11 TAG Meeting September 21, 2010 NCEMC Office Raleigh, NC.

11

TAG MeetingSeptember 21, 2010

NCEMC Office

Raleigh, NC

22

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

33

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

7

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

8

Merchants

Merchant transmission developers may continue to negotiate cost recovery from specific customers

Must comply with all relevant reliability requirements

9

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.

10

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

11

121212

1313

NCTPC 2010 Study Update and Status

Rick Anderson

Fayetteville PWC

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

1515

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

mp

lete

d

1616

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

2222

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

23

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

2525

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

2626

Problems Identified and Solutions Developed

Identify limitations and develop potential alternative solutions for further testing and evaluation

Estimate project costs and schedule

2727

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

2828

2929

2010 Study Preliminary Results

Joey West

Progress Energy

3030

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

3232

Projects now outside of planning window: Fisher 230 kV line (for loss of parallel line)

- Pushed back from 2017

Preliminary Base Case Results - Duke

3333

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

3434


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

3535


Request 1- Cleveland County- CPLE 1000 MW Duke

- Parkwood 500/230 kV transformer (for loss of parallel bank)Operating guide needed by 2020

3636


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

3737


Request 3- SOCO-DVP 1000 MW

Progress - Accelerate Laurinburg 230/115kV Bank Replacement (2-3 yrs)

scheduled for 2017

Duke- No previously unidentified issues

3838


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)

3939


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

4040

Climate Change Legislation Scenarios

Coal Generation Retirements

Hypothetical NC Off- Shore Wind Sensitivity

4141


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

4242

Duke

Retirements

Buck Steam Station (256 MW)

Lee Steam Station (370 MW)

Riverbend Steam Station (266 MW)


4343

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


4444

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


45



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

47

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

48

Hypothetical NC Off- Shore Wind: Option 1B

Southport 375 MW

Sutton

JacksonvilleMorehead 1500 MW

New Bern

Bayboro1125 MW

Wommack

Cumberland

230 KV500 KV


Wake

49

Hypothetical NC Off- Shore Wind: Option 2

Southport 375 MW

Sutton

Jacksonville Morehead 1250 MWHavelock

New BernBayboro875 MW

Wommack

Wake

Cumberland

230 KV500 KV


50

Hypothetical NC Off- Shore Wind: Option 3

Southport 375 MW

Sutton

Jacksonville Morehead 1000 MWHavelock

New BernBayboro625 MW

Greenville West

230 KV500 KV


5151

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

5252

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

53

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

mailto:[email protected]

545454

5555

Major Transmission Project Update

Joey West

Progress Energy

565656

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

575757

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

585858

Import ScenariosMajor Projects in 2009 Plan (Continued)


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)


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

606060

6161

Bob Pierce

Duke Energy

Regional Studies Reports

62

Southeast Inter-Regional Planning Process (SIRPP)

Update

63

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

64

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

65

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

66

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

67

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

68

http://www.southeastirpp.com/

69

Southern Cross Project


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71



7272

737373

SERC Long-term Study Group(LTSG)

747474

Completed 2010 Series LTSG models

Building 2010 Series ERAG MMWG models

SERC LTSG

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

7676

VACAR 2015S Study

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

7979

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.

818181

Carolinas Transmission Planning Coordination Arrangement

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

83


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

84


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.

85


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

86


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.

87

88

Eastern Interconnection Planning Collaborative (EIPC)

89

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

90

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

…

91

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

92

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

94

Report on Eastern Interconnection States

Planning Council (EISPC)

9595

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

96

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

97

August 26-27, 2010 Meeting Relatively light involvement of

southeastern states. Absent:– Florida– Georgia– Louisiana– Virginia

Abstained: Tennessee

98

Stakeholder Steering Committee

Will determine 8 macro-economic futures

3 of which will proceed to transmission build out study

99

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

107

More to do:Learn the CRA (Charles River

Associates) modelsNext meeting: Sept 30 –

October 1

108

109

110110

Rich Wodyka

ITP

2010 TAG Work Plan Review

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

113

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

mailto:[email protected]

116

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

117

118118

TAG Open Forum Discussion

11 TAG Meeting September 21, 2010 NCEMC Office Raleigh, NC.

Documents

cost allocation method

cost allocation dani

cost of lines

transmission needs

cost thresholds

cost recovery

transmission plans

benefits of transmission