1. 11 TAG Meeting May 18, 2010 ElectriCities Office Raleigh, NC

2. 22 TAG Meeting Agenda 1.Introductions and Agenda – Rich Wodyka 2.2010 Study Activities Report and 2010 Study Scope Update – Denise Roeder 3.Regional Studies Update – Bob Pierce 4.NERC TPL-001-1 Standard Update – Bob Pierce 5.NERC / FERC activities related to transmission planning – Bob Pierce 6.2010 TAG Work Plan – Rich Wodyka 7.TAG Open Forum – Rich Wodyka

3. 33 NCTPC 2010 Study Activities Denise Roeder ElectriCities

4. 44  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

5. 55 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

6. 66  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

7. 77 Study Criteria Established  NERC Reliability Standards -Current standards for base study screening - Current SERC Requirements  Individual company criteria

8. 88 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

9. 99  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

10. 10  Last year – Hypothetical import/export scenarios – Hypothetical new base load generation  This year – Retire & replace existing coal generation – Off-shore wind Resource Supply Options Selected

11. 11  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

12. 12  Approximately 3,300 MW total capacity  Injected at three locations on Progress system  MW allocation – 60% Duke, 40% Progress Off-Shore Wind Injection PointOn-peak MW (30-40% CF) Off-peak MW (90% CF) Wilmington125375 Morehead City6751,500 Bayboro4251,125 TOTAL1,2253,000

13. This slide is intentionality left blank Off-Shore Wind- Strawman Proposal

14. 14 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

15. 15 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

16. 16 Problems Identified and Solutions Developed  Identify limitations and develop potential alternative solutions for further testing and evaluation  Estimate project costs and schedule

17. 17 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

18. 18

19. 19 Bob Pierce – Duke Energy Regional Studies Reports

20. 20 Eastern Wind Integration and Transmission StudyEWITS

21. 21 Objectives of EWITS  Evaluate the power system impacts and transmission associated with increasing wind capacity to 20% and 30% of retail electric energy sales in the study area by 2024 ;  Evaluate operations impacts due to variability and uncertainty of wind;  Build upon prior wind integration studies and related technical work;  Coordinate with JCSP and current regional power system study work;  Produce meaningful, broadly supported results through a technically rigorous, inclusive study process.

22. 22 EWITS  Reference Scenario - approximates the current state of wind development. Scenario totaled about 6% of the total 2024 projected load requirements for the U.S. portion of the Eastern Interconnection.  Scenario 1, 20% penetration – High Capacity Factor, Onshore: Utilizes high-quality wind resources in the Great Plains, with other development in the eastern United States where good wind resources exist.  Scenario 2, 20% penetration – Hybrid with Offshore: Some wind generation in the Great Plains is moved east. Some East Coast offshore development is included.

23. 23 EWITS  Scenario 3, 20% penetration – Local with Aggressive Offshore: More wind generation is moved east toward load centers, necessitating broader use of offshore resources. The offshore wind assumptions represent an uppermost limit of what could be developed by 2024 under an aggressive technology-push scenario.  Scenario 4, 30% penetration – Aggressive On- and Offshore: Meeting the 30% energy penetration level uses a substantial amount of the higher quality wind resource in the NREL database. A large amount of offshore generation is needed to reach the target energy level.  Supplying 20% of the U.S. portion of the Eastern Interconnection would call for approximately 225,000 megawatts (MW) of wind generation capacity, which is about a tenfold increase above today’s levels. To reach 30% energy from wind, the installed capacity would have to rise to 330,000 MW.

24. 24 EWITS

25. 25  High penetrations of wind generation—20% to 30% of the electrical energy requirements of the Eastern Interconnection—are technically feasible with significant expansion of the transmission infrastructure.  New transmission will be required for all the future wind scenarios in the Eastern Interconnection, including the Reference Case. Planning for this transmission, then, is imperative because it takes longer to build new transmission capacity than it does to build new wind plants.  Without transmission enhancements, substantial curtailment (shutting down) of wind generation would be required for all the 20% scenarios. EWITS

26. 26

27. 27  Interconnection-wide costs for integrating large amounts of wind generation are manageable with large regional operating pools and significant market, tariff, and operational changes.  Transmission helps reduce the impacts of the variability of the wind, which reduces wind integration costs, increases reliability of the electrical grid, and helps make more efficient use of the available generation resources. Although costs for aggressive expansions of the existing grid are significant, they make up a relatively small portion of the total annualized costs in any of the scenarios studied. EWITS

28. 28 EWITS

29. 29  EWITS Website - http://wind.nrel.gov/public/EWITS/http://wind.nrel.gov/public/EWITS/  Contact Dave Corbus at David_Corbus@nrel.gov (303-384-6966)David_Corbus@nrel.gov EWITS

30. 30 Strategic Midwest Area Renewable Transmission Study SMART

31. 31  Comprehensive study of the transmission in the Upper Midwest to support renewable energy development and transportation of that energy throughout the study area  Study focus is 20 years into the future (2019, 2024 & 2029 models)  Includes potential effects of future economic, regulatory and state RPS issues  Transcends traditional utility and regional boundaries SMART

32. 32  Phase 1 evaluation of transmission system  Natural applications of HVDC were considered and the following were applied:  Underwater cables across waterways  Long distance transmission  Two alternatives remain under consideration  Alternative 2 - Combination 345kV and 765kV  Alternative 5 - 765kV only SMART

33. 33 SMART

34. 34 SMART

35. 35  The reliability impact of the 2 alternatives were evaluated under different sensitivities  On/Off peak  High/Low wind  Imports from SPP  High/Low load  High Gas  Low Carbon  The cost of the 2 alternatives are both in the $25 B range SMART

36. 36  Phase 2 will further examine the two transmission alternatives using production cost to focus on the overall economic impact  Phase 2 is expected to be complete and a final report issued in late June SMART

37. 37 SMART

38. 38  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  Studies are under evaluation by study team members, each using their company’s respective planning criteria  Analysis to be completed and Preliminary Report compiled by June 1, 2010  Meeting/Conference Call with stakeholders to discuss preliminary results tentatively planned for June 15, 2010 Southeast Inter-Regional Planning Process (SIRPP) Update

39. 39 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

40. 40  2010 PJM RTEP  PJM wind integration studies  Interconnection queue review  CIP-002 philosophy PJM Planning Coordination Agreement

41. 41 Approved PJM Backbone 500 kV and 765 kV Facilities Since 2006, the PJM Board has approved six new major 500 kV and 765 kV backbone upgrades, as shown on this map: 1.502 Junction – Loudoun 500 kV line, also known as the TrAIL Line (2006 RTEP) 2.Carson – Suffolk 500 kV line (2006 RTEP) 3.Susquehanna – Roseland 500 kV line (2007 RTEP) 4.Amos – Kemptown 765 kV line, also known as the PATH line (2007 RTEP) 5.Possum Point – Indian River 500 kV line, also known as the MAPP line (2007 RTEP) 6.Branchburg – Roseland – Hudson 500 kV line (2008 RTEP) 1.1. 2. 3. 4. 6. 1.1. 4. 5. Source: PJM 2009 RTEP Report, Feb 26, 2010

42. 42  Building 2010 Series models -Coordinated tie lines and interchange -Submitted 10 years of model data for each control area -Building light load case for 2016 and a 2021 winter case -Models to be complete in early June and submitted to the MMWG process  2010 LTSG Study Scope SERC LTSG (Long-term Study Group)

43. 43 Preliminary Results of Economic Study Requests Submitted by SCRTP Stakeholders  SCE&G to CPLE – 2015 summer – 500 MW*  SCE&G to Duke – 2015 summer – 500 MW*  SCE&G to CPLE – 2020 summer – 500 MW  SCE&G to Duke – 2020 summer – 500 MW  SCE&G to Southern – 2020 summer – 500 MW * submitted by NCTPC South Carolina Regional Transmission Planning (SCRTP) Meeting Highlights

44. 44 Study Methodology – Analysis Performed  Linear transfer analysis, which includes N-1 contingencies of SERC while monitoring SCE&G and Santee Cooper Transmission Systems.  A Thermal and Voltage analysis, which includes N-1, N-2, and selected bus outages with and without the simulated 500 MW transfer in effect. However, this analysis is not a complete testing of NERC TPL standards. SCRTP

45. 45 Preliminary Results - SCE&G to CPLE 500 MW and SCE&G to Duke 500 MW in 2015S *  Urquhart – Langley Tap 115 kV line overload  Estimated cost = $5.1M, 24 month lead time to rebuild * Each transfer done independently, not simultaneously SCRTP

46. 46 Preliminary Results - SCE&G to CPLE 500 MW in 2020S  Georgia Pacific Tap (SCE&G) – Bush River Red (Duke) 115 kV line overload  A Joint Study between SCE&G and Duke is needed to determine best solution, cost est. and schedule  Santee Cooper’s Pomaria – Winnsboro 69 kV line overload  Estimated cost is $3.6 M, 30 month lead time to rebuild SCRTP

47. 47 Preliminary Results - SCE&G to Duke 500 MW in 2020S  White Rock (SCE&G) - Bush River Yellow (Duke) 115 kV tie line overload  Georgia Pacific Tap (SCE&G) – Bush River Red (Duke) 115 kV line overload  A Joint Study between SCE&G and Duke is needed to determine best solution, cost estimate and schedule to address both overloads SCRTP

48. 48 Preliminary Results - SCE&G to Southern 500 MW in 2020S  White Rock (SCEG) - Bush River Yellow (Duke) 115 kV tie line overload  A Joint Study between SCE&G and Duke is needed to determine best solution, cost estimate and schedule SCRTP

49. 49 Lower Load Forecasts  Both SC companies experienced lower load forecasts for planning horizon  Resulted in future capacity changes for serving load  Resulted in several transmission projects being delayed anywhere from 6 months to several years to even being cancelled SCRTP

50. 50 SCE&G New Projected Capacity  2 Nuclear Units (1117 MW/ea)  V. C. Summer #2 - 2016  V. C. Summer #3 - 2019 SCRTP

51. 51 Santee Cooper Projected Capacity Update  Pee Dee 609 MW (Planned for Jan 2014) – CANCELED  Pee Dee – Lake City 230 kV Line (Planned for Jan 2011) – DELAYED but still needed in Long-range plan  V. C. Summer #2 and #3 - Shared Capacity with SCE&G SCRTP

52. 52 SCRTP V.C. Summer Unit #2 Related Projects Santee Cooper  VCS Sub #1- Winnsboro-Richburg-Flat Creek 230kV12/01/2015  Winnsboro 230/69kV Construct12/01/2015  Richburg 230/69kV Construct12/01/2015

53. 53 SCRTP V.C. Summer Unit #2 Related Projects SCE&G  Denny Terrace-Lyles 230kV Line Upgrade12/01/2015  Denny Terrace Add 3rd 336 Autotransformer12/01/2015  Lake Murray Add 3rd 336 Autotransformer12/01/2015  Lake Murray-McMeekin 115kV Line Upgrade12/01/2015  Lake Murray-Saluda 115kV Line Upgrade12/01/2015  Saluda-McMeekin 115kV Line Upgrade12/01/2015  VCS2-Lake Murray #2 230kV Line Construct12/01/2015  VCS2-Winnsboro-Killian 230kV Line Construct12/01/2015

54. 54 SCRTP V.C. Summer Unit #3 Related Projects Santee Cooper  VCS Sub2-Pomaria-Sandy Run-Orangeburg- 12/01/2018 St George-Varnville230kV  Sandy Run 230/115kV Construct12/01/2018  St George 230/115kV Construct12/01/2018

55. 55 SCRTP V.C. Summer Unit #3 Related Projects SCE&G  Saluda-Duke 115kV Tielines Upgrade12/01/2018  South Columbia 230/115kV Construct12/01/2018  South Lexington 230/115kV Construct 12/01/2018  St George 230kV Switching Station Construct12/01/2018  St George-Canadys 230kV Line Upgrade12/01/2018  St George-Summerville 230kV Line Upgrade12/01/2018  VCS Sub #2-St George 230kV Double Circuit Construct 12/01/2018

56. 56  Establish a forum for coordinating certain planning activities among the specific parties  DEC, PEC, SCE&G and SCPSA  Initial study scope being developed  Expect results in September timeframe Carolinas Transmission Planning Coordination Arrangement

57. 57 Eastern Interconnection Planning Collaborative (EIPC)

58. 58  Create an Eastern Interconnection Planning Collaborative (EIPC) process that includes: –Major transmission entities in the east with Planning Authority responsibility –Utilities, cooperatives, municipal systems, and public power authorities –Utilities in Canada (include Quebec) –States and Provinces –Administration (DOE, FERC, …) –A forum where stakeholders from all regional planning processes can effectively participate EIPC

59. 59 Publishes Annual Interconnection Analysis Regional/state compliant plans provided as input Study gaps relative to national, regional and state policy Regional Plans and Projects Annual interconnection analysis States Regional Policy recommendations State energy policies Rate Policies Eastern Interconnection Planning Collaborative Rolls-up regional plans Coordinates with Canada, Western Interconnect and Texas Receives stakeholder input and holds public meetings Performs studies of various transmission alternatives against national, regional and state energy/economic/environmental objectives Identifies gaps for further study DOE/FERC ISO / RTOs & Order 890 Entities Produce Regional Plan through regional stakeholder process FERC Provides policy direction, assumptions & criteria Review/direction Order adjustments Cost recovery States Policy recommendations State energy plans 59

60. 60  Working to finalize stakeholder steering committee structure and representation  PA’s are jointly developing model development/ study practices and working with CRA on economic analysis methods.  For educating stakeholders, coordinate development of a documented roll-up of existing regional transmission plans detailing modeling assumptions for the 2020S model.  Perform TPL standard type analysis of the 2020S model. EIPC Activities

61. 61

62. 62 NERC TPL-001-1 Standard Update  NERC Standards Development Process requires posting and balloting of new/revised standards by the industry  TPL-001-1 covers the fundamental requirements for long term planning

63. 63 NERC TPL-001-1 Standard Update FAILED BALLOT  Quorum: 91.38%  Approval: 35.36%

64. 64 NERC TPL-001-1 Standard Update Common comments  Implementation Plan timeframe  Local Area Load issue  Definition of Protection System  Year One definition  Spare equipment strategy  Protection System modeling  Number of near-term studies

65. 65 Network BES Temporary radial

66. 66 Network BES No Established No Temporary radial Established

67. 67

68. 68 FERC recently issued a series of Orders and NOPR’s  PRC-023  BES definition  TPL-002 R1.3.10 non-operation of protection system  NERC Rules of Procedure on standard development  FERC Penalty Guidelines NERC/FERC Issues

69. 69

70. 70 Rich Wodyka ITP 2010 TAG Work Plan Review

71. 71 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

72. 72 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

73. 73 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

74. 74 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

75. 75 August - September TAG Meeting – September 21st  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

76. 76 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

77. 77

78. 78 TAG Open Forum Discussion