11

TAG MeetingMay 18, 2010

ElectriCities Office

Raleigh, NC

22

TAG Meeting Agenda1. Introductions and Agenda – Rich Wodyka

2. 2010 Study Activities Report and 2010 Study Scope Update – Denise Roeder

3. Regional Studies Update – Bob Pierce

4. NERC TPL-001-1 Standard Update – Bob Pierce

5. NERC / FERC activities related to transmission planning – Bob Pierce

6. 2010 TAG Work Plan – Rich Wodyka

7. TAG Open Forum – Rich Wodyka

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NCTPC 2010 Study Activities

Denise Roeder

ElectriCities

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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

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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 125 375

Morehead City 675 1,500

Bayboro 425 1,125

TOTAL 1,225 3,000

• This slide is intentionality left blank

Off-Shore Wind- Strawman Proposal

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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

202020

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 David_Corbus@nrel.gov (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.

4.

6.

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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SCRTP

V.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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SCRTP

V.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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SCRTP

V.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 Wodyka

ITP

2010 TAG Work Plan Review

71 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

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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