1. 11 TAG Meeting September 21, 2010 NCEMC Office Raleigh, NC

2. 22 TAG Meeting Agenda 1.Introductions and Agenda – Rich Wodyka 2.FERC NOPR on Transmission Planning and Cost Allocation - Dani Bennett 3.2010 Study Scope Update and Status – Rick Anderson 4.2010 Study Preliminary Results – Joey West –Base Reliability –Enhanced Transmission Access Scenarios –Climate Change Scenarios 5.Major Transmission Project Update – Joey West 6.Regional Studies Update – Bob Pierce 7.Report on EISPC Activities – Kim Jones 8.TAG Work Plan – Rich Wodyka 9.TAG Open Forum – Rich Wodyka

3. 33 FERC Notice of Proposed Rulemaking on Transmission Planning and Cost Allocation Dani Bennett Progress Energy

4. Purpose of the NOPR  FERC proposes to require the regions to develop transmission plans and cost allocation methods that consider the benefits of new transmission facilities, including reliability, economics, and complying with state or federal laws or regulations (e.g. public policy).  FERC also proposes to require each pair of neighboring regions to coordinate transmission planning and cost allocation. 4

5. Cost Allocation  Each region to propose its own cost allocation method  FERC would not require a one size fits all method for allocating costs of transmission facilities  Development of cost allocation proposals must start at the regional level  If region can’t decide on a cost allocation method, then FERC would decide based on the record 5

6. Cost Allocation Principles  Regions would develop cost allocation methods based on the following principles: –Costs allocated “roughly commensurate” with estimated benefits –No involuntary allocation of costs to those receiving no benefit –Benefit-to-cost thresholds must not be excessive –No allocation of costs to other regions except pursuant to agreements –Cost allocation methods and identification of beneficiaries must be transparent –Different allocation methods could apply to different types of transmission facilities 6

7. Benefits 7 Regions would be required to consider benefits including reliability, economics, and enabling compliance with existing laws or regulations that may drive transmission needs. The proposal would not prevent regions from considering other public policy objectives. If a state has a law establishing a renewable electricity standard, then a region must consider transmission needs driven by that law.

8. Who Gets to Build  Removal of federal rights of first refusal from FERC jurisdictional tariffs and agreements; but no preemption of states  Encourage competition and new entrants 8

9. Merchants  Merchant transmission developers may continue to negotiate cost recovery from specific customers  Must comply with all relevant reliability requirements 9

10. Coordination Between Regions  Evaluate benefits of transmission lines that begin in one region and end in a second region.  Identify method(s) for allocating the cost of lines that the regions decide are mutually beneficial. 10

11. Timeline  Comments are due on September 29, 2010  Regional compliance filings are due 6 months after final rule promulgated  Interregional transmission planning agreements and interregional cost allocation compliance filings are due 12 months after final rule promulgated 11

12. 12

13. 13 NCTPC 2010 Study Update and Status Rick Anderson Fayetteville PWC

14. 14  Assess Duke and Progress transmission systems' reliability and develop a single Collaborative Transmission Plan  Also assess Enhanced Access Study requests provided by Participants or TAG members Purpose of Study

15. 15 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 Steps and Status of the Study Process Completed

16. 16  Study Years for reliability analyses: – Near-term: 2015 Summer, 2015/2016 Winter – Longer-term: 2020 Summer  LSEs provided: – I nput for load forecasts and resource supply assumptions – Dispatch order for their resources  Interchange coordinated between Participants and neighboring systems Study Assumptions Selected

17. 17 Study Criteria Established  NERC Reliability Standards -Current standards for base study screening - Current SERC Requirements  Individual company criteria

18. 18 Study Methodologies Selected  Thermal Power Flow Analysis – primary methodology  Voltage, stability, short circuit, phase angle analysis - as needed  Each system (Duke and Progress) will be tested for impact of other system’s contingencies

19. 19  Latest available MMWG cases were selected and updated for study years  Adjustments were made based on additional coordination with neighboring transmission systems  Combined detailed model for Duke and Progress was prepared  Planned transmission additions from updated 2009 Plan were included in models Base Case Models Developed

20. 20  Last year – Hypothetical import/export scenarios – Hypothetical new base load generation  This year: Climate Change Legislation Scenarios – Retire and replace existing coal generation – Hypothetical NC off-shore wind Resource Supply Options Selected

21. 21  Retire 100% existing un-scrubbed coal by 2015, approximately – 1,500 MW for Progress – 2,000 MW for Duke  Replace with hypothetical new generation and/or imports Retire & Replace Coal Generation

22. 22  Approximately 3,000 MW total capacity  Injected at three locations on Progress system  MW allocation – 60% Duke, 40% Progress Hypothetical NC Off-Shore Wind Injection PointOn-peak MW (30-40% CF) Off-peak MW (90% CF) Wilmington125375 Morehead City6751,500 Bayboro4251,125 TOTAL1,2253,000

23. NC Off-Shore Wind- Strawman Proposal 23 FERC Order No: 630 The original slide contains Critical Energy Infrastructure Information and is not available to the Public

24. 24 Enhanced Access Requests RequestSOURCESINKMWService Dates 1Cleveland Co. siteCPLE10001/12 to 1/22 2Cleveland Co. siteDVP10001/12 to 1/22 3SOCODVP10001/12 to 1/22 4SOCOCPLE10001/12 to 1/22

25. 25 Technical Analysis  Conduct thermal screenings of the 2015 and 2020 base cases  Conduct thermal screenings of the 2015 Resource Supply Options Scenarios  Conduct thermal screenings of the 2015 Enhanced Access Requests

26. 26 Problems Identified and Solutions Developed  Identify limitations and develop potential alternative solutions for further testing and evaluation  Estimate project costs and schedule

27. 27 Collaborative Plan Projects Selected  Compare all alternatives and select preferred solutions Study Report Prepared  Prepare draft report and distribute to TAG for review and comment

28. 28

29. 29 2010 Study Preliminary Results Joey West Progress Energy

30. 30 2015 & 2020 Summer  No new issues identified in Eastern or Western Areas -Projects already in the Collaborative Plan to address network loadings 2015-16 Winter  No new Issues identified in Western Area Preliminary Base Case Results – Progress Energy

31. 31 Contingencies and Year Upgrade Needed:  Transformer replacement (loss of parallel bank) -Sadler 230/100kV transformer, 2019 (presently scheduled for 2016)  Upgrades needed for loss of parallel line: -London Creek 230kV line, 2020  Operating guides needed for loss of parallel line: -Norman 230kV line, 2018 Preliminary Base Case Results - Duke

32. 32 Projects now outside of planning window:  Fisher 230 kV line (for loss of parallel line) -Pushed back from 2017 Preliminary Base Case Results - Duke

33. 33 Enhanced Transmission Access Scenarios RequestSOURCESINKMWService Dates 1Cleveland Co. siteCPLE10001/12 to 1/22 2Cleveland Co. siteDVP10001/12 to 1/22 3SOCODVP10001/12 to 1/22 4SOCOCPLE10001/12 to 1/22

34. 34 Enhanced Transmission Access Scenarios Request 1- Cleveland County- CPLE 1000 MW  Progress -Construct Lilesville-Rockingham 230 kV 3 rd Line (14 Miles) -Accelerate Laurinburg 230/115kV Bank Replacement (2-3 yrs) scheduled for 2017 -Accelerate Falls 2 nd - 230/115kV Bank Installation (1-2 yrs) scheduled for 2016 -Potentially Accelerate Durham-RTP 230 kV Reconductor scheduled for 2020

35. 35 Enhanced Transmission Access Scenarios Request 1- Cleveland County- CPLE 1000 MW  Duke -Parkwood 500/230 kV transformer (for loss of parallel bank) Operating guide needed by 2020

36. 36 Enhanced Transmission Access Scenarios Request 2- Cleveland County- DVP 1000 MW  Progress -Accelerate Laurinburg 230/115kV Bank Replacement (2-3 yrs) scheduled for 2017 -Accelerate Falls 2 nd - 230/115kV Bank Installation (1-2 yrs) scheduled for 2016 -Construct Lilesville-Rockingham 230 kV 3 rd Line (14 Miles)  Duke -No previously unidentified issues

37. 37 Enhanced Transmission Access Scenarios Request 3- SOCO-DVP 1000 MW  Progress -Accelerate Laurinburg 230/115kV Bank Replacement (2-3 yrs) scheduled for 2017  Duke -No previously unidentified issues

38. 38 Enhanced Transmission Access Scenarios Request 4- SOCO-CPLE 1000 MW  Progress -Accelerate Laurinburg 230/115kV Bank Replacement (2-3 yrs) scheduled for 2017 -Accelerate Falls 2 nd - 230/115kV Bank Installation (1-2 yrs) scheduled for 2016 -Potentially Accelerate Durham-RTP 230 kV Reconductor scheduled for 2020 -Potentially construct Lilesville-Rockingham 230 kV 3 rd Line (14 Miles)

39. 39 Enhanced Transmission Access Scenarios Request 4- SOCO-CPLE 1000 MW  Duke -McGuire 500/230 kV transformer (for loss of Woodleaf - Pleasant Garden 500 kV line) Upgrade needed by 2020

40. 40 Climate Change Legislation Scenarios  Coal Generation Retirements  Hypothetical NC Off- Shore Wind Sensitivity

41. 41 Coal Generation Retirements Progress  Wayne County & Sutton Combined Cycles -Coal plant replacements were modeled -Scheduled for 2013  Cape Fear & Weatherspoon Coal Plants -Retirements built into models -Exact retirement dates TBD

42. 42 Duke Retirements  Buck Steam Station (256 MW)  Lee Steam Station (370 MW)  Riverbend Steam Station (266 MW) Coal Generation Retirements

43. 43 Duke - Preliminary No previously unidentified issues  London Creek 230 kV line -Pushed from 2020 to outside of planning window  Norman 230 kV line -No change  Sadler 230/100 kV transformer -No change Coal Generation Retirements

44. 44  Approximately 3,000 MW total capacity  Injected at three locations on Progress system  MW allocation – 60% Duke, 40% Progress NC Off- Shore Wind Sensitivity Scenario Injection PointOn-peak MW (30-40% CF) Off-peak MW (90% CF) Wilmington125375 Morehead City6751,500 Bayboro4251,125 TOTAL1,2253,000

45. NC Off-Shore Wind- Strawman Proposal 45 FERC Order No: 630 The original slide contains Critical Energy Infrastructure Information and is not available to the Public

46. 46 Hypothetical NC Off-Shore Wind Sensitivity Scenario  Original Strawman -NCTPC starting point in evaluating off-shore wind  Four Options were developed by PWG -Based on power flow results and analysis -Assessment of costs versus benefits  Solving transmission constraints for off-peak loads with wind capacity factor at 90% also solves on-peak transmission problems with lower wind capacity factors

47. 47 Hypothetical NC Off- Shore Wind: Option 1A Total Wind Output: 3000 MW Southport 375 MW Sutton Jacksonville Morehead 1500 MW Havelock New Bern Bayboro 1125 MW Wommack Wake Cumberland 230 KV 500 KV

48. 48 Hypothetical NC Off- Shore Wind: Option 1B Southport 375 MW Sutton J acksonville Morehead 1500 MW New Bern Bayboro 1125 MW Wommack Cumberland 230 KV 500 KV Total Wind Output: 3000 MW Wake

49. 49 Hypothetical NC Off- Shore Wind: Option 2 Southport 375 MW Sutton Jacksonville Morehead 1250 MW Havelock New Bern Bayboro 875 MW Wommack Wake Cumberland 230 KV 500 KV Total Wind Output: 2500 MW

50. 50 Hypothetical NC Off- Shore Wind: Option 3 Southport 375 MW Sutton Jacksonville Morehead 1000 MW Havelock New Bern Bayboro 625 MW Greenville West 230 KV 500 KV Total Wind Output: 2000 MW

51. 51 Duke No previously unidentified issues  Norman 230 kV line -Accelerated from 2018 to 2015  Sadler 230/100 kV transformer -Pushed outside of planning window  London Creek 230 kV line -Pushed outside of planning window Preliminary NC Off- Shore Wind Results

52. 52 Hypothetical NC Off- Shore Wind Options Summary Option 1A: 3,000 MW - Estimated Cost $1.195 B -230 kV wind connection to network Option 1B: 3,000 MW - Estimated Cost $1.310 B -500 kV wind connection to network Option 2: 2,500 MW - Estimated Cost $1.155 B -500 MW reduction of output doesn’t create a breakpoint -Rebuilding 2-230 kV Lines is only difference from 1A Option 3: 2,000 MW - Estimated Cost $0.525 B -Significant breakpoint in transmission upgrades -Removed 500 kV Infrastructure -Construct Greenville West -New Bern 230kV Line

53. 53  TAG is requested to provide input to the OSC and PWG on the technical analysis performed and the problems identified, as well as to propose alternative solutions to those problems  Provide input by October 6, 2010 to ITP (rawodyka@aol.com)rawodyka@aol.com TAG Input Request

54. 54

55. 55 Major Transmission Project Update Joey West Progress Energy

56. 56  Contains 1 Progress Energy project in-service date change that was driven by Wayne County Combined Cycle Plant  Contains 3 Progress Energy projects that are to be removed from the Collaborative Plan 2010 Mid-Year Update to the 2009 Collaborative Transmission Plans

57. 57 Import Scenarios Major Projects in 2009 Plan Reliability ProjectTOPlanned I/S Date Richmond 500 kV sub, reactorProgressIn-service Asheville-Enka 230 kV line, Convert 115 kV line; & Asheville-Enka 115 kV, Build new line Progress December ’10 December ’12 Rockingham-West End 230 kV East lineProgressJune ’11 Ft Bragg Woodruff Street-Richmond 230 kV Line ProgressJune ‘11 Pleasant Garden-Asheboro 230 kV line, replace Asheboro 230 kV xfmrs Progress & Duke June ’11 Clinton-Lee 230 kV lineProgressDecember ’11 (accelerated from ’13) Brunswick 1 - Castle Hayne 230kV Line, Construct New Cape Fear River Crossing ProgressJune ’12

58. 58 Import Scenarios Major Projects in 2009 Plan (Continued) Reliability ProjectTOPlanned I/S Date Jacksonville Static VAR CompensatorProgressJune ‘13 Folkstone 230/115kV SubstationProgressJune ’13 Harris-RTP 230 kV lineProgressJune ’14 Greenville-Kinston Dupont 230 kV lineProgressJune ’17 Durham-RTP 230kV Line, ReconductorProgressJune ’19 Add 3 rd Wake 500/230 kV xfmrProgressRemoved from Plan Cape Fear-West End 230 kV West line, Install reactor ProgressRemoved from Plan Rockingham-Lilesville 230 kV lineProgressRemoved from Plan

59. 59 Import Scenarios Major Projects in 2009 Plan (Continued) Reliability ProjectTOPlanned I/S Date Sadler Tie-Glen Raven Main Circuit 1 & 2 (Elon 100 kV Lines), Reconductor DukeJune ‘11 Reconductor Caesar 230 kV Lines (Pisgah Tie-Shiloh Switching Station #1 & #2) DukeJune ‘13 Reconductor London Creek 230 kV Lines (Peach Valley Tie-Riverview Switching Station #1 & #2) Duke2020 Reconductor Fisher 230 kV Lines (Central Tie-Shady Grove Tap #1 & #2) DukeOutside Planning Window

60. 60

61. 61 Bob Pierce Duke Energy Regional Studies Reports

62. 62 Southeast Inter-Regional Planning Process (SIRPP) Update

63. 63  NCTPC did not submit requests for study  5 requests selected at the October 2009 meeting  2009 series MMWG 2015 and 2020 Summer Peak cases updated to reflect 2014, 2015, and 2018 Summer Peaks SIRPP

64. 64 2009-2010 SIRPP Study Requests  Entergy to Georgia ITS – 2000 MW (2014, Step 2)  MISO to TVA – 2000 MW (2015, Step 1)  Kentucky to Georgia ITS – 1000 MW (2015, Step 1)  MISO & PJM West (SMART) to SIRPP – 3000 MW (2018, Step 1)  SPP to SIRPP – 3000 MW via HVDC (2018, Step 1) SIRPP

65. 65 2009-2010 SIRPP Study Results  Entergy to Georgia ITS – 2000 MW (2014, Step 2) – One (1) 500 kV Line (Southern) – One (1) 500 / 230 kV Transformer (Southern) – Ten (10) 230 kV Lines (Southern) – Six (6) 161 kV Lines (Entergy, TVA) – TOTAL COST: $330,246,000  MISO to TVA – 2000 MW (2015, Step 1) – One (1) 230 kV Line (Southern) – One (1) 161 kV Line (TVA) – TOTAL COST: $53,720,000 SIRPP

66. 66 2009-2010 SIRPP Study Results  Kentucky to Georgia ITS – 1000 MW (2015, Step 1) – One (1) 230 kV Line (Southern) – Two (2) 161 kV Line (E. ON U.S., Southern) – TOTAL COST: $18,700,000  MISO & PJM West (SMART) to SIRPP – 3000 MW (2018, Step 1) – One (1) 500 / 230 kV Transformer (Southern) – Three (3) 500 / 161 kV Transformer (TVA) – Three (3) 230 kV Lines (Southern) – Six (6) 161 kV Lines (TVA) – TOTAL COST: $161,465,000 SIRPP

67. 67 2009-2010 SIRPP Study Results  SPP to SIRPP – 3000 MW via HVDC to Bowen (SOCO) and Montgomery (TVA) (2018, Step 1) – One (1) 500 / 230 kV Transformer (Southern) – One (1) 500 / 161 kV Transformer (TVA) – One (1) 345 / 138 kV Transformer (Entergy) – One (1) 230 kV Lines (Southern) – Sixteen (16) 161 kV Lines (TVA) – TOTAL COST: $289,904,000  Duke Energy Carolinas and Progress Energy Carolinas did not identify any constraints. SIRPP

68. 68 http://www.southeastirpp.com/

69. 69 Southern Cross Project

70. NC Off-Shore Wind- Strawman Proposal 70 FERC Order No: 630 The original slide contains Critical Energy Infrastructure Information and is not available to the Public

71. NC Off-Shore Wind- Strawman Proposal 71 FERC Order No: 630 The original slide contains Critical Energy Infrastructure Information and is not available to the Public

72. 72

73. 73 SERC Long-term Study Group (LTSG)

74. 74  Completed 2010 Series LTSG models  Building 2010 Series ERAG MMWG models SERC LTSG

75. 75 2010 LTSG Study  Evaluate inter-regional and inter-BA transfer capability and base case reliability N-1 reliability in 2016S  Linears transfers run and evaluated  Report being drafted SERC LTSG

76. 76 VACAR 2015S Study

77. 77 VACAR 2015S Study SCOPE  Evaluation of N-1 contingencies for 500 kV, 230 kV, tie lines and any other lines with a significant impact.  Evaluation of N-2 contingencies based combinations of all N-1 contingencies  Evaluation of N-2 failed contingency solutions (solution failed to converge or reached iteration limit)

78. 78 VACAR 2015S Study SIGNIFICANT FACILITY RESULTS  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

79. 79 VACAR 2015S Study DEC & PEC N-2 SIGNIFICANT FACILITY RESULTS  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)  Horseshoe-Pisgah 100 kV Lines (Duke)  Great Falls-Wateree 100 kV Lines (Duke)  Wateree 115/100 kV Transformer (CPLE/Duke)  Havelock 230/115 kV transformers #1/2 (CPLE)  Asheboro East-Biscoe 115 kV Line (CPLE)  Richmond-Rockingham 230 kV East Line (CPLE)

80. 80 VACAR 2015S Study  The assessment of failed contingency solutions found that the majority of the 84 failed solutions involved toggling capacitors or the loss of significant generation due to the tested contingency.  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 was being evaluated to avoid impacting the local impacts of the contingency.

81. 81 Carolinas Transmission Planning Coordination Arrangement

82. 82  Establish a forum for coordinating certain planning activities among the specific parties  DEC, PEC, SCE&G and SCPSA  Studying 2014 and 2021 summer conditions  Expect report in early October Carolinas Transmission Planning Coordination Arrangement

83. NERC TPL-001-2 Standard Update 83

84. NERC TPL-001-2 Standard Update  Response to ballot and comments on the proposed footnote ‘b’ were posted  NERC held a technical conference 8/10/10 to discuss footnote “b” issue 84

85. NERC TPL-001-2 Standard Update  Response to informal comments on the latest draft have been prepared.  Footnote ‘b’ related to TPL-001-1 loss of non-consequential load is open for informal comment through October 8 th.  Standard is expected to be ready for re- ballot in February timeframe with new footnote ‘b’ merged in. 85

86. NERC TPL-001-2 Standard Update b) An objective of the planning process is to avoid interruption of Demand. Interruption of Demand is discouraged and measures to mitigate such interruption should be pursued within the planning process. However, Demand may need to be interrupted in limited circumstances to address BES performance requirements. When interruption of Demand is utilized within the planning process, such interruption is limited to:  Demand that is directly served by the elements that are removed from service as a result of the Contingency  Interruptible Demand or Demand-Side Management 86

87. NERC TPL-001-2 Standard Update  Demand that does not adversely impact overall BES reliability where the circumstances describing the use of such Demand interruption are documented, including alternatives evaluated; and where the application is subject to review and acceptance in an open and transparent stakeholder process. 87

88. 88 Eastern Interconnection Planning Collaborative (EIPC)

89. 89 EIPC background  Formed in 2009  Consists of 26 Planning Authorities in U.S. & Canada  Over 600 GW of connected customer demand with approximately 95% of the Eastern Interconnection customers covered  EIPC objectives 1.Integration (“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

90. EIPC Structure 90 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 …

91. 91 EIPC Focus between now and end of 2012  Perform analysis under the Department of Energy Topic A award for Transmission Planning Analysis for the Eastern Interconnection  Phase I - between now and October, 2011 –Integrate existing regional plans - Perform roll-up of existing 2020 transmission plans –Production cost analysis of regional plans - Perform production costing analysis of existing 2020 transmission plans –Develop macroeconomic scenarios on possible futures and perform analysis on these futures –Agree on expansion scenarios for Interregional Transmission Options development in Phase II  Phase II - October, 2011 to Late 2012 –Develop transmission expansion options, along with associated costs, for agreed on expansion scenarios

92. 92 EIPC Current Activities Planning Authorities  Have developed transmission model development & study practices  Have created roll-up of existing regional transmission plans detailing modeling assumptions for the 2020 summer model for Stakeholders – responding to Stakeholder follow-up questions  Performing analysis of bulk energy transfers between markets/regions on the 2020 summer model by late September  Working with CRA on economic analysis methods

93. EIPC Current Activities  Stakeholder Steering Committee (SSC) has been organized and have several working groups functioning: –Governance –Economic Modeling –Planning Roll-up –Scenario Planning  Next SSC Meeting October 12-14 in Arlington, VA

94. 94

95. Report on Eastern Interconnection States Planning Council (EISPC) 95 Kim Jones NC Utility Commission

96. Eastern Interconnection States Planning Council (EISPC)  41 jurisdictions in the eastern interconnection  Grant funding three-year planning effort  Each state has two representatives  To give policy guidance to transmission planning 96

97. North Carolina is represented by:  Ed Finley, Chairman of NC Utilities Commission  Jennifer Bumgarner, Assistant Secretary, Energy Division, Department of Commerce  Staff Support: –Bob Leker, Renewables Program Manager in State Energy Office –Kim Jones, Analyst, NCUC 97

98. August 26-27, 2010 Meeting  Relatively light involvement of southeastern states. Absent: –Florida –Georgia –Louisiana –Virginia Abstained: Tennessee 98

99. Stakeholder Steering Committee  Will determine 8 macro- economic futures  3 of which will proceed to transmission build out study 99

100. Futures that NC wants studied:  Business as usual  Carbon-constrained future  National renewable energy portfolio standard  Increased use of wind power from –Midwest –Local sources –Offshore  Nuclear renaissance 100

101. Other futures  Least cost energy  Constrained transmission  Expanded hydro  Expanded energy storage  Expanded coal IGCC  Repowering coal plants with gas  Carbon capture and sequestration  Increased energy efficiency / demand response 101

102. Other futures (continued)  Increased use of electric vehicles  More distributed generation  Development of a smart grid  Various growth levels  No build of anything  Increased imports from Canada  Increased gas production from shale 102

103. Reference case 2009 transmission plans “stitched together” What assumptions did NC planning authorities make in last year’s plan? –Growth? –Location of future generation resources? –Effectiveness of energy efficiency and demand-side management programs? –Use of intermittent resources / distributed resources / renewables? 103

104. Next steps / work in progress 1.Energy zones – develop process for defining them Will take about a year Bob Leker to serve on work group bleker@nccommerce.com 2.Defining futures Kim Jones serving on work group kjones@ncuc.net 3.Governance Committee – NC has seat 104

105. Next steps (continued) 4.Select and define 7 white paper / consultant studies State-by-state potential for –Renewable energy –Demand-side resources –Energy storage –Distributed generation –Existing customer-sited generation –Rapid start fossil generation –Existing portfolio standards 105

106. More potential studies  Market structures  Power purchase agreements for renewables, including financial implications  Existing state, regional and federal policies relative to transmission  Incentives / disincentives for development  Plug-in electric vehicles  Generation close to load; far from load 106

107. More potential studies  Economic uncertainties / risk to current plans and cost recovery of emerging technology  Smart grid – potential and impacts  Off ramps for existing state portfolio standards  How is / should “renewable” be defined?  Assess potential location of new nuclear plants and potential upgrades to existing nuclear plants  Assess other initiatives to reduce carbon emissions  Assess gas and other fuel prices 107

108. More to do:  Learn the CRA (Charles River Associates) models  Next meeting: Sept 30 – October 1 108

109. 109

110. 110 Rich Wodyka ITP 2010 TAG Work Plan Review

111. 111 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

112. 112 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 2010 TAG Work Plan

113. 113 April - May TAG Meeting – May 18 th 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

114. 114 June - July  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

115. 115 August - September TAG Meeting – September 21st  2010 STUDY UPDATE Receive a progress report on the Reliability Planning and Enhanced Transmission Access Planning studies –Provide input by October 6, 2010 to ITP (rawodyka@aol.com)rawodyka@aol.com  2010 SELECTION OF SOLUTIONS –TAG will receive feedback from the OSC on any alternative solutions that were proposed by TAG members

116. 116 December 2010 STUDY REPORT –Receive and comment on final draft of the 2010 Collaborative Transmission Plan report TAG Meeting – December 16 th –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

117. 117

118. 118 TAG Open Forum Discussion