11 tag meeting august 27, 2009 electricities office raleigh, nc
TRANSCRIPT
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TAG MeetingAugust 27, 2009
ElectriCities Office
Raleigh, NC
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TAG Meeting Agenda1. Introductions and Agenda – Rich Wodyka
2. Attachment K FERC Ruling – Kendall Bowman
3. 2009 Study Scope Update and Status – Bob Beadle
4. 2009 Study Preliminary Results – Bob Beadle
5. Major Transmission Project Update – Sam Waters
6. Regional Studies – Bob Pierce• EIPC Activities – Ed Ernst• NC Commission Report – Kim Jones
7. TAG Scope – Proposed Changes – Rich Wodyka
8. TAG Work Plan – Rich Wodyka
9. TAG Open Forum – Rich Wodyka
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Duke and Progress Attachment K Compliance
Filing
Kendal Bowman
Progress Energy
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FERC Duke/Progress Attachment K Order – June 18, 2009
Duke/Progress Request for Clarification or in Alternate, Rehearing – July 20, 2009
Duke/Progress Attachment K Filing – August 17, 2009
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Duke/Progress Request for Clarification or in Alternate, Rehearing
• Duke/Progress had included wording in the SIRPP area of the tariff stating that resource specific confidential information would not be made available due to the competitively sensitive nature of the data.
• FERC ordered that this information must be released, under applicable confidentiality provisions, if the information is needed to participate in the transmission planning process and/or to replicate transmission planning studies.
• Duke/Progress Request for Clarification or in Alternate Rehearing seeks to clarify that the confidentiality agreements may restrict the availability of competitive confidential information, such that it is only available to non-merchant function personnel.
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Duke/Progress Attachment K Filing
• Added tariff language stating that the TAG “Eligible Customers and Ancillary Service Providers” Sector can include demand response providers.
• Added language that describes the process that the NCTPC will use to evaluate competing solutions submitted in the transmission planning process.
- Requires that the TAG participants submit information (cost, performance, lead time to install, etc.) associated with an alternative solution so that it can be compared to the transmission solution.
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Duke/Progress Attachment K Filing (cont.)
Changes required related to acquiring data:
• Acquiring CEII data:- Removed requirement to obtain Form 715 approval from
FERC before the release of CEII data.
- NCTPC and SIRPP will now administer the approval process for obtaining CEII data.
• Removed provisions within the SIRPP area that had afforded special protections of release of non-public utility transmission provider data.
• Revised tariff language related to the release of competitively sensitive data, under appropriate confidentiality agreements (as explained in the Request for Clarification, or in Alternate Rehearing slide).
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NCTPC 2009 Study Scope Update and Status
Bob Beadle
North Carolina EMC
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Assess Duke and Progress transmission systems' reliability and develop a single Collaborative Transmission Plan
Also assess Enhanced Access Study requests provided by Participants or TAG members
Purpose of Study
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Study Year – near term reliability analysis:• 2014 Summer, 2014/2015 Winter• 2014 Summer – high import sensitivity to CPLW
Study Year – longer term reliability analysis:• 2019 Summer
LSEs provided: • Input for load forecasts • Resource supply assumptions
Interchange coordinated between Participants and neighboring systems
Study Assumptions Selected
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Study Criteria Established
NERC Reliability Standards• Current standards for base study screening• SERC Requirements
Individual company criteria
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Study Methodologies Selected
Similarities to previous studies:• Thermal Power Flow Analysis• Voltage, stability, short circuit, phase
angle analysis - as needed
Sensitivity to examine the use of high temperature conductor on the DEC Caesar (Shiloh-Pisgah) 230kV line
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Latest available MMWG cases were selected and updated for study years (change made from previous studies to incorporate latest PJM transmission upgrades)
Combined detailed model for Duke and Progress was prepared
Planned transmission additions from updated 2008 Plan were included in models
Base Case Models Developed
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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
Steps and Status of the Study Process
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Hypothetical imports• To Duke• To Progress• To Duke and Progress
Hypothetical export: CPLE to PJM
Resource Supply Options Selected
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Hypothetical Import/Export ScenariosResource From Sink Test Level (MW)
NORTH – PJM (AEP) Duke 600
SOUTH – SOCO Duke 600
SOUTH – SCEG Duke 600
SOUTH – SCPSA Duke 600
EAST – Progress Duke 600
WEST – TVA Duke 600
NORTH – PJM (AEP) Progress (CPLE) 600
NORTH – PJM (DVP) Progress (CPLE) 600
SOUTH – SCEG Progress (CPLE) 600
SOUTH – SCPSA Progress (CPLE) 600
WEST – Duke Progress (CPLE) 600
NORTH – PJM (AEP/AEP) Duke / Progress (CPLE) 600 /600
NORTH – PJM (AEP/DVP) Duke / Progress (CPLE) 600 /600
EAST-Progress PJM (Dominion) 600
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Bob BeadleNorth Carolina EMC
NCTPC 2009 Study Preliminary Results
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2014 Summer No new issues identified in Eastern or Western Areas
• Projects already in the Collaborative Plan to address network loadings
2014-15 Winter Issues identified in Western Area
• Pisgah 115/110kV Transformers• Asheville-DPC Pisgah 230kV Lines, Up-rate
2019 Summer No new issues identified in Eastern or Western Areas
Preliminary Base Case Results – Progress Energy
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Contingencies and Year Upgrade Needed: Transformer replacement (loss of parallel bank)
• Pisgah 115/100kV transformer, 2018• Sadler 230/100kV transformer, 2018 (presently
scheduled for 2016) Upgrades needed for loss of a parallel line:
• Davidson River 100kV line, 2014• Fisher 230kV line, 2016• Norman 230kV line, 2018• London Creek 230kV line, 2015
Preliminary Base Case Results - Duke
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Davidson River 100kV, Fisher 230kV, and London Creek 230kV Lines are affected in the high summer import from CPLE to CPLW transfer sensitivity case.
High import from CPLE causes significant acceleration of projects from outside the planning horizon to inside planning horizon.
Preliminary Base Case Results – Duke (effects of high import sensitivity)
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Caesar 230kV Line Project:• Using high temperature conductor to rebuild the
Caesar 230 kV (Shiloh-Pisgah) Lines only significantly affects the Davidson River 100 kV Lines
• Results show that, with use of the high temperature conductor and the high summer import from CPLE to CPLW transfer, reconductor of the Davidson River Lines is required prior to 2014, which may not be feasible
• Duke is exploring use of operating procedures to alleviate the loading on the Davidson River Lines
Preliminary Base Case Results - Duke (effects of high temperature conductor)
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• 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 September 18, 2009 to ITP ([email protected])
TAG Input Request
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Collaborative Plan Projects Selected Compare all alternatives and select
preferred solutions
Study Report Prepared Prepare draft report and distribute to
TAG for review and comment
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Sam Waters
Progress Energy
Major Transmission Project Update
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Contains 7 Progress Energy project in-service date changes that are driven by a reduction in Eastern Area load forecast
Description of changes in load forecast for Duke and Progress
2009 Mid-Year Update to the 2008 Collaborative Transmission Plan
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Import ScenariosMajor Projects in 2008 Plan
Reliability Project TO Planned I/S Date
Rockingham-West End 230 kV line, Tap Progress In-service
Richmond 500 kV sub, reactor Progress December ’09
Asheville-Enka 230 kV line, Convert 115 kV line; &
Asheville-Enka 115 kV, Build new lineProgress
December ’10
December ’12
Rockingham-West End 230 kV East line Progress June ’11
Richmond-Ft Bragg Woodruff Street 230 kV Line
Progress June ‘11
Pleasant Garden-Asheboro 230 kV line, replace Asheboro 230 kV xfmrs
Progress
& Duke
June ’11
Jacksonville Static VAR Compensator Progress June ’12
Clinton-Lee 230 kV line Progress January ’13 (delayed from ’10)
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Import ScenariosMajor Projects in 2008 Plan (Continued)
Reliability Project TO Planned I/S Date
Folkstone 230/115kV Substation Progress June ’13
Harris-RTP 230 kV line Progress June ’14 (delayed from’11)
Greenville-Kinston Dupont 230 kV line Progress June ’17(delayed from ’13)
Add 3rd Wake 500/230 kV xfmr Progress June ’18(delayed from ’13)
Cape Fear-West End 230 kV West line, Install reactor
Progress June ’19(delayed from ’16)
Durham-RTP 230kV Line, Reconductor Progress June ’19(delayed from ’14)
Rockingham-Lilesville 230 kV line Progress June ’19 (delayed from ’11)
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Import ScenariosMajor Projects in 2008 Plan (Continued)
Reliability Project TO Planned I/S Date
Sadler Tie-Glen Raven Main Circuit 1 & 2 (Elon 100 kV Lines), Reconductor
Duke June ‘11
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Eastern Area Growth Slower than ProjectedProgress Energy
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Western Area Growth Faster than ProjectedProgress Energy
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Load Forecast RevisionsProgress Energy
Difference between 2008 Forecast and 2009 Forecast
Summer Forecast Winter Forecast PEAK MW PEAK MW YEAR SYSTEM EAST WEST YEAR SYSTEM EAST WEST 2009 -539 -566 27 2009/10 -303 -386 82 2010 -505 -525 20 2010/11 -359 -442 83 2011 -565 -583 18 2011/12 -396 -482 86 2012 -640 -658 18 2012/13 -372 -457 86 2013 -616 -642 26 2013/14 -391 -477 87 2014 -644 -671 27 2014/15 -395 -481 87 2015 -648 -678 30 2015/16 -427 -515 88 2016 -683 -713 30 2016/17 -446 -535 89 2017 -705 -736 31 2017/18 -470 -561 91 2018 -734 -766 32 2018/19 -487 -580 93 2019 -754 -787 33 2019/20 -504 -598 95 2020 -774 -808 34 2020/21 -511 -608 97
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Load Forecast RevisionsProgress Energy
Eastern Area load reduction of 671 MW • Approximately 50% is Wholesale• 100 MW’s is DSM and Energy Efficiency• Remainder is loss of Industrial customers and a decline in
Commercial Loads
Western Area increase of 87 MW • Peak loads have exceeded previous year projections• Industrial & Residential sectors have remained stable in WNC
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Load Forecast RevisionsDuke Energy
Decrease in load of 400-500 MW or approximately 2 years of load growth
Going forward Duke would normally expect to see an annual increase of 225-250 MW/year
With the economic downturn and the decrease in new residential connections the rate of load growth is expected to be lower than in the past.
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Bob Pierce – Duke Energy
Regional Studies Reports
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Stakeholders requested the following studies:• Entergy to Georgia ITS (2000 MW)• SPP to SIRPP footprint (5000 MW)• PJM “classic” to Southern (3000 MW)• PJM west to Southern (2000 MW)• Southern to PJM “classic” (3000 MW)
Southeast Inter-Regional Participation Process (SIRPP) Status Update
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SIRPP Status UpdateSIRPP Transfers - Potential Solution Summary
Entergy Facilities Southern
FacilitiesTVA
FacilitiesDuke
FacilitiesSCE&G
FacilitiesPEC
FacilitiesTotal Cost
Entergy to ITS-2000 MW
2 – 230 kV 6 – 161 kV 3 – 115/138 kV
4 – 500 kV5 – 230 kV2 – 115 kV
1 – 500 kV6 – 161 kV
NoneReported
NoneReported
NoneReported
Cost $238,950,000 $247,800,000 $91,500,000 $0 $0 $0 $578,250,000
SPP to SIRPP- 5000 MW
2 – 345/500 kV2 – 161 kV9 – 115/138 kV
5 – 500 kV6 – 230 kV2 – 115 kV
1 – 500 kV1 – 230 kV7 – 161 kV
2 – 500 kV NoneReported
NoneReported
Cost $233,500,000 $309,900,000 $173,200,000 $139,400,000 $0 $0 $856,000,000
PJM Classic to Southern- 3000 MW
NoneReported
4 – 500 kV6 – 230 kV
1 – 500 kV1 – 230 kV4 – 161 kV
1 – 230 kV NoneReported
NoneReported
Cost $0 $289,900,000 $96,200,000 $51,400,000 $0 $0 $437,500,000
PJM West to Southern- 2000 MW
NoneReported
4 – 500 kV4 – 230 kV
1 – 500 kV5 – 161 kV 1 – 230 kV None
ReportedNone
Reported
Cost $0 $275,200,000 $90,500,000 $51,400,000 $0 $0 $417,100,000
Southern to PJM Classic- 3000 MW
1 – 230 kV6 – 161 kV4 – 115/138 kV
2 – 230 kV1 – 115 kV
1 – 500 kV12 – 161 kV 1 – 230 kV 1 – 230 kV 1 – 230 kV
Cost $229,250,000 $1,675,000 $192,130,000 $32,000,000 $4,300,000 $500,000 $459,855,000
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SIRPP Status UpdateTransfer
SensitivityTransferAmount
TransferSource
TransferSink
StudyYear
SPP - SIRPP 5000 MW SPP SIRPP 2014
Thermal Loadings %
AREA Limiting ElementRating (MVA)
WithoutRequest
WithRequest
Contingency Scenario Project
Duke 500/230 kV Antioch transformer 2/1 840 77.6 99.0 500/230 kV Antioch transformer 1/2 1 P1Duke McGuire 500/230 kV transformer 1680 75.1 93.7 Woodleaf – Pleasant Garden 500 kV 2 P2
Scenario Explanations:1 – Belews Creek 1 unit out2 – McGuire Nuclear Unit 1 out
Item Potential Solution Estimated Need Date EstimatedCost
P1 Replace 840 MVA Antioch 500/230 kV transformers with 1680 MVA banks
6/1/2015 $59,400,000
P2Construct new Dooley Tie 500/230 kV station between McGuire and Woodleaf stations
6/1/2019 $80,000,000
TOTAL ($2014) $139,400,000
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SIRPP Status Update
Thermal Loadings %
AREA Limiting ElementRating (MVA)
WithoutRequest
WithRequest
Contingency Scenario Project
Duke Peach Valley – Riverview 230 kV Ckt 1/2 452.5 92.2 107.3 Peach Valley – Riverview 230 kV Ckt 2/1 1 P1
Scenario Explanations:1 – Oconee Nuclear Unit 1 or 2 out
Item Potential Solution Estimated Need Date EstimatedCost
P1 Reconductor 20 mile Peach Valley-Riverview 230 kV Lines to bundled 795 ACSR
6/1/2014 $51,400,000
TOTAL ($2014) $51,400,000
TransferSensitivity
TransferAmount
TransferSource
TransferSink
StudyYear
PJM Classic to SOCO 3000 MW PJM Classic Southern 2014
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SIRPP Status Update
Thermal Loadings %
AREA Limiting ElementRating (MVA)
WithoutRequest
WithRequest
Contingency Scenario Project
Duke Peach Valley – Riverview 230 kV Ckt 1/2 452.5 92.2 100.2 Peach Valley – Riverview 230 kV Ckt 2/1 1 P1
Scenario Explanations:1 – Oconee Nuclear Unit 1 or 2 out
Item Potential Solution Estimated Need Date EstimatedCost
P1 Reconductor 20 mile Peach Valley-Riverview 230 kV Lines to bundled 795 ACSR
6/1/2014 $51,400,000
TOTAL ($2014) $51,400,000
TransferSensitivity
TransferAmount
TransferSource
TransferSink
StudyYear
PJM West to SOCO 3000 MW PJM West Southern 2014
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SIRPP Status Update
Thermal Loadings %
AREA Limiting ElementRating (MVA)
WithoutRequest
WithRequest
Contingency Scenario Project
Duke Central Tie – Shady Grove Tap 230 kV Ckt 1/2 506.7 90 98.4 Central Tie – Shady Grove Tap 230 kV Ckt 2/1 1 P1
Scenario Explanations:1 – Broad River Energy Center 1 unit out
Item Potential Solution Estimated Need Date EstimatedCost
P1 Reconductor 18 mile Central Tie – Shady Grove Tap 230 kV Lines to bundled 954 ACSR
2016 $32,000,000
TOTAL ($2014) $32,000,000
TransferSensitivity
TransferAmount
TransferSource
TransferSink
StudyYear
SOCO to PJM Classic 3000 MW Southern PJM Classic 2014
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Next steps Website Link : www.southeastirpp.com
SIRPP Status Update
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Completed 2009 Series models Supporting development of 2009 Series
ERAG – MMWG powerflow and stability models• Coordinated tie lines and interchange• Submitting 10 years of model data for each
region in the Eastern Interconnection• Powerflow models to be completed in November• Stability models to be completed in
December/January
SERC LTSG (Long-term Study Group)
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LTSG 2015S Study
Base case analysis of bulk energy transfers
N-1 AC analysis of base case and sub-regional transfers
Report is being compiled and should be available in December
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Response to comments on the third draft of the standard should be available within the next month.
A fourth posting of the standard will also be issued in response to industry comments and discussion with FERC staff
Comments will be received on the fourth posting
NERC TPL001-1
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One of the questions being asked on the fourth posting questionnaire is whether stakeholders believe the standard is ready for ballot.
The goal is to have the balloted, approved standard to the NERC BOD by the end of the year.
NERC TPL001-1
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Date & Time: September 18, 2007 at 05:14:54 CDT
Lowest / Highest Frequencies
• 58.43 Hz at approximately 5:21:38 CDT
• 60.87 Hz at approximately 5:21:26 CDT
Load Loss - 18 MW in Island #1
- 770 MW in Island #2
Generation Loss
• 20 conventional generators in 12 plants – 2311 MW capacity
• 9 distributed generation locations – 860 MW capacity at risk
MRO September 18, 2007 Event
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Transmission Involved • 5 – 345 kV lines • 1 – 345/115 kV transformer • 2 – 345/161 kV transformers • 9 – 230 kV lines • 2 – 161 kV lines • 12 – 115 kV lines • 4 – 69 kV lines
System Recovery • First Island resynchronized – 8 minutes, 11 seconds • Second Island resynchronized – 58 minutes, 14 seconds • All load was recovered by 12:30:40 CDT
Major Contributory Factors
• Failure of splice and conductor on 345 kV line • Failure of protection on second 345 kV line • Generation over-frequency trip set points
MRO September 18, 2007 Event
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The event had the following major phases:
• Multiple 345 kV line contingencies occurred within the first 38 seconds of the event. Specifically, both 345 kV lines that form the Minnesota-Wisconsin Stability Interface (MWSI) tripped and locked out within the first 38 seconds of the initiation of the event. There was insufficient time after the first 345 kV line trip to re-adjust the system for the second trip. Preliminary analysis indicates that after both lines had tripped, the system was operating beyond dynamic stability, voltage, and thermal limits.
• North Dakota, Minnesota, Manitoba, part of South Dakota, and Saskatchewan separated from the Eastern Interconnection.
• Saskatchewan then separated from Manitoba and North Dakota.
• Saskatchewan lost a significant amount of load and generation.
MRO September 18, 2007 Event
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The event had the following major phases (continued):
• Rapid coordinated reductions to generation and the DC schedule in Manitoba allowed the frequency in the first island to return to near 60 Hz. This action enabled quick restoration and stabilization of the bulk power system in the North Dakota, South Dakota, Minnesota, and Manitoba area.
• Various MRO entities in the first island were reconnected to the Eastern Interconnection in less than 10 minutes through automatic reclosing (with synchro-check) of a number of the open transmission lines between that island and the Eastern Interconnection.
• Both islands were reconnected to the Eastern Interconnection within 59 minutes.
MRO September 18, 2007 Event
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The following NERC and industry recommendations significant to planning were made:
• That the NERC Resources Committee review the primary governor response on the Eastern Interconnection.
• That NERC, the Regional Entities, Planning Authorities, and Reliability Coordinators develop a method to thoroughly review and check data for interconnection-wide power system dynamic models for data errors – review and correct data errors with owners, and disseminate corrections to planners, transmission operators, and reliability coordinators throughout the interconnection.
• That NERC initiate a dynamic model validation regime of the generators and other dynamic responsive equipment to benchmark the models against observed behavior during system disturbances.
MRO September 18, 2007 Event
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The following NERC and industry recommendations significant to planning were made (continued):
• That NERC issue an alert for generation owners to review the over and under frequency generator protection settings of all units 20 MVA and above, to assure that they coordinate with their regional under-frequency or ride-through requirements. This review should be performed whenever generator protection modifications are made to such units.
• That NERC develop a standard/requirement regarding reporting electrical, dynamics and machine and plant protection characteristics of non-conventional (e.g., wind, solar, small hydro) generation data for use by the planning and reliability coordinators, with a threshold of 1 MW per unit.
MRO September 18, 2007 Event
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Eastern Interconnection Planning Collaborative (EIPC)
Ed Ernst – Duke Energy
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EIPC Challenge
How to provide meaningful response to national Energy Policy discussions which have had an interconnection-wide focus?
EIPC Opportunity
Build upon the Transmission expansion plans in the Eastern Interconnection which are developed and extensively coordinated on a regional and super-regional basis.
Create an EIPC process focused on inter-regional opportunities for enhancing Regional Transmission expansion plans.
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EIPC Success Factors Broad stakeholder involvement –
open, transparent, inclusive A significant role for state and
provincial representatives Federal acceptance of the process A collaborative “grass roots”
approach building on existing regional processes
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EIPC VisionThe Collaborative is a combination of:
Self-formed stakeholder groups (e.g. Transmission Owners, Generation Developers, etc.)
Individual stakeholder participants Federal, State and Provincial representatives Regional planning authorities participating as the Analysis
Team to perform the technical analyses
The Analysis Team: Performs studies and writes draft reports on findings Is comprised of planning authority representatives Facilitates the overall collaborative process - ensures
resources are available to organize and run the open format workshops, meetings, and other processes
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Eastern Interconnection Planning Collaborative (EIPC)
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DRAFT EIPC Process Flow
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EIPC Status 39 planning authorities engaged
• All ISO/RTOs in the Eastern Interconnection• 2 Canadian planning authorities• Includes 9 planning authorities in Florida
monitoring progress through FRCC Developing draft proposals for overall process
• EIPC stakeholder discussions in Fall Actively working with state representatives
and NARUC to continue development of the EIPC process
Developing a proposal to DOE for funding
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DOE Funding Opportunity Resource Assessment and Interconnection-
Level Transmission Analysis and Planning• Topic A – Interconnection-Level Analysis and Planning
• Topic B – Cooperation among States on Electric Resource Planning and Priorities
Planning Authorities in EIPC are preparing a bid on Topic A for the Eastern Interconnection
State representatives are preparing a bid on Topic B
Deadline September 14 (30-day extension)
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DOE Proposal Direction Use EIPC concept and process
• Roll-up of regional plans as starting point is fundamental
• DOE effort a subset of potential EIPC activities - although will likely be the main focus during length of contract
Address ten Topic A requirements in the FOA• Interconnection-wide, transparent, public, multi-
constituency, 1/3 State representation, multi-technology, 6/30/2011 & 6/30/2013 deliverables
• https://www.fedconnect.net/FedConnect/PublicPages/PublicSearch/Public_Opportunities.aspx
• FOA Reference #: DE-FOA-0000068
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Timing and Next Steps FERC Technical Conferences on Regional
Planning
• September 10 (Southeast)
• September 21 (Midwest and East)
DOE proposal due September 14
EIPC Stakeholder meeting(s)/discussions in Fall 2009
EIPC analysis processes begin in early 2010 • DOE work begins (if awarded)
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A Proposal for DOE Funding
NC Commission ReportKim Jones
NC Commission Staff
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• Topic A: Interconnection-level analysis and planning– PJM organizing
transmission planning entities in the eastern interconnection
• Topic B:
Cooperation among states on electric resource planning and priorities– State commissions are
organizing a grant proposal
– North Carolina is participating
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• National Association of Regulatory Utility Commissions (NARUC) is developing a grant proposal for an “Eastern Interconnection Council of States and Provinces”
• Each State in the Eastern Interconnection has two representatives to the Council
• Proposal due to DOE on 9/14/09• Awards to be made 12/31/09• DOE funding for 3-5 years, but project on-
going
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• Develop inputs and scenarios to be studied by the Topic A funding winner (that is, the actual transmission planners)
• Participate on Topic A’s Steering Group• React to study results with economic and
environmental implications• Attempt to reach consensus among states
and provinces regarding generation and transmission options
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• Commissioner Lauren Azar (Wisc), Commissioner Doug Nazarian (Maryland), and Commissioner John McKinney (WV) providing leadership, leaning on staff at NARUC, OPSI and Org. of MISO States
• 7/31/09 Letter of support stated that NC Utilities Commission Chairman Finley and Dept. of Commerce Assistant Sec. of Energy John Morrison would represent NC
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• NARUC would be the grant recipient and administrator – would contract with NRRI (National Regulatory Research Institute) to be the legal employer of EICSP staff
• Staff would be hired at the direction of an Executive Committee– Anticipate they’ll hire an executive director
and two staff people (economist/analyst and engineer)
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• Pay staff– Scott Hempling of NRRI would act as
facilitator until staff can be hired
• Reimburse 40 states for travel and meeting costs
• Conduct studies such as:– Integration of intermittent generation into grid– Availability of low-carbon generation– “Potential” of energy efficiency, etc.
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• Identify renewable energy zones/generation zones (Midwest/on-shore wind versus East Coast/offshore wind?)
• Agree on assumptions regarding carbon legislation and a national renewable energy portfolio standard
• Decide governance issues– What is “consensus”?– What if Council can’t reach consensus?– WV Commissioner McKinney chairing
Governance Committee (NC is a member)
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Rich Wodyka
ITP
TAG Scope – Proposed Changes
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TAG Scope Proposed Changes
Typos and Edits
Establishment of TAG meeting agenda
Vendor presentations at TAG meetings
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Typos and Edits
ITP – independent third party (3 edits)
Page 3 – NCTPC not NCPTPC
Page 5 – total not totals
Page 5 – may not will
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Establishment of TAG meeting agenda
Page 3 Meeting Procedures – Meeting Chair
Clarifies that the ITP establishes and distributes the TAG meeting agenda among other duties and responsibilities
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Vendor presentations at TAG meetings Page 4 Meeting Procedures – Meetings Clarifies that TAG meetings are not a forum
for vendor presentations unless the vendor is specifically providing an alternative solution to a specific problem or issue identified in the NCTPC study results.
Vendors interested in providing information on their latest technology improvements and solutions are encouraged to make separate arrangements to meet with any interested Participant at a time and location mutually agreeable to the respective parties.
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Rich Wodyka
ITP
2009 TAG Work Plan Review
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8383 1st Quarter 2nd Quarter 3rd Quarter 4th Quarter
Perform analysis, identify problems, and develop solutions
Review Reliability Study Results
Evaluate current reliability problems and transmission upgrade plans
Reliability Planning Process
Coordinated Plan Development
OSC publishes DRAFT Plan
TAG review and comment
Finalize Reliability Results
2009 Overview Schedule
TAG Meetings
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January - February
Finalize 2009 Study Scope of Work Receive final 2009 Reliability Study Scope for comment Review and provide comments to the OSC on the final 2009
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
2009 TAG Work Plan
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April - May TAG Meeting – April 23rd
Receive feedback from the OSC on what proposed Enhanced Transmission Access scenarios and interfaces will be included in the 2009 study
Receive a progress report on the 2009 Reliability Planning study activities and results
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July - August TAG Meeting – August 27th 2009 TECHNICAL ANALYSIS, PROBLEM
IDENTIFICATION and SOLUTION DEVELOPMENT TAG will receive a progress report from the PWG on
the 2009 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 2008 Collaborative Plan
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October - December TAG Meeting 2009 STUDY UPDATE
– Receive a progress report on the Reliability Planning and Enhanced Transmission Access Planning studies
2009 SELECTION OF SOLUTIONS– TAG will receive feedback from the OSC on any alternative
solutions that were proposed by TAG members
– 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
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December
2009 STUDY REPORT Receive and comment on final draft of the 2009
Collaborative Transmission Plan report
TAG Meeting Receive presentation on the draft report of 2009
Collaborative Transmission Plan Provide feedback to the OSC on the 2009 NCTPC
Process Review and comment on the 2010 TAG Work Plan
Schedule
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TAG Open Forum Discussion