TAG Meeting
December 9, 2009
NCEMC Office
Raleigh, NC
1
TAG Meeting Agenda
1. 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
2
2009 – 2019 Collaborative Plan
Study Results
Joey West
Progress Energy
3
Outline of Results
 Base Reliability Results
• 2014 and 2019
 Progress Collaborative Plan Project Delays
 Hypothetical Resource Supply Options
• Transfer Scenarios
• Nuclear Generation Scenarios
4
2014S and 2019S
Base Reliability Results
 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
5
Progress Load Forecast Related
Collaborative Plan Project Delays
2009
Plan In-Service Date
2008
Plan In-Service
Date
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
Project
Clinton-Lee 230 kV Line
6
Planned New Generation Units
 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
7
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
8
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.
9
Resource Supply Options
2019 Nuclear Generation Scenarios
Company
Location (County)
MW’S
Duke
Cherokee, SC
1160
Progress
Wake, NC
1125
10
Resource Supply Options
2019 Nuclear Generation Scenarios Results
 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
11
Comparison to Previous
Collaborative Transmission Plan
Number of projects with an estimated
cost of $10 million or more each
Total estimated cost of Plan
2008 Plan
2009 Draft Plan
16
18
$520 M
$595 M
12
Import Scenarios
Preliminary 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
December ’10
Asheville-Enka 230 kV line, Convert
115 kV line; and
Asheville-Enka 115 kV, Build new line
Progress
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
December ’12
13
Import Scenarios
Preliminary Major Projects in 2009 Plan (Continued)
Reliability Project
TO
Planned I/S Date
Brunswick 1 - Castle Hayne 230kV Line, Progress
Construct New Cape Fear River Crossing
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
14
Import Scenarios
Preliminary Major Projects in 2009 Plan (Continued)
Reliability Project
Elon 100 kV Lines (Sadler Tie-Glen
Raven Main #1 & #2, Reconductor
Caesar 230 kV Lines (Pisgah Tie-Shiloh
Switching Station #1 & #2), Reconductor
London Creek 230 kV Lines (Peach
Valley Tie-Riverview Sw. Station #1 & #2),
Reconductor
Fisher 230 kV Lines (Central-Shady
Grove Tap #1 & #2), Reconductor
TO
Planned I/S Date
Duke
June ‘11
Duke
June ‘13
Duke
June ‘15
Duke
June ‘17
15
16
2010 NCTPC Study
Scope
James Manning
North Carolina EMC
17
Study Process Steps
1.
2.
3.
4.
5.
6.
7.
8.
Assumptions Selected
Study Criteria Established
Study Methodologies Selected
Models and Cases Developed
Technical Analysis Performed
Problems Identified and Solutions Developed
Collaborative Plan Projects Selected
Study Report Prepared
18
Collaborative Study Assumptions
 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
19
Study Inputs
 LSEs provide:
– Load forecasts and resource supply
assumptions
– Dispatch order for their resources
 Area interchange coordinated between
Participants and neighboring systems
20
Enhanced Transmission
Access Requests
 TAG request to be distributed in early
February, 2010
 Requests can now include in, out and
through transmission service
21
2010 Study
 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
22
2010 Study
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
23
2010 Study
 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
24
25
Update on Regional Studies
26
Eastern Interconnection
Planning Collaborative (EIPC)
Ed Ernst
Duke Energy Carolinas
27
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
28
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
29
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
30
Who are the Planning Authorities?
•
•
•
•
•
•
•
•
•
•
•
•
•
Alcoa Power Generating
•
American Transmission Co.
•
Duke Energy Carolinas
•
Entergy *
•
E.ON (Louisville/Kentucky
Util.)
•
Florida Power & Light
•
Georgia Transmission Corp. •
IESO (Ontario, Canada)
•
International Transmission Co.•
ISO-New England *
•
JEA (Jacksonville, Florida)
•
MAPPCOR *
Midwest ISO *
Municipal Electric Authority of
Georgia
New York ISO *
PJM Interconnection *
PowerSouth Energy Coop.
Progress Energy – Carolinas
Progress Energy – Florida
South Carolina Electric &Gas
Santee Cooper
Southern Company *
Southwest Power Pool
Tennessee Valley Authority *
31
EIPC Structure
Eastern Interconnection Planning Collaborative (EIPC)
(Open Collaborative Process)
Steering Committee
EIPC Analysis Team
Principal Investigators
Planning Authorities
Executive Leadership
Technical Leadership
&
Support Group
Stakeholder
Work Groups
Stakeholder
Groups
States
Provinces
Federal
Owners
Operators
Users
…
32
EIPC Status
 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)
33
Other Regional Study
Activities
Bob Pierce
Duke Energy Carolinas
34
 SCRTP 2010 study
 PJM interface meeting
 SIRPP
 SERC-RFC East
 VACAR studies
 SERC LTSG 2009 Study
 TPL-001-1
35
SC Regional Transmission
Planning Process
 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
36
NCTPC-PJM
Seams Interface Meeting
37
NCTPC-PJM
Trail Project - 2011
38
NCTPC-PJM
Path Project - 2014
39
NCTPC-PJM
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
40
Southeast Inter-Regional
Planning Process (SIRPP)
 NCTPC did not submit requests for study
 5 studies were selected at the 10/27/09 meeting
41
SIRPP
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.
42
SIRPP
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
43
SIRPP
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.
44
SIRPP
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.
45
SIRPP
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.
46
SIRPP
47
SIRPP
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.
48
SERC East-RFC Near-Term/Long-Term
Working Group (SER NT/LT WG)
49
SERC East-RFC Near-Term/Long-Term
Working Group (SER NT/LT WG)
 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
50
SERC East-RFC Near-Term/Long-Term
Working Group (SER NT/LT WG)
2014 Summer Long-Term Study
SERC East import and export with PJM
 Central (TVA) – 2500 MW Participation
 VACAR – 2500 MW Participation
CP&LE
Duke
Santee Cooper
SCE&G
762.5
1212.5
212
313
MW
MW
MW
MW
51
SERC East-RFC Near-Term/Long-Term
Working Group (SER NT/LT WG)
2014 Summer Long-Term Study
SERC East import and export with MISO
 VACAR – 5000 MW Participation
CP&LE
Duke
Santee Cooper
SCE&G
1525
2425
425
625
MW
MW
MW
MW
52
SERC East-RFC Near-Term/Long-Term
Working Group (SER NT/LT WG)
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.
53
Key Facilities
Outages
Generation
Transfers
McGuire-Riverbend 230 kV #2
McGuire-Riverbend 230 kV #1
McGuire 500 kV PJM to SERC East
& 230 kV
Allen 230 kV & PJM to Non-PJM-VACAR
100 kV
Catawba 230 kV RFC-MISO to SERC East
RFC-MISO to
Non-PJM-VACAR
Clover 500/230 kV #1
Transformer
Wake-Carson 500 kV
Clover 500 kV
Clover-Farmville 230 kV & Farmville
230/115 kV #1 Transformer
SERC East to PJM
Non-PJM-VACAR to PJM
SERC East to RFC-MISO
Non-PJM-VACAR to
RFC-MISO
Antioch 500/230 kV #2
Transformer
Antioch 500/230 kV #1 Transformer
McGuire 500 kV PJM to Non-PJM-VACAR
& 230 kV
Belews Creek
230 kV
MISO to Non-PJMVACAR
54
VACAR Powerflow Working Group
 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
55
VACAR Stability Working Group
 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)
56
SERC LTSG 2009 Study
 Performed analysis of 2015 summer conditions
 Evaluated interregional and inter-balancing area
transfers
 Evaluated base case for N-1 contingency thermal
and voltage performance
57
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
58
PEC Significant Facilities
Asheville 230/115 kV
Import
CPLE,DUKE,
TVA
All limits to transfer were greater than 700 MW
59
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
60
NERC TPL-001-1 Standard Update
Project Scope
Create a new standard that:
1. Has clear, enforceable requirements
2. Is not a Least Common Denominator standard
3. Addresses the issues raised in the SAR and issues
raised by FERC and others
61
NERC TPL-001-1 Standard Update
Overview
R1: Modeling Data
R2: 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
62
NERC TPL-001-1 Standard Update
Overview
R3:
R4:
R5:
R6:
R7:
R8:
Steady-State Studies
Stability Studies
Voltage Criteria
Cascade Criteria
PC/TP Responsibilities
PC/TP Peer Reviews
63
NERC TPL-001-1 Standard Update
Planning Events
• P0:
• P1:
• P2:
• P3:
• P4:
• P5:
• P6:
• P7:
Normal System (N-0)
Single Contingency (N-1)
Single Contingency (N-1) [Lower probability, higher impact]
Generator + 1 (N-2)
Stuck Breaker (N-2+)
Protection System Failure (N-2+)
Overlapping contingencies (N-1-1) [Non-gens, Two P1 Events]
Common Structure (N-2+)
64
NERC TPL-001-1 Standard Update
Planning 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
65
NERC TPL-001-1 Standard Update
Planning Events, Table Components (Columns)
• 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
66
NERC TPL-001-1 Standard Update
Planning Events
Consequential 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 enduser equipment.
67
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)
68
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
69
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
70
2010 TAG Work Plan
Rich Wodyka
Independent Consultant
71
2010 Overview Schedule
Reliability Planning Process
 Evaluate current reliability problems and transmission upgrade plans
 Perform analysis, identify problems, and develop solutions
 Review Reliability Study Results
Enhanced Access Planning Process
 Propose and select enhanced access scenarios and interface
 Perform analysis, identify problems, and develop solutions
 Review Enhanced Access Study Results
Coordinated Plan Development
 Combine Reliability and Enhanced Results
 OSC publishes DRAFT Plan
 TAG review and comment
TAG Meetings
1st Quarter
2nd Quarter
3rd Quarter
4th Quarter
72
Proposed 2010 TAG Work Plan
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
73
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
74
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
75
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
76
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
77
78
TAG
Open Forum Discussion
79