next limiting elements providing 1000 MW of export capability. Under assumed study conditions testing single contingency events, FCITC for a Duke export to CPLW is limited to 600 MW by Duke’s Shiloh-Pisgah 230 kV line for an outage of its parallel line. This limit is a minor restriction on Duke’s export capability to CPLW. No other limits exist up to the 700 MW test level. Under assumed study conditions testing single contingency events, FCITC for a Duke export to SCEG is limited to 1200 MW by Belews Creek-Bob White Tap 230 kV line for an outage of Belews Creek-North
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Greenboro 230 kV line. This limit is a significant restriction on Duke’s export capability to SCEG. Duke’s Belews Creek-Bob White Tap 230 kV lines are also the next limiting elements providing 1400 MW of export capability. Under assumed study conditions testing single contingency events, FCITC for a Duke export to SCPSA is limited to 1200 MW by Belews Creek-Bob White Tap 230 kV line for an outage of Belews Creek-North Greenboro 230 kV line This limit is a significant restriction on Duke’s export capability to SCPSA. Duke’s Belews Creek-Bob White Tap 230 kV lines are also the next limiting elements providing 1400 MW of export capability. Under assumed study conditions testing single contingency events, FCITC for a Duke export to DVP is limited to 650 MW by Duke’s Parkwood 500/230 kV transformer bank 6 for an outage of Duke’s parallel Parkwood 500/230 kV transformer bank 5. This limit is a significant restriction on Duke’s export capability to DVP. Duke’s Belews Creek-Bob White Tap 230 kV lines are the next limiting elements providing 1100 MW of export capability. A complete listing of the resulting Duke transfer capabilities is provided in Section IV. Parallel Transfers North-South (PJM Mid-Atlantic-FRCC) A North to South (PJM Mid-Atlantic to FRCC) transfer with a test level of 4000 MW was run in parallel with each of the five standard Duke imports. The results illustrated remaining FCITC for Duke imports from CPLE, SCEG, SCPSA, DVP, and Yadkin at the parallel transfer test level of 4000 MW. FCITCs for Duke imports from CPLE and DVP were significantly reduced and from SCEG and SCPSA were significantly increased at the parallel transfer test level. Import from CPLE drops slightly from its initial limit of 2200 MW to 2100 MW at a parallel transfer level of 2000 MW and then drops to 1600 MW at the parallel transfer test level of 4000 MW. Import from SCEG rises significantly from its initial limit of 1300 MW to 2100 MW at a parallel transfer level of 3900 MW and then remains at 2100 MW up to the parallel transfer test level of 4000 MW. Import from SCPSA rises significantly from its initial limit of 1000 MW to 2200 MW at a parallel transfer level of 3200 MW, remains at 2200 MW up to a parallel transfer level of 3500 MW, and then drops slightly to 2100 MW at the parallel transfer test level of 4000 MW. Import from DVP drops slightly from its initial limit of 2100 MW to 2000 MW at a parallel transfer level of 2200 MW and then continues to drop to 1600 MW at the parallel transfer test level of 4000 MW. Import from Yadkin remains at its initial limit of 200 MW up to the parallel transfer test level of 4000 MW. South-North (FRCC-PJM Mid-Atlantic) A South to North (FRCC to PJM Mid-Atlantic) transfer with a test level of 4000 MW was run in parallel with each of the five standard Duke imports. The results illustrated remaining FCITC for Duke imports from CPLE, DVP, and Yadkin at the parallel transfer test level of 4000 MW. FCITCs for Duke imports from SCEG and SCPSA were significantly reduced to 0 MW at a parallel transfer level of 3000 MW.
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Import from CPLE rises slightly from its initial limit of 2200 MW to 2400 MW at a parallel transfer level of 3500 MW and then drops slightly to 2300 MW at the parallel transfer test level of 4000 MW. Import from SCEG drops slightly from its initial limit of 1300 MW to 1100 MW at a parallel transfer level of 1200 MW and then drops significantly to 0 MW at a parallel transfer level of 3000 MW. Import from SCPSA drops significantly from its initial limit of 1000 MW to 0 MW at a parallel transfer level of 3000 MW. Import from DVP rises slightly from its initial limit of 2100 MW to 2400 MW at a parallel transfer level of 3900 MW and then drops slightly to 2300 MW at the parallel transfer test level of 4000 MW. Import from Yadkin remains drops slightly from its initial limit of 200 MW to 150 MW at the parallel transfer test level of 4000 MW. Intra-PJM West-East (PJM West-PJM Mid-Atlantic) A West to East intra-PJM (PJM West to PJM Mid-Atlantic) transfer with a test level of 3000 MW was run in parallel with each of the five standard Duke imports. The results illustrated remaining FCITC for Duke imports from CPLE, SCEG, SCPSA, DVP, and Yadkin at the parallel transfer test level of 3000 MW. Import from CPLE remains at its initial limit of 2200 MW up to the parallel transfer test level of 3000 MW. Import from SCEG remains at its initial limit of 1300 MW up to the parallel transfer test level of 3000 MW. Import from SCPSA drops slightly from its initial limit of 1100 MW to 950 MW at the parallel transfer test level of 3000 MW. Import from DVP drops slightly from its initial limit of 1400 MW to 1300 MW at the parallel transfer test level of 3000 MW. Import from Yadkin remains at its initial limit of 200 MW up to the parallel transfer test level of 3000 MW.
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Duke PowerNorth to South Parallel Transfer
0
500
1000
1500
2000
2500
3000
3500
0 500 1000 1500 2000 2500 3000 3500 4000 4500
Single Parallel transfer From PJM_MA_LOAD to FRCC_GEN
L: Bush River-Morris B 100 kV C: Bush River-Morris W 100 kV
L: Antioch 500/230 kV 2C: Antioch 500/230 kV 1
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VACAR 2015 Summer Peak Reliability Study
South Carolina Electric and Gas (SCEG) Transfer Capability SCEG tested the strength of its transmission system using test levels of 1400 MW exports to all VACAR companies. Imports were tested at 2000 MW from CPLE, Duke, and DVP. Imports were tested at 1400 MW from SCPSA and 200 MW from Yadkin. Imports NITC import capability exceeds test levels for SCEG imports from CPLE, Duke, SCPSA, DVP and Yadkin. Under assumed study conditions testing single contingency events, FCITC for a SCEG import from CPLE is not limited by any facility up to the transfer test level of 2000 MW. Under assumed study conditions testing single contingency events, FCITC for a SCEG import from Duke is limited to 1200 MW by Duke’s Belews Creek-Bob White Tap 230 kV for the outage of Duke’s Belews Creek-North Greensboro 230 kV line. Under assumed study conditions testing single contingency events, FCITC for a SCEG import from SCPSA is not limited by any facility up to the transfer test level of 1400 MW. Under assumed study conditions testing single contingency events, FCITC for a SCEG import from DVP is not limited by any facility up to the transfer test level of 2000 MW. Under assumed study conditions testing single contingency events, FCITC for a SCEG import from Yadkin is not limited by any facility up to the transfer test level of 200 MW after Yadkin imposes Operating Procedure YD1. Exports Under assumed study conditions testing single contingency events, FCITC for a SCEG export to CPLE is limited to 700 by SCPSA’s Winyah-Campfield 230 kV line for the outage of SCPSA’s Winyah-Hemingway 230 kV line. Under assumed study conditions testing single contingency events, FCITC for a SCEG export to Duke is limited to 1300 MW by Duke’s Bush River-Morris Sw Sta B 100 kV for the outage of Duke’s Bush River-Morris Sw Sta W 100 kV line. Under assumed study conditions testing single contingency events, FCITC for a SCEG export to SCPSA is not limited by any facility up to the transfer test level of 1400 MW. Under assumed study conditions testing single contingency events, FCITC for a SCEG export to DVP is limited 950 MW by SCPSA’s Winyah-Campfield 230 kV line for the outage of SCPSA’s Winyah-Hemingway 230 kV line. A complete listing of the resulting SCEG transfer capabilities is provided in Section IV.
VACAR 2015 Summer Peak Reliability Study
Parallel Transfers North-South (PJM Mid-Atlantic-FRCC) A North to South (PJM Mid-Atlantic to FRCC) transfer with a test level of 4000 MW was simulated in parallel with each of the five standard SCEG imports from VACAR companies. The results illustrated remaining FCITC for SCEG imports from CPLE, Duke, SCPSA, DVP, and Yadkin at the parallel transfer test level of 4000 MW. Import transfer capability from CPLE is 2600 MW for a 0 MW parallel transfer level. The transfer limit decreases to 2400 MW FCITC at a parallel transfer level of 1500 MW. The transfer limit decreases to 1800 MW FCITC at a parallel transfer level of 4000 MW. This limit is due to SCPSA and SCEG’s Mateeba-Pepperhill 230 kV tie line for the outage of SCPSA and SCEG’s Charity-Williams Station 230 kV tie line. Import transfer capability from Duke is 1200 MW for a 0 MW parallel transfer level. The transfer limit increases to 1400 MW FCITC at a parallel transfer level of 2800 MW. This limit is due to Duke’s Belews Creek-Bob White Tap 230 kV line for the outage of Duke Belews Creek-North Greensboro 230 kV line. The transfer limit decreases to 0 MW FCITC at a parallel transfer level of 4000 MW. This limit is due to SEPA and SOCO’s Hartwell-Athena 230 kV tie line for the outage of Duke and SOCO’s Oconee-South Hall 500 kV tie line. Import transfer capability from SCPSA is 1700 MW for a 0 MW parallel transfer level. The transfer limit decreases to 1500 MW FCITC at a parallel transfer level of 2800 MW. This limit is due to SCPSA and SCEG’s Mateeba-Pepperhill 230 kV tie line for the outage of SCPSA and SCEG’s Charity-Williams Station 230 kV tie line. The transfer limit decreases to 1200 MW FCITC at a parallel transfer level of 4000 MW. This limit is due to SCPSA and SCEG’s Charity-Williams Station 230 kV tie line for the outage of SCPSA’s Carnes-Mateeba 230 kV line. Import transfer capability from DVP is 2800 MW for a 0 MW parallel transfer level. The transfer limit decreases to 2600 MW FCITC at a parallel transfer level of 1500 MW. The transfer limit decreases to 1300 MW FCITC at a parallel transfer level of 4000 MW. This limit is due to DVP’s Everets-Poplar C 115 kV line for the outage of DVP’s Earleys-Everets 230 kV line. Import transfer capability from Yadkin is 200 MW for a 0 MW parallel transfer level. The transfer limit increases to 250 MW FCITC for a parallel transfer level of 3600 MW. This limit is due to Yadkin’s High Rock-High Rock Jct 100 kV line for the outage of Duke’s Pl Garden-Woodleaf 500 kV line. The transfer limit decreases to 60 MW FCITC at a parallel transfer level of 4000 MW. This limit is due to Duke’s Peach Valley-Riverview 2 230 kV line for the outage of Duke’s Peach Valley-Riverview 1 230 kV line. South-North (FRCC-PJM Mid-Atlantic) A South to North (FRCC to PJM Mid-Atlantic) transfer with a test level of 4000 MW was simulated in parallel with each of the five standard SCEG imports. The results illustrated that FCITC for SCEG imports from CPLE, Duke, and SCPSA decline to zero while import from Yadkin allows minimal MW under this parallel transfer. Import transfer capability from CPLE is 2600 MW for a 0 MW parallel transfer level. The transfer limit increases to 2700 MW FCITC at a parallel transfer level of 1500 MW. The transfer limit decreases to 0 MW FCITC at a parallel transfer level of 4000 MW. This limit is due to SCPSA and SCEG’s Yemassee-
VACAR 2015 Summer Peak Reliability Study
Yemassee 230 kV tie line for the outage of SCPSA Bluffton-Purrysburg 230 kV line. Import transfer capability from Duke is 1200 MW for a 0 MW parallel transfer level. The transfer limit remains 1200 MW FCITC at a parallel transfer level of 350 MW. The transfer limit decreases to 0 MW FCITC at a parallel transfer level of 1700 MW. This limit is due to an overload of Duke’s Parkwood 500/230 kV 6 transformer for an outage of the parallel Parkwood 500/230 kV 5 transformer. Import transfer capability from SCPSA is 1700 MW for a 0 MW parallel transfer level. The transfer limit increases to 1800 MW FCITC at a parallel transfer level of 1500 MW. The transfer limit decreases to 0 MW FCITC at a parallel transfer level of 3000 MW. This limit is due to SCPSA’s Pee Dee-Marion 230 kV line for the outage of CPLE and SCPSA’s Kingstree-Kingstree 230 kV tie line. Import transfer capability from DVP is 2800 MW for a 0 MW parallel transfer level. The transfer limit remains 2800 MW FCITC at a parallel transfer level of 600 MW. The transfer limit decreases to 0 MW FCITC at a parallel transfer level of 3200 MW. This limit is due to SCPSA and SCEG’s Yemassee-Yemassee 230 kV tie line for the outage of SCPSA Bluffton-Purrysburg 230 kV line. Import transfer capability from Yadkin is 200 MW for a 0 MW parallel transfer level. The transfer limit decrease by to 150 MW FCITC for a parallel transfer level of 4000 MW. This limit is due to Yadkin’s High Rock-High Rock Jct 100 kV line for the outage of Duke’s Pl Garden-Woodleaf 500 kV line. Intra-PJM West-East (PJM West-PJM Mid-Atlantic) A West to East intra-PJM (PJM West-PJM Mid-Atlantic) transfer with a test level of 3000 MW was simulated in parallel with each of the five standard SCEG imports. The results illustrated remaining FCITC for CPLE imports from Duke, SCEG, SCPSA, DVP, and Yadkin at the parallel transfer test level of 3000 MW. Import transfer capability from CPLE is 2600 MW for a 0 MW parallel transfer level. The transfer limit remains 2600 MW FCITC at a parallel transfer level of 3000 MW. This limit is due to SCPSA and SCEG’s Mateeba-Pepperhill 230 kV tie line for the outage of SCPSA and SCEG’s Charity-Williams Station 230 kV tie line. Import transfer capability from Duke is 1200 MW for a 0 MW parallel transfer level. The transfer limit remains 1200 MW FCITC at a parallel transfer level of 1000 MW. The transfer limit decreases to 500 MW FCITC at a parallel transfer level of 3000 MW. This limit is due to an overload of Duke’s Parkwood 500/230 kV 6 transformer for an outage of the parallel Parkwood 500/230 kV 5 transformer. Import transfer capability from SCPSA is 1700 MW for a 0 MW parallel transfer level. The transfer limit remains 1700 MW FCITC at a parallel transfer level of 3000 MW. This limit is due to SCPSA and SCEG’s Mateeba-Pepperhill 230 kV tie line for the outage of SCPSA and SCEG’s Charity-Williams Station 230 kV tie line. Import transfer capability from DVP is 2800 MW for a 0 MW parallel transfer level. The transfer limit remains 2800 MW FCITC at a parallel transfer level of 3000 MW. This limit is due to SCPSA and SCEG’s Mateeba-Pepperhill 230 kV tie line for the outage of SCPSA and SCEG’s Charity-Williams Station 230 kV tie line. Import transfer capability from Yadkin is 200 MW for a 0 MW parallel transfer level. The transfer limit remains 200 MW FCITC for a parallel transfer level of 3000 MW. This limit is due to Yadkin’s High
VACAR 2015 Summer Peak Reliability Study
Rock-High Rock Jct 100 kV line for the outage of Duke’s Pl Garden-Woodleaf 500 kV line.
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South Carolina Electric and GasNorth to South Parallel Transfer
0
500
1000
1500
2000
2500
3000
0 500 1000 1500 2000 2500 3000 3500 4000 4500
Single Parallel transfer From PJM_MA_LOAD to FRCC_GEN
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South Carolina Public Service Authority (SCPSA) Transfer Capability All import NITCs exceed transfer test levels. The import FCITC’s from CPLE and DVP were not limited by any facility up to the transfer test level of 2000 MW. The import FCITC from SCEG is not limited by any facility up to the transfer test level of 1400 MW. The import FCITC from Duke is limited to 1200 MW by loading on Duke’s Belews Creek-Bob Wwhite Tap 230 kV line for the outage of Duke’s Belews Creek-North Greensboro 230 kV line. A complete listing of the resulting SCPSA transfer capabilities is provided in Section IV. Parallel Transfers North-South (PJM Mid-Atlantic-FRCC) A North to South (PJM Mid-Atlantic to FRCC) transfer with a test level of 4000 MW was run in parallel with each of the four standard SCPSA imports from VACAR companies. The results illustrated remaining FCITC for SCPSA imports from CPLE, Duke, SCEG, and DVP at the parallel transfer test level of 4000 MW. SCPSA’s import transfer capability from CPLE is 2700 MW for a 0 MW parallel transfer level. The transfer limit decreases to a 1700 MW FCITC at the parallel transfer level of 4000 MW. This limit is due to loading on the Weatherspoon Plant-Fairmont 115 kV line for the outage of the Weatherspoon-Weatherspoon Plant 230/115 kV transformer. SCPSA’s import transfer capability from Duke is 1200 MW for a 0 MW parallel transfer level. The transfer limit increases slightly to 1300 MW at a parallel transfer level of 2100 MW. This limit is due to Duke’s Belews Creek-Bob White Tap 230 kV line for the outage of Duke’s Belews Creek-N Greensboro 230 kV line. The transfer limit then decreases to 50 MW at a parallel transfer level of 4000 MW. This limit is due to Duke’s Peach Valley-Riverview 230 kV 1/2 line for the outage of Duke’s Peach Valley-Riverview 230 kV 2/1 line. SCPSA’s import transfer capability from SCEG is 2000 MW for a 0 MW parallel transfer level. The transfer limit decreases slightly to 1700 MW at a parallel transfer level of 4000 MW. This limit is due to loading on SCPSA’s Columbia-Lexington 115 kV line for the outage of SCPSA and SCEG’s Silver Lake-Lyles 115 kV tie line. SCPSA’s import transfer capability from DVP is 2800 MW for a 0 MW parallel transfer level. The transfer limit increases slightly to 3200 MW at a parallel transfer level of 400 MW. The transfer limit then decreases to 1300 MW at a parallel transfer level of 4000 MW. This limit is due to DVP’s Everetts-Poplar Chapel 115 kV line for the outage of DVP’s Earleys-Everetts 230 kV line.
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South-North (FRCC-PJM Mid-Atlantic) A South to North (FRCC to PJM Mid-Atlantic) transfer with a test level of 4000 MW was run in parallel with each of the four standard SCPSA imports. The results illustrated that the FCITC for SCPSA imports from CPLE, Duke, SCEG, and DVP decline to zero under this parallel transfer. SCPSA’s import transfer capability from CPLE is 2700 MW for a 0 MW parallel transfer level. The transfer limit increases slightly to 2900 MW at the parallel transfer level of 2900 MW. The transfer limit then decreases to 0 MW at the parallel transfer level of 4000 MW due to loading on the SCPSA and SCEG Yemassee-Yemassee 230 kV tie for the outage of SCPSA’s Bluffton-Purrysburg 230 kV line. SCPSA’s import transfer capability from Duke is 1200 MW for a parallel transfer level up to 300 MW, limited by loading of Duke’s Belews Creek-Bob White Tap 230 kV line for the outage of Duke’s Belews Creek-North Greensboro 230 kV line. The transfer limit then decreases to 0 MW at a parallel transfer level of 4000 MW due to loading on Duke’s Parkwood 500/230 kV transformer for the outage of the parallel transformer. SCPSA’s import transfer capability from SCEG is 2000 MW for a 0 MW parallel transfer level. The FCITC then increases slightly to 2100 MW, limited due to loading on SCPSA’s Columbia-Lexington 115 kV line for the outage of SCPSA and SCEG’s Silver Lake-Lyles 115 kV tie line. The FCITC then decreases to 0 MW at a parallel transfer level of 4000 MW due to loading on SCPSA and SCEG’s Yemassee-Yemassee 230 kV tie for the outage of SCPSA’s Bluffton-Purrysburg 230 kV line. SCPSA’s import transfer capability from DVP is 2800 MW for a 0 MW parallel transfer level. The transfer limit decreases to 0 MW at a parallel transfer level of 4000 MW due to loading on SCPSA and SCEG’s Yemassee-Yemassee 230 kV tie for the outage of SCPSA’s Bluffton-Purrysburg 230 kV line. Intra-PJM West-East (PJM West-PJM Mid-Atlantic) A West to East intra-PJM (PJM West-PJM Mid-Atlantic) transfer with a test level of 3000 MW was run in parallel with each of the four standard SCPSA imports. The results illustrated remaining FCITC for SCPSA imports from CPLE, Duke, SCEG, and DVP at the parallel transfer test level of 3000 MW. SCPSA’s import transfer capability from CPLE is 2700 MW for a 0 MW parallel transfer level. The transfer limit increases slightly to 2800 MW at the parallel transfer level of 3000 MW due to loading on the Weatherspoon Plant-Fairmont 115 kV line for the outage of the Weatherspoon-Weatherspoon Plant 230/115 kV transformer. SCPSA’s import transfer capability from Duke is 1200 MW for a 0 MW parallel transfer level. The FCITC then decreases slightly to 1100 MW due to loading on Duke’s Belews Creek-Bob White Tap 230 kV line for the outage of Duke’s Belews Creek-North Greensboro 230 kV line. As the parallel transfer increases to 3000 MW, the FCITS decreases to 500 MW due to loading on Duke’s Parkwood 500/230 kV transformer for the outage of the parallel transformer. SCPSA’s import transfer capability from SCEG is 2000 MW for a 0 MW parallel transfer level. The FCITC then decreases by 3 MW at a parallel transfer level of 3000 MW due to loading on SCPSA’s Columbia-Lexington 115 kV tie for the outage of SCPSA and SCEG’s Silver Lake-Lyles 115 kV tie. SCPSA’s import transfer capability from DVP is 2800 MW for a 0 MW parallel transfer level. The transfer limit decreases slightly to 2600 MW at a parallel transfer level of 3000 MW due to loading on
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SCPSA and SCEG’s Yemassee-Yemassee 230 kV tie for the outage of SCPSA’s Bluffton-Purrysburg 230 kV line.
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South Carolina Public Service AuthorityNorth to South Parallel Transfer
0
500
1000
1500
2000
2500
3000
3500
0 500 1000 1500 2000 2500 3000 3500 4000 4500
Single Parallel transfer From PJM_MA_LOAD to FRCC_GEN
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Dominion Virginia Power (DVP) Dominion Virginia Power expects to serve its customers demand and firm contracts with a combination of native generation and purchased power as depicted in the SERC LTSG network model for the 2015 summer case. Based on the results from this study, DVP does not anticipate any problems or negative impacts, due to its operations or facilities, on the VACAR systems during this period.
DVP Import and Export Capability
For the network conditions represented in this study, NITC levels for all transfers meet or exceed test levels. Under assumed study conditions testing single contingency events, the following facilities appear as limits to DVP’s import and export capabilities with FCITC at levels below that established for testing.
Imports From Limiting Facility (Owner) Outaged Facility FCITC
Exports To Limiting Facility (Owner) Outaged Facility FCITC
Duke Antioch 500/230 kV 2 (Duke) Antioch 500/230 kV 2 (Duke) 1400 A complete listing of the resulting DVP transfer capabilities is provided in Section IV. Parallel Transfers In the second phase of the study, two 4000 MW parallel transfers in conjunction with the normal intra-VACAR transfers were studied. One transfer from North (PJM Mid-Atlantic) to South (FRCC) and another transfer from South (FRCC) to North (PJM Mid-Atlantic) were studied. North-South (PJM Mid-Atlantic-FRCC) DVP import limit from CPLE rises from 1780 MW to 3450 MW as the parallel flow rises to 4000 MW with DVP’s Clover 500/230 kV transformer as the limit. DVP import limit from Duke rises from 670 MW to 1200 MW as the parallel flow rises to 1350 MW with Duke’s Parkwood 500/230 kV transformer 6 as the limit. At 3500 MW flow, the FCITC decreased to 0 MW with Hartwell - Athena 230 kV line as the limit. SCEG to DVP transfer rises from 950 MW to 2300 MW as the parallel flow rises to 2400 MW limited by SCPSA’s Winyah-Campfield 230 kV line. The FCITC decreased to 2100 MW as the North to South flow rises to 4000 MW with DVP’s Elmont-NorthWest 230 kV line as the limit. SCPSA to DVP transfer rises from 500 MW to 1900 MW as the parallel flow rises to 4000 MW with CPLE’s Marion-Dillon 115 kV line as the limit.
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South-North (FRCC-PJM Mid-Atlantic) DVP’s import limit from CPL drops from 1780 MW to 120 MW as the parallel flow rises to 4000 MW with DVP’s Clover 500/230 kV transformer as the limit. DVP’s import limit from Duke, SCEG, and SCPSA follows the same pattern as CPL with slightly different FCITC values. Intra-PJM West-East (PJM West-PJM Mid-Atlantic) In the third phase of the study, a 3000 MW intra-PJM parallel transfer in conjunction with the normal intra-VACAR transfers were studied. DVP’s import limit from CPLE drops from 1780 MW to 1100 MW as the parallel flow rises to 3000 MW with DVP’s Clover 500/230 kV transformer as the limit. DVP’s import limit from Duke drops from 650 MW to 200 MW as the parallel flow rises to 3000 MW with Duke’s Parkwood 500/230 kV transformer 6 as the limit. SCEG to DVP transfer drops slightly from 950 MW to 900 MW as the parallel flow rises to 1000 MW limited by SCPSA’s Winyah-Campfield 230 kV line. At 3000 MW flow FCITC drops to 350 MW, Duke’s Parkwood 500/230 kV transformer 6 is the limit. SCPSA to DVP transfer follows the same pattern as SCEG, limited by CPLE’s Marion-Dillon 115 kV line.
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Dominion Virginia PowerNorth to South Parallel Transfer
0
500
1000
1500
2000
2500
3000
3500
4000
0 500 1000 1500 2000 2500 3000 3500 4000 4500
Single Parallel transfer From PJM_MA_LOAD to FRCC_GEN
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APGI – Yadkin The load, generation and transmission systems configuration included as part of Yadkin’s system model represent the current transmission plan that will be installed before the 2015 summer period. Yadkin expects to serve its Badin load during this period with internal generation. Based on the results of this study, transfer capability will be maintained at acceptable levels on all interfaces. Transfer Capability Imports into Yadkin were not tested. The Badin load is small as compared to internal generation. NITC for Yadkin exports exceed the study test level. With assumed study conditions and testing single contingency events, FCITC from Yadkin to Duke, CP&LE, and SCEG are limited by the Tuckertown-High Rock 100 kV. The FCITC is limited for an outage of either the Woodleaf-Pleasant Garden 500 kV line, the McGuire-Woodleaf 500 kV line or the Tillery-Biscoe 115 kV line. But, with the operating guide YD1 invoked Yadkin’s exports exceed the 200 MW tested transfer level. The Duke, CP&LE, and SCEG imports from Yadkin are considered to be satisfactory for the 2015 summer study period.
Parallel Transfers Yadkin has no import transfer so parallel were not performed.
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IV. TRANSFER TABLES AND OPERATING GUIDES
VACAR 2015 Summer Peak Reliability Study April 2009 TABLE A
PROGRESS ENERGY CAROLINAS - CAROLINA POWER AND LIGHT SUMMARY OF INCREMENTAL TRANSFER CAPABILITIES
Notes: * Identified limit for this transfer Notes: (A) FCITC limits are reported a maximum of 3 times for the same limiting facility (1) Operating procedure identified (B) FCITC limits are not reported for limiting facilities with a TDF of less than 3%. (2) Operating procedure in effect (C) Outaged facilities in parenthesis indicate an operating procedure in effect. (3) An operating procedure is in effect; another operating procedure is identified (D) Available operating guide descriptions with corresponding identifier are provided. (4) Denotes exporting area has reduced load 48
Duke to CPLE 2000+ No limit found at 2000 MW None (4) *750 Parkwood 500/230 kV 6 797 7.5 72.9 Parkwood 500/230 kV 5 1000 Belews Creek-Bob White 230 kV 1/2 478 4.2 22.7 Belews Creek-N. Greensboro 230 kV 1100 Belews Creek-Bob White 230 kV 1/2 478 3.9 4.9 Woodleaf-Pleasant Garden 500 kV 1400 Parkwood 500/230 kV 5 840 7.4 72.2 Parkwood 500/230 kV 6 2000+ No other limit found at 2000 MW Any other tested facility SCEG to CPLE 1400+ No limit found at 1400 MW None (4) *700 Winyah-Campfield 230 kV 550 4.3 33.3 Winyah-Hemingway 230 kV 1100 Pee Dee- Marion 230 kV 797 15.3 32.2 Kingstree-Kingstree 230 kV 1200 Marion-Whiteville 115 kV 179 3.8 16.1 Marion-Whiteville 230 kV 1200 Pee Dee-Marion 230 kV 797 15.6 33.2 Kingstree-Florence 230 kV 1300 Parkwood 500/230 kV 6 797 4.1 72.9 Parkwood 500/230 kV 5 1400+ No other limit found at 1400 MW Any other tested facility SCPSA to CPLE 1300 Pee Dee-Marion 230 kV 797 19.4 - None (4) 1400+ No other limit found at 1400 MW Any other tested facility *450 Marion-Weatherspoon 115 kV 97 3.6 9.8 Latta-Weatherspoon 230 kV 700 Marion-Weatherspoon 115 kV 97 3.1 4.7 Marion-Whiteville 230 kV 800 Pee Dee-Marion 230 kV 797 22.1 32.2 Kingstree-Kingstree 230 kV 800 Marion-Weatherspoon 115 kV 97 3.0 5.2 Bennettsville-Laurinburg 230 kV 900 Pee Dee-Marion 230 kV 797 21.8 33.2 Kingstree-Florence 230kV 1000 Marion-Whiteville 115 kV 179 4.6 16.1 Marion-Whiteville 230 kV 1200 Conway-4 Mile 115 kV 122 5.0 9.6 Pee Dee-Marion 230 kV 1400+ No other limit found at 1400 MW Any other tested facility DVP to CPLE 2000+ No limit found at 2000 MW (4) 2000+ No limit found at 2000 MW Any tested facility
VACAR 2015 Summer Peak Reliability Study April 2009 TABLE A
PROGRESS ENERGY CAROLINAS - CAROLINA POWER AND LIGHT SUMMARY OF INCREMENTAL TRANSFER CAPABILITIES
Notes: * Identified limit for this transfer Notes: (A) FCITC limits are reported a maximum of 3 times for the same limiting facility (1) Operating procedure identified (B) FCITC limits are not reported for limiting facilities with a TDF of less than 3%. (2) Operating procedure in effect (C) Outaged facilities in parenthesis indicate an operating procedure in effect. (3) An operating procedure is in effect; another operating procedure is identified (D) Available operating guide descriptions with corresponding identifier are provided. (4) Denotes exporting area has reduced load 49
Yadkin to CPLE 200+ 0 (1) Tuckertown-High Rock 100 kV 102 8.9 1.9 Woodleaf-Pleasant Garden 500 kV YD1 0 (1) Tuckertown-High Rock 100 kV 102 8.9 1.9 McGuire-Woodleaf 500 kV YD1 0 (1) Tuckertown-High Rock 100 kV 102 12.2 17.7 Tillery-Biscoe 115 kV YD1 200+ No other limit found at 200 MW Any other tested facility YD1 CPLE to CPLW 700+ No limit found at 700 MW None *600 Shiloh-Pisgah 230 kV 2/1 507 43.0 64.2 Shiloh-Pisgah 230 kV 1/2 700+ No other limit found at 700 MW Any other tested facility Duke to CPLW 700+ No limit found at 700 MW None *600 Shiloh-Pisgah 230 kV 2/1 507 43.9 64.2 Shiloh-Pisgah 230 kV 1/2 700+ No other limit found at 700 MW Any other tested facility
VACAR 2015 Summer Peak Reliability Study April 2009 TABLE B
DUKE ENERGY CAROLINAS SUMMARY OF INCREMENTAL TRANSFER CAPABILITIES
Notes: * Identified limit for this transfer Notes: (A) FCITC limits are reported a maximum of 3 times for the same limiting facility (1) Operating procedure identified (B) FCITC limits are not reported for limiting facilities with a TDF of less than 3%. (2) Operating procedure in effect (C) Outaged facilities in parenthesis indicate an operating procedure in effect. (3) An operating procedure is in effect; another operating procedure is identified (D) Available operating guide descriptions with corresponding identifier are provided. (4) Denotes exporting area has reduced load 50
CPLE to Duke 2000+ No limit found at 2000 MW None (4) 2000+ No limit found at 2000 MW None SCEG to Duke 1400+ No limit found at 1400 MW None (4) *1300 Bush River-Morris Sw Sta B 100 kV 69.3 3.5 30.3 Bush River-Morris Sw Sta W 100 kV 1400+ No other limit found at 1400 MW Any other tested facility SCPSA to Duke 1400+ No limit found at 1400 MW None (4) *1100 Pee Dee-Marion 230 kV 797 16.4 32.2 Kingstree-Kingstree 230 kV 1200 Pee Dee-Marion 230 kV 797 16.1 33.2 Kingstree-Kingstree North 230 kV 1300 Pee Dee-Marion 230 kV 797 16.1 33.2 Kingstree North-Sardis 230 kV 1400+ No other limit found at 1400 MW Any other tested facility DVP to Duke 2000+ No limit found at 2000 MW None (4) *1400 Antioch 500/230 kV 2 840 18.0 72.0 Antioch 500/230 kV 1 1700 Antioch 500/230 kV 1 840 17.0 68.1 Antioch 500/230 kV 2 1800 Antioch-Mitchell River 230 kV 2/1 717 17.3 67.3 Antioch-Mitchell River 230 kV 1/2 2000+ No other limit found at 2000 MW Any other tested facility Yadkin to Duke 200+ No limit found at 200 MW None 0 (1) Tuckertown-High Rock 100 kV 102 8.8 1.9 Woodleaf-Pleasant Garden 500 kV YD1 50 (1) Tuckertown-High Rock 100 kV 102 8.8 1.9 McGuire-Woodleaf 500 kV YD1 50 (1) Tuckertown-High Rock 100 kV 102 12.1 17.7 Tillery-Biscoe 115 kV YD1 200+ No other limit found at 200 MW Any other tested facility
VACAR 2015 Summer Peak Reliability Study April 2009 TABLE C
SOUTH CAROLINA ELECTRIC AND GAS SUMMARY OF INCREMENTAL TRANSFER CAPABILITIES
Notes: * Identified limit for this transfer Notes: (A) FCITC limits are reported a maximum of 3 times for the same limiting facility (1) Operating procedure identified (B) FCITC limits are not reported for limiting facilities with a TDF of less than 3%. (2) Operating procedure in effect (C) Outaged facilities in parenthesis indicate an operating procedure in effect. (3) An operating procedure is in effect; another operating procedure is identified (D) Available operating guide descriptions with corresponding identifier are provided. (4) Denotes exporting area has reduced load 51
CPLE to SCEG 2000+ No limit found at 2000 MW None 2000+ No limit found at 2000 MW Any tested facility Duke to SCEG 2000+ No limit found at 2000 MW None *1200 Belews Creek-Bob White 230 kV 1/2 478 3.6 22.7 Belews Creek-N. Greensboro 230 kV 1400 Belews Creek-Bob White 230 kV 1/2 478 3.1 4.9 Woodleaf-Pleasant Garden- 500 kV 1500 Parkwood 500/230 kV 6 797 3.6 72.9 Parkwood 500/230 kV 5 2000+ No other limit found at 2000 MW Any other tested facility SCPSA to SCEG 1400+ No limit found at 1400 MW None (4) 1400+ No limit found at 1400 MW Any tested facility DVP to SCEG 2000+ No limit found at 2000 MW None (4) 2000+ No limit found at 2000 MW Any tested facility Yadkin to SCEG 200+ No limit found at 1400 MW None 0 (1) Tuckertown-High Rock 100 kV 102 8.7 1.9 Woodleaf-Pleasant Garden 500 kV YD1 50 (1) Tuckertown-High Rock 100 kV 102 8.7 1.9 McGuire-Woodleaf 500 kV YD1 50 (1) Tuckertown-High Rock 100 kV 102 12.1 17.7 Tillery-Biscoe 115 kV YD1 200+ No other limit found at 200 MW Any other tested facility
VACAR 2015 Summer Peak Reliability Study April 2009 TABLE D
SOUTH CAROLINA PUBLIC SERVICE AUTHORITY SUMMARY OF INCREMENTAL TRANSFER CAPABILITIES
Notes: * Identified limit for this transfer Notes: (A) FCITC limits are reported a maximum of 3 times for the same limiting facility (1) Operating procedure identified (B) FCITC limits are not reported for limiting facilities with a TDF of less than 3%. (2) Operating procedure in effect (C) Outaged facilities in parenthesis indicate an operating procedure in effect. (3) An operating procedure is in effect; another operating procedure is identified (D) Available operating guide descriptions with corresponding identifier are provided. (4) Denotes exporting area has reduced load 52
CPLE to SCPSA 2000+ No limit found at 2000 MW None 2000+ No limit found at 2000 MW Any tested facility Duke to SCPSA 2000+ No limit found at 2000 MW None 1200 Belews Creek-Bob White 230 kV 1/2 478 3.6 22.7 Belews Creek-N. Greensboro 230 kV 1400 Belews Creek-Bob White 230 kV 1/2 478 3.1 49.4 Woodleaf-Pleasant Garden 500 kV 1500 Parkwood 500/230 kV 6 739.8 3.7 72.9 Parkwood 500/230 kV 5 2000+ No other limit found at 2000 MW Any other tested facility SCEG to SCPSA 1400+ No limit found at 1400 MW None 1400+ No limit found at 1400 MW Any tested facility DVP to SCPSA 2000+ No limit found at 2000 MW None (4) 2000+ No limit found at 2000 MW Any tested facility
VACAR 2015 Summer Peak Reliability Study April 2009 TABLE E
DOMINION VIRGINIA POWER SUMMARY OF INCREMENTAL TRANSFER CAPABILITIES
Notes: * Identified limit for this transfer Notes: (A) FCITC limits are reported a maximum of 3 times for the same limiting facility (1) Operating procedure identified (B) FCITC limits are not reported for limiting facilities with a TDF of less than 3%. (2) Operating procedure in effect (C) Outaged facilities in parenthesis indicate an operating procedure in effect. (3) An operating procedure is in effect; another operating procedure is identified (D) Available operating guide descriptions with corresponding identifier are provided. (4) Denotes exporting area has reduced load 53
CPLE to DVP 2000+ No limit found at 2000 MW None *1700 Clover 500/230 kV 927 16.64 22.0 Wake-Carson 500 kV 2000+ No other limit found at 2000 MW Any other tested facility Duke to DVP 2000+ No limit found at 2000 MW None *650 Parkwood 500/230 kV 6 797 8.5 72.8 Parkwood 500/230 kV 5 1100 Belews Creek-Bob White 230 kV 1/2 478 4.0 22.7 Belews Creek-N. Greensboro 230 kV 1200 Belews Creek-Bob White 230 kV 1/2 478 3.7 4.9 Pleasant Garden-Woodleaf 500 kV 1200 Parkwood 500/230 kV 5 840 8.4 72.2 Parkwood 500/230 kV 6 1800 Clover 500/230 kV 927 16.1 22.0 Wake-Carson 500 kV 2000+ No other limit found at 2000 MW Any other tested facility SCEG to DVP 1400+ No limit found at 1400 MW None (4) *950 Winyah-Campfield 230 kV 550 3.2 33.3 Winyah-Hemingway 230 kV 1100 Parkwood 500/230 kV 6 797 4.9 72.8 Parkwood 500/230 kV 5 1200 Fayetteville East-Erwin 230 kV 478 6.3 13.5 Cumberland-Wake 500 kV 1400+ No other limit found at 1400 MW Any other tested facility SCPSA to DVP 1400+ No limit found at 1400 MW None (4) *500 Marion- Weatherspoon 115 kV 97 3.1 9.8 Latta-Weatherspoon 230 kV 650 Rockingham-West End 230 kV West 539 3.1 59.8 Rockingham-West End 230 kV East 1000 Pee Dee-Marion 230 kV 797 16.4 32.2 Kingstree-Kingstree 230 kV 1100 Pee Dee-Marion 230 kV 797 17.8 33.1 Kingstree-Kingstree North 230 kV 1100 Fayetteville East-Erwin 230 kV 478 7.0 13.5 Cumberland-Wake 500 kV 1100 Pee Dee-Marion 230 kV 797 17.8 33.2 Kingstree North-Sardis 230 kV 1300 Parkwood 500/230 kV 6 797 4.2 72.8 Parkwood 500/230 kV 5 1400+ No other limit found at 1400 MW Any other tested facility
VACAR 2015 Summer Peak Reliability Study April 2009 TABLE F
YD1 Open Tuckertown-High Rock 100 kV Tuckertown-High Rock 100 kV Any outaged facility Yadkin Duke
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V. SUPPORTING DATA
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EXHIBIT A MAJOR GENERATION AND TRANSMISSION FACILITY CHANGES
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TABLE A.1 MAJOR GENERATION FACILITY CHANGES
Company Generation Facility Changes Date
PEC Wayne County Generation (CPLE, 157 MW) March-09 PEC Richmond County Generation (CPLE, 660 MW) Jun-11
Duke Retire Buck Unit 4 (39 MW) Jun-11 Duke Retire Buck Unit 3 (73 MW) Jun-12 Duke Install Buck Combined Cycle (621 MW) Jun-12 Duke Install new Cliffside Steam Station Unit 6 (880 MW) Jun-12 Duke Retire Cliffside Steam Station Units 1-4 (202 MW) Jun-12 Duke Install Dan River Combined Cycle (621 MW) Jun-12 Duke Retire Dan River Units 1-2 (136 MW) Jun-12 Duke Retire Dan River Unit 3 (145 MW) Jun-13 Duke Retire Buzzard Roost Combustion Turbines (196 MW) Jun-14 Duke Retire Riverbend Combustion Turbines (120 MW) Jun-15 Duke Retire Buck Combustion Turbines (93 MW) Jun-15 Duke Retire Dan River Combustion Turbines (85 MW) Jun-15 Duke Retire Riverbend Units 4-5 (190 MW) Jun-15 Duke Retire Riverbend Unit 6 (134 MW) Jun-16 Duke Retire Riverbend Unit 7 (135 MW) Jun-17
SCEG Unsited Generation modeled at Jasper 131 MW Jun-08 SCEG Unsited Generation modeled at Jasper 131 MW Jun-09 SCEG Unsited Generation modeled at Yemassee 131 MW Jun-09 SCEG Unsited Generation modeled at Yemassee 131 MW Jun-10 SCEG Unsited Generation modeled at Canadys 131 MW Jun-10
SCPSA Pee Dee Unit #1 Jun-13
DVP Bath County Uprate 85 MW Apr-09 DVP Possum Point 6 uprate 60 MW May-09 DVP Ladysmith #3 & #4, 340 MW May-10 DVP Surry #1 uprate 15 MW Dec-10 DVP Surry #2 uprate 15 MW Dec-10 DVP North Anna 1 uprate 85 MW Jun-10 DVP North Anna 2 uprate 85 MW Jun-12
Yadkin None
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TABLE A.2 MAJOR TRANSMISSION FACILITY CHANGES
Compan
y Transmission Facility Changes Date
PEC Clinton-Lee 230 kV Line, Construct new line Jun-10 PEC Asheville-Enka 230 kV Line, Convert existing 115 kV Line to 230 kV Dec-10 PEC Mt. Olive 230 kV Sub, Construct Sub, Loop-in 1-230 kV and 1-115 kV line Jun-11 PEC Rockingham-West End 230 kV East, Construct new line Jun-11 PEC Asheboro- (Duke) Pleasant Garden 230 kV, Construct new line Jun-11 PEC Harris Plant-RTP 230 kV, Construct new line Jun-11 PEC Rockingham-Lilesville 230 kV, Construct new line Jun-11 PEC Richmond-Ft. Bragg Woodruff Street 230 kV, Construct new line Jun-11 PEC Asheville-Enka 115 kV, Construct new 115 kV Line Dec-12 PEC Greenville-Kinston Dupont 230 kV line, Construct line Jun-13 PEC Folkstone 230/115 kV Substation Jun-13 PEC Wake 500kV, Install 3rd 500/230 kV Transformer Jun-13 PEC Durham-RTP 230kV Line, Reconductor Jun-14
Duke Rebuild Logan (Fairview-McDowell) 100 kV Line to 954 ACSR Jun-05
Duke Rebuild High Point (High Rock Hydro-Healing Springs-Energy United 32) 100 kV Line to 954 ACSR Oct-05
Duke Add Kelsey Creek (Pacolet-Tiger) 230 kV Line 2nd circuit Jun-06 Duke Rebuild Clinchfield (Fairview-Cliffside) 100 kV Line to 556 ACSR Jun-06 Duke Uprate Draytonville (Ripp-Riverview) 230 kV Line to 659 MVA Jun-06 Duke Remove Dutchman (McGuire-Lincoln) 230 kV Line Dec-06 Duke Remove Schoonover (Riverbend-McGuire) 230 kV Line Dec-06 Duke Add Dutchover (Riverbend-Lincoln) 230 kV Line Dec-06 Duke Add Nantahala-Fontana 161 kV Line double circuit tie line to TVA 358 MVA Aug-09
per circuit, replaces existing single circuit tie line Duke Add Cliffside tap of existing McGuire-Jocassee 500 kV Line for new Jun-11
generation site and connection to 230 kV
SCEG Landfill 115kV Sw. Sta and Cap Bank 5/8 SCEG Hopkins 230/115kV Sub and Foldin 5/8 SCEG Hopkins 115kV 60 MVAR Cap Bank 5/8 SCEG Pepperhill 230/115kV Sub and Line Upgrades 5/9 SCEG Pepperhill-Ladson Tap 115kV Double Circuit 5/9 SCEG Killian 115kV 60 MVAR Cap Bank 5/8 SCEG Urquhart-Stevens 115kV Rebuild Double Circuit 5/9 SCEG Thomas Isl-Hobcaw 115kV UG Cable 6/8 SCEG Cola Ind Pk-Master Foods 115kV Upgrade 5/9 SCEG Denny Terrace-Pineland 230kV Line 12/9 SCEG Pineland Add 336 MVA Autotransformer #2 12/9 SCEG Salem Sw Sta 115kV 24 MVAR Cap Bank 5/9 SCEG Church Ck-Savage 115kV Rebuild Double Ckt 5/9 SCEG Yemassee-Burton 115kV Rebuild Double Ckt 5/10 SCEG Hamlin-Osceola Tap 115kV Line 12/9 SCEG Belvedere-Belvedere Sw 115kV Rebuild SPDC 5/10 SCEG Cainhoy 230/115kV Sub 5/10
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SCEG AM Williams -Cainhoy 115kV Convert to 230kV 5/10 SCEG AM Williams-Cainhoy 115kV Construct 5/12 SCEG St Andrews-Queensboro 115kV Line Upgrade 5/10 SCEG Accabee-Hagood-Charlotte St 115kV SPDC 5/10 SCEG Bayview-Charlotte St 115kV Line Upgrade 5/10 SCEG Ritter 36MVAR Cap Bank #2 5/10 SCEG Graniteville 336 MVA Autotranformer #3 12/10 SCEG Lake Murray 336 MVA Autotransformer #2 5/11 SCEG Mt Pleasant-Bayview 115kV Line Upgrade 12/11 SCEG Edenwood-Lake Murray 230kV Double Ckt 5/12 SCEG Pepperhill-Summerville 230kV Line Construct 5/12 SCEG Ritter 230/115kV Sub and Foldin 5/12 SCEG Aiken #3-Aiken Hampton 115kV Line Upgrade 5/12 SCEG Lyles-Denny Terrace 115kV Lines 1&2 Upgrade 12/12 SCEG Lyles-Williams St 115kV Line Upgrade 5/13 SCEG Canadys-Chuch Ck 230kV Rebuild to SPDC 12/13 SCEG Belvedere-Stevens Ck 115kV Rebuild to SPDC 5/14 SCEG Yemassee 336 MVA Autotransformer #3 5/14
SCPSA Bennettsville-Bennettsville (PEC) 230 kV Interconnection 5/2008 SCPSA Reconductor Conway-Singleton Ridge Rd. 115 kV Line 5/2008 SCPSA Bluffton 230/115 kV Substation Transformer Replacement 9/2008 SCPSA Kingstree-Lake City 230 kV Line 12/2008 SCPSA Shamrock 230/115/69 kV Substation 6/2009 SCPSA Varnville-Bluffton 115 kV Line Reconfiguration 6/2009 SCPSA Rebuild Georgetown-Campfield 115 kV for 230/115 kV 11/2009 SCPSA Rebuild Burke Road 69 kV Tap for 115 kV 12/2009 SCPSA Carolina Forest 230/115 kV Substation 6/2010 SCPSA Carolina Forest-Dunes #2 115 kV Line 6/2010 SCPSA Pee Dee-Lake City 230 kV Line 1/2011 SCPSA Mateeba-Johns Island #2 230 kV Line 6/2011 SCPSA Chime Bell 115 kV Switching Station 11/2011 SCPSA Arcadia-Garden City #2 115 kV Line 6/2012 SCPSA Johns Island 115 kV Capacitors (30 MVAR) 6/2012 SCPSA Hilton Head Gas Turbine-Market Place #2 115 kV Line 6/2012 SCPSA Pomaria 230/69 kV Substation 12/2012 SCPSA Carnes Crossroads-Sangaree Tap 115 kV Double-Circuit Rebuild 12/2012 SCPSA Bennettsville 230/69 kV Substation: Add 230/69 kV Transformer 6/2014
DVP Garrisonville 230 kV Line (Loop Line #252) 5/09 DVP Greenwhich 230 kV Cap Bank 5/09 DVP Bristers-Gainesville 230 kV Line 5/09 DVP Endless Caverns - Mt Jackson 115 kVUprate 5/09 DVP Landstown 230 kV Capbank 5/09 DVP Shellbank-Whealton 115 kV Uprate 5/09 DVP Reeves Avenue 230 kV Cap Bank 5/09 DVP Fentress 230 kV Cap Bank 5/09 DVP Kitty Hawk-Colington 2nd 115 kV Line 5/09 DVP Endless Caverns 2nd 230/115 kV TX 5/09 DVP Possum Point 2nd 230/115 kV TX 5/09
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DVP Chickahominy-Old Church 230 kV Line 11/09 DVP Elmont 2nd 230/115 kV TX 5/10 DVP 2nd Harrisonburg-Valley 230 kV Line 5/10 DVP Lanexa 2nd 230/115 kV TX 5/10 DVP Pleasant View-Hamilton 230 kV 5/10 DVP Chickahominy – Old Church 230 kV 11/10 DVP Iron Bridge-Southwest 230 kV Uprate 5/11 DVP Mount Storm-Meadowbrook-Loudoun 500 kV Line 5/11 DVP Carson-Suffolk 500 kV Line 5/11 DVP Suffolk-Thrasher 230 kV Line 5/11 DVP Pleasant View-Dickerson 230 kV Uprate 5/11 DVP Everetts 2nd 230/115 kV TX 5/11 DVP Possum Point 500 kV Interconnect PEPCO 12/11 DVP Northwest 230 kV Cap Bank 5/12 DVP Somerset 115 kV Cap Bank 5/12 DVP Hayes-Yorktown 115 kV Line 5/12 DVP Remington CT-Gainsville 230 kV Line 4/12 DVP Arlington-Ballston 230 kV Line 5/12 DVP Dooms-Lexington 500 kV Line Uprate 5/12 DVP Ladysmith-North Anna 500 kV Line Uprate 5/13 DVP Chancellor 2nd 500/115 kV TX 5/13 DVP Hamilton-Middleburg 230 kV Line 5/13 DVP Burk-Sideburn 230 kV Line 11/13 DVP Northern Neck 2nd 230/115 kV TX 5/14 DVP Harrisonburg-Merk 230 kV Line 5/14 DVP Landstown-VA Beach 230 kV Uprate 5/15
Yadkin None
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EXHIBIT B GENERATION DISPATCH
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TABLE B.1 PROGRESS ENERGY CAROLINAS - CAROLINA POWER AND LIGHT
GENERATION DISPATCH
Export Export Import Import Import Bus Generating Base 2000 700 2000 1400 200
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TABLE B.6 YADKIN
GENERATION DISPATCH
Export Bus Generating Base 200
Number Station kV (MW) (MW) 339001 Badin - Narrows 100 8 90 339001 Badin – Falls 100 0 35 339003 High Rock 100 0 33 339005 Tuckertown 100 0 42
Total 8 200
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EXHIBIT C DETAILED INTERCHANGE
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TABLE C.1 PROGRESS ENERGY CAROLINAS - CAROLINA POWER AND LIGHT
DETAILED INTERCHANGE
Carolina Power and Light East Scheduled Imports/Purchases CPLW 150 MW SCPSA (Foster-Wheeler) 9 MW Duke (Broad River) 850 MW Duke (NCEMC/CNS) 105 MW DVP (Kerr Dam) 95 MW AEP (NCEMC) 100 MW AEP (NCEMC #2) 100 MW Total 1409 MW Carolina Power and Light East Scheduled Exports/Sales Duke (City of Seneca) 30 MW Duke (NEMC) 100 MW DVP (NCEMPA and Littleton) 176 MW DVP (Craven County Wood Energy) _47 MW Total 353 MW CPLE Net Interchange -1056 MW
Carolina Power and Light West Scheduled Imports/Purchases Duke 150 MW TVA (SEPA) 1 MW Total 151 MW Carolina Power and Light West Scheduled Exports/Sales CPLE 150 MW Total 150 MW CPLW Net Interchange -1 MW Note: Positive net interchange indicates an export and negative interchange an import.
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TABLE C.2
DUKE ENERGY CAROLINAS DETAILED INTERCHANGE
Duke Energy Carolinas Scheduled Imports/Purchases CPLE (City of Seneca) 30 MW CPLE (NCEMC) 100 MW SCEG (City of Greenwood) 56 MW SCPSA (New Horizons/NHEC) 985 MW SEPA (Hartwell) 155 MW SEPA (Thurmond) 113 MW Total 1439 MW Duke Energy Carolinas Scheduled Exports/ Sales CPLE (Broad River) 850 MW CPLE (NCEMC/CNS) 105 MW CPLE (PEC/Rowan) 150 MW DVP (NCEMC/CNS) 100 MW SCEG (City of Orangeburg) 189 MW Total 1394 MW Net Interchange -45 MW Note: Positive net interchange indicates an export and negative interchange an import.
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TABLE C.3 SOUTH CAROLINA ELECTRIC AND GAS
DETAILED INTERCHANGE
South Carolina Electric & Gas Interchange Schedule CPLE (NCEMC) 0 MW Duke (Greenwood) 57 MW SCPSA (VC Summer) 322 MW SCPSA (Charleston Navy Yard) -21 MW SCPSA (Woodland Hills) -17 MW SCPSA (NHEC) -18 MW 266 MW Net SETH (SEPA) -22 MW Total Net Interchange 300 MW Note: Positive net interchange indicates an export and negative interchange an import.
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TABLE C.4 SOUTH CAROLINA PUBLIC SERVICE AUTHORITY
DETAILED INTERCHANGE
South Carolina Public Service Authority Scheduled Imports/Purchases SCEG (VC Summer) 322 MW SEPA (Russell) 212 MW SEPA (Thurmond) 63 MW Total 597 MW South Carolina Public Service Authority Scheduled Exports/Sales CPLE (Foster-Wheeler) 9 MW Duke (New Horizons) 985 MW SCEG (Charleston Navy Yard) 21 MW SCEG (Woodland Hills) 17 MW SCEG (New Horizons) 18 MW Total 1,050 MW Net Interchange 453 MW Note: Positive net interchange indicates an export and negative interchange an import.
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TABLE C.5 DOMINION VIRGINIA POWER
DETAILED INTERCHANGE
Dominion Virginia Power Scheduled Imports/Purchases AEP (Philpot) 15 MW AEP (Aquenergy) 2 MW CPLE (Power Agency and Littleton) 176 MW CPLE (PJM-Cravenwood) 47 MW Duke (NCEMC) 100 MW Total 340 MW Dominion Virginia Power Scheduled Exports/Sales AP (Bath County) 1212 MW CPLE (Kerr Dam) 95 MW Total 1307 MW Net Interchange 967 MW Note: Positive net interchange indicates an export and negative interchange an import.
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TABLE C.6
YADKIN DETAILED INTERCHANGE
APGI - Yadkin Scheduled Imports/Purchases No Imports APGI - Yadkin Scheduled Exports/Sales No Exports
Yadkin Net Interchange 0 MW Note: Positive net interchange indicates an export and negative interchange an import.
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EXHIBIT D OUTAGED FACILITIES
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TABLE D.1 PROGESS ENERGY CAROLINAS - CAROLINA POWER AND LIGHT
OUTAGED FACILITIES
FROM BUS TO BUS KV CKT FROM BUS TO BUS KV CKT Asheboro Asheboro East 115 North Wateree Transformer 115/100 1 Asheboro Asheboro East 115 South Robinson Transformer 230/115 1 Asheboro Biscoe 230 1 Robinson Transformer 230/115 2 Asheboro Siler City 230 1 Cape Fear Transformer 230/115 1 Asheboro Siler City 115 1 Cape Fear Transformer 230/115 2 Asheboro E Biscoe 115 1 Weatherspoon Transformer 230/115 1 Aurora Greenville 230 1 Henderson Transformer 230/115 1 Aurora New Bern 230 1 Henderson Transformer 230/115 2 Biscoe Rockingham 230 1 Concord Transformer 230/115 1 Black Creek Wilson 115 East Method Transformer 230/115 1 Black Creek Wilson 115 West Method Transformer 230/115 2 Blewett Rockingham 115 1 Milburnie Transformer 230/115 1 Blewett Tillery 115 1 Milburnie Transformer 230/115 2 Brunswick1 Castle Hayne 230 1 Selma Transformer 230/115 1 Brunswick1 Delco 230 1 Selma Transformer 230/115 2 Brunswick1 Jacksonville 230 1 Falls Transformer 230/115 1 Brunswick1 Weatherspoon Plant 230 1 Falls Transformer 230/115 2 Brunswick2 Delco 230 1 Erwin Transformer 230/115 1 Brunswick2 Wallace 230 1 Erwin Transformer 230/115 2 Brunswick2 Whiteville 230 1 Zebulon Transformer 230/115 1 Brunswick2 Wilmington Corn. Sw Sta 230 1 Clinton Transformer 230/115 1 Camden Camden Dupont 115 1 Rocky Mt Transformer 230/115 1 Camden Camden Junction 115 1 Rocky Mt Transformer 230/115 2 Camden Lugoff 230 1 Wilson Transformer 230/115 1 Camden Dup. Wateree 115 1 Wilson Transformer 230/115 2 Camden Junction Wateree 115 1 Lee Transformer 230/115 1 Cape Fear Biscoe 115 1 Lee Transformer 230/115 2 Cape Fear Erwin 115 1 Mt Olive Transformer 230/115 1 Cape Fear Harris 230 North Biscoe Transformer 230/115 1 Cape Fear Harris 230 South Asheboro Transformer 230/115 1 Cape Fear Method 230 1 Asheboro Transformer 230/115 2 Cape Fear West End 230 1 Siler City Transformer 230/115 1 Cary Regency Durham 230 1 Badin Transformer 115/100 1 Cary Regency Method 230 1 Badin Transformer 115/100 2 Castle Hayne Jacksonville 230 1 Rockingham Transformer 230/115 1 Castle Hayne Wilmington Corn. Sw Sta 230 1 Rockingham Transformer 230/115 2 Castle Hayne Jacksonville City 115 1 West End Transformer 230/115 1 Castle Hayne Wallace 115 1 West End Transformer 230/115 2 Chestnut Hills Falls 115 1 Fayetteville Transformer 230/115 1 Chestnut Hills Milburnie 115 1 Fayetteville Transformer 230/115 2 Clinton Erwin 230 1 Ft Bragg Wdrf St Transformer 230/115 1 Clinton Vander 115 1 Raeford Transformer 230/115 1 Clinton Wallace 230 1 Raeford Transformer 230/115 2 Concord Roxboro 115 1 Laurinburg Transformer 230/115 1 Cumberland Delco 230 1 Laurinburg Transformer 230/115 2 Cumberland Fayetteville 230 North New Bern Transformer 230/115 1 Cumberland Fayetteville 230 South New Bern Transformer 230/115 2 Cumberland Richmond 500 1 Kinston Dup Transformer 230/115 1 Cumberland Wake 500 1 Havelock Transformer 230/115 1 Cumberland Whiteville 230 1 Havelock Transformer 230/115 2 Darlington Florence 230 1 Morehead WW Transformer 230/115 1 Darlington Laurinburg 230 1 Wommack Transformer 230/115 1 Darlington Sumter 230 1 Wommack Transformer 230/115 2 Darlington Robinson 230 North Wallace Transformer 230/115 1 Darlington Robinson 230 South Jacksonville Transformer 230/115 1 Darlington South Bethune 230 1 Jacksonville Transformer 230/115 2 Delco Whiteville 115 1 Castle Hayne Transformer 230/115 1 Durham E. Durham 230 1 Castle Hayne Transformer 230/115 2 Durham Method 230 1 Delco Transformer 230/115 1 Erwin Fayetteville East 230 1 Delco Transformer 230/115 2 Erwin Fayetteville 115 1 Whiteville Transformer 230/115 1 Erwin Milburnie 230 1 Barnard Creek W Transformer 230/115 1
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FROM BUS TO BUS KV CKT FROM BUS TO BUS KV CKT Erwin Selma 230 1 Barnard Creek E Transformer 230/115 1 Falls Franklinton 115 1 Marion Transformer 230/115 1 Falls Henderson 115 1 Marion Transformer 230/115 2 Falls Method 115 1 Florence Transformer 230/115 1 Falls Milburnie 230 1 Florence Transformer 230/115 2 Fayetteville Fay. Dup. Sw.Sta 115 1 Kingstree Transformer 230/115 1 Fayetteville Fayetteville East 230 1 Sumter Transformer 230/115 1 Fayetteville Ft. Bragg Wdrff St 230 1 Sumter Transformer 230/115 2 Fayetteville Raeford 230 1 Camden Transformer 230/115 1 Fayetteville Rockingham 230 1 Pisgah Transformer 115/100 1 Fayetteville Vander 115 North Pisgah Transformer 115/100 2 Fayetteville Vander 115 South Walters Transformer 138/115 1 Fayetteville East Ft. Bragg Wdrff St 230 1 Walters Transformer 161/115 1 Florence Kingstree 230 1 Enka Transformer 230/115 1 Florence Latta 230 1 Craggy Transformer 230/115 1 Florence Marion 115 1 Craggy Transformer 230/115 2 Florence SCPSA Darlington 230 1 Cane River Transformer 230/115 1 Florence Hemingway 115 1 Asheville Transformer 230/115 1 Franklinton Henderson 115 1 Asheville Transformer 230/115 2 Franklinton Spring Hope Sw.Sta 115 1 Asheville Pisgah 230 1 Goldboro Kinston Dup. 115 1 Asheville Pisgah 230 2 Goldboro Lee 115 1 Asheville Horseshooe 115 1 Goldboro Wommack 115 1 Cane River Nagel 230 1 Greenville Everetts 230 1 Walters Douglas 138 1 Greenville Wilson 230 1 Walters Canton 115 1 Harris Cary Regency Park 230 1 Walters Canton 115 2 Harris Erwin 230 1 Canton Hazelwood 115 1 Harris Ft. Bragg Wdrff St 230 1 Canton Pisgah 115 1 Harris Siler City 230 1 Canton Craggy 115 1 Harris Wake 230 1 Canton Enka 115 1 Havelock Jacksonville 230 1 Walters Holston 161 1 Havelock Morehead Wildwood 115 North Craggy Enka 115 1 Havelock Morehead Wildwood 115 South Asheville Enka 115 1 Havelock Morehead Wildwood 230 1 Enka W. Asheville 115 1 Havelock New Bern 115 1 Asheville Enka 115 2 Havelock New Bern 230 1 Asheville Enka 230 1 Henderson Person 230 1 Cane River Craggy 115 1 Henderson Roxboro 115 1 Craggy Vanderbilt 115 1 Henderson Kerr Dam 115 1 Marshall Craggy 115 1 Jacksonville Jacksonville City 115 East Craggy W. Asheville 115 1 Jacksonville Jacksonville City 115 West Marshall Cane River 115 1 Jacksonville New Bern 230 1 Cane River Craggy 230 1 Jacksonville Wallace 230 1 Vanderbilt W. Asheville 115 1 Jacksonville Wommack 115 1 Oteen W. Asheville 115 1 Kingstree Sumter 115 1 Asheville Oteen 115 East Kinston Dup Wommack 230 1 Asheville Oteen 115 West Kinston Dup New Bern 115 1 Robinson SCPSA Darlington 230 1 Latta Marion 230 1 Robinson Sumter 230 1 Lauringburg Richmond 230 1 Rockingham West End 230 East Lauringburg Wagram 115 1 Rockingham West End 230 West Lee Plant Black Creek 115 East Rocky Mt Spring Hope SS 115 1 Lee Plant Black Creek 115 West Rocky Mt Battelboro 115 1 Lee Plant Clinton 115 1 Rocky Mt Edgecombe 230 1 Lee Plant Goldsboro 115 North Rocky Mt Hornertown 230 1 Lee Plant Goldsboro 115 South Rocky Mt Wilson 115 1 Lee Plant Lee 115 North Rocky Mt Wilson 230 1 Lee Plant Lee 115 South Roxboro Danville 230 North Lee Plant Selma 115 1 Roxboro Danville 230 South Lee Milburnie 230 1 Roxboro E. Durham 230 East Lee Selma 230 1 Roxboro E. Durham 230 West Lee Wallace 230 1 Roxboro Eno 230 Black Lee Wommack 230 North Roxboro Eno 230 White Lee Wommack 230 South Roxboro Falls 230 1 Lilesville Oakboro 230 Black Roxboro Person 230 1 FROM BUS TO BUS KV CKT FROM BUS TO BUS KV CKT
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Lilesville Oakboro 230 White Roxboro Person 230 2 Lilesville Rockingham 230 1 Roxboro Person 230 3 Marion SCPSA Marion 230 North Selma Wake 230 1 Marion SCPSA Marion 230 South Spring Hope SS Zebulon 115 1 Marion Whiteville 230 1 Sumter Canadys 230 1 Mayo Person 500 1 Sumter Eastover 115 1 Mayo Durham 500 1 Sumter Wateree 230 1 Durham Wake 500 1 Sutton Castle Hayne 230 1 Method E. Durham 230 1 Sutton Castle Hayne 115 North Method Milburnie 115 North Sutton Castle Hayne 115 South Method Milburnie 115 South Sutton Delco 230 1 Method Milburnie 230 1 Sutton Delco 115 1 Method Raleigh 115 1 Sutton Wallace 230 1 Milburnie Mordecai 115 1 Tillery Badin 115 Black Milburnie Person 230 1 Tillery Badin 115 White Milburnie Selma 115 1 Tillery Biscoe 115 1 Milburnie Wake 230 1 Wake Carson 500 1 Milburnie Zebulon 115 1 Wake Zebulon 230 1 Mordecai Raleigh 115 1 Weatherspoon Fay. Dup. Sw.Sta 115 1 Morehead WW Atlantic Beach 115 1 Weatherspoon Delco 115 1 New Bern Wommack 230 North Weatherspoon Fayetteville 230 1 New Bern Wommack 230 South Weatherspoon Latta 230 1 Person Rocky Mt 230 1 Weatherspoon Laurinburg 230 1 Person Halifax 230 1 Weatherspoon Lumberton 115 1 Raeford Richmond 230 1 Weatherspoon Marion 115 1 Raeford Wagram 115 1 Weatherspoon Raeford 115 1 Richmond Newport 500 1 Wilson Zebulon 230 1 Richmond Rockingham 230 East Asheboro Pleasant Garden 230 1 Richmond Rockingham 230 West Harris RTP 230 1 Robinson Camden Junction 115 1 Bennettsville SCPSA Benetsvill 230 1 Robinson Florence 115 1 Durham Falls 230 1 Robinson Florence 230 1 Marion Whiteville 230 1 Robinson Rockingham 115 1 Clinton Lee 230 1 Robinson Rockingham 230 1 Greenville Kinston Dup. 230 1
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TABLE D.2 DUKE ENERGY CAROLINAS
OUTAGED FACILITIES
FROM BUS TO BUS KV CKT FROM BUS TO BUS KV CKT Asheboro Transformer 230/115 1 East Spartanburg West Spartanburg 100 2 Hendersonville Horseshoe 100 1 Tiger West Spartanburg 100 1 Hendersonville Horseshoe 100 2 Tiger West Spartanburg 100 2 Lee Perry Tap W 100 1 East Greenville Cane Creek 100 1 Shady Grove Greenbriar 100 1 Tiger Cane Creek 100 1 Lawson Fork West Spartanburg 100 1 Tiger Cane Creek 100 2 Bridgewater McDowell 100 1 East Greenville Oakvale 100 1 Horseshoe Pisgah 100 1 East Greenville Oakvale 100 2 Campobello Hendersonville 100 2 Oakvale Shady Grove 100 1 Campobello Tiger 100 1 Greenville Shady Grove 100 1 Campobello Tiger 100 2 Greenville Shady Grove 100 2 North Greenville Tiger 100 1 East Greenville Greenville 100 1 North Greenville Tiger 100 2 Cliffside Inman 100 1 Greenville North Greenville 100 1 Inman Tiger 100 1 Greenville North Greenville 100 2 Cliffside Tiger 100 1 Greenville North Greenville 100 4 Cliffside Peach Valley 100 1 Easley Greenlawn 100 1 Cliffside Peach Valley 100 2 Easley North Greenville 100 1 East Spartanburg Peach Valley 100 1 Greenlawn North Greenville 100 1 East Spartanburg Peach Valley 100 2 Central Greenlawn 100 1 Cliffside Cliffside 2 100 1 Central Greenlawn 100 2 Campobello Cliffside 100 1 Lee Toxaway 100 1 Campobello Cliffside 100 2 Belton Lee 100 1 Gaffney Cliffside 2 100 1 Central Lee 100 1 Gaffney Cliffside 2 100 2 Lee Piercetown 100 1 Cliffside Fairview 100 1 Central Piercetown 100 1 Cliffside Fairview 100 2 Lee Shady Grove 100 1 Cliffside Fairview 100 3 Lee Shady Grove 100 2 Cliffside Fairview 100 4 Lee Shady Grove 100 4 East Greenville Tiger 100 1 Anderson Toxaway 100 1 East Greenville Tiger 100 2 Belton Toxaway 100 1 Blacksburg Shelby 100 1 Belton Hodges 100 1 Chester McDowell 2 100 1 Belton Hodges 100 2 Lancaster Monroe 100 2 Coronaca Hodges 100 1 Allen Peacock 100 1 Coronaca Hodges 100 2 Allen Peacock 100 2 Greenwood Hodges 100 2 Breeden Sw Sta Longview 100 1 Clark Hill Greenwood 100 1 Breeden Sw Sta Longview 100 2 Clark Hill Greenwood 100 2 Newport Peacock 100 1 Creto Greenwood 100 1 Lookout Stamey 100 1 Creto WMGOTNNS 100 1 Lookout Stamey 100 2 WMGOTNNS Coronaca 100 1 Lincolnton Riverbend 100 1 Buzzards Roost Creto 100 1 Lincolnton Riverbend 100 2 Bush River Buzzards Roost 100 1 Bridgewater Breeden Sw Sta 100 1 Bush River Buzzards Roost 100 2 Bridgewater Breeden Sw Sta 100 2 Bush River Laurens 100 1 Chester Great Falls 100 1 Laurens Lee 100 1 Hilltop Peacock 100 1 Laurens Lee 100 2 Hilltop Shelby 100 1 Bush River Morris Sw Sta B 100 1 Hilltop Shelby 100 2 Morris Sw Sta W Pacolet 100 1 BROEWTWA Great Falls 1 100 1 Gaffney Pacolet 100 2 BROEWTWA Great Falls 1 100 2 Cherokee Pacolet 100 1 Great Falls 1 Lancaster 100 1 Cherokee Gaffney 100 1 Fishing Creek Great Falls 1 100 1 East Spartanburg Pacolet 100 1 Fishing Creek Lancaster 100 1 East Spartanburg Pacolet 100 2 McAdenville Peacock 100 1 Lawson Fork Pacolet 100 1 McAdenville Peacock 100 2 Lawson Fork Peach Valley 100 1 Newport Wylie Hydro 100 1
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FROM BUS TO BUS KV CKT FROM BUS TO BUS KV CKT East Spartanburg West Spartanburg 100 1 Newport Wylie Hydro 100 2 Hickory Lookout 100 1 Mocksville Stamey 100 1 Hickory Lookout 100 2 Mocksville Stamey 100 2 BROEWTWA Wylie Hydro 100 1 Buck S34 Buck Tie 100 1 BROEWTWA Wylie Hydro 100 2 Concord Harrisburg 100 1 BROEWTWA PSAPTRS 100 1 Concord Harrisburg 100 2 Great Falls 1 PSAPTRS 100 1 Abbotts Creek Linden Street 100 1 Hickory Longview 100 1 Abbotts Creek Buck Tie 100 1 Hickory Longview 100 2 Linden Street Tomasville 100 1 Allen McAdenville 100 1 Buck Tie Tomasville 100 1 McAdenville Riverbend 100 1 Mitchell River North Wilkesboro 100 1 McAdenville Riverbend 100 2 Mitchell River North Wilkesboro 100 2 BROEWTWA Newport 100 1 Beckerdite Robbins Road Sw Sta 100 1 Hickory Lincolnton 100 1 Oxford Hydro Stamey 100 1 Hickory Lincolnton 100 2 Bannertown Mitchell River 100 1 Great Falls 1 Wateree 100 1 Bannertown Mitchell River 100 2 Allen Wylie Hydro 100 1 Rural Hall Shattalon Sw Sta 100 1 Albemarle Oakboro 100 1 Rural Hall Shattalon Sw Sta 100 3 Albemarle Badin 100 1 Rural Hall Shattalon Sw Sta 100 4 Amity Morning Star 100 1 Robbins Road Sw Sta Winston 100 1 Amity Morning Star 100 2 Robbins Road Sw Sta Winston 100 2 Harrisburg North Charlotte 100 1 North Winston W Shattalon Sw Sta 100 1 Amity Harrisburg 100 1 Madison Walnut Cove 100 1 Amity Woodlawn 100 1 Madison Walnut Cove 100 2 Woodlawn Wylie Hydro 100 1 North Greensboro Robbins Road Sw Sta 100 1 Woodlawn Wylie Hydro 100 2 North Greensboro Robbins Road Sw Sta 100 2 Allen Woodlawn 100 1 Dan River North Greensboro 100 1 North Charlotte Woodlawn 100 1 Dan River North Greensboro 100 2 North Charlotte Woodlawn 100 2 Dan River Madison 100 1 Lakewood North Charlotte 100 1 Dan River Madison 100 2 Lakewood North Charlotte 100 2 Glen Raven North Greensboro 100 1 Lakewood Riverbend 100 1 Glen Raven North Greensboro 100 2 Lakewood Riverbend 100 2 Greensboro North Greensboro 100 1 Lakewood Riverbend 100 3 Greensboro North Greensboro 100 2 Lakewood Riverbend 100 4 Greensboro Linden Street 100 1 Concord Winecoff 100 1 Mebane Pleasant Garden 100 1 Concord Winecoff 100 2 Eno Mebane 100 1 China Grove Winecoff 100 1 Eno Mebane 100 2 China Grove Winecoff 100 2 Durham Eno 100 1 China Grove Winecoff 100 3 Durham Eno 100 2 Albemarle Buck Tie 100 1 Crest Street Durham 100 1 Albemarle Buck Tie 100 2 Crest Street Durham 100 2 Buck S34 Winecoff 100 1 Crest Street Eno 100 1 Buck S34 Winecoff 100 2 Eno Glen Raven 100 1 Buck S34 Salisbury 100 1 Durham East Durham 100 1 China Grove Westfork 100 1 Ashe Street East Durham 100 1 China Grove Westfork 100 2 Ashe Street Durham 100 1 Stamey Statesville 100 1 Linden Street Pleasant Garden 100 1 Riverbend Westfork 100 1 Linden Street Pleasant Garden 100 2 Westfork Winecoff 100 1 Glen Raven Pleasant Garden 100 1 Westfork Winecoff 100 2 Glen Raven Pleasant Garden 100 2 Riverbend Winecoff 100 1 Parkwood Eno 100 1 Poplar Sw Sta Statesville 100 1 Parkwood Eubanks Tap B 100 1 Poplar Sw Sta Statesville 100 2 Eno Eubanks Tap B 100 1 Buck S34 Poplar Sw Sta 100 1 Ashe Street TGTESMDE 100 1 Buck S34 Poplar Sw Sta 100 2 Ashe Street Parkwood 100 1 China Grove Salisbury 100 1 Rural Hall Walnut Cove 100 1 China Grove Salisbury 100 2 Beckerdite Shattalon Sw Sta 100 1
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FROM BUS TO BUS KV CKT FROM BUS TO BUS KV CKT Beckerdite Shattalon Sw Sta 100 2 McGuire Nuclear Sta Woodleaf Sw Sta 500 1 Beckerdite Buck S34 100 1 Pleasant Garden Woodleaf Sw Sta 500 1 Beckerdite Buck S34 100 2 Newport Oconee Nuclear Sta 500 1 North Wilkesboro Oxford Hydro 100 1 Jocassee Hydro Oconee Nuclear Sta 500 1 North Wilkesboro Oxford Hydro 100 2 Jackson Ferry Transformer 765/500 1 Beckerdite Greensboro 100 1 Newport Richmond 500 1 Beckerdite Winston 100 1 Parkwood Pleasant Garden 500 1 Dan River Sadler 100 1 Marshall McGuire Nuclear Sta 230 1 Dan River Sadler 100 3 McGuire Nuclear Sta Riverbend 230 1 Bannertown Rural Hall 100 1 Lincoln Riverbend 230 1 Bannertown Rural Hall 100 2 Harrisburg McGuire Nuclear Sta 230 1 Robbins Road Sw Sta Walnut Cove 100 1 Harrisburg McGuire Nuclear Sta 230 3 Robbins Road Sw Sta Walnut Cove 100 2 Allen Catawba Nuclear Sta 230 1 Shattalon Sw Sta Winston 100 1 Catawba Nuclear Sta Newport 230 1 Glen Raven Sadler 100 1 Catawba Nuclear Sta Newport 230 3 Glen Raven Sadler 100 2 Catawba Nuclear Sta Pacolet 230 1 Glen Raven Sadler 100 3 Catawba Nuclear Sta Peacock 230 1 Glen Raven Sadler 100 4 Catawba Nuclear Sta Ripp Sw Sta 230 1 Mocksville Winston 100 1 Jocassee Hydro Oconee Nuclear Sta 230 1 Mocksville Winston 100 2 Central Oconee Nuclear Sta 230 1 Bush River Buzzards Roost 44 1 North Greenville Oconee Nuclear Sta 230 1 Buzzards Roost Joanna Sw Sta 44 1 Jocassee Hydro Tuckasegee 230 1 Clinton Joanna Sw Sta 44 1 Jocassee Hydro Shiloh Sw Sta 230 1 Blacksburg Ninety-Nine Islands 44 1 Hartwell Anderson 230 1 Blacksburg Gaston Shoals 44 1 Beckerdite Belews Creek 230 1 Gaffney Gaston Shoals 44 1 Belews Creek North Greensboro 230 1 Gaffney Ninety-Nine Islands 44 1 Belews Creek Rural Hall 230 1 Hendersonville Tuxedo Hydro 44 1 Belews Creek Ernest 1 230 1 Campobello Tuxedo Hydro 44 2 Sadler Ernest 2 230 1 Campobello Inman 44 1 Beckerdite Marshall 230 1 Campobello Inman 44 2 Longview Marshall 230 1 Campobello Turner Shoals 44 1 Marshall Stamey 230 1 Campobello Turner Shoals 44 2 Marshall Winecoff 230 1 Fairview Turner Shoals 44 1 Cliffside Pacolet 230 1 Walker Tie Great Falls 2 44 1 Cliffside Shelby 230 1 Walker Tie Great Falls 2 44 2 Allen Riverbend 230 1 Clover Ninety-Nine Islands 44 1 Allen Winecoff 230 1 Woodlawn Wylie Hydro 44 1 Lakewood Riverbend 230 1 Mountain Island Riverbend 44 1 Ripp Sw Sta Riverbend 230 1 Mountain Island Riverbend 44 2 Lincoln Longview 230 1 Rhodhiss Longview 44 1 East Durham Eno 230 1 Lakewood Mountain Island 44 1 East Durham Parkwood 230 1 Lakewood Mountain Island 44 2 East Durham E-REDMT 230 1 Gaffney Transformer 100/44 1 East Durham Bahama 230 1 Gaffney Transformer 100/44 2 East Durham Leesville 230 1 McGuire Nuclear Sta Transformer 500/230 A1 East Durham Durham 230 1 Oconee Nuclear Sta Transformer 500/230 A1 Eno Pleasant Garden 230 1 Antioch Transformer 500/230 1 Eno Roxboro 230 1 Antioch Transformer 500/230 2 Anderson Hodges 230 1 Newport Transformer 500/230 A5 Morning Star Oakboro 230 1 Parkwood Transformer 500/230 5 Morning Star Newport 230 1 Parkwood Transformer 500/230 6 Harrisburg Oakboro 230 1 Pleasant Garden Transformer 500/230 5 Ansonville Oakboro 230 1 Antioch McGuire Nuclear Sta 500 1 Lillesville Oakboro 230 1 McGuire Nuclear Sta Newport 500 1 Pisgah Shiloh Sw Sta 230 1 McGuire Nuclear Sta Cliffside Tap 500 1 Pisgah Asheville 230 1 Jocassee Hydro Cliffside Tap 500 1 Anderson Central 230 1
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FROM BUS TO BUS KV CKT FROM BUS TO BUS KV CKT Antioch Mitchell River 230 1 Bush River R Georgia Pacific 115 1 Beckerdite Buck Tie 230 1 Bush River Y White Rock 115 1 Beckerdite Pleasant Garden 230 1 Newport Parr 230 1 Buck Tie Winecoff 230 1 Clark Hill JS Thurmond 115 1 Mitchell River Rural Hall 230 1 Bush River Parr 230 1 Mitchell River Stamey 230 1 Robbinsville Santeetlah 161 1 North Greenville Shiloh Sw Sta 230 1 Nantahala Fontana HP 161 1 North Greenville Tiger 230 1 Tuckasegee Webster 161 1 Pacolet Tiger 230 1 Wests Mill Tuckasegee 161 1 Peach Valley Riverview Sw Sta 230 1 Nantahala Webster 161 1 Ripp Sw Sta Riverview Sw Sta 230 1 Lake Emory Webster 161 1 Peach Valley Tiger 230 1 Lake Emory Wests Mill 161 1 Ripp Sw Sta Shelby 230 1 Nantahala Wests Mill 161 1 Shiloh Sw Sta Tiger 230 1 Nantahala Marble 161 1 Dan River Ridgeway 138 1 Nantahala Robbinsville 161 1 Mills River Asheville 115 1 Antioch BREMC 6 230 1 Hodges Greenwood County 230 1 Bush River Transformer 230/100 1 Anderson Rainey 230 1 Asheboro Pleasant Garden 230 1 Oconee Nuclear Sta South Hall 500 1
DUKE ENERGY CAROLINAS MULTIPLE BRANCH CONTINGENCIES
FROM BUS TO BUS KV CKT FROM BUS TO BUS KV CKT Bush River Transformer 115/100 7 Peacock Transformer 230/100 1 Bush River Transformer 115/100 8 Catawba Peacock 230 1 Pisgah Transformer 100/115 1 Peacock Transformer 230/100 2 Pisgah Transformer 100/115 2 Catawba Peacock 230 1 Hodges Transformer 230/100 1 Shady Grove Transformer 230/100 1 Hodges Anderson 230 1 Shady Grove Shady Grove Tap B 230 1 Hodges Transformer 230/100 2 Shady Grove Transformer 230/100 2 Hodges Anderson 230 1 Shady Grove Shady Grove Tap W 230 2 Lakewood Transformer 230/100 2 Jocassee Hydro Tuckasegee 230 1 Riverbend Lakewood 230 1 Tuckaseegee Transformer 230/161 2 Lakewood Transformer 230/100 3 Jocassee Hydro Tuckasegee 230 1 Riverbend Lakewood 230 2 Tuckaseegee Transformer 230/161 3 McDowell Transformer 230/100 1 Allen Woodlawn 230 1 Longview McDowell 230 1 Woodlawn Transformer 230/100 4 McDowell Transformer 230/100 2 Allen Woodlawn 230 1 Longview McDowell 230 2 Woodlawn Transformer 230/100 5 Morningstar Transformer 230/100 3 Lee Perry Tap B 100 1 Oakboro Morningstar 230 1 Perry Tap B Reedy River 100 1 Morningstar Transformer 230/100 4 Marietta North Greenville 100 1 Newport Morningstar 230 1 North Greenville Pisgah 100 1
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FROM BUS TO BUS KV CKT FROM BUS TO BUS KV CKT Pisgah E.I. Dupont Tap 100 1 Oakboro Monroe 3T 100 1 E.I. Dupont Tap Marietta 100 1 Monroe 3T Monroe 100 1 Marietta North Greenville 100 1 Pisgah North Greenville 100 1 Albemarle Albemarle 2 100 1 Albemarle 2 Badin Retail 100 1 Bridgewater Marion Main 100 1 Badin Retail Badin 100 1 Marion Main McDowell 100 1 Monroe Stouts Tap 100 1 Lee Piercetown 100 1 Stouts Tap Morning Star 100 1 Central Piercetown 100 1 Central Lee 100 1 Morning Star Springfield B 100 1 Springfield B Wylie Hydro 100 1 Hodges Greenwood C6 100 1 Greenwood C6 Greenwood 100 1 Morning Star Springfield W 100 1 Springfield W Wylie Hydro 100 1 Bush River Clinton 100 1 Clinton Laurens 100 1 Harrisburg Wilgrove 100 1 Wilgrove Morning Star 100 1 Bush River Newberry 100 1 Newberry Whitmire Tap 100 1 Harrisburg Wilgrove W 100 1 Whitmire Tap Morris Sw Sta W 100 1 Wilgrove W Morning Star 100 1 Morris Sw Sta B Midway Tap 100 1 Harrisburg Stetson Tap W 100 1 Midway Tap Pacolet 100 1 Stetson Tap W North Charlotte 100 1 Central Seneca Tap B 100 1 Amity Park Road 100 1 Seneca Tap B Westminster 100 1 Park Road Woodlawn 100 1 Central Seneca T2 100 1 Allen Westinghouse Tap W 100 1 Seneca T2 Seneca C2 100 1 Westinghouse Tap W Wylie Hydro 100 1 Seneca T2 Seneca CT 100 1 Seneca CT Seneca Tap W 100 1 Allen Westinghouse Tap B 100 1 Seneca Tap W Westminster 100 1 Westinghouse Tap B Wylie Hydro 100 1 Peacock Sifford Tap W 100 1 Riverbend Energy United 26 100 1 Sifford Tap W Clover 100 1 Energy United 26 Westfork 100 1 Sifford Tap W Newport 100 1 Riverbend Conley Tap W 100 1 Hilltop Gastonia Junction 100 1 Conley Tap W Winecoff 100 1 Gastonia Junction Peacock 100 1 Beckerdite High Point City 4 100 1 Shelby BP PPTG 100 1 High Point City 4 Linden Street 100 1 BP PPTG Cliffisde 2 100 1 Beckerdite High Point City 4 100 2 Shelby WP PPTG 100 1 High Point City 4 Linden Street 100 2 WP PPTG Cliffisde 2 100 1 Linden Street Energy United 32 B 100 1 BROEWTWA York EC 17 100 1 Energy United 32 B High Rock Junction 100 1 York EC 17 Newport 100 1 Pleasant Garden High Point City 3 100 1 McAdenville Dixie 100 1 High Point City 3 Linden Street 100 1 Dixie Hilltop 100 1 Glen Raven Burlington Tap W 100 1 Hilltop Acrerock B 100 1 Burlington Tap W Mebane 100 1 McAdenville Acrerock B 100 1
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FROM BUS TO BUS KV CKT FROM BUS TO BUS KV CKT Greensboro High Point City 5 100 1 Central Shady Grove Tap B 230 1 High Point City 5 Triad Park 100 1 Shady Grove Tap B North Greenville 230 1 Triad Park Beckerdite 100 1 Shady Grove Tap B Shady Grove 230 1 Beckerdite BSPWAT 100 1 Jocassee Hydro Tuckasegee 230 2 BSPWAT Winston 100 1 Tuckaseegee Transformer 230/161 3 Shattalon Sw Sta Stratford Road Tap B 100 1 Allen Woodlawn 230 2 Stratford Road Tap B Winston 100 1 Woodlawn Transformer 230/100 4 Belews Creek Bob White Tap B 230 1 Bob White Tap B North Greensboro 230 1 Bob White Tap B Pleasant Garden 230 1
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TABLE D.3 SOUTH CAROLINA ELECTRIC AND GAS
OUTAGED FACILITIES
SCE&G tested single contingencies of all branches greater than and equal to 115 kV including tie lines
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TABLE D.4 SOUTH CAROLINA PUBLIC SERVICE AUTHORITY
OUTAGED FACILITIES
SCPSA tested single contingencies of all branches greater than and equal to 115 kV including tie lines
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TABLE D.5 DOMINION VIRGINIA POWER
OUTAGED FACILITIES
Dominion Virginia power tests single contingencies of all Tie Lines, 500 kV, and 230 kV branches, including the multiple facilities identified below. Facilities Switched Together: FROM BUS TO BUS kV CKT Lexington Cloverdale 500 1Lexington Transformer 500/230 1 Cloverdale Transformer 500/230 1&2 Ox Clifton 500 1 Clifton Transformer 500/230 1 Ladysmith Chancellor 500 1 Ladysmith Brister 500 1 Chancellor Transformer 500/230 1 Mt. Storm Valley 500 1 Valley Transformer 500/230 1 Clover Carson 500 1 Clover Transformer 500/230 1 Elmont Chickahominy 500 1 Chickahominy Transformer 500/230 1 Greenbriar Fudge Hollow 138 1 Ronceverte Greenbriar 138 1 Hinton Ronceverte 138 1 North Anna Midlothian 500 1 Midlothian Transformer 500/230 1
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TABLE D.6
APGI - Yadkin OUTAGED FACILITIES
FROM BUS TO BUS KV CKT FROM BUS TO BUS KV CKT Badin Tuckertown 100 1 High Rock Energy United 32 100 1 Badin Badin1 100/115 1 High Rock Linden Street 100 1 Badin Badin2 100/115 1 Tuckertown High Rock 100 1
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EXHIBIT E TRANSFER CAPABILITY DEFINITIONS
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TRANSFER CAPABILITY DEFINITIONS
Transfer capabilities as used by the VACAR Power Flow Working Group are defined as follows in accordance with NERC definitions: 1. Normal Incremental Transfer Capability (NITC) Installed Incremental Transfer Capability is the amount of power, incremental above normal base power transfers, that can be transferred over the transmission network without giving consideration to the effect of transmission facility outages. All facility loadings are within normal ratings and all voltages are within normal limits. 2. First Contingency Incremental Transfer Capability (FCITC) First Contingency Incremental Transfer Capability is the amount of power, incremental above normal base power transfers, that can be transferred over the transmission network in a reliable manner, based on the following conditions. A. With all transmission facilities in service, all facility loadings are within normal ratings and all
voltages are within normal limits. B. The bulk power system is capable of absorbing the dynamic power swings and remaining stable
following a disturbance resulting in the loss of any single generating unit, transmission circuit or transformer.
C. After the dynamic power swings following a disturbance resulting in loss of any single generating
unit, transmission circuit or transformer, but before operator-directed system adjustments are made, all transmission facility loadings are within emergency ratings and all voltages are within emergency limits.
2008 VACAR Drought Study
The purpose of this study is to assess the potential impact of drought conditions on the operations
of the systems within VACAR during the upcoming spring and summer seasons.
Case and Scenario Definition
Utilizing the most recent SERC NTSG OASIS Support Study base cases for the 2008 spring and
2008 summer seasons, a base case and two drought cases were developed as follows:
Base Case – Normal generation dispatch with no drought impacts.
Expected Drought Case – Projected generation dispatch with expected drought impacts.
Moderate Drought Case – Projected generation dispatch with potential constrained
operation of hydro and thermal units due to moderate drought conditions.
Three scenarios were analyzed to assess the impact of imports into the VACAR sub-region to
replace the drought impacted generation reductions. Scenario 1 simulated power transfers to
replace drought impacted generation transitioning from Base Case conditions to Expected
conditions. Scenario 2 simulated power transfers to replace additional drought impacted
generation transitioning from Expected conditions to Moderate conditions. Scenario 3 simulated
power transfers to replace additional drought impacted generation transitioning from Moderate
conditions to Severe conditions. The table below summarizes the replacement power required by
VACAR member companies:
Drought-related Import Replacement Power1
Scenario Study Case Used
2008 Spring
Import
Requirement
2008 Summer
Import
Requirement
1 Base Case 275 MW 275 MW
2 Expected Drought 299 MW 1768 MW
3 Moderate Drought 1208 MW 2736 MW
1
For a breakdown of replacement power by company, see Appendix A.
For each scenario, the replacement power was imported from each of the five different areas
listed below:
MISO/CommEd: MISO control areas, Commonwealth Edison
PJM West: Allegheny, AEP, Dayton, Duquesne
PJM Mid-Atlantic: historic PJM
TVA
Southern Company
Procedure
Siemens PTI PSS/E version 30.2 was used to create the three study base cases for 2008 Spring
and Summer as outlined above.
Siemens PTI MUST version 8.3 was used to run FCITC Analysis on each drought study base
case. Typical monitored element, contingency element, and subsystem MUST input files were
used for this analysis. All replacement power for the FCITC analysis was imported from each of
the five different control areas or combinations of control areas described above. Load was
scaled in the exporting area(s) to allow the generation to be available for export to VACAR.
Limiting constraints with Transfer Distribution Factors (TDFs) greater than or equal to 3 percent
are discussed in the report below. The results were reviewed by all VACAR member companies
and invalid results were removed. The table below summarizes the transfer limits found for each
scenario.
2008 Spring
Export Region Scenario 1 Scenario 2 Scenario 3
MISO/CommEd No limit No limit No limit
PJM West No limit No limit No limit
PJM Mid-Atlantic No limit No limit No limit
TVA No limit No limit 500 MW
Southern Company No limit No limit No limit
2008 Summer
Export Region Scenario 1 Scenario 2 Scenario 3
MISO/CommEd No limit No limit 1800 MW
PJM West No limit No limit 1800 MW
PJM Mid-Atlantic No limit No limit 2200 MW
TVA No limit No limit 1800 MW
Southern Company No limit No limit 1600 MW
For the 2008 Spring, no limits were identified for Scenario 1 or 2. In Scenario 3, which
simulates VACAR imports under severe drought conditions, import from TVA is limited to 500
MW by Southern Company’s Gaston-Roopville 230 kV line for an outage of Farley-Racoon
Creek 230 kV line.
For 2008 Summer, no limits were identified for Scenario 1 or 2. In Scenario 3, which has an
import test level of 2736 MW, imports are limited from all five exporting areas. Imports from
MISO/Commonwealth, PJM West, and PJM Mid-Atlantic are limited to 1800 MW, 1800 MW,
and 2200 MW, respectively, by Axton-Danville 138 kV line. Imports from TVA and Southern
Company TVA are limited to 1800 MW and 1600 MW, respectively, by Duke’s Parkwood
500/230 kV bank 6 for an outage of Parkwood 500/230 kV bank 5.
Individual Assessments
2008 Spring
Dominion Virginia Power
Expected Scenario – No generation changes were made, and no additional imports were added
for the Dominion Virginia Power territory in this scenario. No DVP facilities were found to limit
the transfers to VACAR from the five different sources at the 275 MW test level.
Moderate Scenario – No generation changes were made, and no additional imports were added
for the Dominion Virginia Power territory in this scenario. No DVP facilities were found to limit
the transfers to VACAR from the five different sources at the 299 MW test level.
Severe Scenario – All Dominion Hydro generating units (a total of 564 MW) were removed
from dispatch, and no additional imports were added for the Dominion Virginia Power territory
in this scenario. No DVP facilities were found to limit the transfers to VACAR from the five
different sources at the 1,208 MW test level.
Duke Energy
Generation reductions to simulate three drought condition scenarios included hydro and fossil
units. The spring base case includes 3,500 MW of scheduled generation maintenance outages,
two 230/100 kV bank outages, one 230 kV line outage, and five 100 kV line outages. The Duke-
TVA 161 kV tie line is outaged in the case as well.
Expected Scenario – For the Expected Scenario study, 700 MW of hydro generation was made
unavailable for dispatch. But since only 191 MW of that hydro generation was actually
dispatched in the base case, Duke’s hydro generation was reduced by 191 MW for the Expected
Scenario study. The overall VACAR reductions for the Expected Scenario were 275 MW, so
Duke was responsible for much of that total reduction. No Duke facilities were found to limit
transfers into VACAR from the five sources tested.
Moderate Scenario – The Expected Case served as the starting point for the Moderate Scenario
study. The 191 MW reduction studied as part of the Expected Scenario study was replaced by
Duke internal generation to create the Expected Case. Duke’s fossil generation was reduced by
65 MW for the Moderate Scenario study. The overall VACAR reductions for the Moderate
Scenario were 299 MW. No Duke facilities were found to limit transfers into VACAR from the
five sources tested.
Severe Scenario – The Moderate Case served as the starting point for the Severe Scenario study.
The hydro and fossil reductions studied in the previous two scenarios were replaced by Duke
internal generation to create the Moderate Case. Duke’s fossil generation was reduced by 102
MW for the Severe Scenario study. The overall VACAR reductions for the Severe Scenario
were 1,208 MW. No Duke facilities were found to limit transfers into VACAR from the five
sources tested.
Progress Energy
Expected Scenario – No generation changes were made, and no additional imports were added
in this scenario for the Progress Energy control areas CPLE and CPLW. Therefore, from a
Progress Energy perspective, the Expected case is the same as the Revised Base case. No
Progress Energy facilities were found to limit the transfers to VACAR from the five different
sources with a 275 MW test level.
Moderate Scenario – All Progress Energy Hydro units (110 MW in CPLE and 105 MW in
CPLW) were turned off. In order to build the Moderate case, replacement power came from
internal generation for CPLE and CPLW plus part of a firm network DNR for CPLW. The DNR
power was moved from CPLE to CPLW with the interchanges adjusted accordingly. No
Progress Energy facilities were found to limit the transfers to VACAR from the five different
sources with a 299 MW test level.
Severe Scenario – Progress Energy turned off two fossil units (164 MW) in CPLE and nothing
in CPLW. No additional imports were added for this scenario. No Progress Energy facilities
were found to limit the transfers to VACAR from the five different sources with a 1208 MW test
level.
South Carolina Electric & Gas
Generation reductions to simulate the three Drought Scenarios included Fossil, Hydro and
Pumped Storage units.
Expected Scenario – No generation changes were made to the base case to build the Expected
Case; therefore no additional imports were required for South Carolina Electric & Gas Company
(SCEG) in this scenario. No limiting facilities or outage facilities were found in SCEG’s system
for imports into VACAR from any of the five exporting areas.
Moderate Scenario – Hydro generation was reduced by 19 MW from the Expected Case to
represent a Moderate Scenario simulation. No limiting facilities or outage facilities were found
in SCEG’s system for imports into VACAR from any of the five exporting areas.
Severe Scenario – Fossil generation was reduced by 150 MW and Pumped Storage was reduced
by 228 MW from the Moderate Case to represent the Severe Scenario simulation. No limiting
facilities or outage facilities were found in SCEG’s system for imports into VACAR from any of
the five exporting areas.
Santee Cooper
Generation reductions to simulate three drought condition scenarios included hydro units.
Expected Scenario – For the Expected Scenario study, 84 MW of hydro generation was made
unavailable for dispatch. No Santee Cooper facilities were found to limit transfers into VACAR
from the five sources tested.
Moderate Scenario - The Expected Case served as the starting point for the Moderate Scenario
study. The 84 MW reduction studied as part of the Expected Scenario study was replaced by
Santee Cooper internal generation to create the Expected Case. No additional generation
changes were required for Santee Cooper in this scenario. No Santee Cooper facilities were
found to limit transfers into VACAR from the five sources tested.
Severe Scenario – The Moderate Case served as the starting point for the Severe Scenario study.
No additional generation changes were required for Santee Cooper in this scenario. No Santee
Cooper facilities were found to limit transfers into VACAR from the five sources tested.
2008 Summer
Dominion Virginia Power
Expected Scenario – No generation changes were made, and no additional imports were added
for the Dominion Virginia Power territory in this scenario. No DVP facilities were found to limit
the transfers to VACAR from the five different sources at the 275 MW test level.
Moderate Scenario – No generation changes were made, and no additional imports were added
for the Dominion Virginia Power territory in this scenario. No DVP facilities were found to limit
the transfers to VACAR from the five different sources at the 1,768 MW test level.
Severe Scenario – All Dominion Hydro generating units (564 MW) were removed from
dispatch, and no additional imports were added for the Dominion Virginia Power territory in this
scenario. Transfers to VACAR from the five different sources were tested at the 2,736 MW
level.
No DVP facilities were found to limit the transfers to VACAR from MISO, TVA, and Southern
at the test level.
For the PJM West to VC transfer, DVP’s Halifax-Mt. Laurel 115 kV line was found to be a limit
at 2,570 MW for the loss of the Halifax-Person 230 kV tie line (DVP-CPLE). There were several
other limits identified for the transfer starting at 1,880 MW limited by different facilities.
For the PJM East (Mid Atlantic) to VC transfer, DVP’s Halifax-Mt. Laurel 115 kV line was
found to be a limit at 2,470 MW for the loss of the Halifax-Person 230 kV tie line (DVP-CPLE).
There were several other limits identified for the transfer starting at 2,270 MW limited by
different facilities.
Other than limiting the north to south transfers, there are some circuit reconfiguration
arrangements available depending on the system conditions to alleviate the overload of the
Halifax-Mt. Laurel 115 kV line for the loss of the Halifax-Person 230 kV tie line.
Duke Energy
Generation reductions to simulate three drought condition scenarios included hydro and fossil
units. As was mentioned in SCEG’s write-up, a 420 MW transfer from SCEG to Duke was
modeled in all scenarios for the summer studies. There are no generation outages modeled in the
base case. The Duke-TVA 161 kV tie line is outaged in the case.
Expected Scenario – For the Expected Scenario study, 700 MW of hydro generation was made
unavailable for dispatch. But since only 191 MW of that hydro generation was actually
dispatched in the base case, Duke’s hydro generation was reduced by 191 MW for the Expected
Scenario study. The overall VACAR reductions for the Expected Scenario were 275 MW, so
Duke was responsible for much of that total reduction. In all five import analyses, CPLE’s
Camden-Elgin Tap 115 kV line showed up as a limit, but Duke’s DK1 Operating Guide can be
used to mitigate loading on this facility.
Moderate Scenario – The Expected Case served as the starting point for the Moderate Scenario
study. The 191 MW reduction studied as part of the Expected Scenario study was replaced by
Duke internal generation to create the Expected Case. Duke’s fossil generation was reduced by
540 MW for the Moderate Scenario study. The overall VACAR reductions for the Moderate
Scenario were 1,768 MW. No Duke facilities were found to limit transfers into VACAR from
the five sources tested.
Severe Scenario – The Moderate Case served as the starting point for the Severe Scenario study.
The hydro and fossil reductions studied in the previous two scenarios were replaced by Duke
internal generation to create the Moderate Case. Duke’s fossil generation was reduced by 212
MW for the Severe Scenario study. The overall VACAR reductions for the Severe Scenario
were 2,736 MW. Duke’s Parkwood 500/230 kV bank-6 for loss of Parkwood 500/230 kV bank-
5 emerged as a limiting facility according to the following table:
Duke’s Parkwood 500/230 kV bank-6 for loss of Parkwood 500/230 kV bank-5
2736 MW Transfer Test Level FCITC
MISO – VACAR 2570 MW
PJM West – VACAR No Duke limit
PJM Mid – VACAR No Duke limit
TVA – VACAR 1880 MW
SOCO – VACAR 1640 MW
These first contingency limits on the 500/230 kV Parkwood banks have routinely surfaced in
planning studies, but a permanent fix for this loading issue is not required at this time. The
Parkwood station is configured such that both banks are supplied by a single 500 kV line from
the Pleasant Garden station. Opening this line has the same effect as opening both 500/230 kV
banks at Parkwood. Studies have shown that opening this 500 kV Pleasant Garden line to
mitigate flow on these banks has no adverse effects on the system. However, implementing this
mitigation plan requires relay changes to trip one bank for loss of the other (same as opening the
Pleasant Garden – Parkwood 500 kV line). Planning studies indicate that this work won’t be
necessary for a few years yet. Between now and that time, it may be possible to take a closer
look at the ratings on the Parkwood banks to see if it can be increased, even if it is for a short
time. This potential rating increase would bump up the FCITC somewhat.
Progress Energy
Expected Scenario – No generation changes were made, and no additional imports were added
for the Progress Energy control areas CPLE and CPLW in this scenario. Therefore, from a
Progress Energy perspective, the Expected case is the same as the Revised Base case. No
Progress Energy facilities were found to limit the transfers to VACAR from the five different
sources with a 275 MW test level.
Moderate Scenario – All Progress Energy Hydro units (110 MW in CPLE and 105 MW in
CPLW) plus a couple Fossil units (934 MW in CPLE) were turned off. In order to build the
Moderate case, replacement power came from internal generation for CPLE and part of a firm
network DNR for CPLW. The DNR power was moved from CPLE to CPLW with the
interchanges adjusted accordingly. No Progress Energy facilities were found to limit the
transfers to VACAR from the five different sources with a 1,768 MW test level.
Severe Scenario – Progress Energy turned off one fossil unit and reduced two others by over 50
percent (1104 MW) in CPLE while doing nothing in CPLW. No additional imports were added
for this scenario. No Progress Energy facilities were found to limit the transfers to VACAR
from the five different sources with a 2,736 MW test level.
South Carolina Electric & Gas
Generation reductions to simulate the three Drought Scenarios included Fossil, Hydro and
Pumped Storage units. A new transfer of 420 MW from Columbia Energy Center (an IPP in
SCEG’s system) to Duke was included in the base case for all reserved timeframes. This is a
new transmission service and will be included in all of SCEG’s models except for cases built for
the April and May timeframe.
Expected Scenario – No generation changes were made to the base case to build the Expected
Case; therefore no additional imports were required for South Carolina Electric & Gas Company
(SCEG) in this scenario. No limiting facilities or outage facilities were found in SCEG’s system
for imports into VACAR from any of the five exporting areas.
Moderate Scenario – Hydro generation was reduced by 79 MW from the Expected Case to
represent a Moderate Scenario simulation. No limiting facilities or outage facilities were found
in SCEG’s system for imports into VACAR from any of the five exporting areas.
Severe Scenario – Fossil generation was reduced by 312 MW and Pumped Storage was reduced
by 544 MW from the Moderate Case to represent the Severe Scenario simulation. No limiting
facilities or outage facilities were found in SCEG’s system for imports into VACAR from any of
the five exporting areas.
Santee Cooper
Generation reductions to simulate three drought condition scenarios included hydro units.
Expected Scenario – For the Expected Scenario study, 84 MW of hydro generation was made
unavailable for dispatch. No Santee Cooper facilities were found to limit transfers into VACAR
from the five sources tested.
Moderate Scenario - The Expected Case served as the starting point for the Moderate Scenario
study. Non-firm load in the case was reduced to replace the 84 MW reduction studied as part of
the Expected Scenario study to create the Expected Case. No additional generation changes
were required for Santee Cooper in this scenario. No Santee Cooper facilities were found to
limit transfers into VACAR from the five sources tested.
Severe Scenario – The Moderate Case served as the starting point for the Severe Scenario study.
No additional generation changes were required for Santee Cooper in this scenario. No Santee
Cooper facilities were found to limit transfers into VACAR from the five sources tested.
Appendix A
VACAR Drought Study Assumptions
2008 Spring 2008 Summer
Company Expected Moderate Severe Expected Moderate Severe
DVP 0 0 564 0 0 564
Duke 191 65 102 191 540 212
PEC 0 215 164 0 1149 1104
SCEG 0 19 378 0 79 856
SCPSA 84 0 0 84 0 0
Total 275 299 1208 275 1768 2736
VACAR STABILITY STUDY OF
PROJECTED 2008 LIGHT LOAD CONDITIONS
March 2008
Prepared by VACAR Stability Working Group: Kirit Doshi Dominion Virginia Power
Anthony Williams Duke Energy
John O’Connor Progress Energy Carolinas
Phil Kleckley South Carolina Electric & Gas
Art Brown South Carolina Public Service Authority
Reviewed by VACAR Planning Task Force: N. K. Burks Dominion Virginia Power
B. D. Moss Duke Energy
D. Roeder ElectriCities of North Carolina
R. Anderson Fayetteville Public Works Commission
R. S. Beadle North Carolina Electric Membership Corporation
A. M. Byrd Progress Energy Carolinas
H. C. Young, III South Carolina Electric & Gas
J. E. Peterson South Carolina Public Service Authority
H. Nadler Southeastern Power Administration
March 2008 VACAR Stability Study of Projected 2008 Light Load Conditions i
DOMINION VIRGINIA POWER RESULTS ..........................................................................................................9
DUKE ENERGY RESULTS ....................................................................................................................................13
PROGRESS ENERGY CAROLINAS RESULTS..................................................................................................15
SOUTH CAROLINA ELECTRIC & GAS RESULTS ..........................................................................................19
SOUTH CAROLINA PUBLIC SERVICE AUTHORITY RESULTS .................................................................23
APPENDIX A DOMINION VIRGINIA POWER PLOTS.................................................................................27
APPENDIX B DUKE ENERGY PLOTS .............................................................................................................33
APPENDIX C PROGRESS ENERGY CAROLINAS PLOTS ..........................................................................37
APPENDIX D SOUTH CAROLINA ELECTRIC & GAS PLOTS...................................................................41
APPENDIX E SOUTH CAROLINA PUBLIC SERVICE AUTHORITY PLOTS ..........................................47
March 2008 VACAR Stability Study of Projected 2008 Light Load Conditions ii
March 2008 VACAR Stability Study of Projected 2008 Light Load Conditions iii
Executive Summary
The VACAR Stability Working Group (VSWG) has completed a study to evaluate the bulk transmission system performance of the VACAR member systems under NERC Reliability Standards through an assessment of simulated network dynamic responses for the 2008 light load period. This study assesses both the transient stability and dynamic stability of the VACAR Sub-region of SERC under normal operation and for selected contingencies within the Sub-region. The study focuses on selected contingency events considered to be less severe, yet more probable, as prescribed by Table I of the NERC Reliability Standards related to Transmission Systems (TPL-001, -002 and -003).
While the contingencies evaluated as part of this study are judged to be less severe, they are also thought more likely to occur. Assessing NERC Category A, Category B, and some Category C disturbance events in the near-term planning horizon is judged to be an appropriate appraisal of this study period. The results documented in this report indicate that the VACAR systems remain stable during the period and under the contingencies studied.
In summary, the results of this study indicate that the planned configurations of VACAR systems in the 2008 light load season are in compliance with reliability requirements of Categories A, B and C of Table I of the NERC Reliability Standards TPL-001 through TPL-003 for the contingency scenarios evaluated.
March 2008 VACAR Stability Study of Projected 2008 Light Load Conditions 1
March 2008 VACAR Stability Study of Projected 2008 Light Load Conditions 2
Introduction The Virginia-Carolinas (VACAR) Reliability Agreement requires that studies be conducted to assess the capability of the bulk power system to withstand various contingencies without suffering uncontrolled cascading outages. Dominion Virginia Power (DVP), Duke Energy Corporation (Duke), Progress Energy Carolinas (PEC), South Carolina Electric & Gas (SCE&G) and South Carolina Public Service Authority (SCPSA) have conducted this study as part of ongoing activities to meet the terms of the VACAR Agreement and to ensure continuing compliance with appropriate reliability standards of the North American Electric Reliability Corporation (NERC).
The ability of the interconnected transmission systems to withstand probable contingencies must be determined by simulated testing of the systems, as prescribed by the NERC Reliability Standards related to Transmission Systems. These standards state that entities responsible for the reliability of the interconnected transmission systems shall provide a self-assessment of transmission system performance, based on the results of simulation testing of the system under their responsibility. The NERC standards require that studies be conducted for both the near-term (one through five year) and the long-term (six through ten year) planning horizons. This assessment shall ensure that the system responses are as required in Table I of the NERC Reliability Standards TPL-001 through TPL-004 related to Transmission Systems.
To support the reliability assessment responsibilities as outlined above, the VACAR Planning Task Force (VPTF) has adopted an on-going study plan to alternate the time frame of required assessments between near-term and long-term planning horizons. Usually, near-term studies assess the system against the more severe, less probable contingencies as defined in Table I, particularly contingencies included in Category D. Generally, longer-term studies assess the system against the less severe, more probable contingencies as defined in Categories A, B and C in Table I. Results of this study, together with those of similar studies assessing the long-term planning horizon, will be used to document coordinated activities that serve to measure the performance of the VACAR systems as prescribed in Table I.
With guidance from the VPTF, the VACAR Stability Working Group (VSWG) evaluated the performance of the VACAR member systems in the near-term planning horizon, 2008 light load. This study is somewhat different in that it considers a light load case, so the study deviates somewhat from the past contingency selection by considering the more probable contingencies. This investigation assesses the dynamic stability of the VACAR Sub-region under normal operation as well as the transient stability of the sub-region under selected contingency events. Modifications are included in the study base case to effectively represent each VACAR member system for the projected period. For non-VACAR systems, the case contains data from the 2007 light load dynamics case developed during the 2006 NERC/MMWG series of models. The study efforts focus on screening the VACAR sub-region systems for potential stability issues that may warrant a more detailed investigation.
The VSWG coordinated the selection and simulation of contingency events developed for this study. The VSWG participants evaluated the results of each case simulation to assess potential local system responses as well as potential sub-regional impacts of these contingencies, as defined in Table 1 of the NERC Reliability Standards. The study activities included monitoring
March 2008 VACAR Stability Study of Projected 2008 Light Load Conditions 3
and reviewing various VACAR system elements to check for any stability related problems, as well as coordinating review of study results with neighboring VACAR systems. The study scenarios included in this assessment and the Table 1 Categories that they address are outlined in the VACAR Scenario Matrix included in this report.
March 2008 VACAR Stability Study of Projected 2008 Light Load Conditions 4
TPL-001 through TPL-004 — Table I. Transmission System Standards – Normal and Emergency Conditions
Contingencies System Limits or Impacts
Category
Initiating Event(s) and Contingency Element(s)
System Stable and both Thermal and Voltage Limits within Applicable Rating a
Loss of Demand or Curtailed Firm Transfers
Cascading Outages
A No Contingencies
All Facilities in Service Yes No No
Single Line Ground (SLG) or 3-Phase (3Ø) Fault, with Normal Clearing: 1. Generator 2. Transmission Circuit 3. Transformer Loss of an Element without a Fault
Yes Yes Yes Yes
No b No b
No b
No b
No No No No
B Event resulting in the loss of a single element.
Single Pole Block, Normal Clearing e: 4. Single Pole (dc) Line Yes No b No
SLG Fault, with Normal Clearing e: 1. Bus Section 2. Breaker (failure or internal Fault)
Yes Yes
Planned/ Controlled
c
Planned/ Controlled
c
No No
SLG or 3Ø Fault, with Normal Clearing e, Manual System Adjustments, followed by another SLG or 3Ø Fault, with Normal Clearing e: 3. Category B (B1, B2, B3, or B4) contingency, manual
system adjustments, followed by another Category B (B1, B2, B3, or B4) contingency
Yes Planned/ Controlled
c No
Bipolar Block, with Normal Clearing e: 4. Bipolar (dc) Line Fault (non 3Ø), with Normal
Clearing e: 5. Any two circuits of a multiple circuit towerline f
Yes Yes
Planned/ Controlled
c
Planned/ Controlled
c
No No
C Event(s) resulting in the loss of two or more (multiple) elements.
SLG Fault, with Delayed Clearing e (stuck breaker or protection system failure): 6. Generator 7. Transformer 8. Transmission Circuit 9. Bus Section
Yes Yes Yes Yes
Planned/ Controlled
c
Planned/ Controlled
c
Planned/ Controlled
c
Planned/ Controlled
c
No No No No
March 2008 VACAR Stability Study of Projected 2008 Light Load Conditions 5
March 2008 VACAR Stability Study of Projected 2008 Light Load Conditions 6
D d Extreme event resulting in two or more (multiple) elements removed or Cascading out of service.
3Ø Fault, with Delayed Clearing e (stuck breaker or protection system failure): 1. Generator 3. Transformer 2. Transmission Circuit 4. Bus Section _________________________________________ 3Ø Fault, with Normal Clearing e: 5. Breaker (failure or internal Fault) _________________________________________ 6. Loss of towerline with three or more circuits
7. All transmission lines on a common right-of way
8. Loss of a substation (one voltage level plus transformers)
9. Loss of a switching station (one voltage level plus transformers)
10. Loss of all generating units at a station
11. Loss of a large Load or major Load center
12. Failure of a fully redundant Special Protection System (or remedial action scheme) to operate when required
13. Operation, partial operation, or misoperation of a fully redundant Special Protection System (or Remedial Action Scheme) in response to an event or abnormal system condition for which it was not intended to operate
14. Impact of severe power swings or oscillations from Disturbances in another Regional Reliability Organization.
Evaluate for risks and consequences. � May involve substantial loss of customer Demand and
generation in a widespread area or areas. � Portions or all of the interconnected systems may or may not
achieve a new, stable operating point. � Evaluation of these events may require joint studies with
neighboring systems.
a) Applicable rating refers to the applicable Normal and Emergency facility thermal Rating or system voltage limit as determined and consistently applied by the system or facility owner. Applicable Ratings may include Emergency Ratings applicable for short durations as required to permit operating steps necessary to maintain system control. All Ratings must be established consistent with applicable NERC Reliability Standards addressing Facility Ratings.
b) Planned or controlled interruption of electric supply to radial customers or some local Network customers, connected to or supplied by the Faulted element or by the affected area, may occur in certain areas without impacting the overall reliability of the interconnected transmission systems. To prepare for the next contingency, system adjustments are permitted, including curtailments of contracted Firm (non-recallable reserved) electric power Transfers.
c) Depending on system design and expected system impacts, the controlled interruption of electric supply to customers (load shedding), the planned removal from service of certain generators, and/or the curtailment of contracted Firm (non-recallable reserved) electric power Transfers may be necessary to maintain the overall reliability of the interconnected transmission systems.
d) A number of extreme contingencies that are listed under Category D and judged to be critical by the transmission planning entity(ies) will be selected for evaluation. It is not expected that all possible facility outages under each listed contingency of Category D will be evaluated.
e) Normal clearing is when the protection system operates as designed and the Fault is cleared in the time normally expected with proper functioning of the installed protection systems. Delayed clearing of a Fault is due to failure of any protection system component such as a relay, circuit breaker, or current transformer, and not because of an intentional design delay.
f) System assessments may exclude these events where multiple circuit towers are used over short distances (e.g., station entrance, river crossings) in accordance with Regional exemption criteria.
March 2008 VACAR Stability Study of Projected 2008 Light Load Conditions 7
VACAR Scenario Matrix Contingency Events Tested During Study
TPL-001-004 Table 1, Transmission Systems Standards – Normal and Contingency Conditions
Primary Area
Secondary Area Description Study
Case #
Category A
No Contingencies All facilities in service
All VACAR
N/A Drift run to verify steady state conditions for all VACAR member systems
Drift
Category B
Event resulting in the loss of a single element.
Category B (3) SCEG N/A 3Φ Fault at the V.C. Summer generator terminals. B1-1
Event resulting in the loss of a single element.
Category B (3) DVP N/A 3Φ Fault on the 230 kV side of the 500-230 kV transformer at Clover, normal clearing. (Note: Clover-Carson 500 kV line is also lost since the line and the transformer are in series).
B3-1
Category C
SLG or 3Φ Fault, Normal Clearing
SCPSA N/A
SLG Fault on the Winyah-Jefferies 230 kV line C2-1
SLG or 3Φ Fault, Normal Clearing
Category B (2) / Manual Adjustment / Category B (2)
SCPSA SCE&G
3Φ Fault on the Charity 230-115 kV transformer followed by SLG Fault on the Charity-Jefferies 230 kV line.
C3-1
SLG or 3Φ Fault with Normal Clearing, Manual Adjustments, followed by another SLG or 3Φ Fault with Normal Clearing
Transmission Circuit out of service (no manual adjustments made between events)
DUKE N/A 3Φ Fault with normal clearing on a Jocassee 230 kV line followed by 3Φ Fault with normal clearing on the second Jocassee 230 kV line
C3-2
SLG or 3Φ Fault with Normal Clearing, Manual Adjustments, followed by another SLG or 3Φ Fault with Normal Clearing
Transmission Circuit out of service (no manual adjustments made between events)
DUKE N/A 3Φ Fault with normal clearing on the Guardian 500 kV line followed by 3Φ Fault with normal clearing on the Woodchuck 500 kV line
C3-3
Note: The transmission system owner listed in the Primary Area column has primary responsibility for providing simulation data for this case. Companies designated as Secondary Areas may have specific interest or contributions related to assessing scenarios to be evaluated. Those case scenarios of interest to VSWG as a group, but that are completely within a single area/company boundary are indicated by “N/A” in the Secondary Area column.
8 VACAR Stability Study of Projected 2008 Light Load Conditions
VACAR Scenario Matrix (continued) Contingency Events Tested During Study
TPL-001-004 Table 1, Transmission Systems Standards – Normal and Contingency Conditions
Primary Area
Secondary Area Description Study
Case #
Category C
SLG or 3Φ Fault, Normal Clearing
Category B (2) / Manual Adjustment / Category B (2)
PEC N/A 3Φ Fault on the Asheville Plant-Enka East 115 kV line followed by 3Φ Fault on the Asheville Plant-Enka West 115 kV line.
C3-4
SLG or 3Φ Fault, Normal Clearing
Category B (2) / Manual Adjustment / Category B (2)
PEC N/A 3Φ Fault on the Cumberland-Delco 230 kV line followed by 3Φ Fault on the Brunswick Unit 2-Wilmington Corning 230 kV line.
C3-5
SLG or 3Φ Fault with Normal Clearing, Manual Adjustments, followed by another SLG or 3Φ Fault with Normal Clearing
Category B (2) / Manual Adjustment / Category B (2)
SCEG SCPSA 3Φ Fault with normal clearing on the SCE&G Jasper-SCPSA Purrysburg #1 230kV tie line followed by 3Φ Fault with normal clearing on the SCE&G Jasper-SCPSA Purrysburg #2 230kV tie line.
C3-6
Event(s) resulting in the loss of two or more (multiple) elements
Category C(5) DVP PEC A double-circuit tower failure near Nash resulting in simultaneous loss of Hornertown – Rocky Mt. (PEC) 230 kV and Edgecomb-Rocky Mt. (PEC) 230 kV circuits.
C5-1
Event(s) resulting in the loss of two or more (multiple) elements
Category C(5) DVP PEC A double-circuit tower failure near Roanoke Valley generating plant resulting in simultaneous loss of Roanoke Valley – Carolina 230 kV and Roanoke Valley – Earleys 230 kV circuits.
C5-2
Note: The transmission system owner listed in the Primary Area column has primary responsibility for providing simulation data for this case. Companies designated as Secondary Areas may have specific interest or contributions related to assessing scenarios to be evaluated. Those case scenarios of interest to VSWG as a group, but that are completely within a single area/company boundary are indicated by “N/A” in the Secondary Area column.
March 2008
Dominion Virginia Power Results
All generating units located in the Dominion Virginia Power (DVP) control area remained stable for all of the 11 cases studied across the VACAR system for the projected 2008 light load conditions. This study represents simulations of a near-term horizon with contingency events as directed by the VACAR Planning Task Force. The monitored parameters included rotor angle, unit electrical power, rotor speed, line flow (including tie lines) and bus voltage at critical locations in the DVP system. All oscillations on the DVP system were well damped and there was no indication of cascading outages for any of the 11 cases studied. The analysis of the monitored quantities for all cases indicated no overload on any DVP facility as a result of these simulated disturbances. The voltages at all DVP buses were within the prescribed operating limits once stabilized. The maximum peak-to-peak deviations in some key parameters for disturbances in the DVP system are listed in the table following this narrative. The plots of some of the key parameters for critical cases to the DVP system are included in Appendix A. The most critical cases to the DVP system are when the faults are simulated within the DVP system (Cases B3-1, C5-1 and C5-2; four plots per page/one page per case). The four other cases of interest to DVP from the line flow deviation aspect are also plotted (Cases: B1-1, C3-2, C3-3 and C3-5; total four plots on a single page). The deviations in rotor angles, voltages and speed for these four cases were very minor, and as such, these quantities are not plotted. All remaining cases did not indicate any significant effect on the DVP system. A detailed description of the contingencies simulated in the DVP system and the results observed follow. A three-phase fault at the low side of the 500-230 kV Clover transformer was simulated with normal clearing (category B3, Case #B3-1). The Clover plant has two generating units connected to the 230 kV system and has the total capacity of 882 MW. There is no high-side breaker on this transformer. Therefore, the 500 kV line from Clover to Carson was also tripped, along with the Clover transformer, to clear the fault. All resulting swings were well damped and the voltage levels in the area quickly returned to normal. The reason for selecting this contingency was that (a) the plant is located near the neighboring PEC system, and (b) PSS on both the Clover units were replaced during 2007. Second, a 230 kV double-circuit-tower failure scenario was simulated, resulting in a three-phase fault with normal clearing (category C5, Case #C5-1). The two affected lines are Edgecombe to Rocky Mt. and Hornertown to Rocky Mt. 230 kV tie lines with the neighboring PEC system. There is a generating plant at Edgecombe with two units, totaling 116 MW of capacity. Also, there is a generating plant at Rosemary (radially connected to Hornertown substation) with three units, totaling 281 MW of summer (314 MW winter) capacity. The angular and power oscillations take a little longer to fully damp out. However, the frequency of oscillations is around 1.69 Hz (local mode) with a damping ratio of 3.2, indicating no danger of cascading. The reason for selecting this contingency was that both these lines share a common tower and are important ties between DVP and PEC.
March 2008 VACAR Stability Study of Projected 2008 Light Load Conditions 9
March 2008 VACAR Stability Study of Projected 2008 Light Load Conditions 10
Third, another 230 kV double-circuit-tower failure scenario was simulated, also resulting in a three-phase fault with normal clearing (category C5, Case #C5-2. The two affected lines in this case are Roanoke Valley to Carolina 230 kV and Roanoke Valley to Earleys 230 kV. There is a generating plant at Roanoke Valley with two units, totaling 109 MW of capacity. Also, there is a generating plant at Roanoke Rapids (radially connected to Carolina substation) with four units, totaling 99 MW. The reason for selecting this contingency was that both these lines share a common tower and are important since there is a considerable amount of generation (700+ MW) located in this general area which is close to the neighboring PEC system. In summary, the DVP system was tested from the stability aspect for the selected 11 contingencies in VACAR sub-region of SERC as described in the NERC Reliability Standards, categories A, B and C. The results indicated that the DVP system meets the requirements of the NERC Reliability Standards for these selected contingencies for the projected 2008 light load period.
VACAR Stability Study of Projected 2008 Light Load Conditions 11
Dominion Virginia Power Results Maximum Deviations
Notes: 1. Refer to the Scenario Matrix of this report for an explanation of the relationship of individual cases to the Contingency Categories of Table I of NERC Reliability Standards TPL-001 through TPL-004. 2. For Cases marked with an asterisk, the maximum deviations are negligible, except for the line flows. Therefore, only line flows are plotted for these cases, with all four cases plotted on one page.
March 2008
March 2008 VACAR Stability Study of Projected 2008 Light Load Conditions 12
March 2008 VACAR Stability Study of Projected 2008 Light Load Conditions 13
Duke Energy Results This study considered two Category C events. Both events assumed one element faulted and was later followed by another faulted element.
In the first event, C3-2, a Jocassee 230 kV line was faulted and cleared with normal protection times. Later, another 3-phase fault with normal clearing was simulated on the second Jocassee 230 kV line. A contingency at Jocassee was chosen because the units are in pumping mode during light load system conditions. As one can see in Appendix B, the case is stable and well damped.
The second event is modeled at the McGuire bus. Here, a 3-phase fault with normal clearing on the Guardian 500 kV line was applied and later followed by a fault on the Woodchuck 500 kV line. This gauges the impact of faults on a more centrally located bus. Like the other case, this scenario is also stable.
As a matter of course, a table of maximum deviations is presented below. None of the deviations are too significant given the facilities impacted. Only the Duke Energy contingencies are included because the responses from other company scenarios were much smaller. For the studied VACAR sub-region contingencies, all deviations are acceptable and all Duke Energy generators are stable and well damped.
VACAR Stability Study of Projected 2008 Light Load Conditions 14
1. Refer to the Scenario Matrix of this report for an explanation of the relationship of individual cases to the Contingency Categories of Table I of NERC Reliability Standards TPL-001 through TPL-004.
March 2008
Progress Energy Carolinas Results
The cases of primary interest for Progress Energy Carolinas (PEC) are Case C3-4 and Case C3-5, which involve faults within the PEC service area. Refer to the Scenario Matrix of this report for an explanation of the relationship of these individual case scenarios to the NERC TPL Reliability Standard Table 1 Contingency Categories.
A table showing the maximum deviations of PEC area generating units and monitored lines for all simulated cases is included in this section of the report. Additionally, plots of selected generator rotor angles, electrical powers, rotor speed deviations, and line MVA flows for the cases of primary interest to PEC (Cases C3-4 and C3-5) are provided in Appendix C.
Case C3-4 simulated a three-phase fault with normal clearing on the Asheville Plant-Enka East 115 kV line just outside Asheville Plant. This was followed approximately 14 seconds later by a three-phase fault with normal clearing on the Asheville Plant-Enka West 115 kV line just outside Asheville Plant. Normal clearing time was 5 cycles (0.0833 seconds). This scenario was selected to maximize the stress put on the two Asheville coal units, which are likely to be the only significant generation running in the PEC Western control area during light load conditions similar to those simulated. For simulation purposes, the two Asheville Plant coal units were run at maximum MW output. This dispatch provided additional conservatism since these units would likely be at a lower generation level during the light load condition being studied. (It was necessary to leave the two Asheville Plant combustion turbine units off line at these light load levels, which would almost certainly be the case during actual light load conditions.) Area generation remained well within transient stability limits and the system was adequately damped. These results can be seen in the Appendix C plots for Case C3-4.
Case C3-5 simulated a three-phase fault with normal clearing on the Cumberland-Delco 230 kV line just outside Delco. This was followed approximately 14 seconds later by a three-phase fault with normal clearing on the Brunswick Plant-Wilmington Corning 230 kV line just outside Brunswick Unit 2 Switchyard. Normal clearing time was 5 cycles (0.0833 seconds) for the Cumberland-Delco line and 4 cycles (0.0667 seconds) for the Brunswick Plant-Wilmington Corning line. This scenario was selected primarily to examine the dynamic stability performance (i.e., damping of prolonged oscillations) of the Brunswick units under the simulated light load conditions. The power system stabilizers on both Brunswick units were in service for the simulation. Removal of the Cumberland-Delco 230 kV line is known to reduce area damping. Following this with a close-in fault on one of the lines directly connected to Brunswick Unit 2 was judged to be one of the worst contingencies with respect to dynamic stability. As can be seen from the plots in Appendix C, the damping is minimal, but adequate. An enlarged detail plot showing the electrical power output of Brunswick Units 1 and 2 after the second fault better illustrates that the oscillations are clearly damped out.
The remaining cases were also reviewed and the results summarized in the below maximum deviations table for PEC. For all cases in the study, the PEC units were well within transient stability limits and adequate damping was present. Additionally, area voltages and transmission line/transformer thermal limits were well within acceptable ranges for all the cases.
March 2008 VACAR Stability Study of Projected 2008 Light Load Conditions 15
March 2008 VACAR Stability Study of Projected 2008 Light Load Conditions 16
In summary, a review of all simulation cases, selected from Categories A, B and C of NERC Reliability Standards TPL-001 through TPL-003 Table 1, indicates that the PEC system is in compliance with the requirements outlined in those standards for the projected 2008 light load conditions.
VACAR Stability Study of Projected 2008 Light Load Conditions 17
Progress Energy Carolinas Results Maximum Deviations
Rotor Angle Electric Power Rotor Speed Line Flow
Case #
Facility
Amount (degrees)
Facility
Amount (MW)
Facility
Amount (p.u.)
Facility
Amount (MVA)
B1-1 Robinson #2 -13.5 Robinson #2 -75 Robinson #2 -0.0020 Darlington Plant – South Bethune (SCPSA) 230 kV Tie Line
206
B3-1 Brunswick #1 -5.1 Brunswick #1 -60 Roxboro #2 -0.0016 Person – Halifax (DVP) 230 kV Tie Line
1085
C2-1 Robinson #2 -7.0 Robinson #2 -82 Robinson #2 -0.0016 Marion – SCPSA Marion 230 kV North and South Tie Lines (2 lines)
118
C3-1 Robinson #2 -13.0 Robinson #2 159 Robinson #2 -0.0033 Marion – SCPSA Marion 230 kV North and South Tie Lines (2 lines)
122
C3-2 Asheville #2 11.0 Brunswick #1 -67 Asheville #2 0.0051 Wake – Carson (DVP) 500 kV Tie Line
192
C3-3 Brunswick #1 -16.7 Brunswick #1 -174 Tillery #1 0.0033 Richmond – Newport (Duke) 500 kV Tie Line
506
C3-4 Asheville #2 27.5 Asheville #1 -186 Asheville #2 0.0134 Cane River – Nagel (AEP) 230 kV Tie Line
315
C3-5 Brunswick #2 40.4 Brunswick #2 -968 Brunswick #2 0.0077 Brunswick Unit 2 – Delco West 230 kV Line
392
C3-6 Robinson #2 -6.3 Robinson #2 -72 Robinson #2 -0.0017 Sumter – Canady (SCE&G) 230 kV Tie Line
150
C5-1 Brunswick #1 6.0 Brunswick #1 -118 Brunswick #1 0.0012 Greenville – Everetts (DVP) 230 kV Tie Line
270
C5-2 Brunswick #1 -3.36 Brunswick #1 -53 Brunswick #1 -0.0006 Greenville – Everetts (DVP) 230 kV Tie Line
190
Notes: 1. Refer to the Scenario Matrix of this report for an explanation of the relationship of individual cases to the Contingency Categories of Table I in the NERC Reliability Standards TPL-001 through TPL-004. 2. The cases of primary interest to PEC are Cases C3-4 and C3-5.
March 2008
March 2008 VACAR Stability Study of Projected 2008 Light Load Conditions 18
South Carolina Electric & Gas Results The monitored parameters showed that all SCE&G generators remained stable in each of the VACAR cases that were simulated. These parameters included generator rotor angles, generator rotor speed deviations, generator real electrical power, and system tie line power flows. Other parameters that were monitored but which are not included in the accompanying plots included generator reactive power, generator frequency deviations, and selected transmission voltages. No tie lines experienced overloading in any of the simulations. The 2 cases in which SCE&G was the primary area of study were selected for study in order to examine the results of a 3-phase fault with normal clearing at a generator terminal and a normally cleared 3-phase fault near major generation located near inter-company tie lines followed by a second normally cleared 3-phase fault on an adjacent inter-company tie line. In addition, SCE&G was a secondary area of study in one case which is described below. Representative plots of the monitored parameters for the 3 cases for which SCE&G was the primary and secondary affected area are included in the Appendix. The results of these simulations are summarized in the accompanying table. Case B1-1 simulated a three phase fault with normal clearing at the V.C. Summer generator terminals. SCPSA was the secondary affected area for this contingency. Clearing the fault resulted in the loss of this generator which was producing 966 MW. The greatest rotor angle response to the fault and to this loss of generation occurred at the McMeekin #1 generator which experienced a maximum rotor angle deviation of 21.1 degrees. All SCE&G system generator rotor angles were well damped with no indication of angular instability. The greatest power swing was at the McMeekin #1 generator which experienced a real power deviation of 130 megawatts. The greatest rotor speed deviation of 0.0085 p.u was for the Parr Hydro generators. Tie line flows were all well below the line thermal ratings. The most responsive tie line was the V.C. Summer – Newberry 230kV tie to SCPSA which saw power deviation of 270 MVA during the fault, reaching a maximum value of 331 MVA. Following the clearing of the fault and the trip of the V.C. Summer generator, the power flow on this line leveled off at 65 MVA which was close to the original line flow. Voltage and frequency responses of the SCE&G system were all acceptable. For Case C3-6 a 3 phase fault with normal clearing was simulated at the Jasper end of one of the two Jasper – Purrysburg 230kV intercompany tie lines to SCPSA. This was followed by a second 3 phase fault with normal clearing on the second Jasper – Purrysburg 230kV tie line. SCPSA was the secondary affected area for this contingency. The Jasper Combined Cycle Facility is comprised of three gas turbines rated at approximately 161 MW each and a heat recovery steam generator rated at approximately 385 MW. Two gas turbines were on line generating approximately 160 MW each, and the steam turbine was producing an output of approximately 239 MW. SCPSA was the secondary affected area for this contingency. The greatest rotor angle responses to the fault were at the Jasper Gas Turbines #1 and #2 at a maximum rotor angle deviation of 33.14 degrees. All SCE&G system generator rotor angles were well damped with no indication of angular instability. The maximum power swing was at the Jasper Steam Unit with a real power swing of 323 megawatts due to its proximity to the fault. The greatest rotor speed deviation occurred at the Jasper Facility, with the greatest deviation of 0.0101 p.u. at the Jasper Gas Turbine #2. All SCE&G tie line flows were well below the line
March 2008 VACAR Stability Study of Projected 2008 Light Load Conditions 19
March 2008 VACAR Stability Study of Projected 2008 Light Load Conditions 20
thermal ratings. The tie line flow with the greatest response was the Jasper - Purrysburg 230kV tie #2 to SCPSA with a deviation of 604.8 MVA following the tripping of the Jasper - Purrysburg 230kV tie #1 line. Voltage and frequency responses of the SCE&G system were all acceptable. In the SCPSA Case C3-1 a 3-phase fault with normal clearing was simulated at the Charity 230/115 kV transformer followed by a single line to ground fault on the Charity – Jefferies 230kV transmission line. SCE&G was the secondary affected area for this contingency. The greatest rotor angle response on the SCE&G system to the fault was at the McMeekin #1 generator which had a maximum rotor angle deviation of 23.0 degrees. All SCE&G system generator rotor angles were well damped with no indication of angular instability. The maximum power swing was at the V.C. Summer generator with a real power swing of 266 megawatts. The greatest rotor speed deviation of 0.0140 p.u. was seen at the Westvaco generator. During the single line to ground fault on the Charity – Jefferies 230kV line, the flow on the SCE&G 230kV tie line from A. M. Williams – Charity saw a power deviation of 879 MVA, reaching a maximum of 897 MVA, or 113% of its emergency thermal rating. The MVA flow on this line quickly settled to 68 MVA directly after the 0.1 second fault was cleared. The magnitudes of the MVA flows on all other SCE&G tie lines were well below the line thermal ratings. Voltage and frequency responses of the SCE&G system were all acceptable. The remaining cases in which SCE&G was neither a primary nor secondary area of study were examined to determine if the faults that were studied outside of the SCE&G system revealed any violations of the NERC Reliability Standards. The simulations of all cases demonstrate that the SCE&G system is in compliance with NERC Reliability Standards TPL-001 through TPL-003, for Categories A, B, and C of Table I for the near term planning horizon.
VACAR Stability Study of Projected 2008 Light Load Conditions 21
South Carolina Electric & Gas Results Maximum Deviations
Rotor Angle Electric Power Rotor Speed Line Flow
Case #
Facility
Amount (degrees)
Facility
Amount (MW)
Facility
Amount (p.u.)
Facility
Amount (MVA)
B1-1 McMeekin #1 21.1 Wateree #1 130 Parr Hydro 0.0085 V. C. Summer #2 270
C3-1 McMeekin #1 23.0 V. C. Summer 266 Westvaco 0.0140 A. M. Williams 879
Notes: 1. Refer to the Scenario Matrix of this report for an explanation of the relationship of individual cases to the Contingency Categories of Table I of NERC Reliability Standards TPL-001 through TPL-004. 2. Maximum Deviations indicated for the cases of primary interest to SCE&G (Cases B1-1 and C3-6) and one case of secondary interest to SCE&G (SCPSA Case C3-1). Maximum deviations for other cases were also well within limits.
March 2008
March 2008 VACAR Stability Study of Projected 2008 Light Load Conditions 22
South Carolina Public Service Authority Results
South Carolina Public Service Authority (SCPSA) selected simulation Cases C2-1 and C3-1 to assess the impact of these contingency events addressing specific categories outlined in Table 1 of NERC Planning Standard TPL-001 through TPL-003. These simulations are part of activities to evaluate the potential system stability impacts of contingency events initiating within the SCPSA system under projected fall season light-load conditions for 2008. Key parameters monitored for each study scenario include generator rotor angles, generator rotor speed deviations, generator electrical power and selected transmission line power flows. Selected plots for these parameters are included in the Appendix. Based on these monitored parameters, SCPSA generators remain stable in all cases evaluated. All post-disturbance oscillations are well damped, and no sustained facility overloads are identified from those monitored throughout the VACAR Sub-region. All voltages remain within acceptable operating ranges following the initial oscillations associated with each simulated contingency event. All results depict no indication of cascading outages as a result of the conditions simulated.
Case C2-1 simulates normal clearing of a SLG fault on the Winyah end of the Winyah - Jefferies 230 kV line. This disturbance scenario was selected due to scheduled local transmission line reconstruction plans that will require the Georgetown – Campfield #2 115 kV Line to be out of service. Though using light-load study assumptions, this transmission line serves as an integral link between primary generation resources and SCPSA’s major load center of Myrtle Beach, South Carolina. The protection scheme in place prohibits the reclosing of the circuit breaker protecting the faulted transmission line at the Winyah Generating Station switchyard, so this simulation depicts a sustained outage of the Winyah end of the Winyah-Jefferies 230 kV line following the initial fault condition. Transmission interfaces with both SCE&G and PEC are nearby. Maximum rotor angle deviations for this simulated fault are reported at the Winyah Generating Station. The Winyah Unit #2 experiences a maximum rotor angle change of 13.3 degrees. All rotor angle and speed oscillations are well damped with no indications of instability. The greatest real power swing by SCPSA generators is produced by Winyah Unit #2 due to the proximity to the simulated fault condition. All transmission line power flow deviations remain below the thermal ratings of the lines monitored in this assessment.
Case C3-1 depicts normal clearing of a 3-phase fault internal to one of the two 230-115 kV, 90/120/150 MVA transformers located at SCPSA’s Charity Substation, followed by a secondary SLG fault on the Jefferies – Charity 230 kV line. Following the initial fault and subsequent lock-out of the power transformer at Charity, this scenario depicts normal reclosing of the Jefferies – Charity 230 kV Line following the secondary fault. The maximum rotor angle deviation experienced by SCPSA generators is 20.9 degrees and occurs on the Jefferies Hydro Unit #2. Rotor angle and speed oscillations are well damped, and there are no indications of instability following this simulated event. The largest power swing for SCPSA facilities occurs on the Cross #2 generator with a change in real power of 217 MW. Transmission line power flows remain below thermal ratings following the routine clearing of this fault.
March 2008 VACAR Stability Study of Projected 2008 Light Load Conditions 23
March 2008 VACAR Stability Study of Projected 2008 Light Load Conditions 24
Review of all cases evaluated using contingencies selected from Categories A, B and C of NERC Planning Standard TPL-001 through TPL-003, Table 1 indicates that the SCPSA system is expected to comply with the requirements outlined for these contingency categories under projected light load conditions for study year 2008.
VACAR Stability Study of Projected 2008 Light Load Conditions 25
South Carolina Public Service Authority Results Maximum Deviations
Notes: 1. Refer to the Scenario Matrix of this report for an explanation of the relationship of individual cases to the Contingency Categories of Table I of NERC Reliability Standards TPL-001 through TPL-004.
March 2008
March 2008 VACAR Stability Study of Projected 2008 Light Load Conditions 26
March 2008 VACAR Stability Study of Projected 2008 Light Load Conditions 27
Appendix A Dominion Virginia Power Plots
March 2008 VACAR Stability Study of Projected 2008 Light Load Conditions 28
March 2008 VACAR Stability Study of Projected 2008 Light Load Conditions 29
March 2008 VACAR Stability Study of Projected 2008 Light Load Conditions 30
VACAR Stability Study of Projected 2008 Light Load Conditions 31
March 2008
March 2008 VACAR Stability Study of Projected 2008 Light Load Conditions 32
March 2008 VACAR Stability Study of Projected 2008 Light Load Conditions 33
Appendix B Duke Energy Plots
March 2008 VACAR Stability Study of Projected 2008 Light Load Conditions 34
VACAR Stability Study of Projected 2008 Light Load Conditions 35March 2008
March 2008 VACAR Stability Study of Projected 2008 Light Load Conditions 36
March 2008 VACAR Stability Study of Projected 2008 Light Load Conditions 37
Appendix C Progress Energy Carolinas Plots
March 2008 VACAR Stability Study of Projected 2008 Light Load Conditions 38
March 2008 VACAR Stability Study of Projected 2008 Light Load Conditions 39
VACAR Stability Study of Projected 2008 Light Load Conditions 40
Detail view of electrical power output of Brunswick Units 1 & 2 following second disturbance for Case C3-5, illustrating adequate damping of oscillations. Scale is 10 MW/division.
March 2008
March 2008 VACAR Stability Study of Projected 2008 Light Load Conditions 41
Appendix D South Carolina Electric & Gas Plots
March 2008 VACAR Stability Study of Projected 2008 Light Load Conditions 42
March 2008 VACAR Stability Study of Projected 2008 Light Load Conditions 43
March 2008 VACAR Stability Study of Projected 2008 Light Load Conditions 44
VACAR Stability Study of Projected 2008 Light Load Conditions 45
March 2008
March 2008 VACAR Stability Study of Projected 2008 Light Load Conditions 46
March 2008 VACAR Stability Study of Projected 2008 Light Load Conditions 47
Appendix E South Carolina Public Service Authority Plots
March 2008 VACAR Stability Study of Projected 2008 Light Load Conditions 48
March 2008 VACAR Stability Study of Projected 2008 Light Load Conditions 49
VACAR STABILITY STUDY OF
PROJECTED 2014/2015 WINTER PEAK LOAD
CONDITIONS
DRAFT
April 2009
April 2009 VACAR Stability Study of Projected 2014 Winter Peak Conditions i
Prepared by VACAR Stability Working Group: Kirit Doshi Dominion Virginia Power
Anthony Williams Duke Energy
John O’Connor Progress Energy Carolinas
Joe Hood South Carolina Electric & Gas
Art Brown South Carolina Public Service Authority
Reviewed by VACAR Planning Task Force: J. L. Connors Alcoa Power Generating, Inc.
M. Shakibafar Dominion Virginia Power
B. D. Moss Duke Energy Carolinas
D. Roeder ElectriCities of North Carolina
R. Anderson Fayetteville Public Works Commission
J.R. Manning North Carolina Electric Membership Corporation
A. M. Byrd Progress Energy Carolinas
P. R. Kleckley South Carolina Electric & Gas
J. E. Peterson South Carolina Public Service Authority
H. Nadler Southeastern Power Administration
April 2009 VACAR Stability Study of Projected 2014 Winter Peak Conditions ii
1. Refer to the Scenario Matrix of this report for an explanation of the relationship of individual cases to the Contingency Categories of Table I of NERC
Reliability Standards TPL-001 through TPL-004.
April 2009 VACAR Stability Study of Projected 2014 Winter Peak Conditions 14
Progress Energy Carolinas Results
The cases of primary interest for Progress Energy Carolinas (PEC) are Case B2-2 and Case C8-2,
which involve faults within the PEC service area. Refer to the Scenario Matrix of this report for
an explanation of the relationship of these individual case scenarios to the NERC TPL Reliability
Standard Table 1 Contingency Categories.
A table showing the maximum deviations of PEC area generating units and monitored lines for
all simulated cases is included in this section of the report. Additionally, plots of selected
generator rotor angles, electrical powers, rotor speed deviations and line MVA flows for the
cases of primary interest to PEC (Cases B2-2 and C8-2) are provided in Appendix C.
Case B2-2 simulated a 3-phase fault with normal clearing on the Sutton Plant-Wallace 230 kV
line just outside of Sutton Unit #3 Switchyard. A clearing time of 5 cycles (0.0833 seconds) was
used at both the near and remote ends of the line. This location was selected due to the
importance of Sutton Unit # 3 in providing area voltage support (for the contingency loss of one
of the Brunswick Plant units). In order to demonstrate stability, a Category B2, 3-phase, normal
clearing line fault just outside the Unit #3 switchyard was selected as the worst case fault that
could occur for Sutton Unit #3 without the unit itself being tripped by protective relay action.
(Delayed clearing faults or bus faults also cause the trip of Unit #3 due to the single breaker
arrangement.) The Wallace 230 kV line was selected since it is the highest worth line from a
stability perspective that is connected to the Unit #3 switchyard. The simulation results show
that area generation remained well within transient stability limits and the system was adequately
damped. These results can be seen in the Appendix C plots for Case B2-2.
Case C8-2 simulated a double line to ground (2-phase to ground) fault on the Cumberland-Delco
230 kV line just outside Delco 230 kV substation. A normal clearing time of 5 cycles (0.0833
seconds) was used for the remote end of the line. A delayed clearing time of 14 cycles (0.2333
seconds), based on actual field settings, was used for the near end breaker failure clearing time.
The breaker failure operation also causes tripping of the Delco 230/115 kV #1 Transformer Bank
and opening of the Delco end of the Brunswick Unit #1-Delco West 230 kV line. This case was
chosen to examine the dynamic stability performance of the Brunswick Units (i.e. potential for
prolonged oscillations). The Cumberland-Delco 230 kV line was selected since it is known to be
the highest worth line not directly connected to the Brunswick Units for damping of oscillations
on these units. The simulation results show that area generation remained well within transient
stability limits and the system was adequately damped. These results can be seen in the
Appendix C plots for Case C8-2.
The remaining cases were also reviewed and the results are summarized in the below maximum
deviation table for PEC. For all cases studied, the PEC units were well within transient stability
limits and adequate damping was present. Additionally, area voltages and transmission
line/transformer thermal limits were well within acceptable ranges for all cases.
In summary, the results of this study indicate that the planned configurations of PEC system for
2014/2015 winter peak load conditions meet the requirements of Categories A, B and C of Table
I of the NERC Reliability Standards TPL-001 through TPL-003 for the contingency scenarios
evaluated.
April 2009 VACAR Stability Study of Projected 2014 Winter Peak Conditions 15
1. Refer to the Scenario Matrix of this report for an explanation of the relationship of individual cases to the Contingency Categories of Table I in the
NERC Reliability Standards TPL-001 through TPL-004.
2. The cases of primary interest to PEC are Cases B2-2 and C8-2.
April 2009 VACAR Stability Study of Projected 2014 Winter Peak Conditions 16
South Carolina Electric & Gas Results
In selecting events within the SCE&G transmission system, preference was given to more likely
scenarios. The two events that were chosen (Cases B3-1 and C2-1) simulate highly probable
single equipment failures at critical locations on the system located near major generation and
intercompany tielines. Normal (pre-contingency) operating procedures are included in the
models. The base case used in this study includes adjustments for planned project scopes and
schedules. The base case has all projected firm transfers modeled. In addition, all existing and
planned facilities are modeled. Reactive power resources are included to ensure that adequate
reactive resources are available to meet system performance requirements. The effects of
existing and planned control devices are also included. The planned (including maintenance
outage of any bulk electric equipment (including protection systems or their components) at the
demand levels for which planned (including maintenance)) outages are performed are also
included in the simulation cases. Stability cases simulate the effects of existing and planned
protection systems, including any backup or redundant systems. The effects of existing and
planned control devices are also included. This study simulates the effects of existing and
planned protection systems, including any backup or redundant systems.
SCE&G was not identified as a secondary area for any of the Cases. However, the outputs from
all simulations were reviewed. None of the simulated neighboring events were found to have a
significant impact on SCE&G’s system.
Case B3-1 simulated a 3-phase fault at the 230/115kV autotransformer between the Canadys
230kV and 115kV busses. The three units at Canadys interconnect with the grid on the 115kV
system. There are several 115kV lines connected to the Canadys 115kV busses, but much of the
power injection from the units passes through a single 230/115kV autotransfomer to the Canadys
230kV bus (the exact amount depending strongly on generation dispatch and interarea
interchange). Not only does a fault at this autotransformer represent a close-in fault at the
Canadys station, but upon normal clearing of the fault, the units at Canadys see a significant step
change in system impedance. Also, the Cope unit, because of its close electrical proximity and its
relative isolation from the rest of the system, is affected significantly by this event. In fact, the
result of the simulation shows that Cope was the most responsive unit to this event, followed by
the Canadys units. The angular response of Cope was well damped following the clearing of the
fault. All other units showed excellent damping and small speed and power deviations.
Case C2-1 simulated a 3-phase fault at the Wateree station 230kV bus tie. Because there is a
single breaker on this bus tie, a failure or internal fault of the bus tie breaker would cause both
Wateree busses to clear, tripping the Wateree units offline. Also, a major 230kV tieline to PEC’s
area would feed the fault and be disconnected following the breaker failure operations. V.C.
Summer station is electrically the closest unit to this event not tripped during simulation. The
results of the simulation show a surprisingly small reaction from system generators to the event.
The largest angular response came from V.C. Summer and shows very little oscillation and fast
damping to steady-state following the clearing of the fault. The speed and power deviations of
the units were also small. There were no indications of instability.
April 2009 VACAR Stability Study of Projected 2014 Winter Peak Conditions 17
Notes: 1. Refer to the Scenario Matrix of this report for an explanation of the relationship of individual cases to the Contingency Categories of Table I of NERC
Reliability Standards TPL-001 through TPL-004.
2. Maximum Deviations are indicated for the cases of primary interest to SCE&G, Cases B3-1 and C2-1. Maximum deviations for other cases were well within
limits.
April 2009 VACAR Stability Study of Projected 2014 Winter Peak Conditions 19
April 2009 VACAR Stability Study of Projected 2014 Winter Peak Conditions 20
South Carolina Public Service Authority Results
South Carolina Public Service Authority (SCPSA) selected simulation Cases C1-2 and C3-3 to
assess the impact of these contingency events addressing specific categories outlined in Table 1
of NERC Planning Standard TPL-001 through TPL-003. These simulations are part of activities
to evaluate potential system stability impacts of contingency events initiating within the SCPSA
system under projected winter load conditions for the 2014-2015 season. Key parameters
monitored for each study scenario include generator rotor angles, generator rotor speed
deviations, generator electrical power and selected transmission line power flows. Selected plots
for these parameters are included in the Appendix. Based on these monitored parameters,
SCPSA generators remain stable in all cases evaluated. All post-disturbance oscillations are well
damped, and no sustained facility overloads are identified from those monitored throughout the
VACAR Sub-region. All voltages remain within acceptable operating ranges following the
initial oscillations associated with each simulated contingency event. All results depict no
indication of cascading outages as a result of the conditions simulated.
Case C1-2 simulates a SLG fault on the #2 bus section of the Kingstree 230 kV Switching
Station, resulting in a lock-out of the bus-tie breaker as well as the Kingstree end of Cross –
Kingstree #1 230 kV line, the Jefferies – Kingstree 230 kV line, and the Hemingway – Kingstree
230 kV line. This disturbance scenario was selected to assess its potential impact on local
generation and the SCPSA-PEC interface. This study assumes the 600 MW Pee Dee Generating
Station is operational and is to be interconnected through transmission facilities closely tied to
the Kingstree 230 kV Switching Station.
Following the initial fault and subsequent lock-out of the #2 bus section at Kingstree, maximum
rotor angle deviations for this simulated fault are reported at SCPSA’s Jefferies Generating
Station. Hydro Unit #3 experiences a maximum rotor angle change of 9.9 degrees. All rotor
angle and speed oscillations are well damped with no indications of instability. Cross Unit #3
experiences the largest real power swing (481 MW) by SCPSA generators due to the proximity
to the simulated fault condition to the Cross Generating Station. All transmission line power
flow deviations remain below the thermal ratings of the lines monitored in this assessment.
Case C3-3 simulates a SLG fault on the Pee Dee – Hemingway 230 kV line with no reclosing,
followed by a normally-cleared SLG fault on the Kingstree – Lake City 230 kV line with
reclosing permitted. As with Case C1-2, this disturbance scenario was selected to assess its
potential impact on local generation and the SCPSA-PEC interface. This study assumes the 600
MW Pee Dee Generating Station is operational and is to be interconnected through transmission
facilities closely tied to that existing at both Hemingway and Lake City.
April 2009 VACAR Stability Study of Projected 2014 Winter Peak Conditions 21
Following the initial lock-out of the Pee Dee – Hemingway line and the normal reclosing of the
Kingstree – Lake City 230 kV line following the secondary fault, the maximum rotor angle
deviation experienced by SCPSA generators is 6.6 degrees and occurs on the Pee Dee Unit #1.
Rotor angle and speed oscillations are well damped, and there are no indications of instability
following this simulated event. The largest power swing for SCPSA facilities occurs on the Pee
Dee generator with a change in real power of 163 MW following the second SLG fault.
Transmission line power flows remain below thermal ratings following the routine clearing of
this fault.
Contingency Case B3-1 simulates a 3Φ fault on SCE&G’s Canadys 230-115 kV autotransformer,
located near the SCPSA-SCE&G interface in eastern South Carolina. Responses by SCPSA
machines for this disturbance, most notably the five small hydro units at the Jefferies Generating
Station, are modest and well-damped, with no indication of potential instability. These units are
noted in responses to other sub-regional disturbances included in this study, but resulting
oscillations are quickly dampened and are not considered significant.
In summary, the results of this study indicate that the planned configurations of SCPSA system
for the 2014/2015 winter peak load conditions meet the requirements of Categories A, B and C
of Table I of the NERC Reliability Standards TPL-001 through TPL-003 for the contingency
scenarios evaluated.
April 2009 VACAR Stability Study of Projected 2014 Winter Peak Conditions 22
C3-3 Pee Dee 6.6 Pee Dee 163 Pee Dee 0.0026 Pee Dee-Lake City.230 kV 364
Notes:
1. Refer to the Scenario Matrix of this report for an explanation of the relationship of individual cases to the Contingency Categories of Table I of NERC
Reliability Standards TPL-001 through TPL-004.
April 2009 VACAR Stability Study of Projected 2014 Winter Peak Conditions 23
April 2009 VACAR Stability Study of Projected 2014 Winter Peak Conditions 24
Appendix A
Dominion Virginia Power Plots
April 2009 VACAR Stability Study of Projected 2014 Winter Peak Conditions 25
April 2009 VACAR Stability Study of Projected 2014 Winter Peak Conditions 26
April 2009 VACAR Stability Study of Projected 2014 Winter Peak Conditions 27
April 2009 VACAR Stability Study of Projected 2014 Winter Peak Conditions 28
April 2009 VACAR Stability Study of Projected 2014 Winter Peak Conditions 29
Appendix B
Duke Energy Plots
April 2009 VACAR Stability Study of Projected 2014 Winter Peak Conditions 30
Simulation Plot for DUKE C1-1
April 2009 VACAR Stability Study of Projected 2014 Winter Peak Conditions 31
Simulation Plot for DUKE C2-2
April 2009 VACAR Stability Study of Projected 2014 Winter Peak Conditions 32
April 2009 VACAR Stability Study of Projected 2014 Winter Peak Conditions 33
Appendix C
Progress Energy Carolinas Plots
April 2009 VACAR Stability Study of Projected 2014 Winter Peak Conditions 34
April 2009 VACAR Stability Study of Projected 2014 Winter Peak Conditions 35
April 2009 VACAR Stability Study of Projected 2014 Winter Peak Conditions 36
Appendix D
South Carolina Electric & Gas Plots
April 2009 VACAR Stability Study of Projected 2014 Winter Peak Conditions 37
April 2009 VACAR Stability Study of Projected 2014 Winter Peak Conditions 38
April 2009 VACAR Stability Study of Projected 2014 Winter Peak Conditions 39
April 2009 VACAR Stability Study of Projected 2014 Winter Peak Conditions 40
Appendix E
South Carolina Public Service Authority Plots
April 2009 VACAR Stability Study of Projected 2014 Winter Peak Conditions 41
April 2009 VACAR Stability Study of Projected 2014 Winter Peak Conditions 42
COORDINATED STUDY PROGRESS ENERGY CAROLINAS
AND SOUTH CAROLINA PUBLIC SERVICE
AUTHORITY
2016 SUMMER PEAK
August 19, 2010
Progress Energy Carolinas and South Carolina Public Service Authority Coordinated Study
STUDY PARTICIPANTS
Representative Company S. Tom Abrams South Carolina Public Service Authority J. E. Peterson South Carolina Public Service Authority William K. Gaither South Carolina Public Service Authority A. Mark Byrd Progress Energy Carolinas Joey West Progress Energy Carolinas Reviewed by:
S. Tom Abrams South Carolina Public Service Authority J. E. Peterson South Carolina Public Service Authority A. Mark Byrd Progress Energy Carolinas
Page 2 of 7
Progress Energy Carolinas and South Carolina Public Service Authority Coordinated Study
Overview The purpose of this joint study between South Carolina Public Service Authority (SC) and Progress Energy Carolinas, Inc. (PEC) is to assess the impact of a proposed 230 kV interconnection between SC and PEC. The proposed tie-line extends between SC’s Red Bluff 230-115 kV Substation and PEC’s Prospect 230 kV Substation. The SC decision to permanently defer a coal unit at Pee-Dee made it necessary to revisit this study that was originally performed in 2009. Study Process A base case was developed for the 2016 Summer Peak Period using the 2009 Series SERC Databank Update cases. SC’s and PEC’s reduced representations were replaced with each company’s corresponding detailed internal transmission system model with future transmission facility additions “as currently planned”. MUST was used to run a transfer capability analysis on the base case to assess the impact of the proposed interconnection. Each company provided the contingency files for their system which included single line outages from major buses in each system as well as single ties from each area. The transfers studied were a SC to PEC 1400 MW transfer and a PEC to SC 2000 MW transfer. The SC to PEC transfer was run twice, once with Brunswick Unit #1 participating in the transfer and again with Brunswick Unit #2 participating in the transfer. Transfer Results Base Case For the 2016 Summer Peak Period, no SC or PEC facilities are loaded beyond their thermal limits in the base case. In the PEC import case with Brunswick Unit #1 no limits were found up to the import level of 1400 MW. In the PEC import case with Brunswick Unit #2 no limits were found up to the import level of 1400 MW. In the PEC export case no limits were found up to the export level of 2000 MW. Addition of the Red Bluff-Prospect 230 kV Tie The proposed Red Bluff-Prospect 230 kV Tie was modeled in the powerflow case with an approximately 20-mile long 230 kV transmission line addition from Brunswick Electric Membership Corporation’s (BEMC) Grissettown 230 kV Substation to SC’s Red Bluff 230 kV Substation. The conductor on this line was modeled as single 1272 ACSR conductor with a current rating of 1,480 Amperes. The model also included the existing 14 mile 230 kV line from PEC’s Prospect Substation to BEMC’s Grissettown Substation. For the 2016 Summer Peak Period, no SC or PEC facilities are loaded beyond their thermal limits in the base case.
Page 3 of 7
Progress Energy Carolinas and South Carolina Public Service Authority Coordinated Study
Page 4 of 7
With the addition of the Red Bluff (SC)-Prospect (PEC) 230 kV Tie and for the import case using the Brunswick #1 unit participating, the Brunswick 2-Delco (Brunswick terminal end) 230 kV Line (PEC) limits PEC imports to 1300 MW for the outage of the Brunswick 2-Wilmington Corning Switching Station 230 kV Line (PEC). The limiting element is actually a series device and the line can be uprated. In the PEC import case with Brunswick Unit #2 participating, no limits were found up to the import level of 1400 MW. In the PEC export case no limits were found up to the export level of 2000 MW. Red Bluff-Prospect 230 kV Tie and Uprate of the Brunswick 2-Delco 230 kV Line With this facility/upgrade modeled and without regard to voltage limits and generating unit dynamic stability considerations, there are no transmission facility thermal loadings which limit PEC imports to less than the study level of 1400 MW or for PEC exports of 2000 MW.
Table 1: Summary of Transfer Results for 2016 Summer Study Year Transfer Levels Shown in MW’s
2010 Results for 2016 Study Year|
Transfer Base Red Bluff-Prospect 230 kV Tie Red Bluff-Prospect 230 kV Tie &
Uprate of Brunswick 2- Delco 230 kV Line
PEC Import (Brunswick 1) 1400+ 1300 1400+
PEC Import (Brunswick 2) 1400+ 1400+ 1400+
PEC Export 2000+ 2000+ 2000+
2009 Results for 2016 Study Year
Transfer Base Red Bluff-Prospect 230 kV Tie Red Bluff-Prospect 230 kV Tie &
Uprate of Brunswick 2- Delco 230 kV Line
PEC Import (Brunswick 1) 800 850 1400+
PEC Import (Brunswick 2) 800 950 1400+
PEC Export 2000+ 2000+ 2000+
Summary of Incremental Transfer Capabilities 2010 PEC-SC Coordinated Study
SCPSA to CP&LE 1400 + No limit found at 1400 MW None (Brunswick 1) 1400 + No other limit found at 1400 MW Any other tested facility
SCPSA to CP&LE 1400 + No limit found at 1400 MW None (Brunswick 2) 1400 + No other limit found at 1400 MW Any other tested facility CP&LE to SCPSA 2000 + No limit found at 2000 MW None 2000 + No limit found at 2000 MW Any tested facility
Summary of Incremental Transfer Capabilities 2010 PEC-SC Coordinated Study
SCPSA to CP&LE 1400 + No limit found at 1400 MW None (Brunswick 1) 1300 Brunswick 2-Delco 230 kV 478 10.8 46.2 Brunswick 2-Wilmington Corning Sw. Sta.230 kV 1400 + No other limit found at 1400 MW Any other tested facility SCPSA to CP&LE 1400 + No limit found at 1400 MW None (Brunswick 2) 1400 + No other limit found at 1400 MW Any other tested facility CP&LE to SCPSA 2000 + No limit found at 2000 MW None 2000 + No limit found at 2000 MW Any tested facility
Includes Red Bluff-Grissettown- Prospect 230 kV Line
Summary of Incremental Transfer Capabilities 2010 PEC-SC Coordinated Study
SCPSA to CP&LE 1400 + No limit found at 1400 MW None (Brunswick 1) 1400 + No other limit found at 1400 MW Any other tested facility
SCPSA to CP&LE 1400 + No limit found at 1400 MW None (Brunswick 2) 1400 + No other limit found at 1400 MW Any other tested facility CP&LE to SCPSA 2000 + No limit found at 2000 MW None 2000 + No limit found at 2000 MW Any tested facility
** includes Brunswick #2-Delco 230 kV Uprate
CAROLINAS TRANSMISSION
COORDINATION ARRANGEMENT
(CTCA)
2016 SUMMER PEAK/SHOULDER
RELIABILITY STUDY
FINAL
October 8, 2012
CTCA 2016 Summer Peak\Shoulder Reliability Study October 8, 2012
Page 2
STUDY PARTICIPANTS
Prepared by: CTCA Power Flow Studies Group (PFSG)
Representative Company
Kai Zai Progress Energy Carolinas
Lee Adams Progress Energy Carolinas
Joe Jenkins Progress Energy Carolinas
Brian D. Moss, Chair Duke Energy Carolinas
Bob Pierce Duke Energy Carolinas (Alternate)
Kale Ford South Carolina Electric and Gas
William Gaither South Carolina Public Service Authority
Reviewed by: CTCA Planning Committee (PC)
Representative Company
Samuel Waters, Chair Progress Energy Carolinas
A. Mark Byrd Progress Energy Carolinas
Ed Ernst Duke Energy Carolinas
Bob Pierce Duke Energy Carolinas
Brian D. Moss Duke Energy Carolinas
Clay Young South Carolina Electric and Gas
Phil Kleckley South Carolina Electric and Gas
Tom Abrams South Carolina Public Service Authority
Jim Peterson South Carolina Public Service Authority
CTCA 2016 Summer Peak\Shoulder Reliability Study October 8, 2012
Page 3
PURPOSE OF STUDY
The purpose of this study is to assess the existing transmission expansion plans of Duke Energy
Carolinas (“Duke”), Progress Energy Carolinas (“Progress”), South Carolina Electric and Gas
(“SCE&G”), and South Carolina Public Service Authority (“SCPSA”) to ensure that the plans
are simultaneously feasible. In addition, this study will evaluate any potential joint alternatives
identified by the Planning Committee (“PC”) representatives which might improve the
simultaneous feasibility of the Participants’ transmission expansion plans through potentially
more efficient or cost-effective joint plans. The Power Flow Studies Group (“PFSG”) will
perform the technical analysis outlined in this study scope under the guidance and direction of
the PC.
OVERVIEW OF THE STUDY PROCESS
The scope of the proposed study process will include the following steps:
1. Study Assumptions
Study assumptions selected
2. Study Criteria
Establish the criteria by which the study results will be measured
3. Case Development
Develop the models needed to perform the study
4. Study Methodology
Determine the methodologies that will be used to carry out the study
5. Technical Analysis and Study Results
Perform the technical analysis (thermal, voltage, and stability as needed) and produce
the study results
6. Assessment and Potential Issues Identification
Evaluate the results to identify potential issues
Report potential issues to the PC
7. Potential Alternative Development
Evaluate potential joint alternatives as directed by the PC
8. Report on the Study Results
Combine the study scope and assessment results into a report
CTCA 2016 Summer Peak\Shoulder Reliability Study October 8, 2012
Page 4
STUDY ASSUMPTIONS
Study Year Reliability Study Description
2010 2014/21 Summer Peak 14S: Near-term
21S: Long-term (VC Summer 2-3)
2011 2015/18 Summer Peak 15S: Near-term
18S: Long-term (VC Summer 2)
2012 2016 Summer Peak/Shoulder 16S: VC Summer Transmission Only
16H: Low Gas Price Dispatch
The year to be studied (study year) will be 2016 for a near term reliability analysis. VC
Summer unit 2 has been delayed from 2016 until 2017, while the related transmission
expansion plans continue to be scheduled for completion prior to 2016. A summer peak
case will be used to evaluate the impact of the VC Summer expansion related
transmission plans prior to any new units coming on-line. A shoulder case will be used
to evaluate a potential low gas price dispatch scenario where CCs and/or CTs are being
dispatched before the coal units.
Generation will be dispatched for each Participant in the study cases to meet that
Participant’s peak and shoulder load in accordance with the designated dispatch order.
Participants will also provide generation down scenarios for their resources, as requested
(e.g., generation outage with description of how generation will be replaced, such as by
that Participant’s dispatch orders).
PSS/E and/or MUST will be used for the study.
Load growth assumptions will be in accordance with each Participant company’s
practice.
Generation, interchange, and other assumptions will be coordinated between the
Participant companies as needed. The 2012 series LTSG case for 2016 summer will be
used as the starting points for study cases and interchange development.
A shoulder peak is defined as 70-80% of summer peak load conditions. Each Participant
company will determine the appropriate load and generation dispatch to represent a low
gas price dispatch scenario on their system.
The PFSG will use the 2016 summer and shoulder peak cases to analyze the existing
transmission expansion plans to determine if any reliability criteria violations are created.
Based on this analysis, the PFSG will provide feedback to the PC on the simultaneous
feasibility of these plans for ensuring the reliability of service. The results of this analysis
will be included in the 2012 study report.
CTCA 2016 Summer Peak\Shoulder Reliability Study October 8, 2012
Page 5
STUDY CRITERIA
NERC Reliability Standards
Individual company criteria (voltage, thermal, stability, short circuit and phase angle)
CASE DEVELOPMENT
The latest LTSG models will be used as a starting point for the study cases to be used by
the PFSG in their analyses. Systems external to Duke, Progress, SCE&G, and SCPSA
will come directly from the LTSG model.
The study cases will include the detailed internal models for Duke, Progress, SCE&G,
and SCPSA and will include existing transmission additions planned to be in-service for
the given year (i.e. in-service by 2016 summer).
The Participants will coordinate interchange which will include all confirmed long term
firm transmission reservations with roll-over rights applicable to the study year(s).
Duke, Progress, SCE&G, and SCPSA will each create any requested generation down
cases from the common study cases and share the relevant cases with each other.
Generation Down Cases Shared
Duke: Belews Creek 1, Buck CC, Catawba 1, Cliffside 5, Cliffside 6, Dan River
