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TAG Meeting September 16, 2011

TAG Meeting September 16, 2011. ElectriCities Office Raleigh, NC. 1. TAG Meeting Agenda Introductions and Agenda – Rich Wodyka FERC Order No. 1000 Overview - Dani Bennett 2010 Collaborative Plan Update – Orvane Piper

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TAG Meeting September 16, 2011

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  1. TAG MeetingSeptember 16, 2011 ElectriCities Office Raleigh, NC 1

  2. TAG Meeting Agenda • Introductions and Agenda – Rich Wodyka • FERC Order No. 1000 Overview - Dani Bennett • 2010 Collaborative Plan Update – Orvane Piper • 2011 Study Activities Report on Preliminary Study Results – Orvane Piper and Kai Zai • Regional Studies Update – Bob Pierce • 2011 TAG Work Plan – Rich Wodyka • TAG Open Forum – Rich Wodyka 2

  3. FERC Order No. 1000 Rule on Transmission Planning and Cost Allocation Dani Bennett Progress Energy 3

  4. Order N0. 1000 • Transmission Planning • Public Policy • Interregional Coordination • Cost Allocation • Nonincumbent Transmission Developer • Compliance Filings • Next Steps

  5. Transmission Planning • Public utility transmission providers are required to participate in a regional transmission planning process that satisfies Order No. 890 principles and produces a regional transmission plan • Local and regional transmission planning processes must consider transmission needs driven by public policy requirements established by state or federal laws or regulations • Public utility transmission providers in each pair of neighboring transmission planning regions must coordinate to determine if more efficient or cost‐effective solutions are available

  6. Public Policy • Each public utility transmission provider must establish procedures to: • Identify transmission needs driven by public policy requirements • Evaluate potential solutions to those needs • Public policy requirements are defined as enacted statutes and regulations promulgated by a relevant jurisdiction, whether within a state or at the federal level • No mandate to include any specific requirement

  7. Interregional Coordination • Each pair of neighboring transmission planning regions must: • Share information regarding the respective needs of each region and potential solutions to those needs • Identify and jointly evaluate interregional transmission facilities that may be more efficient or cost‐effective solutions to those regional needs • Interregional transmission facilities are those that are located in two or more neighboring transmission planning regions • No requirement to produce an interregional transmission plan or engage in interconnection-wide planning

  8. Cost Allocation • Regional transmission planning process must have a regional cost allocation method for a new transmission facility selected in the regional transmission plan for purposes of cost allocation • Neighboring transmission planning regions must have a common interregional cost allocation method for a new interregional transmission facility that the regions select • Participant‐funding of new transmission facilities is permitted, but is not allowed as the regional or interregional cost allocation method

  9. Cost Allocation • The rule does not require a one‐size fits all method for allocating costs of transmission facilities • Each region is to develop its own proposed cost allocation method(s) • If region can’t decide on a cost allocation method, then FERC would decide based on the record • No interconnection-wide cost allocation

  10. Nonincumbent Transmission Developers • Rule requires the development of a not unduly discriminatory regional process for transmission project submission, evaluation, and selection

  11. Nonincumbent Transmission Developers • Rule removes any federal right of first refusal from Commission‐approved tariffs and agreements with respect to new transmission facilities selected in a regional transmission plan for purposes of cost allocation, subject to four limitations: • This does not apply to a transmission facility that is not selected in a regional transmission plan for purposes of cost allocation • This does not apply to upgrades to transmission facilities, such as tower change outs or reconductoring • This allows, but does not require, the use of competitive bidding to solicit transmission projects or project developers • Nothing in this requirement affects state or local laws or regulations regarding the construction of transmission facilities, including but not limited to authority over siting or permitting of transmission facilities

  12. Compliance Filings • Oct 11, 2012 - Regional Transmission Planning & Cost Allocation Compliance filing • April 11, 2013 - Interregional Transmission Planning & Cost Allocation Compliance filing

  13. Next Steps • NCTPC members will more fully evaluate the Order and potential impacts to the NCTPC process • Plan to provide progress updates at future TAG meetings • As was done in the Order No. 890 process, stakeholders will be kept informed during the development of the compliance filings and will be given an opportunity to review and comment on the proposed changes to the NCTPC process

  14. Questions ? 14 14 14

  15. Major Transmission Project Update Orvane Piper Duke Energy 15 15

  16. Contains 4 Progress Energy project in-service date changes Contains 1 Duke Energy project in-service date change 2011 Mid-Year Update to the 2010 Collaborative Transmission Plans 16 16 16

  17. Import Scenarios 17 17 17

  18. Import Scenarios 18 18 18

  19. Import Scenarios 19 19 19

  20. Questions ? 20 20 20

  21. 2011 Study Preliminary Results Orvane Piper Duke Energy 21 21

  22. 2021 Hypothetical Import / Export 22

  23. 2021 Hypothetical Import / Export 23

  24. 2021 Hypothetical Import / Export 24

  25. 2021 Hypothetical Import / Export PJM (AEP) - DUKE 600 MW • Progress • No previously unidentified issues • Duke • No previously unidentified issues 25 25

  26. 2021 Hypothetical Import / Export SOCO - DUKE 600 MW • Progress • No previously unidentified issues • Duke • No previously unidentified issues 26 26

  27. 2021 Hypothetical Import / Export SCEG - DUKE 600 MW • Progress • No previously unidentified issues • Duke • No previously unidentified issues 27 27

  28. 2021 Hypothetical Import / Export SCPSA - DUKE 600 MW • Progress • No previously unidentified issues • Duke • No previously unidentified issues 28 28

  29. 2021 Hypothetical Import / Export Progress (CPLE) - DUKE 600 MW • Progress • No previously unidentified issues • Duke • No previously unidentified issues 29 29

  30. 2021 Hypothetical Import / Export TVA - DUKE 600 MW • Progress • No previously unidentified issues • Duke • No previously unidentified issues 30 30

  31. 2021 Hypothetical Import / Export PJM (AEP) – Progress (CPLE) 600 MW • Progress • Construct a 3rd 230 kV line between Rockingham – Lilesville 230 kV substations in 2022. • Reconductor Sumter – SCEG’s Eastover 115 kV Line in 2022. • Duke • No previously unidentified issues 31 31

  32. 2021 Hypothetical Import / Export PJM (DVP) – Progress (CPLE) 600 MW • Progress • Reconductor Sumter – SCEG’s Eastover 115 kV Line in 2022. • Duke • No previously unidentified issues 32 32

  33. 2021 Hypothetical Import / Export SCEG – Progress (CPLE) 600 MW • Progress • Reconductor Sumter – SCEG’s Eastover 115 kV Line in 2021. • Evaluate Wateree/Camden area and open/close status of Wateree 115/100 kV transformer • Duke • No previously unidentified issues 33 33

  34. 2021 Hypothetical Import / Export SCPSA – Progress (CPLE) 600 MW • Progress • Reconductor Sumter – SCEG’s Eastover 115 kV Line in 2021. • Evaluate Wateree/Camden area and open/close status of Wateree 115/100 kV transformer • Duke • No previously unidentified issues 34 34

  35. 2021 Hypothetical Import / Export Duke – Progress (CPLE) 600 MW • Progress • Construct a 3rd Line between Rockingham – Lilesville 230 kV substations in 2021. • Reconductor Sumter – SCEG’s Eastover 115 kV Line in 2023 • Duke • No previously unidentified issues 35 35

  36. 2021 Hypothetical Import / Export PJM (AEP / AEP) – Duke / Progress (CPLE) 1200 MW • Progress • Reconductor Sumter – SCEG’s Eastover 115 kV Line in 2023. • Construct a 3rd Line between Rockingham – Lilesville 230 kV substations in 2024. • Duke • No previously unidentified issues 36 36

  37. 2021 Hypothetical Import / Export PJM (AEP / DVP) – Duke / Progress (CPLE) 1200 MW • Progress • Reconductor Sumter – SCEG’s Eastover 115 kV Line in 2022. • Duke • No previously unidentified issues 37 37

  38. 2021 Hypothetical Import / Export Duke / Progress (CPLE) - PJM (DVP) –1200 MW • Progress • No previously unidentified issues • Duke • No previously unidentified issues 38 38

  39. Davidson County 1000 MW Resource • 2021 Request • Located 5 miles north of Buck Steam Station on Tyro 230 kV lines (Buck – Beckerdite) • Sink/Source in Duke 39 39

  40. Davidson County 1000 MW Resource • Progress • No previously unidentified issues • Duke • Rebuild Tyro (Buck – Beckerdite) 230 kV lines, 2021 • Add Buck 230/100 kV transformer, 2021 • Replace 1Beckerdite 230/100 kV transformer, 2021 • Replace 1Winecoff 230/100 kV transformer, 2021 40 40

  41. 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 7, 2011 to Rich Wodyka - ITP (rawodyka@aol.com) TAG Input Request 41

  42. Questions ? 42 42 42

  43. 2011 Off-Shore Wind Study Preliminary Results Kai Zai Progress Energy 43 43

  44. 2010 NC Off- Shore Wind Results Review • Summary of 2010 Study • Accommodate 3,000 MW’s into PEC Transmission network • Four options were studied. • Option 1A – via 230 kV Network (Est. cost: $1.195B) • Option 1B – via 500 kV Network (Est. cost: $1.310B) • Option 2 – Accommodate 2,500 MW’s (Est. cost: $1.155B) • Option 3 – Accommodate 2,000 MW’s (Est. cost: $0.525B) • Last year - Option 1B was considered to be the best option if considering a long-term build out of off-shore wind that might exceed the 3,000 MW test level.

  45. 2011 PWG Off-Shore Wind Scenario Approximately 5,000 MW total capacity in 2021 Injected at two locations on Progress system MW allocation – 40% (2,000 MW) SOCO, 36% (1,800 MW) Duke, 24% (1,200 MW) Progress 45

  46. 2011 PWG Off-Shore Wind Scenario Wind Generation Output 5,000 MW at New Bern Substation (2) 500/230KV XFMRS 230 KV 500 KV Wake New Bern Bayboro2300/875MW Wommack Total= 5000/2050 MW Cumberland Morehead 2700/1175MW Jacksonville Sutton Total Wind Output:5000 MW Off Peak 2050 MW On Peak

  47. Preliminary Off-Shore Wind Results – Duke • No thermal overloads identified for off-peak and on-peak loads.

  48. Thermal overload issues identified for both off-peak and on-peak loads. Off-peak system load with 5,000 MW New Bern 500/230 kV transformer Overload New Bern – Aurora 230 kV Line Overload New Bern – Wommack 230 kV Line Overload New Bern 230/115 kV transformer Overload New Bern – Kinston Dupont 115 kV Line Overload Rocky Mt. – (DVP) Battleboro 115 kV Line Overload On-peak system load with 2,050 MW New Bern 230/115 kV transformer Overload New Bern – Aurora 230 kV Line Overload Preliminary Off-Shore Wind Results – Progress Energy 48 48

  49. Preliminary Off-Shore Wind Results – Progress Energy • Off-peak system load with 4000 MW’s • New Bern – Aurora 230 kV LineOverload • Off-peak system load with 3500 MW’s • None • The results have shown that the transmission identified in Option 1B will accommodate 3,500 MW’s of wind generation without any additional upgrades.

  50. Preliminary Off-Shore Wind Results – Progress Energy • Modify Transmission in Option 1B to accommodate 5,000 MW’s of generation during off peak. • Add Wommack 500/230 kV Transformers (w & w/o Xfmrs at New Bern). • Add Clinton 500/230 kV Transformers. • Conclusion: • No easy solution. Too much of power tries to flow toward North (Dominion). • Move the generation connection to Jacksonville 230 kV substation. • Some incremental transmission is still needed.

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