1. 11 TAG Meeting December 9, 2009 NCEMC Office Raleigh, NC

2. 22 TAG Meeting Agenda 1.Administrative Items – Rich Wodyka 2.2009 – 2019 Collaborative Plan Study Results – Joey West 3.2010 Study Scope – James Manning 4.Regional Studies Update – Ed Ernst and Bob Pierce 5.2010 TAG Work Plan – Rich Wodyka 6.TAG Open Forum – Rich Wodyka

3. 333 Joey West Progress Energy 2009 – 2019 Collaborative Plan Study Results

4. 444  Base Reliability Results 2014 and 2019  Progress Collaborative Plan Project Delays  Hypothetical Resource Supply Options Transfer Scenarios Nuclear Generation Scenarios Outline of Results

5. 555  Two new projects identified: Brunswick 1 - Castle Hayne 230kV Line, Construct New Cape Fear River Crossing (Progress) Reconductor Pisgah Tie-Shiloh Switching Station 230 kV lines (Duke)  Two Duke projects back in Plan: Reconductor Central Tie-Shady Grove Tap 230 kV lines Reconductor Peach Valley Tie- Riverview Switching Station 230 kV lines 2014S and 2019S Base Reliability Results

6. 666 Progress Load Forecast Related Collaborative Plan Project Delays Project 2009 Plan In-Service Date 2008 Plan In-Service Date Clinton-Lee 230 kV Line12/1/2011 (1.5 yrs)6/1/2010 Harris Plant – RTP 230 kV Line6/1/2014 (3 yrs)6/1/2011 Greenville-Kinston Dupont 230 kV Line6/1/2017 (6 yrs)6/1/2011 Wake 500 kV Sub, Add 3rd 500/230 kV Transformer 6/1/2018 (5 yrs)6/1/2013 Durham-RTP 230 kV Line, Reconductor6/1/2019 (5 yrs)6/1/2014 Cape Fear-West End 230 kV West Line6/1/2019 (3 yrs)6/1/2016 Rockingham-Lilesville 230 kV Line, Add 3rd Line 06/1/2019 (8 yrs)6/1/2011

7. 777  List of Units Included in Base Case Cliffside Coal – 825 MW Buck Combined Cycle – 620 MW Dan River Combined Cycle – 620 MW Richmond County Combined Cycle – 660 MW Wayne County CT – 160 MW Planned New Generation Units

8. 888 Resource Supply Options 2019 Hypothetical Transfer Scenarios Resource FromSinkTest Level (MW)Estimated Cost ($M) NORTH – PJM (AEP)Duke6000 SOUTH - SOCODuke6000 SOUTH – SCEGDuke600129 SOUTH – SCPSADuke6000 EAST – ProgressDuke6000 WEST - TVADuke6000 NORTH – PJM (AEP)Progress (CPLE)6000 NORTH – PJM (DVP)Progress (CPLE)6000 SOUTH – SCEGProgress (CPLE)6000 SOUTH – SCPSAProgress (CPLE)6000 WEST - DukeProgress (CPLE)6000 NORTH – PJM (AEP/AEP)Duke / Progress (CPLE)600 / 6000/0 NORTH – PJM (AEP/DVP)Duke / Progress (CPLE)600 / 6000/0 EAST - ProgressPJM (Dominion)6000

9. 999 Resource Supply Options 2019 Hypothetical Transfer Scenarios Results  Except 600 MW South Carolina Electric & Gas (SCEG) to Duke Transfer Scenario Upgrade Parr-Newport Tie (Parr) 230 kV Line: $89 M Upgrade Bush River Tie-Clinton Tie (Clinton) 100 kV Line: $40 M  All transfer resource supply options can be accommodated without additional projects.

10. 10 Resource Supply Options 2019 Nuclear Generation Scenarios CompanyLocation (County)MW’S DukeCherokee, SC1160 ProgressWake, NC1125

11. 11  Progress can accommodate an 1125 MW unit at Harris Nuclear Station without additional transmission upgrades  Duke can accommodate an 1160 MW unit at Lee Nuclear Station with one additional transmission upgrade Bundle Lee Nuclear Station-Pacolet Tie (Roddey West) 230 kV Line: $12 M Resource Supply Options 2019 Nuclear Generation Scenarios Results

12. 12 Comparison to Previous Collaborative Transmission Plan 2008 Plan2009 Draft Plan Number of projects with an estimated cost of $10 million or more each 1618 Total estimated cost of Plan$520 M$595 M

13. 13 Import Scenarios Preliminary Major Projects in 2009 Plan Reliability ProjectTOPlanned I/S Date Rockingham-West End 230 kV lineProgressIn-Service Richmond 500 kV sub, reactorProgressIn-Service Asheville-Enka 230 kV line, Convert 115 kV line; and Asheville-Enka 115 kV, Build new line Progress December ’10 December ’12 Rockingham-West End 230 kV East lineProgressJune ’11 Pleasant Garden-Asheboro 230 kV line, replace Asheboro 230 kV xfmrs Progress & Duke June ’11 Ft Bragg Woodruff Street-Richmond 230 kV Line ProgressJune ‘11 Clinton-Lee 230 kV lineProgressDec’11

14. 14 Import Scenarios Preliminary Major Projects in 2009 Plan (Continued) Reliability ProjectTOPlanned I/S Date Brunswick 1 - Castle Hayne 230kV Line, Construct New Cape Fear River Crossing ProgressJune ‘12 Jacksonville Static VAR CompensatorProgressJune ’12 Folkstone 230/115kV SubstationProgressJune ’13 Harris-RTP 230 kV lineProgressJune ’14 Greenville-Kinston Dupont 230 kV lineProgressJune ’17 Add 3 rd Wake 500/230 kV xfmrProgressJune ’18 Durham-RTP 230kV Line, ReconductorProgressJune ‘ 19 Cape Fear-West End 230 kV West line, Install reactor ProgressJune ’19 Rockingham-Lilesville 230 kV lineProgressJune ’19

15. 15 Import Scenarios Preliminary Major Projects in 2009 Plan (Continued) Reliability ProjectTOPlanned I/S Date Elon 100 kV Lines (Sadler Tie-Glen Raven Main #1 & #2, Reconductor DukeJune ‘11 Caesar 230 kV Lines (Pisgah Tie-Shiloh Switching Station #1 & #2), Reconductor DukeJune ‘13 London Creek 230 kV Lines (Peach Valley Tie-Riverview Sw. Station #1 & #2), Reconductor DukeJune ‘15 Fisher 230 kV Lines (Central-Shady Grove Tap #1 & #2), Reconductor DukeJune ‘17

16. 16

17. 17 2010 NCTPC Study Scope James Manning North Carolina EMC

18. 18 1.Assumptions Selected 2.Study Criteria Established 3.Study Methodologies Selected 4.Models and Cases Developed 5.Technical Analysis Performed 6.Problems Identified and Solutions Developed 7.Collaborative Plan Projects Selected 8.Study Report Prepared Study Process Steps

19. 19  Study years -Short term (5 yr) and long term (10 yr) base reliability analysis -Alternate model scenarios  Thermal power flow analysis - Duke & Progress contingencies - Duke & Progress monitored elements Internal lines Tie lines Collaborative Study Assumptions

20. 20  LSEs provide: –Load forecasts and resource supply assumptions –Dispatch order for their resources  Area interchange coordinated between Participants and neighboring systems Study Inputs

21. 21  TAG request to be distributed in early February, 2010  Requests can now include in, out and through transmission service Enhanced Transmission Access Requests

22. 22  Base reliability case analysis for 2015 summer and winter, and 2020 summer  An “All Firm Transmission” Case(s) will be developed which will include all confirmed long term firm transmission reservations with roll-over rights applicable to the study year(s).  Duke and Progress will each create their respective generation down cases from the common Base Case and share the relevant cases with each other.  Additional cases will be developed for different scenarios under a “climate change” legislation scenario 2010 Study

23. 23 Proposed coal sensitivity scenario for 2015:  Retire 100% of existing unscrubbed coal generation plants (approximately 1,500MW in the PEC control area, 2,000MW in the Duke control area) by 2015, replace with new generation and/or imports 2010 Study

24. 24  Proposed wind sensitivity scenarios for 2015: 1.Coastal NC wind sensitivity with wind injections in the following locations, based on information obtained from the UNC report: –2015 case, on peak: –Wilmington (30% capacity factor): 125 MW –Morehead City (40% capacity factor): 675 MW –Bayboro (35% capacity factor): 425 MW 2.2015 case, off-peak (the final MW output studied at these locations will depend on a further assessment of loads during the off-peak case to verify operational limits and how much excess energy could be sold or exported): –Wilmington (90% capacity factor): 375 MW –Morehead City (90% capacity factor): 1,500 MW –Bayboro (90% capacity factor): 1,125 MW 2010 Study

25. 25

26. 26 Update on Regional Studies

27. 27 Eastern Interconnection Planning Collaborative (EIPC) Ed Ernst Duke Energy Carolinas

28. 28 What is the EIPC?  Eastern Interconnection Planning Collaborative an open approach to addressing transmission analyses with an interconnection scale  Began through discussions between regional Planning Authorities  Backdrop Broad energy policy discussions on future renewable resources and on transmission infrastructure Historical development and coordination of transmission plans on a regional and super-regional basis

29. 29 What are the Objectives of the EIPC? 1.Roll-up and analysis of approved regional plans 2.Development of possible interregional expansion scenarios to be studied 3.Development of interregional transmission expansion options

30. 30 The Collaborative is a combination of:  Regional Planning Authorities participating in a joint agreement to form an Analysis Team to perform technical studies  Federal, State and Provincial representatives  Self-formed stakeholder groups (e.g. Regional TO groups, IPPs, etc.)  Individual stakeholder participants

31. 31 Alcoa Power Generating American Transmission Co. Duke Energy Carolinas Entergy * E.ON (Louisville/Kentucky Util.) Florida Power & Light Georgia Transmission Corp. IESO (Ontario, Canada) International Transmission Co. ISO-New England * JEA (Jacksonville, Florida) MAPPCOR * Midwest ISO * Municipal Electric Authority of Georgia New York ISO * PJM Interconnection * PowerSouth Energy Coop. Progress Energy – Carolinas Progress Energy – Florida South Carolina Electric &Gas Santee Cooper Southern Company * Southwest Power Pool Tennessee Valley Authority * Who are the Planning Authorities?

32. 32 EIPC Structure Eastern Interconnection Planning Collaborative (EIPC) (Open Collaborative Process) EIPC Analysis Team Principal Investigators Planning Authorities Steering Committee Stakeholder Work Groups Executive Leadership Technical Leadership & Support Group Stake- holder Groups States ProvincesFederal Owners Operators Users …

33. 33  EIPC Analysis Team structure in place  24 Planning Authorities signed – approximately 95% of customers covered  DOE funding proposal submitted; awaiting DOE response  Stakeholder dialog - webinar on October 13 with a repeat on October 16 – over 400 participants  Continued stakeholder discussion through beginning of DOE study cycle  Website launched – www.eipconline.comwww.eipconline.com  EIPC analysis processes begin in early 2010 –DOE work begins (if awarded) EIPC Status

34. 34 Other Regional Study Activities Bob Pierce Duke Energy Carolinas

35. 35  SCRTP 2010 study  PJM interface meeting  SIRPP  SERC-RFC East  VACAR studies  SERC LTSG 2009 Study  TPL-001-1

36. 36  Two NCTPC related requests were submitted for study:  600 MW transfer from SCE&G to CPLE;  600 MW transfer from SCE&G to Duke;  No other requests were submitted SC Regional Transmission Planning Process

37. 37 NCTPC-PJM Seams Interface Meeting

38. 38 Trail Project - 2011 NCTPC-PJM

39. 39 Path Project - 2014 NCTPC-PJM

40. 40 OTHER DISCUSSIONS  Generation interconnection queue coordination and how to identify projects that may impact each party  Modeling of generation dispatch in PJM and NCTPC footprints and its impact on study results  Identified PJM contacts to be included when dealing directly with AEP and DVP  Future studies under consideration NCTPC-PJM

41. 41  NCTPC did not submit requests for study  5 studies were selected at the 10/27/09 meeting Southeast Inter-Regional Planning Process (SIRPP)

42. 42 Entergy to Georgia ITS – 2000 MW (2014, Step 2 Evaluation) Type of Transfer: Generation to Generation Source: Same as utilized in the Step 1 evaluation. Sink: Same as utilized in the Step 1 evaluation. SIRPP

43. 43 Entergy to Georgia ITS Step 2 Evaluation  Detailed evaluation of the requested transfer  Identify the final transmission enhancements to resolve the identified constraints  Provides detailed cost estimates and timelines associated with the identified transmission enhancements SIRPP

44. 44 MISO to TVA – 2000 MW (2015, Step 1 Evaluation) Type of Transfer: Load to Generation Source: Uniform load scale of the MISO area. Sink: Generation within TVA’s area. SIRPP

45. 45 Northern Kentucky to Georgia ITS – 1000 MW (2015, Step 1 Evaluation) Type of Transfer: Generation to Generation Source: Three existing substations in Kentucky. Sink: Generation within the Georgia ITS. SIRPP

46. 46 MISO/PJM West (SMART) to SIRPP - 3000 MW (2018, Step 1 Evaluation) Type of Transfer: TBD to Generation Source: Strategic Midwest Area Renewable Transmission study Sink: Generation within the SIRPP. Generation will be allocated to the Participating Transmission Owners by the ratio of their load to the total load of all of the Participating Transmission Owners. SIRPP

47. 47 SIRPP

48. 48 SPP to SIRPP – 3000 MW via HVDC (2018, Step 1 Evaluation) Type of Transfer: TBD to Generation via single or multiple HVDC transmission lines Source: TBD Sink: Generation within the SIRPP. Generation will be allocated to the Participating Transmission Owners by the ratio of their load to the total load of all of the Participating Transmission Owners. SIRPP

49. 49 SERC East-RFC Near-Term/Long-Term Working Group (SER NT/LT WG)

50. 50  Appraisal of the interregional transmission system performance during the 2014 summer period  Supports NERC reliability standard TPL-005-0 - Regional and Interregional Self-Assessment Reliability Reports  Transfers to/from PJM, the RFC portion of the Midwest ISO, and SERC East (Non-PJM-VACAR and CENTRAL)  The next NT/LT WG study will be performed in 2011 for the conditions expected during the 2021 summer period SERC East-RFC Near-Term/Long-Term Working Group (SER NT/LT WG)

51. 51 2014 Summer Long-Term Study SERC East import and export with PJM  Central (TVA) – 2500 MW Participation  VACAR – 2500 MW Participation CP&LE 762.5 MW Duke 1212.5 MW Santee Cooper 212 MW SCE&G 313 MW SERC East-RFC Near-Term/Long-Term Working Group (SER NT/LT WG)

52. 52 2014 Summer Long-Term Study SERC East import and export with MISO  VACAR – 5000 MW Participation CP&LE 1525 MW Duke 2425 MW Santee Cooper 425 MW SCE&G 625 MW SERC East-RFC Near-Term/Long-Term Working Group (SER NT/LT WG)

53. 53 Key Facilities Index Each of the facilities listed is key to the performance of the interregional transmission network. These facilities are most responsive to the actions listed as change conditions. SERC East-RFC Near-Term/Long-Term Working Group (SER NT/LT WG)

54. 54 Key FacilitiesOutagesGenerationTransfers McGuire-Riverbend 230 kV #2McGuire-Riverbend 230 kV #1McGuire 500 kV & 230 kV PJM to SERC East Allen 230 kV & 100 kV PJM to Non-PJM-VACAR Catawba 230 kVRFC-MISO to SERC East RFC-MISO to Non-PJM-VACAR Clover 500/230 kV #1 Transformer Wake-Carson 500 kVClover 500 kVSERC East to PJM Clover-Farmville 230 kV & Farmville 230/115 kV #1 Transformer Non-PJM-VACAR to PJM SERC East to RFC-MISO Non-PJM-VACAR to RFC-MISO Antioch 500/230 kV #2 Transformer Antioch 500/230 kV #1 TransformerMcGuire 500 kV & 230 kV PJM to Non-PJM-VACAR Belews Creek 230 kV MISO to Non-PJM- VACAR

55. 55  Appraisal of the VACAR company transmission systems’ performance for the conditions expected during the 2015 summer period  Done in support of the NERC TPL reliability standards  (N-1) and (N-2) contingency analyses performed across VACAR while monitoring all of VACAR for thermal and voltage impacts  Final report to be published Summer 2010 VACAR Powerflow Working Group

56. 56  Appraisal of the VACAR company transmission systems’ dynamic performance for the conditions expected during the 2014 summer period  Done in support of the NERC TPL reliability standards  Voltage stability analyses with emphasis on category C contingencies using dynamic load models  Final report to be published Summer 2011 (2 years to allow for development of dynamic load models) VACAR Stability Working Group

57. 57  Performed analysis of 2015 summer conditions  Evaluated interregional and inter-balancing area transfers  Evaluated base case for N-1 contingency thermal and voltage performance SERC LTSG 2009 Study

58. 58 Duke Significant Facilities Parkwood 500/230 kV transformersExportCPLE, DVP Riverview-Peach Valley 230 kV LinesExportSOCO, GTC, SCPSA McGuire-Riverbend 230 kV LinesImportCPLE, Ameren All limits to transfer were greater than 1100 MW

59. 59 PEC Significant Facilities Asheville 230/115 kVImportCPLE,DUKE, TVA All limits to transfer were greater than 700 MW

60. 60 NERC TPL-001-1 Standard Update Standards Involved TPL-001-0.1 (NERC A, No Contingency) TPL-002-0a (NERC B, Single Contingency) TPL-003-0 (NERC C, Multiple Contingency) TPL-004-0 (NERC D, Extreme Contingency) TPL-005-0 (RRO Regional and Interregional Studies) TPL-006-0.1 (RRO Data, Reports, as requested by NERC) Applicable Entities Involved Planning Authority (Planning Coordinator) Transmission Planner Regional Reliability Organization

61. 61 NERC TPL-001-1 Standard Update Project Scope Create a new standard that: 1. Has clear, enforceable requirements 2. Is not a Least Common Denominator standard 3. Addresses the issues raised in the SAR and issues raised by FERC and others

62. 62 NERC TPL-001-1 Standard Update Overview R1: Modeling Data R2: Assessments Near-term Steady-State Long-term Steady-State Short Circuit Near-term Stability Long-term Stability Qualified Past Studies Corrective Action Plans Corrective Action Plans Short Circuit Largest Load Drop N-1

63. 63 NERC TPL-001-1 Standard Update Overview R3: Steady-State Studies R4: Stability Studies R5: Voltage Criteria R6: Cascade Criteria R7: PC/TP Responsibilities R8: PC/TP Peer Reviews

64. 64 NERC TPL-001-1 Standard Update Planning Events P0: Normal System (N-0) P1: Single Contingency (N-1) P2: Single Contingency (N-1) [Lower probability, higher impact] P3: Generator + 1 (N-2) P4: Stuck Breaker (N-2+) P5: Protection System Failure (N-2+) P6: Overlapping contingencies (N-1-1) [Non-gens, Two P1 Events] P7: Common Structure (N-2+)

65. 65 NERC TPL-001-1 Standard Update Planning Events Simulate the removal of all elements that Protection Systems and other controls are expected to automatically disconnect for each event. Require Corrective Action Plans for inability to meet performance requirements

66. 66 NERC TPL-001-1 Standard Update Category (P0, P1, … P7) Initial system condition Event Fault Type (3-phase or Single Line to Ground) BES Level (EHV or HV) Interruption of Firm Transmission Service Allowed Non-Consequential Load Loss Allowed Planning Events, Table Components (Columns)

67. 67 NERC TPL-001-1 Standard Update Planning Events Consequential Load Loss: All Load that is no longer served by the Transmission System as a result of Transmission Facilities being removed from service by a Protection System operation designed to isolate the fault. Non-Consequential Load Loss: Non-Interruptible Load loss other than Consequential Load Loss and the response of voltage sensitive Load including Load that is disconnected from the System by end- user equipment.

68. 68 NERC TPL-001-1 Standard Update  Areas where “bar was raised” for EHV Single contingency (P1 and P2) Generator + 1 (P3) Stuck Breaker (P4) Protection System Failure (P5)

69. 69 NERC TPL-001-1 Standard Update  R1 (Modeling) and R7(Responsibilities) are effective 12 months after regulatory approval  All other requirements (R2 – R6 and R8) become effective 24 months after regulatory approval except for more stringent performance requirements  60 months before “raising the bar” performance becomes effective

70. 70 NERC TPL-001-1 Standard Update  Team is responding to Draft 4 Comments  Expect some adjustments to standard for clarity  Team plans to ballot Draft 5  Plan to ballot in early Q1 2010 30 day pre-ballot period 10 day ballot period Need to achieve quorum (75% of Registered Ballot Body) Approval requires 2/3 approval from ballot body

71. 71 Rich Wodyka Independent Consultant 2010 TAG Work Plan

72. 72 1 st Quarter 2 nd Quarter3 rd Quarter 4 th Quarter Enhanced Access Planning Process Coordinated Plan Development  Perform analysis, identify problems, and develop solutions  Review Reliability Study Results  Evaluate current reliability problems and transmission upgrade plans  Propose and select enhanced access scenarios and interface  Perform analysis, identify problems, and develop solutions  Review Enhanced Access Study Results Reliability Planning Process  OSC publishes DRAFT Plan  TAG review and comment  Combine Reliability and Enhanced Results 2010 Overview Schedule TAG Meetings

73. 73 January - February  Finalize 2010 Study Scope of Work -Receive final 2010 Reliability Study Scope for comment -Review and provide comments to the OSC on the final 2010 Reliability Study Scope including the Study Assumptions; Study Criteria; Study Methodology and Case Development -Receive request from OSC to provide input on proposed Enhanced Transmission Access scenarios and interfaces for study -Provide input to the OSC on proposed Enhanced Transmission Access scenarios and interfaces for study Proposed 2010 TAG Work Plan

74. 74 April - May TAG Meeting  Receive feedback from the OSC on what proposed Enhanced Transmission Access scenarios and interfaces will be included in the 2010 study  Receive a progress report on the 2010 Reliability Planning study activities and results

75. 75 June - July TAG Meeting  2010 TECHNICAL ANALYSIS, PROBLEM IDENTIFICATION and SOLUTION DEVELOPMENT –TAG will receive a progress report from the PWG on the 2010 study –TAG will be requested to provide input to the OSC and PWG on the technical analysis performed, the problems identified as well as proposing alternative solutions to the problems identified –Receive update status of the upgrades in the 2009 Collaborative Plan –TAG will be requested to provide input to the OSC and PWG on any proposed alternative solutions to the problems identified through the technical analysis

76. 76 August - September TAG Meeting  2010 STUDY UPDATE –Receive a progress report on the Reliability Planning and Enhanced Transmission Access Planning studies  2010 SELECTION OF SOLUTIONS –TAG will receive feedback from the OSC on any alternative solutions that were proposed by TAG members

77. 77 December 2010 STUDY REPORT –Receive and comment on final draft of the 2010 Collaborative Transmission Plan report TAG Meeting –Receive presentation on the draft report of 2010 Collaborative Transmission Plan –Provide feedback to the OSC on the 2010 NCTPC Process –Review and comment on the 2011 TAG Work Plan Schedule

78. 78

79. 79 TAG Open Forum Discussion