TAG Meeting December 9, 2009
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22
TAG Meeting Agenda1. Administrative Items – Rich Wodyka
2. 2009 – 2019 Collaborative Plan Study Results – Joey West
3. 2010 Study Scope – James Manning
4. Regional Studies Update – Ed Ernst and Bob Pierce
5. 2010 TAG Work Plan – Rich Wodyka
6. TAG Open Forum – Rich Wodyka
444
Base Reliability Results
• 2014 and 2019 Progress Collaborative Plan Project Delays Hypothetical Resource Supply Options
• Transfer Scenarios
• Nuclear Generation Scenarios
Outline of Results
555
Two new projects identified:• Brunswick 1 - Castle Hayne 230kV Line, Construct New Cape
Fear River Crossing (Progress)• Reconductor Pisgah Tie-Shiloh Switching Station 230 kV lines
(Duke)
Two Duke projects back in Plan:• Reconductor Central Tie-Shady Grove Tap 230 kV lines• Reconductor Peach Valley Tie- Riverview Switching Station
230 kV lines
2014S and 2019S Base Reliability Results
666
Progress Load Forecast RelatedCollaborative Plan Project Delays
Project2009
Plan In-Service Date
2008 Plan In-Service
Date
Clinton-Lee 230 kV Line 12/1/2011 (1.5 yrs) 6/1/2010
Harris Plant – RTP 230 kV Line 6/1/2014 (3 yrs) 6/1/2011
Greenville-Kinston Dupont 230 kV Line 6/1/2017 (6 yrs) 6/1/2011
Wake 500 kV Sub, Add 3rd 500/230 kV Transformer
6/1/2018 (5 yrs) 6/1/2013
Durham-RTP 230 kV Line, Reconductor 6/1/2019 (5 yrs) 6/1/2014
Cape Fear-West End 230 kV West Line 6/1/2019 (3 yrs) 6/1/2016
Rockingham-Lilesville 230 kV Line, Add 3rd Line
06/1/2019 (8 yrs) 6/1/2011
777
List of Units Included in Base Case• Cliffside Coal – 825 MW• Buck Combined Cycle – 620 MW• Dan River Combined Cycle – 620 MW• Richmond County Combined Cycle – 660 MW• Wayne County CT – 160 MW
Planned New Generation Units
888
Resource Supply Options 2019 Hypothetical Transfer Scenarios
Resource From Sink Test Level (MW) Estimated Cost ($M)
NORTH – PJM (AEP) Duke 600 0
SOUTH - SOCO Duke 600 0
SOUTH – SCEG Duke 600 129
SOUTH – SCPSA Duke 600 0
EAST – Progress Duke 600 0
WEST - TVA Duke 600 0
NORTH – PJM (AEP) Progress (CPLE) 600 0
NORTH – PJM (DVP) Progress (CPLE) 600 0
SOUTH – SCEG Progress (CPLE) 600 0
SOUTH – SCPSA Progress (CPLE) 600 0
WEST - Duke Progress (CPLE) 600 0
NORTH – PJM (AEP/AEP) Duke / Progress (CPLE) 600 / 600 0/0
NORTH – PJM (AEP/DVP) Duke / Progress (CPLE) 600 / 600 0/0
EAST - Progress PJM (Dominion) 600 0
999
Resource Supply Options 2019 Hypothetical Transfer Scenarios
Results Except 600 MW South Carolina Electric & Gas (SCEG)
to Duke Transfer Scenario• Upgrade Parr-Newport Tie (Parr) 230 kV Line: $89 M• Upgrade Bush River Tie-Clinton Tie (Clinton) 100
kV Line: $40 M All transfer resource supply options can be
accommodated without additional projects.
101010
Resource Supply Options 2019 Nuclear Generation Scenarios
Company Location (County) MW’S
Duke Cherokee, SC 1160
Progress Wake, NC 1125
111111
Progress can accommodate an 1125 MW unit at Harris Nuclear Station without additional transmission upgrades
Duke can accommodate an 1160 MW unit at Lee Nuclear Station with one additional transmission upgrade• Bundle Lee Nuclear Station-Pacolet Tie (Roddey West)
230 kV Line: $12 M
Resource Supply Options 2019 Nuclear Generation Scenarios Results
121212
Comparison to Previous Collaborative Transmission Plan
2008 Plan 2009 Draft Plan
Number of projects with an estimated cost of $10 million or more each
16 18
Total estimated cost of Plan $520 M $595 M
131313
Import ScenariosPreliminary Major Projects in 2009 Plan
Reliability Project TO Planned I/S Date
Rockingham-West End 230 kV line Progress In-Service
Richmond 500 kV sub, reactor Progress In-Service
Asheville-Enka 230 kV line, Convert 115 kV line; and
Asheville-Enka 115 kV, Build new lineProgress
December ’10
December ’12
Rockingham-West End 230 kV East line Progress June ’11
Pleasant Garden-Asheboro 230 kV line, replace Asheboro 230 kV xfmrs
Progress
& Duke
June ’11
Ft Bragg Woodruff Street-Richmond 230 kV Line
Progress June ‘11
Clinton-Lee 230 kV line Progress Dec’11
141414
Import ScenariosPreliminary Major Projects in 2009 Plan (Continued)
Reliability Project TO Planned I/S Date
Brunswick 1 - Castle Hayne 230kV Line, Construct New Cape Fear River Crossing
Progress June ‘12
Jacksonville Static VAR Compensator Progress June ’12
Folkstone 230/115kV Substation Progress June ’13
Harris-RTP 230 kV line Progress June ’14
Greenville-Kinston Dupont 230 kV line Progress June ’17
Add 3rd Wake 500/230 kV xfmr Progress June ’18
Durham-RTP 230kV Line, Reconductor Progress June ‘ 19
Cape Fear-West End 230 kV West line, Install reactor
Progress June ’19
Rockingham-Lilesville 230 kV line Progress June ’19
151515
Import Scenarios
Preliminary Major Projects in 2009 Plan (Continued)
Reliability Project TO Planned I/S Date
Elon 100 kV Lines (Sadler Tie-Glen Raven Main #1 & #2, Reconductor
Duke June ‘11
Caesar 230 kV Lines (Pisgah Tie-Shiloh Switching Station #1 & #2), Reconductor
Duke June ‘13
London Creek 230 kV Lines (Peach Valley Tie-Riverview Sw. Station #1 & #2), Reconductor
Duke June ‘15
Fisher 230 kV Lines (Central-Shady Grove Tap #1 & #2), Reconductor
Duke June ‘17
18
1. Assumptions Selected2. Study Criteria Established3. Study Methodologies Selected 4. Models and Cases Developed5. Technical Analysis Performed6. Problems Identified and Solutions Developed7. Collaborative Plan Projects Selected8. Study Report Prepared
Study Process Steps
19
Study years- Short term (5 yr) and long term (10 yr)
base reliability analysis- Alternate model scenarios
Thermal power flow analysis - Duke & Progress contingencies- Duke & Progress monitored elements
• Internal lines• Tie lines
Collaborative Study Assumptions
20
LSEs provide:– Load forecasts and resource supply
assumptions– Dispatch order for their resources
Area interchange coordinated between Participants and neighboring systems
Study Inputs
21
TAG request to be distributed in early February, 2010
Requests can now include in, out and through transmission service
Enhanced Transmission Access Requests
22
Base reliability case analysis for 2015 summer and winter, and 2020 summer
An “All Firm Transmission” Case(s) will be developed which will include all confirmed long term firm transmission reservations with roll-over rights applicable to the study year(s).
Duke and Progress will each create their respective generation down cases from the common Base Case and share the relevant cases with each other.
Additional cases will be developed for different scenarios under a “climate change” legislation scenario
2010 Study
23
Proposed coal sensitivity scenario for 2015: Retire 100% of existing unscrubbed coal
generation plants (approximately 1,500MW in the PEC control area, 2,000MW in the Duke control area) by 2015, replace with new generation and/or imports
2010 Study
24
Proposed wind sensitivity scenarios for 2015:1. Coastal NC wind sensitivity with wind injections in the
following locations, based on information obtained from the UNC report:
– 2015 case, on peak:– Wilmington (30% capacity factor): 125 MW– Morehead City (40% capacity factor): 675 MW– Bayboro (35% capacity factor): 425 MW
2. 2015 case, off-peak (the final MW output studied at these locations will depend on a further assessment of loads during the off-peak case to verify operational limits and how much excess energy could be sold or exported):
– Wilmington (90% capacity factor): 375 MW– Morehead City (90% capacity factor): 1,500 MW– Bayboro (90% capacity factor): 1,125 MW
2010 Study
2828
What is the EIPC? Eastern Interconnection Planning Collaborative
• an open approach to addressing transmission analyses with an interconnection scale
Began through discussions between regional Planning Authorities
Backdrop• Broad energy policy discussions on future renewable
resources and on transmission infrastructure
• Historical development and coordination of transmission plans on a regional and super-regional basis
2929
What are the Objectives of the EIPC?
1. 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
30
The Collaborative is a combination of: Regional Planning Authorities participating
in a joint agreement to form an Analysis Team to perform technical studies
Federal, State and Provincial representatives
Self-formed stakeholder groups (e.g. Regional TO groups, IPPs, etc.)
Individual stakeholder participants
32
EIPC Structure
Eastern Interconnection Planning Collaborative (EIPC)
(Open Collaborative Process)
EIPC Analysis TeamPrincipal InvestigatorsPlanning Authorities
Steering Committee
Stakeholder Work Groups
Executive LeadershipTechnical Leadership
&Support Group
Stake-holder Groups
States Provinces FederalOwners
OperatorsUsers
…
33
EIPC Analysis Team structure in place 24 Planning Authorities signed – approximately 95%
of customers covered DOE funding proposal submitted; awaiting DOE
response Stakeholder dialog - webinar on October 13 with a
repeat on October 16 – over 400 participants Continued stakeholder discussion through beginning
of DOE study cycle Website launched – www.eipconline.com EIPC analysis processes begin in early 2010
– DOE work begins (if awarded)
EIPC Status
3535
SCRTP 2010 study PJM interface meeting SIRPP SERC-RFC East VACAR studies SERC LTSG 2009 Study TPL-001-1
3636
Two NCTPC related requests were submitted for study:
600 MW transfer from SCE&G to CPLE; 600 MW transfer from SCE&G to Duke;
No other requests were submitted
SC Regional Transmission Planning Process
4040
OTHER DISCUSSIONS
Generation interconnection queue coordination and how to identify projects that may impact each party
Modeling of generation dispatch in PJM and NCTPC footprints and its impact on study results
Identified PJM contacts to be included when dealing directly with AEP and DVP
Future studies under consideration
NCTPC-PJM
4141
NCTPC did not submit requests for study
5 studies were selected at the 10/27/09 meeting
Southeast Inter-Regional Planning Process (SIRPP)
4242
Entergy to Georgia ITS – 2000 MW
(2014, Step 2 Evaluation)
Type of Transfer: Generation to Generation
Source: Same as utilized in the Step 1 evaluation.
Sink: Same as utilized in the Step 1 evaluation.
SIRPP
4343
Entergy to Georgia ITS
Step 2 Evaluation
Detailed evaluation of the requested transfer Identify the final transmission enhancements to
resolve the identified constraints Provides detailed cost estimates and timelines
associated with the identified transmission enhancements
SIRPP
4444
MISO to TVA – 2000 MW
(2015, Step 1 Evaluation)
Type of Transfer: Load to Generation
Source: Uniform load scale of the MISO area.
Sink: Generation within TVA’s area.
SIRPP
4545
Northern Kentucky to Georgia ITS – 1000 MW (2015, Step 1 Evaluation)
Type of Transfer: Generation to Generation
Source: Three existing substations in Kentucky.
Sink: Generation within the Georgia ITS.
SIRPP
4646
MISO/PJM West (SMART) to SIRPP - 3000 MW
(2018, Step 1 Evaluation)
Type of Transfer: TBD to Generation
Source: Strategic Midwest Area Renewable Transmission study
Sink: Generation within the SIRPP. Generation will be allocated to the Participating Transmission Owners by the ratio of their load to the total load of all of the Participating Transmission Owners.
SIRPP
4848
SPP to SIRPP – 3000 MW via HVDC
(2018, Step 1 Evaluation)
Type of Transfer: TBD to Generation via single or multiple HVDC transmission lines
Source: TBD
Sink: Generation within the SIRPP. Generation will be allocated to the Participating Transmission Owners by the ratio of their load to the total load of all of the Participating Transmission Owners.
SIRPP
5050
Appraisal of the interregional transmission system performance during the 2014 summer period
Supports NERC reliability standard TPL-005-0 - Regional and Interregional Self-Assessment Reliability Reports
Transfers to/from PJM, the RFC portion of the Midwest ISO, and SERC East (Non-PJM-VACAR and CENTRAL)
The next NT/LT WG study will be performed in 2011 for the conditions expected during the 2021 summer period
SERC East-RFC Near-Term/Long-Term Working Group (SER NT/LT WG)
5151
2014 Summer Long-Term Study
SERC East import and export with PJM
Central (TVA) – 2500 MW Participation
VACAR – 2500 MW Participation
CP&LE 762.5 MW
Duke 1212.5 MW
Santee Cooper 212 MW
SCE&G 313 MW
SERC East-RFC Near-Term/Long-Term Working Group (SER NT/LT WG)
5252
2014 Summer Long-Term Study
SERC East import and export with MISO
VACAR – 5000 MW Participation
CP&LE 1525 MW
Duke 2425 MW
Santee Cooper 425 MW
SCE&G 625 MW
SERC East-RFC Near-Term/Long-Term Working Group (SER NT/LT WG)
5353
Key Facilities Index
Each of the facilities listed is key to the performance of the interregional transmission network. These facilities are most
responsive to the actions listed as change conditions.
SERC East-RFC Near-Term/Long-Term Working Group (SER NT/LT WG)
5555
Appraisal of the VACAR company transmission systems’ performance for the conditions expected during the 2015 summer period
Done in support of the NERC TPL reliability standards
(N-1) and (N-2) contingency analyses performed across VACAR while monitoring all of VACAR for thermal and voltage impacts
Final report to be published Summer 2010
VACAR Powerflow Working Group
5656
Appraisal of the VACAR company transmission systems’ dynamic performance for the conditions expected during the 2014 summer period
Done in support of the NERC TPL reliability standards
Voltage stability analyses with emphasis on category C contingencies using dynamic load models
Final report to be published Summer 2011 (2 years to allow for development of dynamic load models)
VACAR Stability Working Group
5757
Performed analysis of 2015 summer conditions
Evaluated interregional and inter-balancing area transfers
Evaluated base case for N-1 contingency thermal and voltage performance
SERC LTSG 2009 Study
58
Duke Significant Facilities
Parkwood 500/230 kV transformers Export CPLE, DVP
Riverview-Peach Valley 230 kV Lines Export SOCO, GTC, SCPSA
McGuire-Riverbend 230 kV Lines Import CPLE, Ameren
All limits to transfer were greater than 1100 MW
59
PEC Significant Facilities
Asheville 230/115 kV Import CPLE,DUKE,TVA
All limits to transfer were greater than 700 MW
60
NERC TPL-001-1 Standard Update
Standards Involved• TPL-001-0.1 (NERC A, No Contingency)• TPL-002-0a (NERC B, Single Contingency)• TPL-003-0 (NERC C, Multiple Contingency)• TPL-004-0 (NERC D, Extreme Contingency)• TPL-005-0 (RRO Regional and Interregional Studies)• TPL-006-0.1 (RRO Data, Reports, as requested by NERC)
Applicable Entities Involved• Planning Authority (Planning Coordinator) • Transmission Planner• Regional Reliability Organization
61
NERC TPL-001-1 Standard Update
Project ScopeCreate a new standard that:1. Has clear, enforceable requirements2. Is not a Least Common Denominator standard3. Addresses the issues raised in the SAR and issues raised by FERC and others
62
NERC TPL-001-1 Standard Update
OverviewR1: Modeling DataR2: Assessments
• Near-term Steady-State• Long-term Steady-State• Short Circuit• Near-term Stability• Long-term Stability • Qualified Past Studies• Corrective Action Plans• Corrective Action Plans Short Circuit• Largest Load Drop N-1
63
NERC TPL-001-1 Standard Update
Overview
R3: Steady-State StudiesR4: Stability StudiesR5: Voltage CriteriaR6: Cascade CriteriaR7: PC/TP ResponsibilitiesR8: PC/TP Peer Reviews
64
NERC TPL-001-1 Standard Update
Planning EventsPlanning Events• P0: Normal System (N-0)
• P1: Single Contingency (N-1)
• P2: Single Contingency (N-1) [Lower probability, higher impact]
• P3: Generator + 1 (N-2)
• P4: Stuck Breaker (N-2+)
• P5: Protection System Failure (N-2+)
• P6: Overlapping contingencies (N-1-1) [Non-gens, Two P1 Events]
• P7: Common Structure (N-2+)
65
NERC TPL-001-1 Standard Update
Planning EventsPlanning Events• Simulate the removal of all elements that Protection Systems
and other controls are expected to automatically disconnect for each event.
• Require Corrective Action Plans for inability to meet performance requirements
66
NERC TPL-001-1 Standard Update
• Category (P0, P1, … P7)
• Initial system condition
• Event
• Fault Type (3-phase or Single Line to Ground)
• BES Level (EHV or HV)
• Interruption of Firm Transmission Service Allowed
• Non-Consequential Load Loss Allowed
Planning Events, Table Components (Columns)Planning Events, Table Components (Columns)
67
NERC TPL-001-1 Standard Update
Planning EventsPlanning EventsConsequential Load Loss: All Load that is no longer served by the Transmission System as a result of Transmission Facilities being removed from service by a Protection System operation designed to isolate the fault.
Non-Consequential Load Loss: Non-Interruptible Load loss other than Consequential Load Loss and the response of voltage sensitive Load including Load that is disconnected from the System by end-user equipment.
68
NERC TPL-001-1 Standard Update
Areas where “bar was raised” for EHV• Single contingency (P1 and P2)• Generator + 1 (P3)• Stuck Breaker (P4)• Protection System Failure (P5)
69
NERC TPL-001-1 Standard Update
R1 (Modeling) and R7(Responsibilities) are effective 12 months after regulatory approval
All other requirements (R2 – R6 and R8) become effective 24 months after regulatory approval except for more stringent performance requirements
60 months before “raising the bar” performance becomes effective
70
NERC TPL-001-1 Standard Update
Team is responding to Draft 4 Comments
Expect some adjustments to standard for clarity
Team plans to ballot Draft 5
Plan to ballot in early Q1 2010• 30 day pre-ballot period• 10 day ballot period• Need to achieve quorum (75% of Registered Ballot Body)• Approval requires 2/3 approval from ballot body
72 1st Quarter 2nd Quarter 3rd Quarter 4th 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
73
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
Proposed 2010 TAG Work Plan
74
April - May TAG Meeting
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
75
June - July TAG Meeting 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
76
August - September TAG Meeting 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
77
December
2010 STUDY REPORT– Receive and comment on final draft of the 2010
Collaborative Transmission Plan report
TAG Meeting– 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
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