11 tag meeting september 21, 2010 ncemc office raleigh, nc
TRANSCRIPT
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TAG Meeting Agenda1. Introductions and Agenda – Rich Wodyka2. FERC NOPR on Transmission Planning and Cost
Allocation - Dani Bennett 3. 2010 Study Scope Update and Status
– Rick Anderson4. 2010 Study Preliminary Results – Joey West
– Base Reliability – Enhanced Transmission Access Scenarios – Climate Change Scenarios
5. Major Transmission Project Update – Joey West6. Regional Studies Update – Bob Pierce7. Report on EISPC Activities – Kim Jones8. TAG Work Plan – Rich Wodyka9. TAG Open Forum – Rich Wodyka
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FERC Notice of Proposed Rulemaking on
Transmission Planning and Cost Allocation
Dani Bennett
Progress Energy
Purpose of the NOPR FERC proposes to require the regions to
develop transmission plans and cost allocation methods that consider the benefits of new transmission facilities, including reliability, economics, and complying with state or federal laws or regulations (e.g. public policy).
FERC also proposes to require each pair of neighboring regions to coordinate transmission planning and cost allocation.
4
Cost Allocation Each region to propose its own cost allocation
method FERC would not require a one size fits all
method for allocating costs of transmission facilities
Development of cost allocation proposals must start at the regional level
If region can’t decide on a cost allocation method, then FERC would decide based on the record
5
Cost Allocation Principles Regions would develop cost allocation methods
based on the following principles:– Costs allocated “roughly commensurate” with
estimated benefits– No involuntary allocation of costs to those receiving
no benefit– Benefit-to-cost thresholds must not be excessive– No allocation of costs to other regions except
pursuant to agreements– Cost allocation methods and identification of
beneficiaries must be transparent– Different allocation methods could apply to different
types of transmission facilities 6
Benefits
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Regions would be required to consider benefits including reliability, economics, and enabling compliance with existing laws or regulations that may drive transmission needs. The proposal would not prevent regions from considering other public policy objectives.
If a state has a law establishing a renewable electricity standard, then a region must consider transmission needs driven by that law.
Who Gets to Build
Removal of federal rights of first refusal from FERC jurisdictional tariffs and agreements; but no preemption of states
Encourage competition and new entrants
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Merchants
Merchant transmission developers may continue to negotiate cost recovery from specific customers
Must comply with all relevant reliability requirements
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Coordination Between Regions Evaluate benefits of
transmission lines that begin in one region and end in a second region.
Identify method(s) for allocating the cost of lines that the regions decide are mutually beneficial.
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Timeline Comments are due on September 29, 2010
Regional compliance filings are due 6 months after final rule promulgated
Interregional transmission planning agreements and interregional cost allocation compliance filings are due 12 months after final rule promulgated
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1414
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
Co
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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
1717
Study Criteria Established
NERC Reliability Standards- Current standards for base study screening- Current SERC Requirements
Individual company criteria
1818
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
1919
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
2020
Last year– Hypothetical import/export scenarios– Hypothetical new base load generation
This year: Climate Change Legislation Scenarios– Retire and replace existing coal generation– Hypothetical NC off-shore wind
Resource Supply Options Selected
2121
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 3,000 MW total capacity Injected at three locations on Progress
system
MW allocation – 60% Duke, 40% Progress
Hypothetical NC Off-Shore Wind
Injection Point On-peak MW(30-40% CF)
Off-peak MW(90% CF)
Wilmington 125 375
Morehead City 675 1,500
Bayboro 425 1,125
TOTAL 1,225 3,000
NC Off-Shore Wind- Strawman Proposal
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FERC Order No: 630The original slide contains
Critical Energy Infrastructure Informationand is not available to the Public
2424
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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2015 & 2020 Summer No new issues identified in Eastern or Western
Areas- Projects already in the Collaborative Plan to
address network loadings
2015-16 Winter No new Issues identified in Western Area
Preliminary Base Case Results – Progress Energy
3131
Contingencies and Year Upgrade Needed: Transformer replacement (loss of parallel bank)
- Sadler 230/100kV transformer, 2019 (presently scheduled for 2016)
Upgrades needed for loss of parallel line:- London Creek 230kV line, 2020
Operating guides needed for loss of parallel line:- Norman 230kV line, 2018
Preliminary Base Case Results - Duke
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Projects now outside of planning window: Fisher 230 kV line (for loss of parallel line)
- Pushed back from 2017
Preliminary Base Case Results - Duke
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Enhanced Transmission Access Scenarios
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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Enhanced Transmission Access Scenarios
Request 1- Cleveland County- CPLE 1000 MW
Progress - Construct Lilesville-Rockingham 230 kV 3rd Line (14 Miles)
- Accelerate Laurinburg 230/115kV Bank Replacement (2-3 yrs)scheduled for 2017
- Accelerate Falls 2nd- 230/115kV Bank Installation (1-2 yrs)scheduled for 2016
- Potentially Accelerate Durham-RTP 230 kV Reconductor scheduled for 2020
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Enhanced Transmission Access Scenarios
Request 1- Cleveland County- CPLE 1000 MW Duke
- Parkwood 500/230 kV transformer (for loss of parallel bank)Operating guide needed by 2020
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Enhanced Transmission Access Scenarios
Request 2- Cleveland County- DVP 1000 MW Progress
- Accelerate Laurinburg 230/115kV Bank Replacement (2-3 yrs)scheduled for 2017
- Accelerate Falls 2nd- 230/115kV Bank Installation (1-2 yrs)scheduled for 2016
- Construct Lilesville-Rockingham 230 kV 3rd Line (14 Miles)
Duke- No previously unidentified issues
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Enhanced Transmission Access Scenarios
Request 3- SOCO-DVP 1000 MW
Progress - Accelerate Laurinburg 230/115kV Bank Replacement (2-3 yrs)
scheduled for 2017
Duke- No previously unidentified issues
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Enhanced Transmission Access Scenarios
Request 4- SOCO-CPLE 1000 MW
Progress - Accelerate Laurinburg 230/115kV Bank Replacement (2-3 yrs)
scheduled for 2017- Accelerate Falls 2nd- 230/115kV Bank Installation (1-2 yrs)
scheduled for 2016- Potentially Accelerate Durham-RTP 230 kV Reconductor
scheduled for 2020- Potentially construct Lilesville-Rockingham 230 kV 3rd Line
(14 Miles)
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Enhanced Transmission Access Scenarios
Request 4- SOCO-CPLE 1000 MW
Duke- McGuire 500/230 kV transformer
(for loss of Woodleaf - Pleasant Garden 500 kV line)Upgrade needed by 2020
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Climate Change Legislation Scenarios
Coal Generation Retirements
Hypothetical NC Off- Shore Wind Sensitivity
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Coal Generation Retirements
Progress Wayne County & Sutton Combined Cycles
- Coal plant replacements were modeled- Scheduled for 2013
Cape Fear & Weatherspoon Coal Plants- Retirements built into models- Exact retirement dates TBD
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Duke
Retirements
Buck Steam Station (256 MW)
Lee Steam Station (370 MW)
Riverbend Steam Station (266 MW)
Coal Generation Retirements
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Duke - Preliminary
No previously unidentified issues London Creek 230 kV line
- Pushed from 2020 to outside of planning window Norman 230 kV line
- No change Sadler 230/100 kV transformer
- No change
Coal Generation Retirements
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Approximately 3,000 MW total capacity Injected at three locations on Progress system
MW allocation – 60% Duke, 40% Progress
NC Off- Shore Wind Sensitivity Scenario
Injection Point On-peak MW(30-40% CF)
Off-peak MW(90% CF)
Wilmington 125 375
Morehead City 675 1,500
Bayboro 425 1,125
TOTAL 1,225 3,000
NC Off-Shore Wind- Strawman Proposal
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FERC Order No: 630The original slide contains
Critical Energy Infrastructure Informationand is not available to the Public
4646
Hypothetical NC Off-Shore Wind Sensitivity Scenario Original Strawman
- NCTPC starting point in evaluating off-shore wind
Four Options were developed by PWG- Based on power flow results and analysis
- Assessment of costs versus benefits
Solving transmission constraints for off-peak loads with wind capacity factor at 90% also solves on-peak transmission problems with lower wind capacity factors
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Hypothetical NC Off- Shore Wind: Option 1A
Total Wind Output: 3000 MW
Southport 375 MW
Sutton
Jacksonville Morehead 1500 MW
Havelock
New Bern
Bayboro1125 MW
Wommack
Wake
Cumberland
230 KV500 KV
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Hypothetical NC Off- Shore Wind: Option 1B
Southport 375 MW
Sutton
JacksonvilleMorehead 1500 MW
New Bern
Bayboro1125 MW
Wommack
Cumberland
230 KV500 KV
Total Wind Output: 3000 MW
Wake
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Hypothetical NC Off- Shore Wind: Option 2
Southport 375 MW
Sutton
Jacksonville Morehead 1250 MWHavelock
New BernBayboro875 MW
Wommack
Wake
Cumberland
230 KV500 KV
Total Wind Output: 2500 MW
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Hypothetical NC Off- Shore Wind: Option 3
Southport 375 MW
Sutton
Jacksonville Morehead 1000 MWHavelock
New BernBayboro625 MW
Greenville West
230 KV500 KV
Total Wind Output: 2000 MW
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Duke
No previously unidentified issues Norman 230 kV line
- Accelerated from 2018 to 2015
Sadler 230/100 kV transformer- Pushed outside of planning window
London Creek 230 kV line- Pushed outside of planning window
Preliminary NC Off- Shore Wind Results
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Hypothetical NC Off- Shore Wind Options Summary
Option 1A: 3,000 MW - Estimated Cost $1.195 B- 230 kV wind connection to network
Option 1B: 3,000 MW - Estimated Cost $1.310 B- 500 kV wind connection to network
Option 2: 2,500 MW - Estimated Cost $1.155 B- 500 MW reduction of output doesn’t create a breakpoint- Rebuilding 2-230 kV Lines is only difference from 1A
Option 3: 2,000 MW - Estimated Cost $0.525 B- Significant breakpoint in transmission upgrades- Removed 500 kV Infrastructure- Construct Greenville West -New Bern 230kV Line
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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 October 6, 2010 to ITP ([email protected])
TAG Input Request
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Contains 1 Progress Energy project in-service date change that was driven by Wayne County Combined Cycle Plant
Contains 3 Progress Energy projects that are to be removed from the Collaborative Plan
2010 Mid-Year Update to the 2009 Collaborative Transmission Plans
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Import ScenariosMajor Projects in 2009 Plan
Reliability Project TO Planned I/S Date
Richmond 500 kV sub, reactor Progress In-service
Asheville-Enka 230 kV line, Convert 115 kV line; &Asheville-Enka 115 kV, Build new line
ProgressDecember ’10
December ’12
Rockingham-West End 230 kV East line Progress June ’11
Ft Bragg Woodruff Street-Richmond 230 kV Line
Progress June ‘11
Pleasant Garden-Asheboro 230 kV line, replace Asheboro 230 kV xfmrs
Progress& Duke
June ’11
Clinton-Lee 230 kV line Progress December ’11(accelerated from ’13)
Brunswick 1 - Castle Hayne 230kV Line, Construct New Cape Fear River Crossing
Progress June ’12
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Import ScenariosMajor Projects in 2009 Plan (Continued)
Reliability Project TO Planned I/S Date
Jacksonville Static VAR Compensator Progress June ‘13
Folkstone 230/115kV Substation Progress June ’13
Harris-RTP 230 kV line Progress June ’14
Greenville-Kinston Dupont 230 kV line Progress June ’17
Durham-RTP 230kV Line, Reconductor Progress June ’19
Add 3rd Wake 500/230 kV xfmr Progress Removed from Plan
Cape Fear-West End 230 kV West line, Install reactor
Progress Removed from Plan
Rockingham-Lilesville 230 kV line Progress Removed from Plan
595959
Import ScenariosMajor Projects in 2009 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
Reconductor Caesar 230 kV Lines(Pisgah Tie-Shiloh Switching Station #1 & #2)
Duke June ‘13
Reconductor London Creek 230 kV Lines(Peach Valley Tie-Riverview Switching Station #1 & #2)
Duke 2020
Reconductor Fisher 230 kV Lines (Central Tie-Shady Grove Tap #1 & #2)
Duke Outside Planning Window
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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
SIRPP
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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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2009-2010 SIRPP Study Results Entergy to Georgia ITS – 2000 MW (2014, Step 2)
– One (1) 500 kV Line (Southern)
– One (1) 500 / 230 kV Transformer (Southern)
– Ten (10) 230 kV Lines (Southern)
– Six (6) 161 kV Lines (Entergy, TVA)
– TOTAL COST: $330,246,000
MISO to TVA – 2000 MW (2015, Step 1)– One (1) 230 kV Line (Southern)
– One (1) 161 kV Line (TVA)
– TOTAL COST: $53,720,000
SIRPP
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2009-2010 SIRPP Study Results Kentucky to Georgia ITS – 1000 MW (2015, Step 1)
– One (1) 230 kV Line (Southern)
– Two (2) 161 kV Line (E. ON U.S., Southern)
– TOTAL COST: $18,700,000
MISO & PJM West (SMART) to SIRPP – 3000 MW (2018, Step 1)– One (1) 500 / 230 kV Transformer (Southern)
– Three (3) 500 / 161 kV Transformer (TVA)
– Three (3) 230 kV Lines (Southern)
– Six (6) 161 kV Lines (TVA)
– TOTAL COST: $161,465,000
SIRPP
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2009-2010 SIRPP Study Results SPP to SIRPP – 3000 MW via HVDC to Bowen
(SOCO) and Montgomery (TVA) (2018, Step 1)– One (1) 500 / 230 kV Transformer (Southern)– One (1) 500 / 161 kV Transformer (TVA)– One (1) 345 / 138 kV Transformer (Entergy)– One (1) 230 kV Lines (Southern)– Sixteen (16) 161 kV Lines (TVA)– TOTAL COST: $289,904,000
Duke Energy Carolinas and Progress Energy Carolinas did not identify any constraints.
SIRPP
NC Off-Shore Wind- Strawman Proposal
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FERC Order No: 630The original slide contains
Critical Energy Infrastructure Informationand is not available to the Public
NC Off-Shore Wind- Strawman Proposal
71
FERC Order No: 630The original slide contains
Critical Energy Infrastructure Informationand is not available to the Public
757575
2010 LTSG Study Evaluate inter-regional and inter-BA transfer
capability and base case reliability N-1 reliability in 2016S
Linears transfers run and evaluated
Report being drafted
SERC LTSG
7777
VACAR 2015S Study
SCOPE Evaluation of N-1 contingencies for 500 kV, 230 kV, tie
lines and any other lines with a significant impact.
Evaluation of N-2 contingencies based combinations of all N-1 contingencies
Evaluation of N-2 failed contingency solutions (solution failed to converge or reached iteration limit)
7878
VACAR 2015S Study
SIGNIFICANT FACILITY RESULTS
The facility is loading greater than or equal to 100% of its contingency specific rating
The response of the facility to a contingency and/or a VACAR Reserve Sharing scenario
The number of different companies impacted
If the facility requires the use of an operating guide
If the outage of the facility results in the overload of numerous major transmission elements
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VACAR 2015S StudyDEC & PEC N-2 SIGNIFICANT FACILITY RESULTS Mills River-Asheville 115 kV Tie Line (Duke/CPLW) Jocassee 500/230 kV Transformer (Duke) Parkwood 500/230 kV Transformers (Duke) Allen-Woodlawn 230 kV Line (Duke) Anderson-Hartwell 230 kV Tie Line (Duke/SEPA) Pisgah 230/100/44 kV Transformers (Duke) Horseshoe 115/100 kV Transformers (Duke) Horseshoe-Pisgah 100 kV Lines (Duke) Great Falls-Wateree 100 kV Lines (Duke) Wateree 115/100 kV Transformer (CPLE/Duke) Havelock 230/115 kV transformers #1/2 (CPLE) Asheboro East-Biscoe 115 kV Line (CPLE) Richmond-Rockingham 230 kV East Line (CPLE)
8080
VACAR 2015S Study The assessment of failed contingency solutions found that the
majority of the 84 failed solutions involved toggling capacitors or the loss of significant generation due to the tested contingency.
Failed solutions were found to solve when they were rerun with the toggling capacitor fixed (removed from voltage control) or the lost generation moved to a remote bus as part of the contingency description.
The toggling capacitors were fixed at their max MVAR output and the lost generation was moved to a bus remote from the location where the contingency was being evaluated to avoid impacting the local impacts of the contingency.
828282
Establish a forum for coordinating certain planning activities among the specific parties
DEC, PEC, SCE&G and SCPSA
Studying 2014 and 2021 summer conditions
Expect report in early October
Carolinas Transmission Planning Coordination Arrangement
NERC TPL-001-2 Standard Update
Response to ballot and comments on the proposed footnote ‘b’ were posted
NERC held a technical conference 8/10/10 to discuss footnote “b” issue
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NERC TPL-001-2 Standard Update
Response to informal comments on the latest draft have been prepared.
Footnote ‘b’ related to TPL-001-1 loss of non-consequential load is open for informal comment through October 8th.
Standard is expected to be ready for re-ballot in February timeframe with new footnote ‘b’ merged in.
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NERC TPL-001-2 Standard Update
b) An objective of the planning process is to avoid interruption of Demand. Interruption of Demand is discouraged and measures to mitigate such interruption should be pursued within the planning process. However, Demand may need to be interrupted in limited circumstances to address BES performance requirements. When interruption of Demand is utilized within the planning process, such interruption is limited to:
Demand that is directly served by the elements that are removed from service as a result of the Contingency
Interruptible Demand or Demand-Side Management
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NERC TPL-001-2 Standard Update
Demand that does not adversely impact overall BES reliability where the circumstances describing the use of such Demand interruption are documented, including alternatives evaluated; and where the application is subject to review and acceptance in an open and transparent stakeholder process.
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EIPC background Formed in 2009 Consists of 26 Planning Authorities in U.S. & Canada Over 600 GW of connected customer demand with
approximately 95% of the Eastern Interconnection customers covered
EIPC objectives1. Integration (“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
EIPC Structure
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Eastern Interconnection Planning Collaborative (EIPC)
(Open Collaborative Process)
EIPC Analysis TeamPrincipal InvestigatorsPlanning Authorities
Steering Committee
Stakeholder Work Groups
Executive Leadership
Technical Leadership &
Support Group
Stake-holder Groups
States Provinces FederalOwners
OperatorsUsers
…
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EIPC Focus between now and end of 2012 Perform analysis under the Department of Energy Topic A award for
Transmission Planning Analysis for the Eastern Interconnection Phase I - between now and October, 2011
– Integrate existing regional plans - Perform roll-up of existing 2020 transmission plans
– Production cost analysis of regional plans - Perform production costing analysis of existing 2020 transmission plans
– Develop macroeconomic scenarios on possible futures and perform analysis on these futures
– Agree on expansion scenarios for Interregional Transmission Options development in Phase II
Phase II - October, 2011 to Late 2012– Develop transmission expansion options, along with associated
costs, for agreed on expansion scenarios
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EIPC Current ActivitiesPlanning Authorities
Have developed transmission model development & study practices
Have created roll-up of existing regional transmission plans detailing modeling assumptions for the 2020 summer model for Stakeholders – responding to Stakeholder follow-up questions
Performing analysis of bulk energy transfers between markets/regions on the 2020 summer model by late September
Working with CRA on economic analysis methods
EIPC Current Activities Stakeholder Steering Committee (SSC) has been
organized and have several working groups functioning:– Governance– Economic Modeling– Planning Roll-up – Scenario Planning
Next SSC Meeting October 12-14 in Arlington, VA
Report on Eastern Interconnection States
Planning Council (EISPC)
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Kim Jones
NC Utility Commission
Eastern Interconnection States Planning Council (EISPC)
41 jurisdictions in the eastern interconnection
Grant funding three-year planning effort Each state has two representatives To give policy guidance to transmission
planning
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North Carolina is represented by: Ed Finley, Chairman of NC Utilities
Commission Jennifer Bumgarner, Assistant Secretary,
Energy Division, Department of Commerce
Staff Support:– Bob Leker, Renewables Program Manager in
State Energy Office– Kim Jones, Analyst, NCUC
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August 26-27, 2010 Meeting Relatively light involvement of
southeastern states. Absent:– Florida– Georgia– Louisiana– Virginia
Abstained: Tennessee
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Stakeholder Steering Committee
Will determine 8 macro-economic futures
3 of which will proceed to transmission build out study
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Futures that NC wants studied: Business as usual Carbon-constrained future National renewable energy portfolio standard Increased use of wind power from
– Midwest– Local sources– Offshore
Nuclear renaissance
100
Other futures Least cost energy Constrained transmission Expanded hydro Expanded energy storage Expanded coal IGCC Repowering coal plants with gas Carbon capture and sequestration Increased energy efficiency / demand response
101
Other futures (continued) Increased use of electric vehicles More distributed generation Development of a smart grid Various growth levels No build of anything Increased imports from Canada Increased gas production from shale
102
Reference case2009 transmission plans “stitched together”
What assumptions did NC planning authorities make in last year’s plan?– Growth?– Location of future generation resources?– Effectiveness of energy efficiency and
demand-side management programs?– Use of intermittent resources / distributed
resources / renewables?103
Next steps / work in progress1. Energy zones – develop process for defining
them• Will take about a year• Bob Leker to serve on work group• [email protected]
2. Defining futures • Kim Jones serving on work group• [email protected]
3. Governance Committee – NC has seat104
Next steps (continued)4. Select and define 7 white paper /
consultant studies
State-by-state potential for– Renewable energy– Demand-side resources– Energy storage– Distributed generation– Existing customer-sited generation– Rapid start fossil generation– Existing portfolio standards
105
More potential studies Market structures Power purchase agreements for renewables,
including financial implications Existing state, regional and federal policies
relative to transmission Incentives / disincentives for development Plug-in electric vehicles Generation close to load; far from load
106
More potential studies Economic uncertainties / risk to current plans and
cost recovery of emerging technology Smart grid – potential and impacts Off ramps for existing state portfolio standards How is / should “renewable” be defined? Assess potential location of new nuclear plants and
potential upgrades to existing nuclear plants Assess other initiatives to reduce carbon emissions Assess gas and other fuel prices
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111 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
112
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
114
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
115
August - September TAG Meeting – September 21st 2010 STUDY UPDATE
Receive a progress report on the Reliability Planning and Enhanced Transmission Access Planning studies
– Provide input by October 6, 2010 to ITP ([email protected])
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