Presentations - South Carolina Regional Transmission Planning

South Carolina Regional Transmission Planning
Stakeholder Meeting
Hilton Garden Inn – Charleston Airport
Charleston,
Charleston SC
September 8, 2011
Purpose and Goals for Today’s Meeting
• Review Initial Results of Reliability Assessments
• Local Area
• Inter-regional
• SERC
• ERAG
• Multi
Multi-Party
Party
• Discuss Proposed Changes to Expansion Plans
• Discuss Alternative Solutions from Stakeholders
• Present Information on FERC Order 1000
2
3
Stakeholder
Meetings
4 - Economic
Transfer
Studies Initial Results
Economic
Transfers
Reliability
Planning
1 - Reliability
R li bilit
Planning
Kick-off
2 - Reliability
Studies Initial Results
3 - Economic
Transfers
Selected
4
Transmission Expansion Drivers:
– Criteria Testing
• NERC Reliability Standards
• Internal Planning Guidelines
– Customer Needs
•
•
•
•
Distribution
st but o & Industrial
dust a
Wholesale (cooperative & municipal)
Network
Firm PTP
– Generator Interconnection Needs
– Actual system performance (poor performance)
5
Reliability Planning Study Activities
SCE&G
Joe Hood
6
NERC TPL Standards
NERC
TPL Standards
Table 1
7
SCE&G Internal Planning Criteria
Event resulting in the
lloss off a single
i l componentt
Generator
Transformer
Transmission line
Underground cable
Capacitor bank
Voltage limit
95.0%
95.0%
95.0%
95.0%
95.0%
Event resulting in the loss
of two or more components
One bus segment
Two bus segments (one bus tie breaker failure)
Multiple circuits on a same structure
All generation
ti in
i any one plant
l t
Generator+ Transmission Line or Underground Cable
Generator + Generator
Generator + Transformer
Generator + Capacitor bank
Transformer + Transformer
Transformer + Transmission Line or Underground Cable
Transformer + Switch
Transformer + Capacitor bank
Transmission line + Transmission line
Transmission line + Underground cable
Transmission line + Capacitor bank
Capacitor bank + Underground cable
Voltage limit
95.0%
92.5%
95.0%
95 0%
95.0%
92.5%
92.5%
92.5%
92.5%
92.5%
92.5%
92.5%
92.5%
92.5%
92.5%
92.5%
92.5%
Thermal
li it
limit
100%
100%
100%
100%
100%
Thermal
limit
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
8
Modeling Assumptions
Basecase Development:
– SCE&G Area: Detailed Data from Model Database ‐ Including Most Current Transmission Expansion Plan p
– SERC Region: Latest 2011 Series
Reduced Long Term Study Group Models
– North America: 2010 Series MMWG Models (Electrically Equivalenced)
9
Modeling Assumptions
• Dispersed Substation Load Forecast – Summer/Winter Peak, Off‐Peak and Seasonal Load Levels
• Existing Generation
Existing Generation
– Input from Generation Maintenance Schedule
• Generation Additions
– Input from Generation Expansion Plan
f
l
• Transmission Additions
– Input from Planners and Engineering
• Firm Transmission Service
– Input from OASIS, Coordinate with Neighbors
• Neighboring Transmission Systems Modeled
Neighboring Transmission Systems Modeled
10
Reliability Study Procedure
Analysis Tools:
– Siemens
Siemens PSS/E Power PSS/E Power
Systems Simulator
– PowerWorld Simulator
PowerWorld Simulator
– Automation Programs (Python NET)
(Python, .NET)
11
Reliability Study Procedure
Start
Run Criteria Screening
Violations ?
Yes
Create/Change Project or Create/Change Procedure and Update Model
• Run all NERC TPL Category A, B and C contingencies, and selected D contingencies for each iteration and each seasonal/loading condition (~100,000 contingencies per iteration)
• Violations may initiate transmission expansion studies or require operating procedures depending on probability and severity of problem
No
E d
End
Initiate Detailed Alternative Studies
12
Santee Cooper Local Reliability Studies
• Planning Criteria
• Reliability Study Procedure
Willi G
William
Gaither
ith
Planning Criteria
• Santee Cooper Internal Planning Criteria
– D
Documented
t d iin 1987
– Last revised in September, 2007
• North American Electric Reliability Corporation (NERC)
TPL Standards
SCPSA Internal Planning Criteria
Event Description
Voltage limit
Delivery Point Bus
Bus, normal operating conditions
Delivery Point Bus, emergency operating conditions
Transmission lines, within continuous rating during normal operations
Transmission lines, within emergency rating during contingency events
Transformers, within its max. 55 degree C rating during normal operations
Transformers, within 107 % of its max. 65 degree C rating during
contingency events
92.5%
92
5% to 102.5%
102 5%
90.0% to 104.0%
NERC TPL Standards
Table 1
Reliability Study Procedure
• Power Flow Models
– Updated loads from current corporate load forecast,
Central supplied load forecast, industrial loads
– Detailed data including the most current transmission
expansion plan
– Transmission associated with new generation
– SERC Region:
g
2011 Series Reduced LTSG Models
– North America: 2011 Series MMWG Models (Electrically
Equivalenced)
Reliability Study Procedure
• Analysis Tools
– Siemens/PTI PSS/E Power Systems Simulator
– Python Automation Programs
– Microsoft Access and Excel
Reliability Study Procedure
• Contingencies Tested:
–
–
–
–
–
–
–
–
–
–
All Single Transmission Line Outages at 230 kV, 115 kV, and 69 kV
All Single Transformer Outages
All Single
Si l B
Bus O
Outages
t
All Single Generator Unit Outages
Selected Combinations of 2 Transmission Line Outages
S l t dC
Selected
Combinations
bi ti
off 2 Transformer
T
f
Outages
O t
Selected Combinations of 2 Generator Unit Outages
Selected Combinations of 1 Transmission Line Outage and 1 Transformer Outage
S
Selected
Combinations
C
off 1 Transmission Line Outage
O
and 1 Generator
G
Unit Outage
O
Selected Combinations of 1 Transformer Outage and 1 Generator Unit Outage
Reliability Study Procedure
•
•
•
•
•
•
Review results of tested contingencies
Identifyy contingencies
g
that fail to meet p
planning
g criteria
Recommend project to correct facility not meeting criteria
Test recommended p
project
j against
g
planning
p
g criteria
If recommended project meets criteria add to transmission plan
If recommended project does not meet criteria, develop
alternative project and re-test until planning criteria met
• Develop transmission plan based on recommended projects
CTPCA Future Year Assessments
Kale Ford
CTPCA Purpose
• Collection of agreements developed concurrently by the
Principals and Planning Representatives of multiple two
twoparty Interchange Agreements
• Establishes a forum for coordinating certain transmission
planning and assessment activities among the specific
parties associated with the CTPCA
CTPCA Purpose
Interchange Agreements associated with the CTPCA
Duke Energy
gy Corporation
p
((“Duke”)) and Progress
g
Energy
gy Carolinas ((“PEC”))
Duke Energy Corporation (“Duke”) and South Carolina Electric & Gas Company (“SCE&G”)
Duke Energy Corporation (“Duke”) and South Carolina Public Service Authority (“SCPSA”)
Progress
g
Energy
gy Carolinas ((“PEC”)) and South Carolina Electric & Gas Company
p y ((“SCE&G”))
Progress Energy Carolinas (“PEC”) and South Carolina Public Service Authority (“SCPSA”)
South Carolina Electric & Gas Company (“SCE&G”) and South Carolina Public Service Authority
(“SCPSA”)
35
CTPCA Power Flow Study Group
•
Duke Energy Carolinas (“Duke”)
•
Progress Energy Carolinas (“Progress”)
•
South Carolina Electric & Gas (“SCEG”)
•
South Carolina Public Service Authority (“SCPSA”)
37
CTPCA Studies
Purpose
• Assess the existing transmission expansion plans of Duke, Progress,
SCEG, and SCPSA to ensure that the plans are simultaneously
feasible.
• Identify any potential joint solutions which would improve the
simultaneous feasibility of the Participant companies’
companies transmission
expansion plans.
• The Power Flow Study Group (“PFSG“) will perform the technical
analysis outlined in this study scope under the guidance and
direction of the Steering Committee (“SC”).
38
CTPCA Studies
Scope
• NERC Reliability Standards, SERC Requirements, and individual
company
p y studyy criteria.
• Cases are developed with detailed internal models with current
transmission expansion plans from each participating company.
• Generation down cases are developed from starting point cases with
internal generation redispatch and Transmission Reserve Margin (TRM)
import(s)
po t(s) implemented.
p e e ted
39
CTPCA Studies
Scope (continued)
• Studyy results are obtained byy use of PTI's MUST and PSS/E pprograms.
g
• Report on thermal loading(s) above 90% and voltage(s) violating
individual company criteria
• 2014/21 Summer Study report, Spring 2011 (2010 Study)
• 2015/18 Summer Study report draft, Fall/Winter 2011 (2011 Study)
-Results
Results are currently being compiled
40
CTPCA 2014/21 Summer Study
Element
Contingency
McIntosh-Jasper Tap
115 kV Line
(Southern/SCE&G)
Cross 3 Gd
Jasper-Yemassee
230 kV Line
Cross 3 Gd
Lyles-Edenwood
230 kV Line
Cliffside 6 Gm
Saluda-Georgia Pacific
Tap 115 kV Line
Belews Creek 1 Gm
McIntosh-Purrysburg
230 kV Line
(Southern/SCPSA)
(Sout
e /SC S )
Lyles-Williams St
115 kV Line
Georgia Pacific Tap
McIntosh-Jasper Tap
115 kV Line
(Southern/SCE&G)
Year
Potential
Issue
Potential
Solution
2014
Loading
(100.6 %)
Jasper-Okatie-Yemassee
230 kV Line
2014
Loading
(104.3 %)
Line Upgrade
2014/21
High
Voltage
Transformer Tap Changes
2021
Loading
(118.8 %)
SCE&G and Southern Company are
jointly investigating
Upgrade Transformer to 336 MVA
and leave 224 MVA as in-service
spare
Winnsboro or Blythewood
Substation
Summerville
230/115 kV 2
Cross 3 Gd
Summerville
230/115 kV 1
2021
Loading
(100.1 %)
Parr-Winnsboro
Parr
Winnsboro
115 kV Line
Pineland-North
Pineland
North Point
115 kV Line
2021
Loading
(100.4 %)
40
McIntosh-Jasper 115 kV
Lyles-Williams Street 115 kV
Georgia Pacific Tap 115 kV
Summerville 230/115 kV
Parr-Winnsboro115 kV
CTPCA 2014/21 Summer Study
Element
Contingency
Year
Potential
Issue
Arcadia-Parkersville
115 kV Line
Brunswick 2 Gd (TRM)
Perry Road-Campfield
230 kV Line
2014
Loading
(91.8 %)
Winyah-Campfield
230 kV Line
Brunswick 1 Gd (TRM)
Winyah-Hemingway
230 kV Line
2014
Loading
(96.9 %)
Georgetown-Campfield
3 115 kV Line
McGuire 1 or 2 Gm
Winyah-Campfield
230 kV Line
2014
Loading
(115.2 %)
Georgetown-Winyah 1
115 kV Line
Brunswick
B
i k 1 or 2 Gd
(TRM)
Georgetown-Winyah 2
115 kV Line
2021
Loading
(93.0 %)
Potential
Solution
Bucksville 230-115 kV Sub. [2015]
Winyah-Bucksville 230 kV [2016]
Bucksville-Garden City 115 kV
[2017]
Bucksville 230-115 kV Sub. [2015]
Winyah-Bucksville 230 kV [2016]
Bucksville-Garden City 115 kV
[2017]
Bucksville 230-115 kV Sub. [2015]
Winyah-Bucksville 230 kV [2016]
Bucksville-Garden City 115 kV
[2017]
Bucksville
uc sv e 230-115
30 5 kV
V Sub. [[2015]
0 5]
Winyah-Bucksville 230 kV Line
[2016]
Bucksville-Garden City 115 kV Line
[2017]
40
Arcadia-Parkersville115 kV
Winyah-Campfield 230 kV
Georgetown-Campfield
Georgetown
Campfield 3 115 kV
Georgetown-Winyah 1 115 kV
CTPCA Studies
Questions?
41
SERC Future Year Assessments
Long Term Study Group (LTSG)
42
SERC LTSG 2017 Summer Study
Purpose
• Analysis
y of the pperformance of the members’ transmission
systems that identifies limits to power transfers occurring nonsimultaneously among the SERC members.
• Analysis of the performance of the members’ transmission
systems under normal conditions and loss of a single element.
element
43
SERC LTSG 2017 Summer Study
Scope
• Assess the strength of the SERC interconnected network by
d t i i itits ability
determining
bilit tto supportt power ttransfers.
f
• NERC Reliability Standards and SERC Requirements.
Requirements
• Case is developed by the SERC LTSG Modeling Group.
Group
44
SERC LTSG 2017 Summer Study
Scope (continued)
• Study results are obtained by use of PTI's MUST and PSS/E
programs.
• Identify
Id tif Significant
Si ifi t F
Facilities
iliti under
d ttransfer
f analysis.
l i
• Study
St d scheduled
sched led to be completed December 2011
45
SERC LTSG 2017 Summer Study
Si ifi t Facilities
Significant
F iliti
• If the facility is a hard limit to a transfer
• The level at which it limits a transfer compared to the test level
• The response of the facility to the transfer
• The number of different transfers/companies impacted
46
SERC LTSG 2017 Summer Study
Si ifi t Facilities
Significant
F iliti ((continued)
ti d)
• If the facility requires the use of an operating guide
• If the outage of the facility results in the overload of numerous
major
j ttransmission
i i elements
l
t
• If an act
actual
al TLR has been called on the facility
facilit
47
SERC LTSG 2017 Summer Study
V i bl Factors
Variable
F t
• Load forecasts and generation availability
• Anticipated drought conditions in the SERC area
• Geographic distribution of load and generation
48
SERC LTSG 2017 Summer Study
Variable
V i bl Factors
F t
(continued)
( ti d)
• Transmission system configuration
• Simultaneous inter-system power transfers
• Operation based on regional requirements to respect
additional contingencies
49
2017 LTSG Summer Reliability Study
Preliminary Results
Element
SRS-Canadys 230 kV
Contingency
Potential
Issue
McIntosh-Purrysburg
McIntosh
Purrysburg
FCITC Import
230 kV (open McIntoshlimit
Jasper Tap 115 kV)
Potential
Solution
Evaluating
L i t L l 115 kV
Lexington-Lyles
P
Pomaria-VCS
i VCS S
Sub
b2
FCITC Export
p
Limit
R
Reconductor
d t
McIntosh-Purrysburg
230 kV
None
NITC Import
Limit
Evaluating
50
Lexington-Lyles 115 kV
SRS-Canadys 230 kV
McIntosh-Purrysburg 230 kV
SERC LTSG Study
Questions?
Q ti ?
51
ERAG Future Year Assessments
Phil Kleckley
SERC EastEast-RFCRFC-NPCC
•
•
SERC East
9 VACAR (Duke, DVP, PEC, SCE&G, SCPSA)
9 Central (TVA, EON U.S., EKPC, BREC)
Reliabilityy First Corporation
p
9 PJM (Pennsylvania, New Jersey, Maryland)
p
System
y
Operator)
p
)
9 MISO ((Midwest Independent
SERC EastEast-RFCRFC-NPCC
(CONT.)
•
Northeast Power Coordinating Council
9 Northeast United States
9 Southeast Canada
SERC EastEast-RFCRFC-NPCC
Long--Term Studies
Long
•
•
•
Analysis of interregional system performance during
regional and sub-regional power transfers
Study of normal and contingency conditions
p outages
g and simultaneous
Effects of selected multiple
transfers on system performance
SERC EastEast-RFCRFC-NPCC
Long--Term Studies
Long
•
•
•
•
Identifyy transfer limits from and to each studyy region
g
Transfer limits are not ATC or TTC as required in FERC
Orders 888 and 889 and posted on OASIS
Results are conditional, not absolute or optimal
Identifyy facilities havingg thermal or selected
voltage/reactive limits for regional and sub-regional
transfers
SERC EastEast-RFCRFC-NPCC
Long--Term Studies
Long
• FCITC - First Contingency
g y Incremental Transfer Capability
p
y
is the incremental transfer capability above the transfers
modeled in the base case
• FCTTC - First Contingency Total Transfer Capability is the
algebraic sum of the FCITC and the base case region-toregion
i ttransfer
f
SERC EastEast-RFCRFC-NPCC
Long--Term Studies
Long
•
•
•
Analysis of FCITCs for simultaneous transfers among, or
through study areas
FCITCs and FCTTCs for non-simultaneous transfers
Appraisals
pp
for PJM,, Midwest ISO,, SERC East and NPCC
study areas
SERC EastEast-RFCRFC-NPCC
Long--Term Studies
Long
FCITC values are based on the prediction of many factors that
could change in daily operation of the power system
SERC EastEast-RFCRFC-NPCC
Long-Term Studies
LongReliability Assessment Assumptions
•
•
•
Load forecasts and generation availability
Geographic distribution of load and generation
Transmission system configuration
SERC EastEast-RFCRFC-NPCC
Long-Term Studies
LongReliabilityy Assessment Assumptions
p
•
•
•
Simultaneous inter
inter-system
system power transfers
Regional operational requirements for contingencies
Phase Angle Regulator control settings
SERC EastEast-RFCRFC-NPCC
2021 Summer Long Term Study
Scope
•
•
•
•
Due November 2011
Develop 2021 summer base case with all scheduled firm
capacity backed transactions
Determine thermal regional and sub-regional FCITCs
Determine FCTTCs for regional and sub-regional transfers
SERC EastEast-RFCRFC-NPCC
Scope
Scope
• Reliability Analysis for selected transfers occurring
•
•
•
simultaneously among, or through the SERN regions
Identify Limiting facilities for non-simultaneous emergency
transfers among MISO
MISO, SERC East,
East expanded PJM and NPCC
Appraisals for the PJM, MISO ,SERC East and NPCC study areas
The FCITCs reported in the study are based on simulated
system operation
SERC EastEast-RFCRFC-NPCC
Interregional Transmission System
S stem
Reliability Assessments
Questions?
Multi--Party Studies
Multi
59
SCE&G/Santee Cooper/Southern
Interface Assessment
William Gaither
Study Scope
•
A multimulti-party assessment
•
Conducted under multiple
p twotwo-p
partyy Interchange
g Agreements
g
–
–
–
•
Identify potential transfer limits across these interfaces:
–
–
–
•
Southern Company and South Carolina Electric & Gas
Southern Company and South Carolina Public Service Authority
South Carolina Electric & Gas and South Carolina Public Service Authority
Southern Balancing Authority - South Carolina Electric & Gas
Southern
S th
Balancing
B l i Authority
A th it – Santee
S t Cooper
C
South Carolina Electric & Gas – Santee Cooper
Study timeframe – long
long--term planning horizon (2016(2016-2020)
Study Results
• Development of operating guide SO1
• SO1 operating guide – for the loss of the McIntosh
McIntosh--Purrysburg
230 kV tie, open the McIntoshMcIntosh-Jasper Tap 115 kV tie
• SO1 utilized in the current SERC LTSG study of 2017 Summer
Proposed Changes to
Transmission Expansion Plan
SCE&G
Joe Hood
63
SCE&G Recently Completed Transmission Projects
y
p
j
9 Pepperhill
pp
– Robert Bosch 115kV Line Upgrade
pg
9 Lake Murray – McMeekin 115kV Line Upgrade
9 Lake Murray –
Lake Murray – Saluda Hydro 115kV Line Upgrade Saluda Hydro 115kV Line Upgrade
9 Saluda Hydro – McMeekin 115kV Line Upgrade Saluda River 230kV Transmission Project
• Adds a new 230/115kV Substation
• Located between Lake Murray and Downtown db
k
d
Columbia near the Saluda River
• Allows the following costly projects to be canceled:
• Denny Terrace Add 3rd Autotransformer
• Lake Murray Add 3rd Autotransformer
Greater Columbia Area
Saluda River 230kV Transmission
Charleston Peninsula Area Improvement Projects
• Consolidates and Changes the Scope of the following Projects:
• Accabee – Charlotte St 115kV Line Upgrade to Double Circuit
Charlotte St 115kV Line Upgrade to Double Circuit
• Faber Place – Accabee 115kV Line Upgrade
• Adds the Following Projects:
Add th F ll i P j t
• Upgrade Hagood – Bee St 115kV Line to B‐795 ACSR
• Construct Faber Place – Hagood 115kV Line #2
• Retires Aging Accabee 115kV Substation
Charleston Peninsula Area Improvement
Charleston Peninsula Area Improvement
Postponed Projects
• Lake Murray 2nd Autotransformer
12/31/2012
5/1/2013
• Belvedere – Church Ck 115kV Upgrade
12/31/2012
5/1/2014
• Yemassee – Burton #2 115kV Upgrade 5/1/2013
5/1/2014
• Pepperhill – Summerville 230kV Line
5/1/2013
5/1/2014
• Okatie 230kV Substation
230kV Substation
5/1/2014
5/1/2015
V.C. Summer Unit #2 Related Projects
•
•
•
•
•
•
Denny Terrace ‐ Lyles 230kV Line Upgrade
Lake Murray ‐
y McMeekin 115kV Line Upgrade
pg
Lake Murray ‐ Saluda 115kV Line Upgrade
Saluda ‐ McMeekin 115kV Line Upgrade
VCS2 ‐ Lake Murray #2 230kV Line Construct
y
VCS2 ‐ Winnsboro ‐ Killian 230kV Line Construct
12/31/2015
12/31/2015
12/31/2015
12/31/2015
12/31/2015
/ /
12/31/2015
V.C. Summer Unit #3 Related Projects
•
•
•
•
•
Saluda ‐ Duke 115kV Tielines Upgrade
St George 230kV Switching Station Construct
St George ‐ Canadys 230kV Line Upgrade
St George ‐ Summerville 230kV Line Upgrade
VCS Sub #2 ‐ St George 230kV Double Circuit Construct 12/31/2018
12/31/2018
12/31/2018
12/31/2018
12/31/2018
Proposed Changes to
Transmission Expansion Plan
Santee Cooper
William Gaither
74
Transmission Network
C
Completed
l t d Projects
P j t
•
•
•
•
•
Carnes Crossroads-Cane Bay Tap Double Circuit 115 kV
Cane Bay 115 kV Tap Line
Lake Ridge 115 kV Tap Line
Red Dam 115 kV Tap Line
Bennettsville City-Mohawk 69 kV Line
Transmission Network
Planned Projects
•
•
•
•
•
•
•
•
•
•
Arcadia-Garden City #2 115 kV Line
Carolina Forest 230-115 kV Substation
Carolina Forest-Dunes #2 115 kV Line
Fold Hemingway-Marion 230 kV Line into Lake City
Orangeburg 230-115 kV Substation
Pomaria 230-69 kV Substation
Bucksville 230-115 kV Substation
Winyah-Bucksville 230 kV Line
Bucksville-Garden City 115 kV Line
Transmission Plans Associated with VCS #2 (2016) and VCS #3 (2019)
12/2011
06/2012
06/2012
06/2012
12/2012
06/2013
06/2015
06/2016
06/2017
06/2014
06/2015
06/2016
Grand Strand Area
Myrtle Beach Area
• Issues:
– Large load center served from remote resources
– Tightly-integrated
Ti htl i t
t d transmission
t
i i system
t
– Numerous contingencies impact “source” lines into the area
– Line loadings projected to exceed their normal rating
Arcadia-Garden City #2 115 kV Line
• Problem:
– Contingency:
• Outage
O t
off Campfield-Perry
C
fi ld P
Road
R d 230 kV Line
Li
• Severe or extreme events in the Myrtle Beach Area
– Result:
• Arcadia-Litchfield 115 kV line section mayy overload
– Base case loading projected to exceed normal rating in 2012
Arcadia-Garden City #2 115 kV Line
• Solution:
– Rebuild the existing Garden
City-Arcadia 115 kV Line as
a double
do ble circuit
circ it line
• Benefit:
– Provide another source into
southern portion of Myrtle
Beach area.
Carolina Forest 230/115 kV Substation
Carolina
Forest
• Solution:
– Construct the Carolina Forest
230/115 kV Substation
– Construct 115 kV line from
Carolina Forest to Dunes
115-12 kV Substation
• Benefits:
– Provide another bulk source into
the central part of Myrtle Beach
– Relieve
R li
dependency
d
d
on P
Perry
Road and Myrtle Beach
Substations
Fold Hemingway-Marion 230 kV into Lake City
Orangeburg-St. George-Varnville 69 kV System
Orangeburg
230/115 kV
Sub
Pomaria 230-69 kV Substation
Marion
Bucksville Transmission Projects
Fold Hemingway
HemingwayMarion 230 kV Line
into Lake City
Red Bluff
Carolina Forest 230115 kV Substation
Conway
Bucksville 230-115
kV Substation
S b t ti
Lake City
y
Dunes
Perry Road
Hemingway
Kingstree
Winyah-Bucksville
230 kV Line
Garden City
Campfield
Arcadia-Garden City
115 kV Line #2
Georgetown
Winyah
Arcadia
VC Summer #2 Transmission Plan (ISD 2016)
Flat Creek 230-69 kV Sub.
Richburg 69 kV Sw.
Sw Sta.
Sta
Winnsboro 69 kV Sw. Sta.
VC Summer Nuclear Plant
Camden 230-69 kV Sub.
Lugoff 230-69 kV Sub.
Pomaria 69 kV Sw.
Sw Sta.
Sta
Blythewood 230-115-69 kV Sub.
VC Summer #2 Transmission Plan (ISD 2016)
Flat Creek 230-69 kV Sub.
Richburg 230-69
230 69 kV Sub
Sub.
Winnsboro 230-69 kV Sub.
VC Summer Nuclear Plant
Camden 230-69 kV Sub.
Lugoff 230-69 kV Sub.
Pomaria 230-69
230 69 kV Sub
Sub.
Blythewood 230-115-69 kV Sub.
VCS #2 Transmission Projects
•
•
•
•
•
Winnsboro 230-69 kV Substation
VCS-Winnsboro
CS
sbo o 230
30 kV Linee
Richburg 230-69 kV Substation
Winnsboro-Richburg 230 kV Line
Richburg Flat Creek 230 kV Line
Richburg-Flat
09/2013
11/2013
/ 0 3
06/2014
08/2014
10/2015
VC Summer #3 Transmission Plan (ISD 2019)
VC Summer Nuclear
Newberry 230-69 kV Sub.
Pomaria 69 kV SS
Blythewood 230-69 kV Sub.
Sandy Run 115 kV SS
Orangeburg 115-69 kV Sub.
Bamberg 69 kV SS
Sycamore 69 kV SS
St George 115-69
St.
115 69 kV
Sub.
Varnville 230
230-115-69
115 69 kV Sub
Sub.
Yemassee 230 kV SS
VC Summer #3 Transmission Plan (ISD 2019)
VCS-Pomaria 230 kV Line
VC Summer Nuclear
Pomaria-Sandy Run 230 kV Line
Newberry 230-69 kV Sub.
Pomaria 230-69 kV Sub.
Blythewood 230-69 kV Sub.
Pomaria-Sandy Run 230 kV Line
Sandy Run 230-115 kV Sub.
Sandy Run-Orangeburg 230 kV Line
Orangeburg 230-115-69 kV Sub.
Orangeburg-St. George 230 kV Line
Bamberg 69 kV SS
St. George 230-115 kV Sub.
Sycamore 69 kV SS
St George 115-69
St.
115 69 kV
Sub.
St. George-Varnville 230 kV Line
Varnville 230
230-115-69
115 69 kV Sub
Sub.
Yemassee 230 kV SS
VCS #3 Transmission Projects
•
•
•
•
•
•
•
VCS-Pomaria #2 230 kV Line
Sandy Run 230-115 kV Substation
P
Pomaria-Sandy
i S d R
Run 230 kV Line
Li
Sandy Run-Orangeburg 230 kV Line
St. George 230-115 kV Substation
Varnville 230-115 kV Substation
St. George-Varnville 230 kV Line
05/2014
04/2016
05/2016
05/2017
04/2018
05/2019
06/2019
Stakeholder Input
p and
Alternative Discussion On
Proposed Changes to
Transmission Expansion Plans
92
FERC Order 1000
Transmission Planning and Cost Allocation
93
FERC Order 1000
•
•
•
•
Planningg Requirements
Cost Allocation Requirements
N i
Non-incumbent
b tD
Developer
l
R
Requirements
i
t
Compliance
p
94
Planning Requirements
• Public utility transmission providers are required to
participate in a regional transmission planning process
• Local and regional transmission planning processes
must consider
id transmission
i i needs
d driven
di
by
b public
bli
policy
• Public utility transmission providers in each pair of
neighboring transmission planning regions must
coordinate to determine if more efficient or
cost effective solutions are available
95
Regional Planning
• Each transmission pplanningg region
g must pproduce a
regional transmission plan reflecting solutions that
g
needs more efficientlyy or cost
meet the region’s
effectively
• Stakeholders must have an opportunity to participate
in identifying and evaluating potential solutions to
regional needs
96
Interregional Coordination
• Each ppair of neighboring
g
g transmission pplanningg
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
cost effective to those regional needs
• Interregional transmission facilities are those that are
located in two or more neighboring transmission
planning regions
97
Cost Allocation Requirements
• Regional
g
transmission pplanningg pprocess must have a
regional cost allocation method for a new transmission
g
transmission pplan for
facilityy selected in the regional
purposes of cost allocation
• Neighboring transmission planning regions must have a
common interregional cost allocation method for a new
interregional transmission facility that the regions select
98
Non--incumbent Developers
Non
• Rule promotes competition in regional transmission
planning processes
• Rule requires
q
the development
p
of a not undulyy
discriminatory regional process for transmission
pproject
j submission,, evaluation,, and selection
99
Compliance
• Each transmission pprovider is required
q
to make a
compliance filing within twelve months of the effective
date of the Final Rule ((October 2012))
• The compliance filings for interregional transmission
coordination and interregional cost allocation must be
filed within eighteen months of the effective date (April
2013)
100
SCRTP - Next Meeting
• Discuss Alternative Solution Analyses
• SCRTP St
Stakeholder
k h ld Group
G
will
ill propose and
d select
l t5
intra-regional economic transfers for study
• Proposed inter-regional
inter regional economic transfers will be
advanced to the SIRPP
101
South Carolina Regional Transmission Planning
Stakeholder Meeting
Hilton Garden Inn – Charleston Airport
Charleston,
Charleston SC
September 8, 2011