Transcript TAG Meeting Presentations for September 16, 2011

TAG Meeting
September 16, 2011
ElectriCities Office
Raleigh, NC
1
TAG Meeting Agenda
Introductions and Agenda – Rich Wodyka
FERC Order No. 1000 Overview - Dani Bennett
2010 Collaborative Plan Update – Orvane Piper
2011 Study Activities Report on Preliminary
Study Results – Orvane Piper and Kai Zai
5. Regional Studies Update – Bob Pierce
6. 2011 TAG Work Plan – Rich Wodyka
7. TAG Open Forum – Rich Wodyka
1.
2.
3.
4.
2
FERC Order No. 1000 Rule on
Transmission Planning and
Cost Allocation
Dani Bennett
Progress Energy
3
Order N0. 1000
 Transmission Planning
– Public Policy
– Interregional Coordination




Cost Allocation
Nonincumbent Transmission Developer
Compliance Filings
Next Steps
4
Transmission Planning
1. Public utility transmission providers are required
to participate in a regional transmission planning
process that satisfies Order No. 890 principles
and produces a regional transmission plan
2. Local and regional transmission planning
processes must consider transmission needs
driven by public policy requirements established
by state or federal laws or regulations
3. Public utility transmission providers in each pair
of neighboring transmission planning regions
must coordinate to determine if more efficient or
5
cost‐effective solutions are available
Public Policy
1. Each public utility transmission provider must
establish procedures to:
–
–
Identify transmission needs driven by public policy
requirements
Evaluate potential solutions to those needs
2. Public policy requirements are defined as
enacted statutes and regulations promulgated by
a relevant jurisdiction, whether within a state or at
the federal level
3. No mandate to include any specific requirement
6
Interregional Coordination
1. Each pair of neighboring transmission planning
regions must:
– Share information regarding the respective needs of
each region and potential solutions to those needs
– Identify and jointly evaluate interregional transmission
facilities that may be more efficient or cost‐effective
solutions to those regional needs
2. Interregional transmission facilities are those that
are located in two or more neighboring
transmission planning regions
3. No requirement to produce an interregional
transmission plan or engage in interconnectionwide planning
7
Cost Allocation
1. Regional transmission planning process must
have a regional cost allocation method for a
new transmission facility selected in the
regional transmission plan for purposes of cost
allocation
2. Neighboring transmission planning regions
must have a common interregional cost
allocation method for a new interregional
transmission facility that the regions select
3. Participant‐funding of new transmission
facilities is permitted, but is not allowed as the
regional or interregional cost allocation method
8
Cost Allocation
4. The rule does not require a one‐size fits all
method for allocating costs of transmission
facilities
– Each region is to develop its own proposed cost
allocation method(s)
5. If region can’t decide on a cost allocation
method, then FERC would decide based on the
record
6. No interconnection-wide cost allocation
9
Nonincumbent Transmission Developers
1. Rule requires the development of a not unduly
discriminatory regional process for transmission
project submission, evaluation, and selection
10
Nonincumbent Transmission Developers
2. Rule removes any federal right of first refusal
from Commission‐approved tariffs and
agreements with respect to new transmission
facilities selected in a regional transmission
plan for purposes of cost allocation, subject to
four limitations:
– This does not apply to a transmission facility that is not selected
in a regional transmission plan for purposes of cost allocation
– This does not apply to upgrades to transmission facilities, such
as tower change outs or reconductoring
– This allows, but does not require, the use of competitive bidding
to solicit transmission projects or project developers
– Nothing in this requirement affects state or local laws or
regulations regarding the construction of transmission facilities,
including but not limited to authority over siting or permitting of
transmission facilities
11
Compliance Filings
 Oct 11, 2012 - Regional Transmission
Planning & Cost Allocation Compliance
filing
 April 11, 2013 - Interregional
Transmission Planning & Cost Allocation
Compliance filing
12
Next Steps
 NCTPC members will more fully evaluate the
Order and potential impacts to the NCTPC
process
 Plan to provide progress updates at future TAG
meetings
 As was done in the Order No. 890 process,
stakeholders will be kept informed during the
development of the compliance filings and will be
given an opportunity to review and comment on
the proposed changes to the NCTPC process
13
14
Major Transmission Project
Update
Orvane Piper
Duke Energy
15
2011 Mid-Year Update to the
2010 Collaborative Transmission Plans
 Contains 4 Progress Energy project in-service
date changes
 Contains 1 Duke Energy project in-service date
change
16
Import Scenarios
Major Projects in 2010 Plan
Reliability Project
Asheville-Enka 230 kV line, Convert 115 kV
line; &
TO
Planned I/S Date
Progress
December ’10
In-Service
Asheville-Enka 115 kV, Build new line
December ’12
Rockingham-West End 230 kV East line
Progress
June ’11
In-Service
Pleasant Garden-Asheboro 230 kV line,
replace Asheboro 230 kV xfmrs
Progress
& Duke
June ’11
In-Service
Ft Bragg Woodruff Street-Richmond 230 kV
Line
Progress
June ’11
In-Service
Clinton-Lee 230 kV line
Progress
December ’11
17
Import Scenarios
Major Projects in 2010 Plan (Continued)
Reliability Project
TO
Planned I/S Date
Brunswick 1 - Castle Hayne 230kV Line,
Construct New Cape Fear River Crossing
Progress
June ’12
December ’12
Jacksonville Static VAR Compensator
Progress
June ‘13
Folkstone 230/115kV Substation
Progress
June ’13
December ’12
Harris-RTP 230 kV line
Progress
June ’14
Greenville-Kinston Dupont 230 kV line
Progress
June ’17
Durham-RTP 230kV Line, Reconductor
Progress
June ’20
June ’21
18
Import Scenarios
Major Projects in 2010 Plan (Continued)
Reliability Project
TO
Planned I/S Date
Reconductor Elon 100 kV Lines (Sadler TieGlen Raven Main)
Duke
June ‘11
In-Service
Reconductor Caesar 230 kV Lines
(Pisgah Tie-Shiloh Switching Station)
Duke
June ‘13
Reconductor London Creek 230 kV Lines
(Peach Valley Tie-Riverview Switching
Station)
Duke
June ‘20
June ‘21
19
20
2011 Study Preliminary
Results
Orvane Piper
Duke Energy
21
2021 Hypothetical Import / Export
Resource 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
22
2021 Hypothetical Import / Export
Resource From
Sink
Test Level (MW)
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
23
2021 Hypothetical Import / Export
Resource From
Sink
Test Level
(MW)
NORTH – PJM (AEP / AEP)
Duke / Progress (CPLE)
600 / 600
NORTH – PJM (AEP / DVP)
Duke / Progress (CPLE)
600 / 600
Duke / EAST - Progress
PJM (DVP)
600 / 600
24
2021 Hypothetical Import / Export
PJM (AEP) - DUKE 600 MW
 Progress
-
No previously unidentified issues
 Duke
-
No previously unidentified issues
25
2021 Hypothetical Import / Export
SOCO - DUKE 600 MW
 Progress
-
No previously unidentified issues
 Duke
-
No previously unidentified issues
26
2021 Hypothetical Import / Export
SCEG - DUKE 600 MW
 Progress
-
No previously unidentified issues
 Duke
-
No previously unidentified issues
27
2021 Hypothetical Import / Export
SCPSA - DUKE 600 MW
 Progress
-
No previously unidentified issues
 Duke
-
No previously unidentified issues
28
2021 Hypothetical Import / Export
Progress (CPLE) - DUKE 600 MW
 Progress
-
No previously unidentified issues
 Duke
-
No previously unidentified issues
29
2021 Hypothetical Import / Export
TVA - DUKE 600 MW
 Progress
-
No previously unidentified issues
 Duke
-
No previously unidentified issues
30
2021 Hypothetical Import / Export
PJM (AEP) – Progress (CPLE) 600 MW
 Progress
-
Construct a 3rd 230 kV line between Rockingham – Lilesville
230 kV substations in 2022.
-
Reconductor Sumter – SCEG’s Eastover 115 kV Line in 2022.
 Duke
-
No previously unidentified issues
31
2021 Hypothetical Import / Export
PJM (DVP) – Progress (CPLE) 600 MW
 Progress
-
Reconductor Sumter – SCEG’s Eastover 115 kV Line in 2022.
 Duke
-
No previously unidentified issues
32
2021 Hypothetical Import / Export
SCEG – Progress (CPLE) 600 MW
 Progress
-
Reconductor Sumter – SCEG’s Eastover 115 kV Line in 2021.
-
Evaluate Wateree/Camden area and open/close status of
Wateree 115/100 kV transformer
 Duke
-
No previously unidentified issues
33
2021 Hypothetical Import / Export
SCPSA – Progress (CPLE) 600 MW
 Progress
-
Reconductor Sumter – SCEG’s Eastover 115 kV Line in 2021.
-
Evaluate Wateree/Camden area and open/close status of
Wateree 115/100 kV transformer
 Duke
-
No previously unidentified issues
34
2021 Hypothetical Import / Export
Duke – Progress (CPLE) 600 MW
 Progress
-
Construct a 3rd Line between Rockingham – Lilesville 230 kV
substations in 2021.
-
Reconductor Sumter – SCEG’s Eastover 115 kV Line in 2023
 Duke
-
No previously unidentified issues
35
2021 Hypothetical Import / Export
PJM (AEP / AEP) – Duke / Progress (CPLE) 1200
MW
 Progress
-
Reconductor Sumter – SCEG’s Eastover 115 kV Line in 2023.
-
Construct a 3rd Line between Rockingham – Lilesville 230 kV
substations in 2024.
 Duke
-
No previously unidentified issues
36
2021 Hypothetical Import / Export
PJM (AEP / DVP) – Duke / Progress (CPLE) 1200
MW
 Progress
-
Reconductor Sumter – SCEG’s Eastover 115 kV Line in 2022.
 Duke
-
No previously unidentified issues
37
2021 Hypothetical Import / Export
Duke / Progress (CPLE) - PJM (DVP) –1200 MW
 Progress
-
No previously unidentified issues
 Duke
-
No previously unidentified issues
38
Davidson County 1000 MW Resource
 2021 Request
Located 5 miles north of
Buck Steam Station on
Tyro 230 kV lines (Buck –
Beckerdite)
Sink/Source in Duke
39
Davidson County 1000 MW Resource
 Progress
-
No previously unidentified issues
 Duke
-
Rebuild Tyro (Buck – Beckerdite) 230 kV lines, 2021
-
Add Buck 230/100 kV transformer, 2021
-
Replace 1 Beckerdite 230/100 kV transformer, 2021
-
Replace 1 Winecoff 230/100 kV transformer, 2021
40
TAG Input Request
 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 7, 2011 to Rich
Wodyka - ITP ([email protected])
41
42
2011 Off-Shore Wind Study
Preliminary Results
Kai Zai
Progress Energy
43
2010 NC Off- Shore Wind Results Review
Summary of 2010 Study
Accommodate 3,000 MW’s into PEC Transmission network
 Four options were studied.
-
Option 1A – via 230 kV Network (Est. cost: $1.195B)
-
Option 1B – via 500 kV Network (Est. cost: $1.310B)
-
Option 2 – Accommodate 2,500 MW’s (Est. cost: $1.155B)
-
Option 3 – Accommodate 2,000 MW’s (Est. cost: $0.525B)
 Last year - Option 1B was considered to be the best
option if considering a long-term build out of off-shore
wind that might exceed the 3,000 MW test level.
44
2011 PWG Off-Shore Wind Scenario
 Approximately 5,000 MW total capacity in 2021
 Injected at two locations on Progress system
Injection Point
On-peak MW
(35-40% CF)
Off-peak MW
(90% CF)
Morehead City
1175
2,700
Bayboro
875
2,300
2,050
5,000
TOTAL
 MW allocation – 40% (2,000 MW) SOCO,
36% (1,800 MW) Duke, 24% (1,200 MW) Progress
45
2011 PWG Off-Shore Wind Scenario
Wind Generation Output 5,000 MW at New Bern Substation
(2) 500/230KV XFMRS
Wake
New Bern
Bayboro
2300/875MW
Wommack
Total= 5000/2050 MW
Cumberland
Jacksonville
Morehead
2700/1175MW
Sutton
Total Wind Output:
5000 MW Off Peak
2050 MW On Peak
230 KV
500 KV
46
Preliminary Off-Shore Wind Results – Duke
 No thermal overloads identified for off-peak and onpeak loads.
47
Preliminary Off-Shore Wind Results – Progress Energy
 Thermal overload issues identified for both off-peak
and on-peak loads.
 Off-peak system load with 5,000 MW
–
–
–
–
–
–
New Bern 500/230 kV transformer Overload
New Bern – Aurora 230 kV Line Overload
New Bern – Wommack 230 kV Line Overload
New Bern 230/115 kV transformer Overload
New Bern – Kinston Dupont 115 kV Line Overload
Rocky Mt. – (DVP) Battleboro 115 kV Line Overload
 On-peak system load with 2,050 MW
–
–
New Bern 230/115 kV transformer Overload
New Bern – Aurora 230 kV Line Overload
48
Preliminary Off-Shore Wind Results – Progress Energy
 Off-peak system load with 4000 MW’s
–
New Bern – Aurora 230 kV Line Overload
 Off-peak system load with 3500 MW’s
–
None
The results have shown that the transmission
identified in Option 1B will accommodate 3,500 MW’s
of wind generation without any additional upgrades.
49
Preliminary Off-Shore Wind Results – Progress Energy
Modify Transmission in Option 1B to accommodate
5,000 MW’s of generation during off peak.


Add Wommack 500/230 kV Transformers (w & w/o Xfmrs at
New Bern).
Add Clinton 500/230 kV Transformers.
Conclusion:



No easy solution. Too much of power tries to flow toward
North (Dominion).
Move the generation connection to Jacksonville 230 kV
substation.
Some incremental transmission is still needed.
50
Preliminary Off-Shore Wind Results – Progress Energy
Wind Generation Output 5,000 MW at Jacksonville Sub.
(2) 500/230KV XFMRS
Wake
Wommack
Bayboro
2300/875 MW
New Bern
Cumberland
Jacksonville
Sutton
Total Wind Output:
5000 MW Off Peak
2050 MW On Peak
Morehead
2700/1175MW
(2) 500/230KV XFMRS
230 KV
500 KV
51
Preliminary Off-Shore Wind Results – Progress Energy
New Bern vs. Jacksonville Side by Side Comparison
New Bern (3,000 – 3,500 MW)
Jacksonville (5,000 MW)
Morehead City area – New Bern 500 kV Lines
(2 Lines = 100 Miles )
Morehead City area – Jacksonville 500 kV Lines
( 2 Lines = 80 Miles)
Bayboro – New Bern 500 kV lines
(2 Lines = 50 Miles)
Bayboro – Jacksonville 500 kV Lines
(2 Lines = 80 Miles)
New Bern 500KV Substation w/ 2 Banks
New Jacksonville 500KV Substation w/ 2 Banks
New Bern – Wommack 500 kV lines
(2 Lines = 70 Miles)
Jacksonville – Wommack 500 kV Lines
(2 Lines = 80)
Wake - Wommack 500 kV line
(65 Miles)
Wake - Wommack 500 kV line
(65 Miles)
Cumberland-Wommack 500 kV line
(80 Miles)
Cumberland-Jacksonville 500 kV line
(70 Miles)
SVC at Wommack
SVC at Wommack
Wommack 500 kV Switch Station
New Wommack 500KV Substation w/ 2 Banks
-----
Reconductor Wommack – Kinston DuPont 230 kV Line
(17 Miles) & Rocky Mt – (VA) Battleboro 115 kV Line (9
Miles)
52
Preliminary Off-Shore Wind Results – Progress Energy
Wind Generation Output 3,000 MW at Jacksonville Sub.
(2) 500/230KV XFMRS
Wake
Wommack
Bayboro
2300/875 MW
New Bern
Cumberland
Jacksonville
Sutton
Total Wind Output:
3000 MW Off Peak
Morehead
2700/1175MW
(2) 500/230KV XFMRS
230 KV
500 KV
53
Preliminary Off-Shore Wind Results – Progress Energy
New Bern vs. Jacksonville Side by Side Comparison
New Bern (3,000 – 3,500 MW)
Jacksonville (3,000 MW)
Morehead City area – New Bern 500 kV Lines
(2 Lines = 100 Miles )
Morehead City area – Jacksonville 500 kV Lines
( 2 Lines = 80 Miles)
Bayboro – New Bern 500 kV lines
(2 Lines = 50 Miles)
Bayboro – Jacksonville 500 kV Lines
(2 Lines = 80 Miles)
New Bern 500KV Substation w/ 2 Banks
New Jacksonville 500KV Substation w/ 2 Banks
New Bern – Wommack 500 kV lines
(2 Lines = 70 Miles)
Jacksonville – Wommack 500 kV Lines
(2 Lines = 80)
Wake - Wommack 500 kV line
(65 Miles)
Wake - Wommack 500 kV line
(65 Miles)
Cumberland-Wommack 500 kV line
(80 Miles)
Cumberland-Jacksonville 500 kV line
(70 Miles)
SVC at Wommack
SVC at Wommack
Wommack 500 kV Switch Station
New Wommack 500KV Substation w/ 2 Banks
-----
Reconductor Wommack – Kinston DuPont 230 kV Line
(17 Miles) & Rocky Mt – (VA) Battleboro 115 kV Line (9
Miles)
54
Preliminary Off-Shore Wind Results – Progress Energy
Wind Generation Output 2,000 MW at Jacksonville Sub.
Wake
Wommack
Bayboro
2300/875 MW
New Bern
Cumberland
Morehead
2700/1175MW
Jacksonville
Sutton
Total Wind Output:
5000 MW Off Peak
2050 MW On Peak
230 KV
500 KV
55
Preliminary Off-Shore Wind Results – Progress Energy
New Bern vs. Jacksonville Side by Side Comparison
New Bern (2,000 MW)
Jacksonville (2,000 MW)
Morehead City area – New Bern 230 kV Lines
(2 Lines = 100 Miles )
Morehead City area – Jacksonville 230 kV Lines
( 2 Lines = 80 Miles)
Bayboro – New Bern 230 kV lines
(2 Lines = 50 Miles)
Bayboro – Jacksonville 230 kV Lines
(2 Lines = 80 Miles)
Havelock – New Bern 230 kV line
(30 Miles)
Jacksonville – Wommack 230 kV lines
(2 Lines = 70 Miles)
Greenville West- New Bern 230 kV line
(40 Miles)
-----
New Bern SVC
Wommack SVC
56
TAG Input Request
 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 7, 2011 to Rich
Wodyka - ITP ([email protected])
57
58
Regional Studies Reports
Bob Pierce
Duke Energy
59
Carolinas Transmission Planning
Coordination Arrangement (CTPCA)
60
CTPCA
STUDY PURPOSE:
 Assess the existing transmission expansion plans
of DEC, PEC, SCEG, and SCPSA to ensure that the
plans are simultaneously feasible.
 Evaluate any potential joint alternatives identified
by the Steering Committee representatives which
might improve the simultaneous feasibility of the
participants’ transmission expansion plans.
61
CTPCA
STUDY ASSUMPTIONS
 2011 Series LTSG models for 2015S and 2018S are
being used for external systems
 Models were updated to include the detailed internal
models for DEC, PEC, SCEG, and SCPSA
 Models include transmission additions planned to be
in-service for the given year
62
CTPCA
STUDY ASSUMPTIONS
 Evaluating multiple generation down cases in each
area
 Interchange was coordinated to include all confirmed
long term firm transmission reservations with rollover rights applicable to the study year(s).
 Performing analysis with report expected to
complete in October
63
Eastern Interconnection Planning
Collaborative (EIPC)
64
EIPC background
 EIPC Objectives
1. 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
65
EIPC Structure
Eastern Interconnection Planning Collaborative (EIPC)
(Open Collaborative Process)
Steering Committee
EIPC Analysis Team
Principal Investigators
Planning Authorities
Executive
Leadership
Technical
Leadership &
Support Group
Stakeholder
Work Groups
Stakeholder
Groups
States
Provinces
Federal
Owners
Operators
Users
…
66
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
– Creation of the 8 futures and sensitivities by the SSC
– CRA to perform macroeconomic analysis, to include transmission
high level cost estimate by PA’s
– SSC selection of the 3 cases for full transmission build out analysis
and cost estimate
– Development of the Phase I report
 Phase II - October, 2011 to Late 2012
– Develop transmission expansion options, along with associated
costs, for 3 agreed on expansion scenarios
67
EIPC Current Activities
Planning Authorities
 Developing high level transmission expansion cost
estimates for futures 2, 3, 5, 6, & 8.
• 2 – Federal Carbon Constraint; National
Implementation
• 3 – Federal Carbon Constraint; Regional
Implementation
• 5 – National RPS; Top-Down Implementation
• 6 – National RPS; State/Regional Implementation
• 8 – Combined Federal Climate & Energy Policies
68
Southeast Inter-Regional
Planning Process (SIRPP)
Update
69
SIRPP
 Next meeting is September 30th in
Columbia, SC
 Will select next 5 economic studies to be
performed
70
http://www.southeastirpp.com/
71
Joint NCTPC/AEP/PJM STUDY
72
Joint NCTPC/AEP/PJM STUDY
 Evaluating 2021 summer and 2016 winter
conditions
 Detailed models for DEC, PEC and AEP areas
being used
 Will evaluate NERC TPL-002 Single Element
and TPL-003 Multiple element contingencies
 Includes the impact of retirement of older fossil
units on all three systems
73
 Compiling final report
SERC Long-term Study Group
(LTSG)
74
SERC LTSG
 2011 Series ERAG MMWG models
being developed
 2011 Study of 2017 Summer report
being drafted, complete by December
75
NERC Reliability Standards Update
76
NERC Reliability Standards Update
 PRC-023 Relay Loadability
 TPL-001-2
 BES Definition
77
BES Definition
Bulk Electric System (BES): Unless modified by the lists shown
below, all Transmission Elements operated at 100 kV or higher and
Real Power and Reactive Power resources connected at 100 kV or
higher. This does not include facilities used in the local distribution
of electric energy.
Inclusions:
 I1 - Transformers with primary and secondary terminals operated
at 100 kV or higher unless excluded under Exclusion E1 or E3.
 I2 - Generating resource(s) (with gross individual or gross
aggregate nameplate rating per the ERO Statement of Compliance
Registry Criteria) including the generator terminals through the
high-side of the step-up transformer(s) connected at a voltage of
100 kV or above.
78
BES Definition
 I3 - Blackstart Resources identified in the Transmission
Operator’s restoration plan.
 I4 - Dispersed power producing resources with aggregate
capacity greater than 75 MVA (gross aggregate nameplate rating)
utilizing a system designed primarily for aggregating capacity,
connected at a common point at a voltage of 100 kV or above.
 I5 – Static or dynamic devices dedicated to supplying or
absorbing Reactive Power that are connected at 100 kV or higher,
or through a dedicated transformer with a high-side voltage of 100
kV or higher, or through a transformer that is designated in
Inclusion I1.
79
BES Definition
Exclusions:
 E1 - Radial systems: A group of contiguous transmission
Elements that emanates from a single point of connection of 100
kV or higher and:
a) Only serves Load. Or,
b) Only includes generation resources, not identified in
Inclusion I3, with an aggregate capacity less than or equal to
75 MVA (gross nameplate rating). Or,
c) Where the radial system serves Load and includes
generation resources, not identified in Inclusion I3, with an
aggregate capacity of non-retail generation less than or
equal to 75 MVA (gross nameplate rating).
Note – A normally open switching device between radial systems, as depicted
on prints or one-line diagrams for example, does not affect this exclusion.
80
BES Definition
 E2 - A generating unit or multiple generating units that serve all
or part of retail customer Load with electric energy on the
customer’s side of the retail meter if:
(i) the net capacity provided to the BES does not exceed 75 MVA,
and
(ii) standby, back-up, and maintenance power services are
provided to the generating unit or multiple generating units or
to the retail Load by a Balancing Authority, or provided
pursuant to a binding obligation with a Generator Owner or
Generator Operator, or under terms approved by the applicable
regulatory authority.
81
BES Definition
 E3 - Local networks (LN): A group of contiguous transmission
Elements operated at or above 100 kV but less than 300 kV that
distribute power to Load rather than transfer bulk power across
the interconnected system. LN’s emanate from multiple points of
connection at 100 kV or higher to improve the level of service to
retail customer Load and not to accommodate bulk power
transfer across the interconnected system.
82
BES Definition
The LN is characterized by all of the following:
a) Limits on connected generation: The LN and its underlying Elements do
not include generation resources identified in Inclusion I3 and do not
have an aggregate capacity of non-retail generation greater than 75 MVA
(gross nameplate rating) ;
b) Power flows only into the LN: The LN does not transfer energy
originating outside the LN for delivery through the LN; and
c) Not part of a Flowgate or transfer path: The LN does not contain a
monitored Facility of a permanent Flowgate in the Eastern
Interconnection, a major transfer path within the Western
Interconnection, or a comparable monitored Facility in the ERCOT or
Quebec Interconnections, and is not a monitored Facility included in an
Interconnection Reliability Operating Limit (IROL).
83
BES Definition
 E4 – Reactive Power devices owned and operated by the retail
customer solely for its own use.
Note - Elements may be included or excluded on a case-by-case basis through the
Rules of Procedure exception process.
84
2011 TAG Work Plan Review
Rich Wodyka
ITP
85
2011 Overview Schedule
Reliability Planning Process
 Evaluate current reliability problems and transmission upgrade plans
 Perform analysis, identify problems, and develop solutions
 Review Reliability Study Results
Enhanced Access Planning Process
 Propose and select enhanced access scenarios and interface
 Perform analysis, identify problems, and develop solutions
 Review Enhanced Access Study Results
Coordinated Plan Development
 Combine Reliability and Enhanced Results
 OSC publishes DRAFT Plan
 TAG review and comment
TAG Meetings
1st Quarter
2nd Quarter
3rd Quarter
4th Quarter
86
2011 TAG Work Plan
January - February
 Finalize 2011 Study Scope of Work

Receive final 2011 Reliability Study Scope for comment

Review and provide comments to the OSC on the final
2011 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
87
April - June
TAG Meeting – June 13th
 Receive a progress report on the 2011 Reliability
Planning study activities and preliminary results
88
June - July
 2011 TECHNICAL ANALYSIS, PROBLEM
IDENTIFICATION and SOLUTION DEVELOPMENT
 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 2010
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
89
August - October
TAG Meeting – September 16th
 2011 STUDY UPDATE
 Receive a progress report on the Reliability Planning
 2011 SELECTION OF SOLUTIONS
–
TAG will receive feedback from the OSC on any alternative
solutions that were proposed by TAG members
90
December
2011 STUDY REPORT
– Receive and comment on final draft of the 2011
Collaborative Transmission Plan report
TAG Meeting
– Receive presentation on the draft report of 2011
Collaborative Transmission Plan
– Provide feedback to the OSC on the 2011 NCTPC
Process
– Review and comment on the proposed 2012 TAG
Work Plan Schedule
91
92
TAG
Open Forum Discussion
93