Download - TAG Meeting May 18, 2010
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TAG MeetingMay 18, 2010
ElectriCities Office Raleigh, NC
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TAG Meeting Agenda1. Introductions and Agenda – Rich Wodyka2. 2010 Study Activities Report and 2010 Study
Scope Update – Denise Roeder3. Regional Studies Update – Bob Pierce4. NERC TPL-001-1 Standard Update – Bob Pierce5. NERC / FERC activities related to transmission
planning – Bob Pierce6. 2010 TAG Work Plan – Rich Wodyka7. TAG Open Forum – Rich Wodyka
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NCTPC 2010 Study Activities
Denise RoederElectriCities
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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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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
Com
plet
ed
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Study Years for reliability analyses:– Near-term: 2015 Summer, 2015/2016 Winter– Longer-term: 2020 Summer
LSEs provided:– Input for load forecasts and resource supply
assumptions– Dispatch order for their resources
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- Current SERC Requirements
Individual company criteria
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Study Methodologies Selected
Thermal Power Flow Analysis – primary methodology
Voltage, stability, short circuit, phase angle analysis - as needed
Each system (Duke and Progress) will be tested for impact of other system’s contingencies
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Latest available MMWG cases were selected and updated for study years
Adjustments were made based on additional coordination with neighboring transmission systems
Combined detailed model for Duke and Progress was prepared
Planned transmission additions from updated 2009 Plan were included in models
Base Case Models Developed
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Last year– Hypothetical import/export scenarios– Hypothetical new base load generation
This year– Retire & replace existing coal generation– Off-shore wind
Resource Supply Options Selected
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Retire 100% existing un-scrubbed coal by 2015, approximately– 1,500 MW for Progress– 2,000 MW for Duke
Replace with hypothetical new generation and/or imports
Retire & Replace Coal Generation
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Approximately 3,300 MW total capacity Injected at three locations on Progress
system
MW allocation – 60% Duke, 40% Progress
Off-Shore Wind
Injection Point On-peak MW(30-40% CF)
Off-peak MW(90% CF)
Wilmington 125 375Morehead City 675 1,500Bayboro 425 1,125
TOTAL 1,225 3,000
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Enhanced Access Requests
Request SOURCE SINK MW Service Dates
1 Cleveland Co. site CPLE 1000 1/12 to 1/22
2 Cleveland Co. site DVP 1000 1/12 to 1/22
3 SOCO DVP 1000 1/12 to 1/22
4 SOCO CPLE 1000 1/12 to 1/22
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Technical Analysis Conduct thermal screenings of the
2015 and 2020 base cases Conduct thermal screenings of the
2015 Resource Supply Options Scenarios
Conduct thermal screenings of the 2015 Enhanced Access Requests
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Problems Identified and Solutions Developed
Identify limitations and develop potential alternative solutions for further testing and evaluation
Estimate project costs and schedule
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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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Bob Pierce – Duke Energy
Regional Studies Reports
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Eastern Wind Integration and Transmission Study
EWITS
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Objectives of EWITS Evaluate the power system impacts and transmission associated
with increasing wind capacity to 20% and 30% of retail electric energy sales in the study area by 2024 ;
Evaluate operations impacts due to variability and uncertainty of wind;
Build upon prior wind integration studies and related technical work;
Coordinate with JCSP and current regional power system study work;
Produce meaningful, broadly supported results through a technically rigorous, inclusive study process.
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EWITS Reference Scenario - approximates the current state of wind
development. Scenario totaled about 6% of the total 2024 projected load requirements for the U.S. portion of the Eastern Interconnection.
Scenario 1, 20% penetration – High Capacity Factor, Onshore: Utilizes high-quality wind resources in the Great Plains, with other development in the eastern United States where good wind resources exist.
Scenario 2, 20% penetration – Hybrid with Offshore: Some wind generation in the Great Plains is moved east. Some East Coast offshore development is included.
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EWITS Scenario 3, 20% penetration – Local with Aggressive Offshore: More
wind generation is moved east toward load centers, necessitating broader use of offshore resources. The offshore wind assumptions represent an uppermost limit of what could be developed by 2024 under an aggressive technology-push scenario.
Scenario 4, 30% penetration – Aggressive On- and Offshore: Meeting the 30% energy penetration level uses a substantial amount of the higher quality wind resource in the NREL database. A large amount of offshore generation is needed to reach the target energy level.
Supplying 20% of the U.S. portion of the Eastern Interconnection would call for approximately 225,000 megawatts (MW) of wind generation capacity, which is about a tenfold increase above today’s levels. To reach 30% energy from wind, the installed capacity would have to rise to 330,000 MW.
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EWITS
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High penetrations of wind generation—20% to 30% of the electrical energy requirements of the Eastern Interconnection—are technically feasible with significant expansion of the transmission infrastructure.
New transmission will be required for all the future wind scenarios in the Eastern Interconnection, including the Reference Case. Planning for this transmission, then, is imperative because it takes longer to build new transmission capacity than it does to build new wind plants.
Without transmission enhancements, substantial curtailment (shutting down) of wind generation would be required for all the 20% scenarios.
EWITS
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Interconnection-wide costs for integrating large amounts of wind generation are manageable with large regional operating pools and significant market, tariff, and operational changes.
Transmission helps reduce the impacts of the variability of the wind, which reduces wind integration costs, increases reliability of the electrical grid, and helps make more efficient use of the available generation resources. Although costs for aggressive expansions of the existing grid are significant, they make up a relatively small portion of the total annualized costs in any of the scenarios studied.
EWITS
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EWITS
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EWITS Website - http://wind.nrel.gov/public/EWITS/
Contact Dave Corbus at [email protected] (303-384-6966)
EWITS
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Strategic Midwest AreaRenewable Transmission Study
SMART
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Comprehensive study of the transmission in the Upper Midwest to support renewable energy development and transportation of that energy throughout the study area
Study focus is 20 years into the future (2019, 2024 & 2029 models)
Includes potential effects of future economic, regulatory and state RPS issues
Transcends traditional utility and regional boundaries
SMART
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Phase 1 evaluation of transmission system Natural applications of HVDC were considered
and the following were applied: Underwater cables across waterways Long distance transmission
Two alternatives remain under consideration Alternative 2 - Combination 345kV and 765kV Alternative 5 - 765kV only
SMART
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SMART
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SMART
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The reliability impact of the 2 alternatives were evaluated under different sensitivities On/Off peak High/Low wind Imports from SPP High/Low load High Gas Low Carbon
The cost of the 2 alternatives are both in the $25 B range
SMART
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Phase 2 will further examine the two transmission alternatives using production cost to focus on the overall economic impact
Phase 2 is expected to be complete and a final report issued in late June
SMART
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SMART
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NCTPC did not submit requests for study 5 requests selected at the October 2009 meeting 2009 series MMWG 2015 and 2020 Summer Peak cases updated
to reflect 2014, 2015, and 2018 Summer Peaks Studies are under evaluation by study team members, each
using their company’s respective planning criteria Analysis to be completed and Preliminary Report compiled by
June 1, 2010 Meeting/Conference Call with stakeholders to discuss
preliminary results tentatively planned for June 15, 2010
Southeast Inter-Regional Planning Process (SIRPP) Update
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2009-2010 SIRPP Study Requests Entergy to Georgia ITS – 2000 MW (2014, Step 2) MISO to TVA – 2000 MW (2015, Step 1) Kentucky to Georgia ITS – 1000 MW (2015, Step 1) MISO & PJM West (SMART) to SIRPP – 3000 MW
(2018, Step 1) SPP to SIRPP – 3000 MW via HVDC (2018, Step 1)
SIRPP
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2010 PJM RTEP PJM wind integration studies Interconnection queue review CIP-002 philosophy
PJM Planning Coordination Agreement
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Approved PJM Backbone 500 kV and 765 kV Facilities Since 2006, the PJM Board
has approved six new major 500 kV and 765 kV backbone upgrades, as shown on this map:
1.502 Junction – Loudoun 500 kV line, also known as the TrAIL Line (2006 RTEP)
2.Carson – Suffolk 500 kV line (2006 RTEP)
3.Susquehanna – Roseland 500 kV line (2007 RTEP)
4.Amos – Kemptown 765 kV line, also known as the PATH line (2007 RTEP)
5.Possum Point – Indian River 500 kV line, also known as the MAPP line (2007 RTEP)
6.Branchburg – Roseland – Hudson 500 kV line (2008 RTEP)
1.
2.
3.
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1. 4.
5.
Source: PJM 2009 RTEP Report, Feb 26, 2010
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Building 2010 Series models- Coordinated tie lines and interchange- Submitted 10 years of model data for each
control area- Building light load case for 2016 and a 2021
winter case- Models to be complete in early June and
submitted to the MMWG process
2010 LTSG Study Scope
SERC LTSG (Long-term Study Group)
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Preliminary Results of Economic Study Requests Submitted by SCRTP Stakeholders
SCE&G to CPLE – 2015 summer – 500 MW* SCE&G to Duke – 2015 summer – 500 MW* SCE&G to CPLE – 2020 summer – 500 MW SCE&G to Duke – 2020 summer – 500 MW SCE&G to Southern – 2020 summer – 500 MW
* submitted by NCTPC
South Carolina Regional Transmission Planning (SCRTP)
Meeting Highlights
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Study Methodology – Analysis Performed Linear transfer analysis, which includes N-1
contingencies of SERC while monitoring SCE&G and Santee Cooper Transmission Systems.
A Thermal and Voltage analysis, which includes N-1, N-2, and selected bus outages with and without the simulated 500 MW transfer in effect. However, this analysis is not a complete testing of NERC TPL standards.
SCRTP
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Preliminary Results - SCE&G to CPLE 500 MW and SCE&G to Duke 500 MW in 2015S *
Urquhart – Langley Tap 115 kV line overloadEstimated cost = $5.1M, 24 month lead time to rebuild
* Each transfer done independently, not simultaneously
SCRTP
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Preliminary Results - SCE&G to CPLE 500 MW in 2020S
Georgia Pacific Tap (SCE&G) – Bush River Red (Duke) 115 kV line overload A Joint Study between SCE&G and Duke is needed to determine
best solution, cost est. and schedule Santee Cooper’s Pomaria – Winnsboro 69 kV line
overload Estimated cost is $3.6 M, 30 month lead time to rebuild
SCRTP
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Preliminary Results - SCE&G to Duke 500 MW in 2020S
White Rock (SCE&G) - Bush River Yellow (Duke) 115 kV tie line overload
Georgia Pacific Tap (SCE&G) – Bush River Red (Duke) 115 kV line overload
A Joint Study between SCE&G and Duke is needed to determine best solution, cost estimate and schedule to address both overloads
SCRTP
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Preliminary Results - SCE&G to Southern 500 MW in 2020S
White Rock (SCEG) - Bush River Yellow (Duke) 115 kV tie line overload A Joint Study between SCE&G and Duke is needed to determine
best solution, cost estimate and schedule
SCRTP
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Lower Load Forecasts
Both SC companies experienced lower load forecasts for planning horizon Resulted in future capacity changes for serving load
Resulted in several transmission projects being delayed anywhere from 6 months to several years to even being cancelled
SCRTP
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SCE&G New Projected Capacity
2 Nuclear Units (1117 MW/ea) V. C. Summer #2 - 2016
V. C. Summer #3 - 2019
SCRTP
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Santee Cooper Projected Capacity Update
Pee Dee 609 MW (Planned for Jan 2014) – CANCELED Pee Dee – Lake City 230 kV Line (Planned for Jan 2011) –
DELAYED but still needed in Long-range plan
V. C. Summer #2 and #3 - Shared Capacity with SCE&G
SCRTP
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SCRTP
V.C. Summer Unit #2 Related Projects
Santee Cooper
VCS Sub #1- Winnsboro-Richburg-Flat Creek 230kV 12/01/2015 Winnsboro 230/69kV Construct 12/01/2015 Richburg 230/69kV Construct 12/01/2015
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SCRTPV.C. Summer Unit #2 Related Projects
SCE&G
Denny Terrace-Lyles 230kV Line Upgrade 12/01/2015 Denny Terrace Add 3rd 336 Autotransformer 12/01/2015 Lake Murray Add 3rd 336 Autotransformer 12/01/2015 Lake Murray-McMeekin 115kV Line Upgrade 12/01/2015 Lake Murray-Saluda 115kV Line Upgrade 12/01/2015 Saluda-McMeekin 115kV Line Upgrade 12/01/2015 VCS2-Lake Murray #2 230kV Line Construct 12/01/2015 VCS2-Winnsboro-Killian 230kV Line Construct 12/01/2015
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SCRTPV.C. Summer Unit #3 Related Projects
Santee Cooper
VCS Sub2-Pomaria-Sandy Run-Orangeburg- 12/01/2018 St George-Varnville230kV Sandy Run 230/115kV Construct 12/01/2018 St George 230/115kV Construct 12/01/2018
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SCRTPV.C. Summer Unit #3 Related Projects
SCE&G
Saluda-Duke 115kV Tielines Upgrade 12/01/2018 South Columbia 230/115kV Construct 12/01/2018 South Lexington 230/115kV Construct 12/01/2018 St George 230kV Switching Station Construct 12/01/2018 St George-Canadys 230kV Line Upgrade 12/01/2018 St George-Summerville 230kV Line Upgrade 12/01/2018 VCS Sub #2-St George 230kV Double Circuit Construct 12/01/2018
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Establish a forum for coordinating certain planning activities among the specific parties
DEC, PEC, SCE&G and SCPSA Initial study scope being developed Expect results in September timeframe
Carolinas Transmission Planning Coordination Arrangement
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Eastern Interconnection Planning Collaborative (EIPC)
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Create an Eastern Interconnection Planning Collaborative (EIPC) process that includes:– Major transmission entities in the east with Planning Authority
responsibility– Utilities, cooperatives, municipal systems, and public power
authorities– Utilities in Canada (include Quebec)– States and Provinces– Administration (DOE, FERC, …) – A forum where stakeholders from all regional planning
processes can effectively participate
EIPC
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Publishes Annual Interconnection
Analysis
Regional/state compliant plans
provided as input
Study gaps relative to national, regional
and state policy
Regional Plans and Projects
Annual interconnection
analysis
States•Regional Policy
recommendations•State energy policies
•Rate Policies
Eastern Interconnection Planning Collaborative • Rolls-up regional plans
• Coordinates with Canada, Western Interconnect and Texas• Receives stakeholder input and holds public meetings• Performs studies of various transmission alternatives
against national, regional and state energy/economic/environmental objectives
• Identifies gaps for further study
DOE/FERC
ISO / RTOs & Order 890 Entities•Produce Regional Plan through regional stakeholder process
FERC
Provides policy direction,assumptions &
criteria
• Review/direction• Order adjustments• Cost recovery
States•Policy
recommendations•State energy plans
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Working to finalize stakeholder steering committee structure and representation
PA’s are jointly developing model development/ study practices and working with CRA on economic analysis methods.
For educating stakeholders, coordinate development of a documented roll-up of existing regional transmission plans detailing modeling assumptions for the 2020S model.
Perform TPL standard type analysis of the 2020S model.
EIPC Activities
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NERC TPL-001-1 Standard Update
NERC Standards Development Process requires posting and balloting of new/revised standards by the industry
TPL-001-1 covers the fundamental requirements for long term planning
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NERC TPL-001-1 Standard Update
FAILED BALLOT Quorum: 91.38%
Approval: 35.36%
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NERC TPL-001-1 Standard Update
Common comments Implementation Plan timeframe Local Area Load issue Definition of Protection System Year One definition Spare equipment strategy Protection System modeling Number of near-term studies
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Network BES
Temporary radial
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Network BES
No Temporary radial Established
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FERC recently issued a series of Orders and NOPR’s
PRC-023 BES definition TPL-002 R1.3.10 non-operation of protection
system NERC Rules of Procedure on standard
development FERC Penalty Guidelines
NERC/FERC Issues
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Rich WodykaITP
2010 TAG Work Plan Review
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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
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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
2010 TAG Work Plan
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April - May TAG Meeting – May 18th
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
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June - July 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
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August - September TAG Meeting – September 21st 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
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December 2010 STUDY REPORT
– Receive and comment on final draft of the 2010 Collaborative Transmission Plan report
TAG Meeting – December 16th – 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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TAG Open Forum Discussion