11

TAG MeetingAugust 27, 2009

ElectriCities Office

Raleigh, NC

22

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

33

Duke and Progress Attachment K Compliance

Filing

Kendal Bowman

Progress Energy

44

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

55

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.

66

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.

77

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

1010

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

1111

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

1212

Study Criteria Established

NERC Reliability Standards• Current standards for base study screening• SERC Requirements

Individual company criteria

1313

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

1414

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

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

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mp

lete

d

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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

1919

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

2020

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)

23

• 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 (r.wodyka@accenture.com)

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

282828

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)

292929

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

41414141

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

42424242

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

45454545

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

4747474747

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

5050505050

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

5151515151

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

5252525252

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

5353535353

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

56

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.

57

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

58

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

59

Eastern Interconnection Planning Collaborative (EIPC)

60

DRAFT EIPC Process Flow

61

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

62

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)

63

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

64

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)

656565

66

A Proposal for DOE Funding

NC Commission ReportKim Jones

NC Commission Staff

67

• 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

68

• 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

69

• 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

70

71

• 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

72

• 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)

73

• 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.

74

• 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

77

TAG Scope Proposed Changes

Typos and Edits

Establishment of TAG meeting agenda

Vendor presentations at TAG meetings

78

Typos and Edits

ITP – independent third party (3 edits)

Page 3 – NCTPC not NCPTPC

Page 5 – total not totals

Page 5 – may not will

79

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

80

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

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

8484

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

8585

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

8686

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

8787

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