VACAR 2015 SUMMER PEAK RELIABILITY STUDY

Transcription

1 VACAR 2015 SUMMER PEAK RELIABILITY STUDY August 2010

2 STUDY PARTICIPANTS Prepared by: VACAR Power Flow Working Group (PFWG) Representative Joey West Brian D. Moss Kale L. Ford, Chair Vanessa M. Abercrombie William K. Gaither Peter Nedwick Helen Stines Company Progress Energy Carolinas Duke Energy Carolinas South Carolina Electric and Gas South Carolina Electric and Gas (Alternate) South Carolina Public Service Authority Dominion Virginia Power Alcoa Power Generating, Inc. (APGI) - Yadkin Reviewed by: VACAR Planning Task Force (PTF) Representative Company A. Mark Byrd Progress Energy Carolinas Brian D. Moss Phil R. Kleckley, Chair Jim Peterson Mehdi Shakibafar James Manning Douglas Spencer Rick Anderson Jennifer Connors Duke Energy Carolinas South Carolina Electric and Gas South Carolina Public Service Authority Dominion Virginia Power North Carolina Electric Membership Corporation Southeastern Power Administration Fayetteville Public Works Commission Alcoa Power Generating, Inc. (APGI) - Yadkin i

3 TABLE OF CONTENTS I. EXECUTIVE SUMMARY... 1 A. OVERVIEW... 2 II. INTRODUCTION... 4 A. INTRODUCTION... 5 B. STUDY PROCEDURE... 5 III. STUDY RESULTS... 7 A. SIGNIFICANT FACILITIES DISCUSSION... 8 B. INDIVIDUAL ASSESSMENTS Progress Energy Carolinas - Carolina Power and Light (CPL) Duke Energy Carolinas (Duke) South Carolina Electric and Gas (SCEG) South Carolina Public Service Authority (SCPSA) Dominion Virginia Power (DVP) APGI - Yadkin IV. THERMAL ASSESSMENT RESULTS TABLES V. SUPPORTING DATA Exhibit A. Major Generation and Transmission Facility Changes Exhibit B. Generation Dispatch Exhibit C. Detailed Interchange Exhibit D. Outaged Facilities ii

4 I. EXECUTIVE SUMMARY 1

5 A. OVERVIEW The purpose of this study is to coordinate and jointly assess the ability of the transmission systems within the Virginia-Carolinas (VACAR) area to meet NERC s TPL reliability standards. The study is based on the 2015 Summer Peak power flow case developed by the Eastern Interconnection Reliability Assessment Group (ERAG) Multiregional Modeling Working Group (MMWG) in October Part 1 is an update to the latest MMWG case for 2015 Summer Peak. The interchange utilized in the MMWG starting case was reviewed by each company to identify and coordinate any necessary updates to create a new base case interchange table. If any interchange adjustments are identified, each affected company will provide a dispatch for the new base case to support the new base case interchange table. Each company may choose to provide their latest 2015 Summer Peak detailed (unequivalized), internal control area model or any other case updates for inclusion in the new base case. Any replacement individual control area models and case updates will be merged inside the MMWG starting case to develop an updated model (VACAR15S.sav) of the VACAR systems for the 2015 Summer Peak. Part 2 is an assessment of the steady state performance of the transmission systems within VACAR under NERC s TPL-002 reliability standard. This study focuses on the 500 kv, 230 kv, all tie-lines, and any other single contingencies which may significantly impact each company s neighboring utilities. The assessment is performed on the updated 2015 Summer Peak power flow case. The worst thermal loading scenario for any significant facilities loading greater than or equal to 100% of their contingency specific rating can be found in the (N-1) Thermal Assessment Results Tables in Section IV. There were no significant facilities found to be heavily loaded in Part 2 of this study. Since there are no facilities that are significantly loaded by a TPL-002 single contingency, these facilities do not require infrastructure upgrades or additional operating procedures. Part 3 is an assessment of the steady state performance of the transmission systems within VACAR under NERC s TPL-003 reliability standard. This study focuses on double contingency combinations of the single contingences, as well as some common tower contingencies, concentrating on double contingencies where the facilities are in different systems, near the borders, or expected to significantly impact a company s neighboring utilities. The assessment is performed on the updated 2015 Summer Peak power flow case. The worst thermal loading scenario for any significant facilities loading greater than or equal to 100% of their contingency specific rating can be found in the (N-2) Thermal Assessment Results Tables in Section IV. The following list provides a summary of the most significant facilities found to be heavily loaded in Part 3 of this study. Mills River-Asheville 115 kv Tie Line (Duke/CPLW) Jocassee 500/230 kv Transformer (Duke) Parkwood 500/230 kv Transformers (Duke) Allen-Woodlawn 230 kv Line (Duke) Anderson-Hartwell 230 kv Tie Line (Duke/SEPA) Pisgah 230/100/44 kv Transformers (Duke) Horseshoe 115/100 kv Transformers (Duke) Great Falls-Wateree 100 kv Lines (Duke) Horseshoe-Pisgah 100 kv Lines (Duke) 2

6 Wateree 115/100 kv Transformer (CPLE/Duke) Havelock 230/115 #1/2 (CPLE) Asheboro East-Biscoe 115 kv (CPLE) Richmond-Rockingham 230 kv East (CPLE) Lyles-Lexington 115 kv line (SCEG) Jasper Tap-McIntosh 115 kv tie line (SCEG/Southern) Savannah River Services-Vogtle 230 kv tie line (SCEG/Southern) Tuckertown-High Rock 100 kv (Yadkin) Each of the above facilities are significantly loaded by a TPL-003 multiple contingency. Elimination of these facilities as heavily loaded may require infrastructure upgrades or additional operating procedures. Details concerning these key facilities can be found in the significant facilities discussion in Section III. Part 4 is an assessment of any failed contingency solutions found in parts 2 and 3. The majority of the 84 failed solutions in this study involved toggling capacitors or the loss of significant generation due to the tested contingency. Each of these failed solutions were found to solve when they were rerun with the toggling capacitor fixed (removed from voltage control) or the lost generation moved to a remote bus as part of the contingency description. The toggling capacitors were fixed at their max MVAR output and the lost generation was moved to a bus remote from the location where the contingency is being evaluated to avoid impacting the local impacts of the contingency. Both of these rerun solution efforts produced valid results included in the ACCC results used to complete the (N-1) and (N-2) Thermal Assessment Results Tables in Section IV. 3

7 II. INTRODUCTION 4

8 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), Alcoa Power Generating Inc. - Yadkin, and Dominion Virginia Power (DVP) have conducted this joint study to assess the ability of the transmission systems within the Virginia-Carolinas (VACAR) area to support the NERC Reliability Standards and SERC Reliability Corporation Supplements. 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 (PTF), the primary purpose of this study is to coordinate and jointly assess the ability of the transmission systems within the Virginia-Carolinas (VACAR) area to meet NERC s TPL reliability standards. This investigation was initiated in August 2009 as a part of the VACAR Power Flow Working Group s (PFWG) normal schedule for conducting studies of future system performance. The power flow cases for this study are created by incorporating each VACAR company s updates into the power flow base cases developed by the ERAG MMWG and released in October B. STUDY PROCEDURE This assignment is a multi-part study to assess the performance of the transmission systems within VACAR for the projected 2015 summer peak load, using an updated version of the 2015 Summer Peak power flow base case developed by the ERAG MMWG and released in October PSSE software is used to produce the AC Contingency Calculation (ACCC) results for each thermal assessment. Part 1 is an update to the latest MMWG case (MMWG_2009series_2015S_final.sav) for 2015 Summer Peak. The interchange utilized in the MMWG starting case will be reviewed by each company to identify and coordinate any necessary updates to create a new base case interchange table. If any interchange adjustments are identified, each affected company will provide a dispatch for the new base case to support the new base case interchange table. Each company may choose to provide their latest 2015 Summer Peak detailed (unequivalized), internal control area model or any other case updates for inclusion in the new base case. Any replacement individual control area models and case updates will be merged inside the MMWG starting case to develop an updated model (VACAR15S.sav) of the VACAR systems for the 2015 Summer Peak. Part 2 is an assessment of the steady state performance of the transmission systems within VACAR under NERC s TPL-002 reliability standard. Each company will share their monitor and single (N-1) contingency files to support the development of a single set of monitor and contingency files. This study should focus on the 500 kv, 230 kv, all tie-lines, and any other single contingencies which may significantly impact each company s neighboring utilities. Using the merged monitor and contingency files, the new base case (VACAR15S.sav) will be assessed for thermal and voltage impacts. Any monitored facilities loading greater than or equal to 90% of their contingency specific rating will be reported back to the study group for information purposes, but the report will focus on those facilities loading greater than or equal to 100% of their contingency specific rating. 5

9 Part 3 is an assessment of the steady state performance of the transmission systems within VACAR under NERC s TPL-003 reliability standard. Starting with the merged contingency file, a double (N-2) contingency file will be created. This new double contingency file will include double contingency combinations of the contingences in the merged contingency file, concentrating on double contingencies where the facilities are in different systems, near the borders, or expected to significantly impact a company s neighboring utilities. The study group may use its engineering judgment to eliminate double contingencies involving electrically remote elements and double contingencies deemed to have been adequately covered in internal studies. Using the new double contingency file and the merged monitor file, the new base case (VACAR15S.sav) will be assessed for thermal and voltage impacts. Any monitored facilities loading greater than or equal to 90% of their contingency specific rating will be reported back to the study group for information purposes, but the report will focus on those facilities loading greater than or equal to 100% of their contingency specific rating. Part 4 is an assessment of any failed contingency solutions found in parts 2 and 3. Parts 2 and 3 of this study will evaluate numerous contingency/rating combinations. Based on the findings of the study group s 2007 study effort, a number of combinations will either (1) fail to produce a converged solution (diverge, blown up) or (2) fail to solve (converge) within the solution iteration limit. The study group will evaluate these failed solutions to gain an understanding of the potential problems that these failed solutions may represent. 6

10 III. STUDY RESULTS 7

11 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: The facility is loading greater than or equal to 100% of its contingency specific rating The response of the facility to a contingency and/or a VACAR Reserve Sharing scenario The number of different 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 Mills River-Asheville 115 kv Tie Line (Duke/CPLW) Duke s Mills River-Asheville 115 kv tie line with Progress exceeds its 207 MVA LTE rating for the loss of both Duke s Pisgah 230/100 kv transformers. This line is currently limited by Progress 1272 ACSR conductor rating. The loading on this line can be mitigated by opening the Mills River-Asheville 115 kv tie line with Progress. Jocassee 500/230 kv Transformer (Duke) Duke s Jocassee 500/230 kv transformer exceeds its MVA 12 hour rating for the loss of Duke s McGuire-Cliffside Tap 500 kv line and Duke s Jocassee-Oconee 500 kv line. This contingency forces the entire 800 MW of Duke s Cliffside generation and 1400 MW of Duke s Bad Creek generation to flow through this transformer. Upgrading some ancillary equipment would bring the transformer up to its MVA 12 hour rating. The new transformer rating would be adequate to support the load levels produced in this assessment. The new MVA 1 hour rating of the transformer is adequate to protect the transformer at the load levels produced in this assessment to allow time for Duke s TCC and/or SOC to make system adjustments to reduce the loading on the transformer. Duke s Cliffside and Bad Creek generation could be limited to adequately protect the transformer while this contingency event exists. Assuming 1.4% annual load growth on the line, additional transformer capacity or a precontingency operating solution needs to be implemented in approximately 3 years from the 2015 Summer Peak. Parkwood 500/230 kv Transformers (Duke) Duke s Parkwood 500/230 kv transformer bank 5 exceeds its 840 MVA 12 hour rating for the loss of the parallel Parkwood transformer and Duke s Pleasant Garden 500/230 kv transformer. The 840 MVA transformer ratings would not be adequate to support the load levels produced in this assessment. The transformer needs to be upgraded or a relaying solution needs to be implemented prior to the 2015 Summer Peak. The possible relaying solution would trip the remaining Parkwood transformer bank following the loss of the parallel transformer bank. Duke s Parkwood 500/230 kv transformer bank 6 exceeds its MVA 12 hour rating for the loss of the parallel Parkwood transformer and Duke s Pleasant Garden 500/230 kv transformer. Upgrading some ancillary equipment would bring the transformer up to its 12 hour rating of MVA. The new transformer rating would be adequate to support the load levels produced in this assessment. The new 1260 MVA 1 hour rating of the transformer is adequate to protect the transformers at the load levels produced in this assessment to allow time for Duke s TCC and/or SOC to make system adjustments to reduce the loading on the transformer. Without these system adjustments and assuming 1.4% annual load growth on the transformer, additional transformer capacity or a relaying solution needs to be 8

12 implemented in approximately 14 years from the 2015 Summer Peak. The possible relaying solution would trip the remaining Parkwood transformer bank following the loss of the parallel transformer bank. Allen-Woodlawn 230 kv Line (Duke) Duke s Allen-Woodlawn 230 kv line exceeds its 598 MVA LTE rating for the loss of its parallel line, Duke s Allen 230/100 kv transformer, and Duke s Woodlawn 230/100/44 kv transformer. Upgrading some ancillary equipment would bring the line up to its clearance limited 2156 ACSR conductor MVA LTE rating. The new line rating would be adequate to support the load levels produced in this assessment. Assuming 1.4% annual load growth on the line, the line s clearance issues would need to be removed in approximately 3 years from the 2015 Summer Peak. Anderson-Hartwell 230 kv Tie Line (Duke/SEPA) Duke s Anderson-Hartwell 230 kv tie line with SEPA exceeds its 478 MVA 12 hour rating for the loss of its parallel line and Southern s Hartwell Energy-Bio 230 kv line. This contingency forces the entire 440 MW of SEPA s Hartwell generation and 296 MW of Southern s Hartwell Energy generation to flow through this line. Upgrading some ancillary equipment would bring the line up to its 954 ACSR conductor MVA 12 hour rating. The new line rating would not be adequate to support the load levels produced in this assessment. The new 686 MVA 1 hour rating of the line would not be adequate to protect the line at the load levels produced in this assessment to allow time for Duke s TCC and/or SOC to make system adjustments to reduce the loading on the transformer. SEPA s Hartwell and Southern s Hartwell Energy generation could be limited to adequately protect the line while this contingency event exists. Without implementing pre-contingency system adjustments, the conductor would need to be upgraded prior to the 2015 Summer Peak. Pisgah 230/100/44 kv Transformers (Duke) Duke s Pisgah 230/100/44 kv transformer banks exceed their 239 MVA LTE rating for the loss of the parallel bank and Duke s Mills River-Asheville 115 kv tie line with Progress. Upgrading some ancillary equipment would bring the transformers up to their respective transformer or MVA 12 hour rating. The transformer ratings would be adequate to support the load levels produced in this assessment. Assuming 1.4% annual load growth on this transformer, additional transformer capacity would be needed in approximately 3 years from the 2015 Summer Peak. Horseshoe 115/100 kv Transformers (Duke) Duke s Horseshoe 115/100 kv transformers exceed their MVA LTE rating for the loss of the parallel transformer and one of Duke s Pisgah 230/100/44 kv transformers. Upgrading some ancillary equipment would bring the transformers up to their LTE rating of MVA. The new transformer rating would be adequate to support the load levels produced in this assessment. The new 168 MVA 1 hour rating of the transformers is adequate to protect the transformers at the load levels produced in this assessment to allow time for Duke s TCC and/or SOC to make system adjustments to reduce the loading on the transformers. Without these system adjustments and assuming 1.4% annual load growth on the line, the transformers would need to be upgraded in approximately 1 year from the 2015 Summer Peak. At this time, Duke has no projects planned to make these upgrades and currently relies on a switching solution to mitigate this overload. Since both of these transformer banks are tied to the same breaker, should one of these banks fail, Duke would need to outage both banks, cut out the failed bank, and then place the remaining bank back in service. Duke would work with Progress to open the Asheville 115 kv tie line at the Progress West Asheville substation end in order to allow Duke to continue serving its Mills River Retail customer out of the Horseshoe substation. In this scenario, Duke s 115 kv tie line with Progress will be open and may not return to service until the failed bank is repaired or replaced. These transformer loadings can be impacted by increased imports into CPLW which flow through Duke. 9

13 Great Falls-Wateree 100 kv Lines (Duke) Duke s Great Falls-Wateree 100 kv lines exceed their 58.5 MVA LTE rating for the loss of the parallel line and Progress Asheboro 230/115 kv transformer. The study case was created with the Wateree 115/100 kv transformer out of service to prevent overloads in the Great Falls-Wateree-Elgin-Camden area. System loading under 2015 summer peak conditions is predicted to require pre-contingency opening of the Progress/Duke tie at Wateree in order to avoid overloads in the area. Combined with the additional loss of one Great Falls-Wateree line, the entire 83 MW of Duke s Wateree generation is forced to flow through the one in-service Great Falls-Wateree line. This line is currently limited by its 2/0 Cu conductor rating. The 71.2 MVA 1 hour rating of the conductor is also not adequate to protect the line at the load levels produced in this assessment to allow time for Duke s TCC and/or SOC to make system adjustments to reduce the loading on the line. In this scenario, placing the Wateree 115/100 kv transformer back in service relieves the overload on the one in-service Great Falls-Wateree line. Duke s Wateree generation could also be reduced to prevent overloading the line. The line needs to be upgraded or a pre-contingency operating solution needs to be implemented prior to the 2015 Summer Peak. Horseshoe-Pisgah 100 kv Lines (Duke) Duke s Horseshoe-Pisgah 100 kv lines exceed their MVA 12 hour rating for the loss of the parallel line and Duke s Mills River-Asheville 115 kv tie line with Progress. Upgrading some ancillary equipment would bring the lines up to their 477 ACSR conductor 12 hour rating of MVA. This conductor rating would not be adequate to support the load levels produced in this assessment. The 151 MVA 1 hour rating of the conductor is also not adequate to protect the line at the load levels produced in this assessment to allow time for Duke s TCC and/or SOC to make system adjustments to reduce the loading on the line. These lines need to be upgraded or a pre-contingency operating solution needs to be implemented prior to the 2015 Summer Peak. This line loading can be impacted by increased imports into CPLW which flow through Duke. 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. Havelock 230/115 kv transformers #1/2 (CPLE) PEC s Havelock 230/115 kv transformers (#1 or 2) load to 135% of their 200 MVA rating for an N-2 contingency consisting of the loss of the remaining (#2 or #1) Havelock 230/115 kv transformer and an outage of the Morehead Wildwood 230/115 kv transformer #1. These events are for a fairly isolated pocket of 115 kv load and would have little impact on networked transmission facilities. This event can be mitigated via local area operating guides that could consist of sectionalizing lines or reconfiguring bus arrangements. Asheboro East-Biscoe 115 kv Line (CPLE) PEC s Asheboro East-Biscoe 115 kv line loads to 125% of its 148 MVA rating for an N-2 contingency consisting of the loss of both Asheboro 230/115 kv banks (#1 & #2). These events are for an isolated pocket of 115 kv load and would have very limited impact on networked transmission facilities. This event can be mitigated via local area operating guides that could consist of sectionalizing lines or reconfiguring bus arrangements. 10

14 Richmond-Rockingham 230 kv East Line (CPLE) PEC s Richmond-Rockingham 230 kv East line loads to 111% of its 1014 MVA rating for an N-2 contingency consisting of the loss of the Cumberland-Richmond 500 kv line and the parallel Richmond- Rockingham 230 kv West line. This event can be mitigated via an operating guide that would reduce the output of local generation at Richmond County Plant. Lyles-Lexington 115 kv line (SCEG) SCE&G Lyles-Lexington 115 kv line loads to 101.2% of its 133 MVA rating during a N-2 contingency. This event is caused by the outage of two facilities in SCPSA s Control Area. SCEG will work with SCPSA to further assess the constraint to find remedial action. Jasper Tap-McIntosh 115 kv tie line (SCEG/Southern) SCE&G and Southern s Jasper Tap-McIntosh 230 kv tie line loads to 106.8% of its 240 MVA rating during the N-2 contingency of Savannah River Services-Canadys 230 kv and SCPSA s Purrysburg- Southern s McIntosh 230 kv line. Southern Company has a corrective action plan that will alleviate this tie line constraint. Savannah River Services-Vogtle 230 kv tie line (SCEG/Southern) SCE&G and Southern s Savannah River Services-Vogtle 230 kv tie line loads to 108.6% of its 950 MVA rating during a N-2 contingency. This event is caused by the outage of two facilities in Southern s control area. SCEG and Southern Company will continue to look at ways to assess this tie line constraint. Tuckertown-High Rock 100 kv (Yadkin) The Tuckertown-High Rock 100 kv line limits the PEC, Duke and SCE&G import into Yadkin. Yadkin has an operating guide (YD1) that alleviates the overload and the flows will be above the 200 MW test level. 11

15 B. INDIVIDUAL ASSESSMENTS The following discussions center on each company s adequacy of reliability under (N-1) and (N-2) contingency analysis for the 2015 summer peak season. 12

16 Progress Energy Carolinas - Carolina Power and Light (CPLE and CPLW) 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 results related to its eastern and western control areas are noted using CPLE and CPLW, respectively. PEC assessed N-1 and N-2 contingencies on a 2015 summer peak case. Common Tower Contingencies The tested (N-1) contingency events include a set of common tower contingencies which are considered multiple contingencies in NERC s TPL-003 reliability standard. Common tower N-2 events were not part of the N-2 assessment. (N-1) Thermal Assessment 2015 Summer Peak PEC did not have any voltage or loading concerns in its control areas for N-1 contingency events using the 2015 summer peak load flow case. (N-2) Thermal Assessment 2015 Summer Peak PEC s Havelock 230/115 kv transformers (#1 or 2) load to 135% of their 200 MVA rating for an N-2 contingency consisting of the loss of the remaining (#2 or #1) Havelock 230/115 kv transformer and an outage of the Morehead Wildwood 230/115 kv transformer #1. These events are for a fairly isolated pocket of 115 kv load and would have little impact on networked transmission facilities. This event can be mitigated via local area operating guides that could consist of sectionalizing lines or reconfiguring bus arrangements. Specifically sectionalizing the Havelock-Morehead Wildwood 115 kv Line precontingency will alleviate this condition. PEC s Asheboro East-Biscoe 115 kv line loads to 125% of its 148 MVA rating for an N-2 contingency consisting of the loss of both Asheboro 230/115 kv banks (#1 & #2). These events are for an isolated pocket of 115 kv load and would have very limited impact on networked transmission facilities. This event can be mitigated via local area operating guides that could consist of sectionalizing lines or reconfiguring bus arrangements. Opening the Asheboro East-Biscoe 115 kv Line at Asheboro East 115 kv substation pre-contingency will alleviate this condition. PEC s Folkstone-Jacksonville City 115 kv line loads to 114% of its 158 MVA rating for an N-2 contingency consisting of the loss of both Jacksonville 230/115 kv banks (#1 & #2). These events are for an isolated pocket of 115 kv load and would have very limited impact on networked transmission facilities. This event can be mitigated via local area operating guides that could consist of sectionalizing lines or reconfiguring bus arrangements. Opening the Folkstone 230/115 kv transformer precontingency will alleviate this condition. PEC s Weatherspoon Plant-Fayetteville Dupont Switching Station 115 kv line loads to 112% of its 119 MVA rating for an N-2 contingency consisting of the loss of both Fayetteville 230/115 kv banks (#1 & #2). These events are for an isolated pocket of 115 kv load and would have very limited impact on networked transmission facilities. This event can be mitigated via a local area operating guide that would simply open the Weatherspoon Plant-Fayetteville Dupont Switching Station 11 5k V Line. 13

17 PEC s Richmond-Rockingham 230 kv East line loads to 111% of its 1014 MVA rating for an N-2 contingency consisting of the loss of the Cumberland-Richmond 500 kv line and the parallel Richmond- Rockingham 230 kv West line. This event can be mitigated via an operating guide that would reduce the output of local generation at Richmond County Plant. PEC s Marshall Plant-Craggy 115 kv line loads to 109% of its 123 MVA rating for an N-2 contingency consisting of the loss of the Cane River 230/115 kv transformer and the Cane River-Craggy 115 kv line. This event can be mitigated via local area operating guides that could consist of sectionalizing lines or reconfiguring bus arrangements. Opening the Marshall Plant- Craggy 115 kv Line pre-contingency will alleviate this condition. PEC s Asheville Plant-(DPC) Mills River 115 kv line loads to 103% of its 207 MVA rating for an N-2 contingency consisting of the loss of both Duke- Pisgah 230/100/44 kv transformers. The loading on this line can be mitigated by opening the Mills River-Asheville 115 kv tie line with Progress. PEC s Raeford -Wagram 115 kv line loads to 100% of its 190 MVA rating for an N-2 contingency consisting of the loss of the Raeford-Richmond 230 kv line and the Fayetteville-Raeford 230 kv line. This event can be mitigated via a local area operating guide to open the Raeford-Wagram 115 kv Line prior to the second contingency or by having the area EMC redistribute there load to other sections of the CPLE transmission system. 14

18 Duke Energy Carolinas (Duke) (N-1) Thermal Assessment The following discussions provide facility details for the significant facility loadings reported in Duke s (N-1) Thermal Assessment Results Tables in Section IV. Duke s Morning Star-Newport 230 kv line loads to 99.9% of its 401 MVA 12 hour rating for the loss of the Richmond-Newport 500 kv line. This line is currently limited by its conductor rating due to some clearance issues. Duke is currently correcting the clearance issues on this line and the work should be completed in Once the clearance issues are removed, the conductor, CT setting, and 51 XYZ relay setting will be the limiting elements each with a 478 MVA 12 Hour rating. Assuming 1.4% annual load growth on this line, the conductor would need to be upgraded in approximately 14 years from the 2015 Summer Peak. Duke s North Greensboro 230/100/44 kv transformer bank 3 loads to 99.9% of its 500 MVA LTE rating for the loss of the parallel bank 2. This transformer is currently limited by a high tension watt/var meter rating. Duke is currently upgrading the metering and the work should be completed in Once the meter limit is removed, the transformer will be the limiting element with a MVA LTE rating. Assuming 1.4% annual load growth on this transformer, additional transformer capacity would be needed in approximately 6 years from the 2015 Summer Peak. Duke s Horseshoe 115/100 kv transformers both load to 107.1% of their MVA LTE rating for the loss of the parallel transformer. These transformer banks are currently limited by some 300 Cu. Upgrading the 300 Cu, as well as the 1/2 Cu Pipe and 600 Cu Switches, would bring the transformers up to their LTE rating of MVA. The new transformer rating would be adequate to support the load levels produced in this assessment. Assuming 1.4% annual load growth on the transformers, additional transformer capacity would be needed in approximately 10 years from the 2015 Summer Peak. At this time, Duke has no projects planned to make these upgrades and currently relies on a switching solution to mitigate this overload. Since both of these transformer banks are tied to the same breaker, should one of these banks fail, Duke would need to outage both banks, cut out the failed bank, and then place the remaining bank back in service. Duke would work with Progress to open the Asheville 115 kv tie line at the Progress West Asheville substation end in order to allow Duke to continue serving its Mills River Retail customer out of the Horseshoe substation. In this scenario, Duke s 115 kv tie line with Progress will be open and may not return to service until the failed bank is repaired or replaced. (N-2) Thermal Assessment The following discussions provide facility details for the significant facility loadings reported in Duke s (N-2) Thermal Assessment Results Tables in Section IV. Duke s Mills River-Asheville 115 kv tie line with Progress loads to103% of its 207 MVA LTE rating for the loss of both Duke s Pisgah 230/100 kv transformers. This line is currently limited by Progress 1272 ACSR conductor rating. The loading on this line is can be mitigated by opening the Mills River- Asheville 115 kv tie line with Progress. Duke s Antioch-McGuire 500 kv line loads to 118.8% of its 1081 MVA LTE rating for the loss of the Duke s Pleasant Garden-Woodleaf 500 kv line and Duke s McGuire 500/230 kv transformer. The contingency analysis should have used the current updated 2598 MVA LTE rating for the line. This line is currently limited by a CT setting. The updated line rating would be adequate to support the load levels 15

19 produced in this assessment. Assuming 1.4% annual load growth on the lines, the CT setting would need to be upgraded in approximately 11 years from the 2015 Summer Peak. Duke s Jocassee-Oconee 500 kv line loads to 116.9% of its MVA LTE rating for the loss of the Duke s McGuire-Cliffside Tap 500 kv line and Duke s Jocassee 500/230 kv transformer. The line is currently limited by its CT setting. Upgrading the CT settings and the 51XYZ Relays would bring the line up to its breaker LTE rating of MVA. The new line rating would be adequate to support the load levels produced in this assessment. Assuming 1.4% annual load growth on the line, the breakers would need to be upgraded in approximately 28 years from the 2015 Summer Peak. Duke s Jocassee 500/230 kv transformer loads to 139.5% of its MVA 12 hour rating for the loss of Duke s McGuire-Cliffside Tap 500 kv line and Duke s Jocassee-Oconee 500 kv line. This contingency forces the entire 800 MW of Duke s Cliffside generation and 1400 MW of Duke s Bad Creek generation to flow through this transformer. The transformer is currently limited by its CT settings. Increasing the CT settings would bring the transformer up to its MVA 12 hour rating. The new transformer rating would be adequate to support the load levels produced in this assessment. The new MVA 1 hour rating of the transformer is adequate to protect the transformer at the load levels produced in this assessment to allow time for Duke s TCC and/or SOC to make system adjustments to reduce the loading on the transformer. Duke s Cliffside and Bad Creek generation could be limited to adequately protect the transformer while this contingency event exists. Assuming 1.4% annual load growth on the line, additional transformer capacity or a pre-contingency operating solution needs to be implemented in approximately 3 years from the 2015 Summer Peak. Duke s McGuire-Cliffside Tap 500 kv line loads to 118% of its MVA LTE rating for the loss of the Duke s Jocassee-Oconee 500 kv line and Duke s Jocassee 500/230 kv transformer. The contingency analysis should have used the current updated 3328 MVA LTE rating for the line. This line is currently limited by a CT setting. The updated line rating would be adequate to support the load levels produced in this assessment. Assuming 1.4% annual load growth on the lines, the CT setting would need to be upgraded in approximately 29 years from the 2015 Summer Peak. Duke s Parkwood 500/230 kv transformer bank 5 loads to 111.1% of its 840 MVA 12 hour rating for the loss of the parallel Parkwood transformer and Duke s Pleasant Garden 500/230 kv transformer. The 840 MVA transformer ratings would not be adequate to support the load levels produced in this assessment. The transformer needs to be upgraded or a relaying solution needs to be implemented prior to the 2015 Summer Peak. The possible relaying solution would trip the remaining Parkwood transformer bank following the loss of the parallel transformer bank. Duke s Parkwood 500/230 kv transformer bank 6 loads to 118% of its MVA 12 hour rating for the loss of the parallel Parkwood transformer and Duke s Pleasant Garden 500/230 kv transformer. The transformer is currently limited by its CT settings. Increasing the CT settings, as well as upgrading the 51THXYZ Relays, breakers, and some ACSR, would bring the transformer up to its 12 hour rating of MVA. The new transformer rating would be adequate to support the load levels produced in this assessment. The new 1260 MVA 1 hour rating of the transformer is adequate to protect the transformers at the load levels produced in this assessment to allow time for Duke s TCC and/or SOC to make system adjustments to reduce the loading on the transformer. Without these system adjustments and assuming 1.4% annual load growth on the transformer, additional transformer capacity or a relaying solution needs to be implemented in approximately 14 years from the 2015 Summer Peak. The possible relaying solution would trip the remaining Parkwood transformer bank following the loss of the parallel transformer bank. 16

20 Duke s Allen-Catawba 230 kv lines load to 101.4% of its MVA 12 hour rating for the loss of its parallel line and Duke s McGuire 500/230 kv transformer. The line is currently limited by its CT setting. Upgrading the CT settings would bring the line up to its 2 Al Pipe MVA 12 hour rating. The new line rating would be adequate to support the load levels produced in this assessment. Assuming 1.4% annual load growth on the line, the 2 Al Pipe would need to be upgraded in approximately 10 years from the 2015 Summer Peak. Duke s Allen-Woodlawn 230 kv line loads to 107.2% of its 598 MVA LTE rating for the loss of its parallel line, Duke s Allen 230/100 kv transformer, and Duke s Woodlawn 230/100/44 kv transformer. The line is currently limited by its CT setting. Upgrading the CT settings would bring the line up to its clearance limited 2156 ACSR conductor MVA LTE rating. The new line rating would be adequate to support the load levels produced in this assessment. Assuming 1.4% annual load growth on the line, the line s clearance issues would need to be removed in approximately 3 years from the 2015 Summer Peak. Duke s Anderson-Hartwell 230 kv tie line with SEPA loads to 148.2% of its 478 MVA 12 hour rating for the loss of its parallel line and Southern s Hartwell Energy-Bio 230 kv line. This contingency forces the entire 440 MW of SEPA s Hartwell generation and 296 MW of Southern s Hartwell Energy generation to flow through this line. The line is currently limited by its CT setting. Upgrading the CT settings, 750 Cu, 1200 Switch, and 1200 Trap would bring the line up to its 954 ACSR conductor MVA 12 hour rating. The new line rating would not be adequate to support the load levels produced in this assessment. The new 686 MVA 1 hour rating of the line would not be adequate to protect the line at the load levels produced in this assessment to allow time for Duke s TCC and/or SOC to make system adjustments to reduce the loading on the transformer. SEPA s Hartwell and Southern s Hartwell Energy generation could be limited to adequately protect the line while this contingency event exists. Without implementing pre-contingency system adjustments, the conductor would need to be upgraded prior to the 2015 Summer Peak. Duke s Harrisburg-McGuire (Mecklenburg) 230 kv lines load to % of their 479 MVA 12 hour rating for the loss of two of its three parallel lines. This line is currently limited by its conductor rating due to some clearance issues. Duke is currently correcting the clearance issues on this line and the work should be completed in Once the clearance issues are removed, the 1200 Trap will be the limiting element with a MVA 12 Hour rating. Assuming 1.4% annual load growth on this line, the 1200 Trap would need to be upgraded in approximately 4 years from the 2015 Summer Peak. Duke s Jocassee-Shiloh 230 kv lines load to 104.3% of their 660 MVA 12 hour rating for the loss of Duke s McGuire-Cliffside Tap 500 kv line and Duke s Jocassee-Oconee 500 kv line. This contingency forces the entire 800 MW of Duke s Cliffside generation and 1400 MW of Duke s Bad Creek generation to flow through the Jocassee 500/230 kv transformer and then out of the substation through six 230 kv lines. The lines are currently limited by their conductor ratings due to some clearance issues. Duke is currently correcting the clearance issues on this line and the work should be completed in Once the clearance issues are removed, the CT setting will be the limiting element with a MVA 12 Hour rating. Assuming 1.4% annual load growth on this line, the CT setting would need to be upgraded in approximately 11 years from the 2015 Summer Peak. Duke s Marshall-Stamey 230 kv line loads to 101% of its 725 MVA LTE rating for the loss of its parallel line and Duke s Buck 230/100 kv transformer. The line is currently limited by its 1600 Al Switch rating. Upgrading the switch would bring the line up to its ACSR conductor 947 MVA LTE rating. The new line rating would be adequate to support the load levels produced in this 17

21 assessment. Assuming 1.4% annual load growth on this line, the conductor would need to be upgraded in approximately 16 years from the 2015 Summer Peak. Duke s Morning Star-Newport 230 kv line loads to 109.1% of its 401 MVA 12 hour rating for the loss of Duke s Pleasant Garden-Woodleaf 500 kv line and the Richmond-Newport 500 kv line. This line is currently limited by its conductor rating due to some clearance issues. Duke is currently correcting the clearance issues on this line and the work should be completed in Once the clearance issues are removed, the conductor, CT setting, and 51 XYZ relay setting will be the limiting elements each with a 478 MVA 12 Hour rating. Assuming 1.4% annual load growth on this line, the conductor would need to be upgraded in approximately 8 years from the 2015 Summer Peak. Duke s Pisgah 230/100/44 kv transformer banks load to % of their 239 MVA LTE rating for the loss of the parallel bank and Duke s Mills River-Asheville 115 kv tie line with Progress. These transformers are currently limited by their CT settings. Upgrading the CT settings and some 1250 Al would bring the transformers up to their transformer or MVA 12 hour rating. The new transformer ratings would be adequate to support the load levels produced in this assessment. Assuming 1.4% annual load growth on this transformer, additional transformer capacity would be needed in approximately 3 years from the 2015 Summer Peak. Duke s Horseshoe 115/100 kv transformers both load to 122.1% of their MVA LTE rating for the loss of the parallel transformer and one of Duke s Pisgah 230/100/44 kv transformers. These transformers are currently limited by some 300 Cu. Upgrading the 300 Cu, as well as 1/2 Cu Pipe and 600 Cu Switches, would bring the transformers up to their transformer LTE rating of MVA. The new transformer rating would be adequate to support the load levels produced in this assessment. The new 168 MVA 1 hour rating of the transformers is adequate to protect the transformers at the load levels produced in this assessment to allow time for Duke s TCC and/or SOC to make system adjustments to reduce the loading on the transformers. Without these system adjustments and assuming 1.4% annual load growth on the line, the transformers would need to be upgraded in approximately 1 year from the 2015 Summer Peak. At this time, Duke has no projects planned to make these upgrades and currently relies on a switching solution to mitigate this overload. Since both of these transformer banks are tied to the same breaker, should one of these banks fail, Duke would need to outage both banks, cut out the failed bank, and then place the remaining bank back in service. Duke would work with Progress to open the Asheville 115 kv tie line at the Progress West Asheville substation end in order to allow Duke to continue serving its Mills River Retail customer out of the Horseshoe substation. In this scenario, Duke s 115 kv tie line with Progress will be open and may not return to service until the failed bank is repaired or replaced. These transformer loadings can be impacted by increased imports into CPLW which flow through Duke. Duke s Great Falls-Wateree 100 kv lines load to 122.7% of their 58.5 MVA LTE rating for the loss of the parallel line and Progress Asheboro 230/115 kv transformer. The study case was created with the Wateree 115/100 kv transformer out of service to prevent overloads in the Great Falls-Wateree-Elgin- Camden area. System loading under 2015 summer peak conditions is predicted to require precontingency opening of the Progress/Duke tie at Wateree in order to avoid overloads in the area. Combined with the additional loss of one Great Falls-Wateree line, the entire 83 MW of Duke s Wateree generation is forced to flow through the one in-service Great Falls-Wateree line. This line is currently limited by its 2/0 Cu conductor rating. The 71.2 MVA 1 hour rating of the conductor is also not adequate to protect the line at the load levels produced in this assessment to allow time for Duke s TCC and/or SOC to make system adjustments to reduce the loading on the line. In this scenario, placing the Wateree 115/100 kv transformer back in service relieves the overload on the one in-service Great Falls- Wateree line. Duke s Wateree generation could also be reduced to prevent overloading the line. The 18

22 line needs to be upgraded or a pre-contingency operating solution needs to be implemented prior to the 2015 Summer Peak. Duke s Horseshoe-Pisgah 100 kv lines load to 147.9% of their MVA 12 hour rating for the loss of the parallel line and Duke s Mills River-Asheville 115 kv tie line with Progress. These lines are currently limited by some 300 Cu. Upgrading the 300 Cu would bring the lines up to their 477 ACSR conductor 12 hour rating of MVA. This conductor rating would not be adequate to support the load levels produced in this assessment. The 151 MVA 1 hour rating of the conductor is also not adequate to protect the line at the load levels produced in this assessment to allow time for Duke s TCC and/or SOC to make system adjustments to reduce the loading on the line. These lines need to be upgraded or a pre-contingency operating solution needs to be implemented prior to the 2015 Summer Peak. This line loading can be impacted by increased imports into CPLW which flow through Duke. 19

23 South Carolina Electric and Gas (SCEG) (N-1) Thermal and Voltage Assessment SCEG did not have any thermal or voltage constraints in its control areas for N-1 contingency events using the 2015 summer peak case. (N-2) Thermal and Voltage Assessment Advanced Fiberglass Yarn-Aiken Hampton 115 kv line loads to 100.4% of its MVA rating during the N-2 contingency of Ward-Graniteville 230 kv line and SCPSA s Briggs Road-SEPA s Thurmond 115 kv line. This event can be alleviated by reducing generation at Urquhart. Savannah River Services-Canadys 230 kv line loads to 100.6% of its MVA rating during the N-2 contingency of Southern s Warthen-Hancock County 500 kv line and Southern s Vogtle-West McIntosh 500 kv line. This overload is caused by the outage of two facilities in Southern Company s Control Area. SCEG will further assess the constraint to find remedial action. Lyles-Lexington 115 kv line loads to 101.2% of its 133 MVA rating during the N-2 contingency of SCPSA s Orangeburg-Cross 230 kv line and SCPSA s Batesburg-Newberry 230 kv line. This event is caused by the outage of two facilities in SCPSA s Control Area. SCEG will further assess the constraint to find remedial action. Okatie 230/115 kv Transformer loads to 102.2% of its 336 MVA rating during the N-2 contingency of Yemassee-Jasper 230 kv line and SCPSA s Bluffton-Yemassee 230 kv line. This event can be alleviated by reducing generation at Jasper. Yemassee-Jasper 230 kv line loads to 102.6% of its MVA rating during the N-2 contingency of Savannah River Services-Vogtle 230 kv line and SCPSA s Bluffton-Yemassee 230 kv line. This event can be alleviated with a local area operating guide. Advanced Fiberglass Yarn-Aiken Hampton 115 kv line loads to 102.7% of its MVA rating during the N-2 contingency of Ward-Graniteville 230 kv line and Orangeburg-Cope 230 kv line. This event can be alleviated by reducing generation at Urquhart. Advanced Fiberglass Yarn-Aiken Hampton 115 kv line loads to 104.4% of its MVA rating during the N-2 contingency of Ward-Graniteville 230 kv line and Southern s Vogtle-West McIntosh 230 kv line. This event can be alleviated by reducing generation at Urquhart. Jasper Tap-McIntosh 115 kv tie line loads to 106.8% of its 240 MVA rating during the N-2 contingency of Savannah River Services-Canadys 230 kv and SCPSA s Purrysburg- Southern s McIntosh 230 kv line. SCEG and Southern Company will continue to look at ways to assess this tie line constraint. Savannah River Services 230/115 kv 1 transformer loads to 106.2% of its 336 MVA rating during the N- 2 contingency of Savannah River Services 230/115 kv 2 transformer and Graniteville-Urquhart 230 kv line. This event can be alleviated with a local area operating guide. Savannah River Services-Vogtle 230 kv tie line loads to 108.6% of its 950 MVA rating during the N-2 contingency of Southern s Warthen-Hancock County 500 kv line and Southern s Vogtle-West McIntosh 20