Transmission Expansion Advisory Committee

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1 Transmission Expansion Advisory Committee February 7,

2 Issues Tracking 2

3 Issues Tracking Open Issues None New Issues 3

4 2013 RTEP Scenario Analysis 4

5 RTEP Scenario Analysis 2012 North Carolina Transmission Planning Collaborative (NCTPC) PJM Joint Interregional Reliability Study 5

6 Objective: Assess reliability screening and transmission upgrades 2012 NCTPC PJM Joint Study: Scope PJM and North Carolina Transmission Planning Collaborative (NCTPC) footprints Hypothetical off-shore wind injections - PJM and Progress Energy Carolinas (PEC) Landstown 230 kv Substation, Dominion Morehead City Substation, Progress Energy Southport Substation, Progress Energy Three scenarios of wind penetration Varying levels of power transfer between PJM/DEC/PEC Analysis: N-1 contingency thermal analysis 100 KV and above Develop: Network upgrades to mitigate identified constraints 6

7 2012 NCTPC PJM Joint Study: Injection Points 7

8 Three wind scenarios: 2027 topology at 60% of summer peak load 2012 NCTPC PJM Joint Study: Wind Scenarios Injection Location Scenario 1 Scenario 2 Scenario 3 PJM Landstown 1,000 MW (60% in DEC, 40% in PEC) 2,000 MW (100% in PJM) 4,500 MW (100% in PJM) NCTPC Morehead City 1,000 MW (60% in DEC, 40% in PEC) 1,500 MW (60% in DEC, 40% in PEC) 3,500 MW (43.6% in DEC, 29.1% in PEC, 27.3% in PJM) NCTPC - Southport 1,000 MW (60% in DEC, 40% in PEC) 1,500 MW (60% in DEC, 40% in PEC) 2,000 MW (43.6% in DEC, 29.1% in PEC, 27.3% in PJM) Total Scenario Wind Injection 3,000 MW 5,000 MW 10,000 MW 8

9 Scenario NCTPC PJM Joint Study: Summary of Results No issues identified in PJM Scenario 2 Two N-1 thermal issues: Landstown Stumpy Lake 230 kv Landstown Lynnhaven 230 kv Conceptual Upgrades: 2 nd Landstown Stumpy Lake 230 kv line Upgrade terminal equipment on Landstown Lynnhaven 230 kv line Scenario 3 Multiple pre-contingency and N-1 overloads on local Dominion 230 kv system 9

10 2012 NCTPC PJM Joint Study: Scenario 2 Map 10

11 2012 NCTPC PJM Joint Study: Scenario 3 Maps 11

12 2012 NCTPC PJM Joint Study Summary of Results Conceptual Scenario 3 Upgrades - (pre-contingency) New Landstown 500 kv Substation (for wind injection) Two new Landstown 500/230 kv transformers New Landstown Yadkin 500 kv line 2 nd Landstown Fentress 230 kv line 2 nd Fentress Thrasher 230 kv line 2 nd Landstown Stumpy Lake 230 kv line 2 nd Stumpy Lake Thrasher 230 kv line Conceptual Scenario 3 Upgrades - (N-1) 2 nd Surry Chickahominy 500 kv line 2 nd Chickahominy 500/230 kv transformer Add Chickahominy 500 kv breaker Terminal equipment upgrade - Chaparal Locks 230 kv line Convert one Landstown Fentress 230 kv to 500 kv 12

13 Conclusions: 2012 NCTPC PJM Joint Study Conclusions Landstown 230 kv substation is capable of handling wind injections of 1,000 MW and 2,000 MW without major upgrades due to the strength of the local Dominion 230 kv system Wind penetration of 4,500 MW or greater at Landstown 230 kv substation may require a 500 kv network at Landstown as well as reinforcements and upgrades to the 500 kv and local 230 kv system Wind scenarios in the context of Dominion s RPS requirements: 1 Based on approximate offshore wind capacity factors of 37% 2 Based on state RPS requirements of North Carolina and Virginia for Dominion load 13

14 PJM RPS Scenario Analysis Update 14

15 2013 RTEP Scenario Analysis Hudson Cardiff RPS Sensitivity 15

16 Overview Modeling Assumptions Continuation of 2012 RPS Scenarios Sensitivities based on the RPS1 and RPS2 from the 2027 RPS Study: Offshore DC modeled only the segment from Hudson to Cardiff 1000 MW wind injection at each of Hudson and Cardiff points. No other offshore wind. No change to land based wind. 16

17 Sensitivities 17

18 Overview Reporting Current report focuses on Eastern States: New Jersey PSEG JCPL AE RECO Delmarva Peninsula Maryland 18

19 Approximate Gross Flowgate Congestion 2027 Nominal Dollars 19

20 Approximate Gross Flowgate Congestion 2027 Nominal Dollars 20

21 Gross Flowgate Congestion Differences 2027 Nominal Dollars 21

22 Gross Flowgate Congestion Differences 2027 Nominal Dollars Positive values are congestion savings of the DC line 22

23 Approximate Gross Load Payments 2027 Nominal Dollars 23

24 Approximate Gross Load Payments 2027 Nominal Dollars 24

25 2027 Nominal Dollars Gross Load Payment Differences 25

26 Gross Load Payment Differences 2027 Nominal Dollars 26

27 2027 Nominal Dollars On Peak LMP 27

28 On Peak LMP LMP values are load weighted by TO and in 2027 nominal dollars. 28

29 2027 Nominal Dollars Off Peak LMP 29

30 Off Peak LMP LMP values are load weighted by TO and in 2027 nominal dollars. 30

31 2027 Nominal Dollars Approximate Generator Revenue 31

32 Approximate Generator Revenue 2027 Nominal Dollars 32

33 Approximate Generator Revenue Differences 2027 Nominal Dollars 33

34 2027 Nominal Dollars Approximate Generator Revenue Differences 34

35 Capital Cost Estimates 35

36 AC On-Shore Overlay Cost Estimate Assumptions (2012 Nominal $) Costs from PJM RTEP database PJM TEAC 2//7/13 36

37 Cost Estimating Assumptions (2012 Nominal $) Costs from PJM RTEP database Additional researched estimates ranged from $3-$5 million / mi Costs from ERCOT project in the gulf Costs from EIPC DOE project 37

38 RPS Wind and Overlay Cost Estimates (2027 Nominal $) PJM TEAC 12/13/

39 2013 RTEP Scenario Analysis 39

40 At-Risk Generation Approximately 4,500 MW of At- Risk generation remains Known deactivation notifications not included 40

41 2013 RTEP - At-Risk Generation Next Steps Recent deactivation notifications Future analysis 41

42 2013 RTEP - DR Sensitivity Identify locational supply concerns before they actually occur Reduce each LDAs DR by amount of generation in LDA that did not clear in RPM auction (load deliverability test only) 42

43 2013 RTEP - RPS Scenario Finalize RPS1 2GW scenario Optimize transmission overlay 2012 RTEP scenarios all assumed the same transmission overlay 2013 RTEP will investigate what parts of overlay may not be required for a given scenario Generation commitment Sensitivity study around unit commitment assumptions used in production cost simulations check impact on wind curtailment 43

44 Generation Deactivation Notification (Retirements) Update 44

45 Generation Retirements PJM TEAC 02/07/

46 Deactivation Status Unit(s) Transmission Zone Requested Deactivation Date PJM Reliability Status Hutchings 3, 5, & 6 Dayton 6/1/2015 Reliability Analysis underway Burlington 11 (111, 112, 113, 114) PSEG 6/1/2015 Reliability Analysis underway Edison 1 (11, 12, 13, 14), 2 (21, 22, 23, 24), & 3 (31, 32, 33, 34) Essex 10 (101, 102, 103, 104), & 11 (111, 112, 113, 114) PSEG 6/1/2015 Reliability Analysis underway PSEG 6/1/2015 Reliability Analysis underway Middle Energy Center 1, 2, & 3 AE 5/31/2015 Reliability Analysis underway Werner CT 1, 2, 3 & 4 JCPL 5/1/2015 Reliability Analysis underway Gilbert CT 1, 2, 3, & 4 JCPL 5/1/2015 Reliability Analysis underway Gilbert 8 JCPL 5/1/2015 Reliability Analysis underway PJM TEAC 02/07/

47 Brattle Recommendation 2017 CETO/CETL Values 47

48 2012 RTEP Assumptions Include transmission approved by the PJM Board through December CETO values from 2012 RTEP 2017 CETL values are currently being calculated Limiting facility will be identified Brattle Recommendation Area / Year 2017 CETO AE 1000 AEP 1470 APS 1740 ATSI 5460 BGE 4080 CLEV 3850 COMED 2610 DAYTON 610 DLCO 1470 DPL 980 DPL SOUTH 1550 DUKE 3930 EKPC 990 EMAAC 5010 JCPL 3190 MAAC 1100 METED 1310 PECO 2840 PENELEC 1210 PEPCO 2880 PJM WEST PJM WEST+DUKE 7010 PLGRP 1640 PSEG 4830 PSEG NORTH 2430 SWMAAC 4640 VAP

49 Reliability Analysis Update 49

50 AEP Transmission Zone Project Scope Expansion (B1660) Previous B Install a 765/500 kv transformer at Cloverdale - $65 M Expanded B1660 Scope Install kv circuit breakers Establish a 500 kv Cloverdale east station and 765 kv to Cloverdale 500 kv East Tie Line Incremental 765 kv station work to add 2 additional 765 kv Circuit Breakers Reconfiguration of miscellaneous facilities including relocation (B1660.1) Incremental Cost Estimate: $85 M Updated Total Estimated Project Cost: $150 M Projected IS Date: 12/31/

51 Short Circuit Update 51

52 AP Transmission Area The Wylie Ridge 138 kv breakers W-2 and W-6 are overstressed Proposed Solution: Replace the Wylie Ridge 138 kv breakers W-2 and W-6 with 63kA rated breakers (b2210-b2211) Estimated Project Cost: $600 K Expected IS Date: 06/01/

53 DLCO Transmission Area The Brunot Island 138 kv breakers Z-40 COLLIER and Z-41 COLLIER are overstressed Proposed Solution: Revise the reclosing of the Brunot Island 138 kv breakers Z-40 COLLIER and Z-41 COLLIER (b2198-b2199) Estimated Project Cost: $0 Expected IS Date: 06/01/

54 DLCO Transmission Area The Crescent 138 kv breakers Z-29 Beaver, Z-82 VALLEY, and Z-21 NORTH are overstressed Proposed Solution: Revise the reclosing of Crescent 138 kv breakers Z-29 Beaver, Z-82 VALLEY, and Z-21 NORTH (b2200-b2202) Estimated Project Cost: $0 Expected IS Date: 06/01/

55 DLCO Transmission Area The Elrama 138 kv breakers Z18-USX CLAI, Z13-WEST MIF, and Z15-DRAVOSBU are overstressed Proposed Solution: Revise the reclosing of The Elrama 138 kv breakers Z18-USX CLAI, Z13-WEST MIF, and Z15- DRAVOSBU (b2203-b2205) Estimated Project Cost: $0 Expected IS Date: 06/01/

56 DLCO Transmission Area The Woodville 138 kv breakers Z-106 PINEY and Z-64 COLLIER are overstressed Proposed Solution: Revise the reclosing of Woodville 138 kv breakers Z-106 PINEY and Z-64 COLLIER (b2206-b2207) Estimated Project Cost: $0 Expected IS Date: 06/01/

57 DLCO Transmission Area The Beaver Valley 138 kv breaker Z-28 CRESCEN is overstressed Proposed Solution: Revise the reclosing of Beaver Valley 138 kv breaker Z-28 CRESCEN (b2208) Estimated Project Cost: $0 Expected IS Date: 06/01/

58 DLCO Transmission Area The Cheswick 138 kv breaker Z-51 WILMERD is overstressed Proposed Solution: Revise the reclosing of Cheswick 138 kv breaker Z-51 WILMERD (b2209) Estimated Project Cost: $0 Expected IS Date: 06/01/

59 Supplemental Projects 59

60 AEP Transmission Zone Supplemental Project Replace the existing Cloverdale 500/345 kv transformer banks 6A and 6B and associated facilities. (S0505) Estimated Project Cost: $80M Projected IS Date: 12/31/

61 DLCO Transmission Zone Supplemental Project Replace No. 2-4 Autotransformer 345kV breaker at Beaver Valley 345/138kV substation with 80kA breaker, 6/1/2013, $1.4M (S0504.1) Replace Crescent (318) No.4 Bus 345kV breaker at Beaver Valley 345/138kV substation with 80kA breaker, 12/31/2013, $1.4M (S0504.2) Replace Unit 1, No. 3 Bus 345kV breaker at Beaver Valley 345/138kV substation with 80kA breaker, 12/31/2013, $1.4M (S0504.3) Replace Unit 2, No kV breaker at Beaver Valley 345/138kV substation with 80kA breaker, 6/1/2014, $1.4M (S0504.4) Replace Clinton (314) No. 3 Bus 345kV breaker at Beaver Valley 345/138kV substation with 80kA breaker, 12/31/2014, $1.4M (S0504.5) 61

62 DLCO Transmission Zone Supplemental Project Replace Mansfield (316) 345kV breaker at Beaver Valley 345/138kV substation with 80kA breaker, 6/1/2015, $1.4M (S0504.6) Replace Unit 1, No. 4 Bus 345kV breaker at Beaver Valley 345/138kV substation with 80kA breaker, 12/31/2015, $1.4M (S0504.7) Replace Unit 2, No kV breaker at Beaver Valley 345/138kV substation with 80kA breaker, 6/1/2016, $1.4M (S0504.8) Replace Clinton (314) No. 4 Bus 345kV breaker at Beaver Valley 345/138kV substation with 80kA breaker, 12/31/2016, $1.4M (S0504.9) Replace No. 3-8 Autotransformer 345kV breaker at Beaver Valley 345/138kV substation with 80kA breaker, 12/31/2016, $1.4M (S ) 62

63 DLCO Transmission Zone Supplemental Project Replace 1B Station Service 138kV breaker at Beaver Valley 345/138kV substation with 63kA breaker, 12/31/2016, $0.5M (S ) Replace 2A Station Service 138kV breaker at Beaver Valley 345/138kV substation with 63kA breaker, 6/1/2016, $0.5M (S ) Replace 1A Station Service 138kV breaker at Beaver Valley 345/138kV substation with 63kA breaker, 12/31/2015, $0.5M (S ) 63

64 Next Steps Continue 2013 RTEP Scenario Analysis development Brattle Recommendations Continue 2018 RTEP base case development Finalize High Voltage in PJM Operations recommendations 64

65 Questions? 65

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