1st Qua u r a ter e M e M e e t e in i g 2nd Qua u r a ter e M e M e e t e in i g

Transcription

1 2011 SERTP Welcome SERTP 2011 First RPSG Meeting & Interactive Training Session 9:00 AM 3:00 PM 1

2 2011 SERTP The SERTP process is a transmission planning process. Please contact the respective transmission provider for questions related to real-time operations or OATT transmission service. 2

3 2011 SERTP Purposes & Goals of the Meeting SERTP Process Overview Form the RPSG Regional Planning Stakeholders Group Committee Structure and Requirements Economic Planning Studies Review Previous Study Selections Review Requested Sensitivities for 2011 RPSG To Select The Five Economic Planning Studies Interactive Training Session Model & Expansion Plan Development Next Meeting s Activities

4 2011 SERTP Process Overview 4

5 2011 SERTP 2011 SERTP Process Overview 5 1 st Quarter Meeting First RPSG Meeting & Interactive Training Session Form RPSG Select Five Economic Planning Studies Interactive Training Session 2 nd Quarter Meeting Preliminary Expansion Plan Meeting Review Modeling Assumptions Discuss Preliminary 10 Year Expansion Plan Stakeholder Input and Feedback Regarding the Plan

6 2011 SERTP 2011 SERTP Process Overview 3 rd Quarter Meeting Second RPSG Meeting Discuss the Preliminary Results of the Five Economic Studies Stakeholder Input and Feedback Regarding the Study Results Discuss Previous Stakeholder Input on the Expansion Plan 4 th Quarter Meeting Annual Transmission Planning Summit & Assumptions Input Meeting Discuss Final Results of the Five Economic Studies Discuss the 10 Year Transmission Expansion Plan Obtain Stakeholder Input on the Transmission Model Assumptions Used in Developing Next Year s Plan 6

7 2011 SERTP The SERTP Stakeholder Group: RPSG Serves Two Primary Purposes 1)The RPSG is charged with determining and proposing up to five (5) Economic Planning Studies on an annual basis 1)The RPSG serves as the representatives in interactions with the Transmission Provider and Sponsors for the eight (8) industry sectors 7

8 2011 SERTP RPSG Committee Structure RPSG Sector Representation 1) Transmission Owners / Operators 2) Transmission Service Customers 3) Cooperative Utilities 4) Municipal Utilities 5) Power Marketers 6) Generation Owners / Developers 7) Independent System Operators (ISOs) / Regional Transmission Operators (RTOs) 8) Demand Side Management / Demand Side Response 8

9 2011 SERTP RPSG Committee Structure Sector Representation Requirements Maximum of two (2) representatives per sector Maximum of 16 total sector members 9 A single company, and all of its affiliates, subsidiaries, and parent company, is limited to participating in a single sector

10 2011 SERTP RPSG Committee Structure Annual Reformulation Reformed annually at each 1 st Quarter Meeting Sector members will be elected for a term of approximately one year Term ends at the start of the following year s 1 st Quarter SERTP Meeting Sector Members shall be elected by the Stakeholders present at the 1 st Quarter Meeting Sector Members may serve consecutive, one-year terms if elected There is no limit on the number of terms that a Sector Member may serve 10

11 2011 SERTP RPSG Committee Structure Simple Majority Voting RPSG decision-making that will be recognized by the Transmission Provider for purposes of Attachment K shall be those authorized by a simple majority vote by then-current Sector Members 11 Voting by written proxy is allowed

12 2011 SERTP 2011 Economic Planning Study Requests Previous Economic Planning Studies Current Economic Planning Study Requests 12

13 2011 SERTP RPSG Formation 2010 Sector Representatives 2011 Sector Representatives 13

14 2011 SERTP 2011 Economic Planning Studies Vote on Economic Planning Studies 14

15 2011 SERTP Interactive Training Session 15

16 2011 SERTP Interactive Training Session Explain and discuss the underlying methodology and criteria that will be utilized to develop the transmission expansion plan Planning Criteria: On the SERTP Website 16

17 2011 SERTP Interactive Training Session Model Development SERTP Model Southern Balancing Authority, PowerSouth, SMEPA Eastern Interconnect Model Expansion Plan Development 17

18 2011 SERTP Interactive Training Session SERTP Model Basic Principles Area Interchange Loads Generation Transmission System Topology 18

19 Transmission Model Development Basic Principles Generation = Load + Losses + Interchange The model includes: The Projected Load for each year and season The Losses produced in serving that load (produced from transmission line & transformer impedances) The Area Interchange of long-term firm commitments across the interface The Generation needed to balance all of the above The Current Transmission System Topology & Expansion Plan 19

20 2011 SERTP Interactive Training Session SERTP Model Basic Principles Area Interchange Loads Generation Transmission System Topology 20

21 Transmission Model Development Area Interchange The net total of all transactions leaving or entering a balancing authority Long-Term Firm Commitments Only TVA Simplified Example: SBA Interchange = 200 MW 100 MW Southern Balancing Authority 150 MW =

22 2011 SERTP Interactive Training Session SERTP Model Basic Principles Area Interchange Loads Generation Transmission System Topology 22

23 Transmission Model Development Loads Models include forecasted MW & MVAR amounts for each season (Summer, Winter, Spring, Fall) Provided by Load Serving Entities

24 Transmission Model Development Loads Models include forecasted MW & MVAR amounts for each season (Summer, Winter, Spring, Fall) Provided by Load Serving Entities 24 Provided by Load Serving Entities (LSEs) Alabama Power Georgia Power Gulf Power Mississippi Power GTC MEAG City of Dalton Power South SMEPA

25 Transmission Model Development SERTP Sponsor Load Forecasts 25

26 2011 SERTP Interactive Training Session SERTP Model Basic Principles Area Interchange Loads Generation Transmission System Topology 26

27 Transmission Model Development Generation Assumptions Receive resource assumptions from LSEs to serve load Generator Locations Amounts (MW) Models also include generator assumptions for Point to Point Transmission Service commitments i.e. Harris 1 FPL (584 MW) 27

28 Conasauga Dahlberg Hancock CC Rocky Mtn Warren Co Bio McDonough Tenaska Wansley Vogtle Kemper Central AL Piedmont Bio Washington Co CT Moselle Harris CC West Georgia Franklin CC Lee Road Warthen CT SMARR CC SOWEGA 28 McIntosh Farley *Location of changes to existing resource assumptions throughout the 10 year planning horizon Baconton East Bainbridge Existing Generation Future Generation

29 Transmission Model Development Generation Models Models include: Voltage Schedule Real Power Capabilities (MOD 24) Reactive Power Capabilities (MOD 25) 29

30 2011 SERTP Interactive Training Session SERTP Model Basic Principles Area Interchange Loads Generation Transmission System Topology 30

31 2011 SERTP Interactive Training Session Transmission System Topology Transmission Lines & Substations Transformers Switched Shunts 31

32 2011 SERTP Interactive Training Session Transmission System Topology Transmission Line Design Groups calculate the impedance and ratings of the transmission elements, which are then provided as inputs for use by the Transmission Planner. The subsequent slides are a brief overview of the modeling of these inputs. 32

33 Transmission Model Development Transmission Lines & Substations Modeled as branches & nodes (buses) Impedances & ratings included for each branch Values provided by Transmission Line Design Groups Based on Facility Rating Methodology (FAC 008) Explicit Representation To Sub A Sub B Transmission Model Sub A To Sub B 33

34 Transmission Model Development Transmission Lines & Buses Transmission Line Impedance is based on factors such as: Conductor type Structure Type» Conductor Spacing» Height Terrain Line Length Frequency (60 Hz) Structure Conductor 34 Mutual Impedances

35 Transmission Model Development Transmission Line Ratings Ampacity is based on factors such as:» Conductor Type (Ampacity)» Ambient Temperature / Wind Speed» Conductor Operating Temperature MVA rating is based on:» Operating Voltage Branch Ratings» MVA = 3 * Ampacity * (Voltage line Based on: line-line line)» Lower of the line rating or the terminal equipment ratings 35

36 Transmission Model Development Transmission Line Ratings Sub 1 Sub 2 S1 B1 S2 S5 B2 S6 Switches (S1 S2): 898 MVA Breakers (B1): 828 MVA Line Conductor: 807 MVA Switches (S5 S6): 718 MVA Breakers (B2): 828 MVA How it modeled: Sub 1 Sub 2 Conductor Impedance 36 Switch Rating (718 MVA)

37 2011 SERTP Interactive Training Session Transmission System Topology Transmission Lines & Substations Transformers Switched Shunts 37

38 Transmission Model Development Transformers Impedances and Ratings included for each transformer Models include transformer winding ratio Explicit Representation Rating based on lowest of: Transformer Rating Switch Ratings Buswork Rating 38

39 2011 SERTP Interactive Training Session Transmission System Topology Transmission Lines & Substations Transformers Switched Shunts 39

40 Transmission Model Development Switched Shunts Supply MVARs (Capacitors) or Consume MVARs (Reactors) Set to operate at voltage set points to control area voltage Models Include:» Number of steps» MVARs / step» Voltage Schedule MVARs MVARs 40

41 2011 SERTP Interactive Training Session Model Development SERTP Model SBA, PowerSouth, SMEPA Eastern Interconnect Model Expansion Plan Development 41

42 Transmission Model Development Eastern Interconnect Model Development Coordination Transfers (Interchange) Tie Lines Voltage Schedules Model Numbers (Areas, Bus, Owner, etc) SERTP Sponsors SERC NERC 42

43 2011 SERTP Interactive Training Session Model Development SERTP Model SBA, PowerSouth, SMEPA Eastern Interconnect Model Expansion Plan Development 43

44 2011 SERTP Interactive Training Session Expansion Plan Development Power Flow Analyses Planning Criteria Project Identification Expansion Plan Timeline 44

45 Transmission Expansion Plan Power Flow Solutions Performed using PSS\E and MUST Non-linear, iterative solutions for bus voltages and branch currents Power Flow Analyses Base Case Analysis All Bulk Electric System facilities in-service Contingency Analysis Bulk Electric System elements out of service» Generator» Transmission Circuit» Transformer 45

46 2011 SERTP Interactive Training Session Expansion Plan Development Power Flow Analyses Planning Criteria Project Identification Expansion Plan Timeline 46

47 Transmission Expansion Plan Planning Criteria Similar for all SERTP Sponsors» Meet NERC TPL Standards The subsequent slides apply directly to Southern Company guidelines 47

48 Transmission Expansion Plan Voltage Generating Plants: Terminal voltage on high side of GSU should not exceed the maximum or minimum allowable voltage limits for all facilities in service and during planning contingency conditions 48

49 49 Transmission Expansion Plan Voltage Load Buses: Sub 1 No contingency:» < 500 kv: 95% to 105% of connected transformer voltage rating» 500 kv: 98% to 107.5% of connected transformer voltage rating 1.0 PU.99 PU.98 PU To 115 kv Network Sub 2 (Unregulated, Load Bus) Load bus voltages acceptable (between.95 & 1.05 PU precontingency) Sub 3 (Regulated, Load Bus)

50 Transmission Expansion Plan Voltage Load Buses: With contingency: 1.0 PU» +/- 5% deviation for non-regulated buses» +/- 8% deviation for regulated buses» Voltage should not drop below 97% for 500 kv buses and below 90% for buses less than 500 kv To 115 kv Network Sub 2 (Unregulated, Load Bus) 50 Sub 1.96 PU.92 PU Do these bus voltages still meet the planning criteria? Sub 3 (Regulated, Load Bus)

51 Transmission Expansion Plan Voltage Load Buses: Sub 2: PASS» Deviation = 99% - 96% = 3% (<5% for unregulated buses)» Bus Voltage = 96% (> 90% for post-contingency) Sub 3: 1.0 PU 51 Sub 1 PASS» Deviation = 98% - 92% = 6% (<8% for regulated buses)» Bus Voltage = 92% (> 90% for post-contingency) Load bus voltages acceptable.96 PU To 115 kv Network Sub 2 (Unregulated, Load Bus).92 PU Sub 3 (Regulated, Load Bus)

52 Transmission Expansion Plan Voltage Load Buses: Why can regulated buses deviate more than unregulated buses? Transmission model only captures distribution load, not bus regulators or transformer load tap changers (LTCs) Transmission Model Explicit Representation 52

53 Transmission Expansion Plan Thermal Loading Transmission Lines: Line loadings should not exceed design specifications of terminal connections, substation infrastructure or the line itself Transformers: Transformer loading should not exceed nameplate rating for normal conditions. Transformer loading should not exceed calculated capability rating for contingency conditions. 53

54 Transmission Expansion Plan Planning Contingencies Summer Peak Loss of one transmission element and one critical generating unit Shoulder Conditions 93% of summer peak load Hydro generation off-line Loss of one transmission element and one critical generating unit 54

55 Transmission Model Development Daily Load Curve Summer Summer Load Levels Evaluated Peak Shoulder 100 Peak Load (% of Peak) Shoulder Time (Daily Hour)

56 Transmission Expansion Plan Additional Evaluations Stability Studies Interface Screens 56

57 Transmission Expansion Plan Additional Studies (as appropriate) Multiple unit and voltage levels at plants Breaker failure/bus differential scenarios Loss of common tower or ROW outages Low probability, high consequence scenarios Valley, Winter, and Hot Weather conditions Below 93% of forecasted peak with loss of multiple units and/or transmission elements 57

58 2011 SERTP Interactive Training Session Expansion Plan Development Power Flow Analyses Planning Criteria Project Identification Expansion Plan Timeline 58

59 Transmission Expansion Plan Simple Example Neglects transmission losses N 1 evaluation only (no unit offline scenarios) Voltage impacts not assessed 59

60 Transmission Expansion Plan P = 16.4 Q = 5.3 P = 6.4 Q = 2.3 A C E P = 15.0 Q = MVA 33 MVA P = 10.0 Q = 3.0 P = 20.0 Q = 7.0 P = 1.4 Q = 1.3 B P = 6.4 Q = 2.3 D P = 13.6 Q = MVA 33 MVA 40 MVA P = 5.0 Q = 1.0 P = 20.0 Q = No transmission lines overloaded without contingencies

61 Transmission Expansion Plan P = 30.0 Q = 10.0 P = 20.0 Q = 7.0 A C E 96.0% 64.0% P = 15.0 Q = % P = 10.0 Q = 3.0 P = 20.0 Q = 7.0 P = 15.0 Q = 6.0 B 64.0% P = 20.0 Q = 7.0 D P = 0.0 Q = P = 5.0 Q = 1.0 P = 20.0 Q = 7.0 No transmission lines overloaded with contingencies (Highest loading shown: Line A C)

62 Transmission Expansion Plan What if the load at substation B was significantly reduced? Real Power ( MW) Reactive Power ( MVAR) Generation at Bus A reduced to balance MW / MVARs 62

63 Transmission Expansion Plan P = 15.8 Q = 5.2 P = 5.8 Q = 2.2 A C E P = 11.0 Q = MVA 33 MVA P = 10.0 Q = 3.0 P = 20.0 Q = 7.0 P = 4.8 Q = 1.9 B P = 5.8 Q = 2.2 D P = 14.2 Q = MVA 33 MVA 40 MVA P = 1.0 Q = 0.3 P = 20.0 Q = No transmission lines overloaded without contingencies

64 Transmission Expansion Plan P = 30.0 Q = 10.0 P = 20.0 Q = 7.0 A C E 96.0% 64.0% P = 11.0 Q = % 33 MVA P = 10.0 Q = 3.0 P = 20.0 Q = 7.0 P = 19.0 Q = 6.7 B 64.0% P = 20.0 Q = 7.0 D P = 14.2 Q = 4.8 P = 1.0 Q = 0.3 P = 20.0 Q = 7.0 Line A B overloaded for contingency D E 64

65 Transmission Expansion Plan Potential Solutions for A B Upgrade Increase the conductor operating temperature of A B Reconductor Replace the existing A B conductor with a higher-rated rated conductor New Transmission Line Construct a new transmission line that alleviates the loading on A B 65

66 Transmission Expansion Plan Transmission Line Upgrade Increasing conductor operating temperature The more current, the higher the operating temperature» Higher maximum temperature = higher line ampacity» Maximum temperature based on transmission line sag, ambient conditions, and conductor specifications ACSS versus ACSR» ACSS aluminum is fully annealed & intended for higher temperatures (>100 ºC) 66 Line sag

67 Transmission Expansion Plan Reconductor Replacing the existing conductor with a higher rated conductor type Differences in conductors Ampacity Weight / Thickness Sag Span Lengths Therefore, structure replacement may be necessary 67

68 2011 SERTP Interactive Training Session Stakeholder feedback at the 2010 SERTP Summit: Unfamiliar with transmission line conductors and sizes 68

69 Transmission Expansion Plan Conductors ACSR (Aluminum Conductor Steel Reinforced) Ex: 1351 ACSR 54/19» 1351 indicates the overall conductor size (cross sectional area - kcmil)» 54 Aluminum Strands / 19 Steel Strands» Approximately 1.5 in diameter Aluminum Steel This would represent a bundled (2) 10/4 ACSR 69

70 Transmission Expansion Plan New Transmission Line Some potential applications: Multiple overloads in an area Voltage support Overload of a long transmission line Stability Needs Considerations: Right of Way 70

71 Transmission Expansion Plan In previous example, assume Line D F is tapped with a new load Real Power = 10.0 MW Reactive Power = 3.0 MVAR Generation at Bus A is designated by the LSE for an additional 10 MW to serve the new load 71

72 Transmission Expansion Plan P = 25.0 Q = 7.0 P = 20.7 Q = 6.6 P = 10.7 Q = 3.6 A C E 33 MVA 33 MVA P = 10.0 Q = 3.0 P = 20.0 Q = 7.0 P = 9.3 Q = MVA New substation & load tapping the D E transmission line Additional generation to support the new load P = 4.3 Q = 0.4 B P = 0.7 Q = 0.6 D P = 19.3 Q = 6.4 F 20 MVA 33 MVA 40 MVA P = 5.0 Q = 1.0 P = 20.0 Q = 7.0 P = 10.0 Q = No transmission lines overloaded without contingencies

73 Transmission Expansion Plan P = 40.0 Q = 13.0 P = 30.0 Q = 10.0 A C E 127.0% 96.0% P = 10.0 Q = 3.0 P = 25.0 Q = % P = 10.0 Q = 3.0 P = 20.0 Q = % P = 15.0 Q = 6.0 P = 20.0 Q = 7.0 P = 0.0 Q = 0.0 B D F 64.0% P = 5.0 Q = 1.0 P = 20.0 Q = 7.0 P = 10.0 Q = Line A C overloaded for contingency D F

74 Transmission Expansion Plan P = 0.0 Q = 0.0 P = 10.0 A Q = 3.0 C E 32.0% P = 30.0 Q = 10.0 P = 25.0 Q = % P = 10.0 Q = 3.0 P = 20.0 Q = % P = 25.0 Q = 7.0 P = 20.0 Q = 6.0 P = 40.0 Q = 13.0 B D F 63.0% 105.0% 74 P = 5.0 Q = 1.0 P = 20.0 Q = 7.0 Line A B overloaded for contingency A C Line D F overloaded for contingency A C P = 10.0 Q = 3.0

75 Transmission Expansion Plan P = 13.9 Q = 4.7 P = 3.9 Q = 1.7 A C E P = 16.1 Q = 5.3 P = 25.0 Q = 7.0 New transmission line from A F P = 4.8 Q = 2.2 P = 9.8 Q = 3.2 P = 10.0 Q = 3.0 P = 20.0 Q = 7.0 P = 10.2 Q = 3.8 B D F P = 15.9 Q = 4.5 P = 5.0 Q = 1.0 P = 20.0 Q = 7.0 P = 10.0 Q = No transmission lines overloaded without contingencies

76 Transmission Expansion Plan P = 30.0 Q = 7.0 P = 20.0 Q = 7.0 A C E 96.0% 64.0% P = 0.0 Q = 0.0 P = 25.0 Q = % P = 10.0 Q = 3.0 P = 20.0 Q = 7.0 P = 8.8 Q = 3.7 P = 13.8 Q = 4.7 P = 6.2 Q = 2.3 B D F 44.0% 17.0% 76 P = 3.8 Q = 0.7 P = 5.0 Q = % P = 20.0 Q = 7.0 P = 10.0 Q = 3.0 No transmission lines overloaded with contingencies (worst case shown)

77 Transmission Expansion Plan Alternative solutions Reconductor A B, A C, and D F New transmission line from D C and reconductor A B Many more options 77

78 Transmission Expansion Plan Example 2010 SERTP Study: Birmingham, AL GA ITS 1000 MW 2016 Study Year 78

79 Overloaded Elements Bessemer Gaston Sylacauga South Bessemer Hillabee Duncanville Sunny Level Danway North Opelika Fortson SONAT Autaugaville County Line Rd. Goat Rock Talbot County Montgomery Pike County Pinckard Farley 79 South Bainbridge

80 Potential Enhancements - Option 1 P3 Bessemer Gaston P6 P1 P4 P10 South Bessemer Sylacauga Hillabee Duncanville Sunny Level P5 Danway Lagrange North Opelika Fortson SONAT Autaugaville County Line Rd. Montgomery Goat Rock P8 Talbot County P2 Pike County 80 Total Cost: $347,500,000 P7 Pinckard P9 Farley South Bainbridge

81 Overloaded Elements Bessemer Gaston Sylacauga South Bessemer Hillabee Duncanville Sunny Level Danway North Opelika Fortson SONAT Autaugaville County Line Rd. Goat Rock Talbot County Montgomery Pike County Pinckard Farley 81 South Bainbridge

82 Potential Enhancements - Option 2 P1 Plant Wansley Bessemer Gaston South Bessemer Duncanville Billingsley Autaugaville Sylacauga Hillabee Sunny Level North Opelika Danway Fortson SONAT County Line Rd. Montgomery Goat Rock Talbot County P2 Pike County 82 Total Cost: $293,500,000 Pinckard Farley South Bainbridge

83 2011 SERTP Interactive Training Session Expansion Plan Development Power Flow Analyses Planning Criteria Project Identification Expansion Plan Timeline 83

84 Transmission Expansion Plan Expansion Plan Timeline First Five Year Focus Second Five Year Focus 84

85 First Five Year Focus Focus is on near-term reliability constraints Utilize the most recent base case assumptions Re-evaluate evaluate existing projects for timing and need Assess the need for additional projects Coordinate with SERTP Sponsors and SERC Members Input from SERTP Stakeholders Preliminary plan discussed, along with years 6-10 (projected), at the Preliminary Expansion Plan Meeting in the 2 nd Quarter 85

86 Approximate Time Line for Area Planning (Years 1 5) Base cases updated with most recent input assumptions. Assess need for additional new projects. Approximate target for completion of year 1 5 evaluation. Discuss the preliminary expansion plan with the SERTP Stakeholders and obtain input. May Jan Feb Mar Apr Jun Begin re-evaluation evaluation of existing projects for timing and need. Coordination among SERTP Sponsors and SERC members.

87 Second Five Year Focus Focus is on outer-year reliability constraints Update the base cases Re-evaluate evaluate existing projects for timing and need Assess the need for additional projects Coordinate with SERTP Sponsors and SERC Members Input from SERTP Stakeholders Year-end end review of 10 year expansion plan Update the base cases for next year s evaluation 87

88 Approximate Time Line for Area Planning (Years 6 10) Approximate target for Base cases updated completion of year 6 10 with most recent data. evaluation. Base cases updated Assess need for with most recent data additional new projects. and begin reviewing 10 year expansion plan. Discuss 10 year expansion plan at the Summit. Jun July Sep Aug Oct Nov Dec Begin re-evaluation evaluation of existing projects for timing and need. Discuss previous or obtain additional SERTP stakeholder input on expansion plan. Coordination among SERTP Sponsors and SERC members. Obtain input from stakeholders on assumptions for next year s expansion plan process.

89 Questions on the Interactive Training? 89

90 2011 SERTP Next Meeting Activities 2011 SERTP 2 nd Quarter Meeting Location: TBD Date: June 2011 Purpose: Discuss preliminary 10 year expansion plan Obtain stakeholder input and feedback regarding the plan 90

91 2011 SERTP Questions? 91