Dear Chairman Wood and Commissioners Brownell, Kelly and

Transcription

Monday, January 28, 2013
1:00 - 5:00 p.m.
Southwest Power Pool Offices
Little Rock, Arkansas
1. CALL TO ORDER
2. PRELIMINARY MATTERS
a. Declaration of a Quorum
b. Adoption of October 29, 2012 Minutes
3. UPDATES
a. RSC Financial Report
b. SPP
c. FERC
4. BUSINESS MEETING
a. Consultants
b. Auditor
5. REPORTS/PRESENTATION
a. CAWG Report.................................................................................................................... Tom DeBaun
b. SPP 2013 STEP/2013 ITP Near Term ................................................ Lanny Nickell and Paul Suskie
c. Order 1000 Regional Update ............................................................................................ Paul Suskie
d. Order 1000 Interregional Update
-Seams Steering Committee Update .............................................................................. Paul Malone
e. Update on Regional Cost Allocation Review (RCAR) ..................................................... Paul Suskie
f.
Update on Balance Portfolio ................................................................ Lanny Nickell & Paul Suskie
g. Integrated Marketplace Update .......................................................................................... Bruce Rew
6. OTHER RSC MATTERS
a.
SPP Outreach and Training to the RSC & States in 2013 ...................................... Paul Suskie
7. SCHEDULING OF NEXT REGULAR MEETINGS, SPECIAL MEETINGS OR EVENTS
RSC Meetings:
April 29, 2013 – Kansas City, MO
July 29, 2013 – Denver, CO
8. ADJOURN
* NOTE: ADDITIONAL INFORMATIONAL MATERIAL
Attached to the RSC’s meeting agenda and background material is additional material that is either for
informational or reporting purposes.
Southwest Power Pool
REGIONAL STATE COMMITTEE
Southwest Power Pool Campus, Little Rock, AR
October 29, 2012
•
MINUTES
•
Administrative Items:
The following members were in attendance:
Kevin Gunn, Missouri Public Service Commission (MOPSC)
Patrick Lyons, New Mexico Public Regulation Commission (NMPRC)
Dana Murphy, Oklahoma Corporation Commission (OCC)
Donna Nelson, Public Utility Commission of Texas (PUCT)
Olan Reeves, Arkansas Public Service Commission (APSC)
Mike Siedschlag, Nebraska Power Review Board (NPRB)
Thomas Wright, Kansas Corporation Commission (KCC)
President Olan Reeves called the Regional State Committee (RSC) meeting to order at 1:00 p.m. with roll
call and a quorum was declared. He then requested a round of introductions. There were 105 in attendance
either in person or via phone (Attendance & Proxies – Attachment 1).
President Reeves asked for approval of the July 30, 2012 meeting minutes (RSC Minutes 7/30/12 Attachment 2). Tom Wright moved to approve the minutes as presented; Patrick Lyons seconded the
motion. The minutes were approved.
UPDATES
RSC Financial Report
Paul Suskie provided the RSC Financial Report (Financial Report – Attachment 3). Mr. Suskie reported that
the Seams Cost Allocation line item is for cost budgeted in 2011 but expended in 2012. He also reported
that travel costs were over budget but not significantly.
SPP Report
Nick Brown welcomed everyone to the new SPP Corporate Campus. SPP moved into the new facility in
mid-July with a very smooth migration over one weekend. Mr. Brown said that he was proud to announce
that the facility was completed on schedule and at 5% under budget.
Mr. Brown presented a high level update on the Integrated Marketplace. He stated that SPP had benefited
from lessons learned in talks with the Electric Reliability Council of Texas (ERCOT) and thanked Trip Dogget
for his assessment report. The SPP program is being monitored utilizing an outside consultant and SPP’s
Internal Audit staff, all reporting directly to Mr. Brown. The current status of the seven areas of the program
is: four green, two yellow and one orange. Regarding the orange status, SPP is working with the vendor at
issue (Alstom) to address delays. A more detailed report will be provided at the October 30 SPP Board
meeting.
Mr. Brown stated that the Arkansas Public Service Commission had issued an order on October 26
approving Entergy’s request to join the Midwest ISO. Mr. Brown reported that SPP will continue to argue
Regional State Committee
October 29, 2012
that SPP is the better choice; will be aggressive in protecting its Members interest; and will work to help
make the integration fair to all. RSC will need to continue to help with regional cost allocation, which will take
on a whole new meaning. SPP is reviewing the order and will have recommendations for the RSC in the
near future.
FERC
Mr. Patrick Clarey provided an update on recent FERC activities:
August
FERC held five regional technical conferences on better coordination between natural gas and
electricity markets. The conferences explored gas-electric interdependence as well as ways to
improve coordination and communication between the two industries. The regions included the
Northeast, Mid-Atlantic, Southeast, Central and West regions. FERC appreciates SPP’s
participation in this effort.
September
FERC granted SPP’s Petition for Declaratory Order and conditionally accepted the proposed
Western-SPP JOA, subject to a compliance filing.
Commission Chairman Jon Wellinghoff announced the creation of a new FERC office that will help
the Commission focus on potential cyber and physical security risks to energy facilities under its
jurisdiction. The new Office of Energy Infrastructure Security (OEIS) will provide leadership,
expertise and assistance to the Commission to identify, communicate and seek comprehensive
solutions to potential risks to FERC-jurisdictional facilities from cyber attacks and such physical
threats as electromagnetic pulses. OEIS will be led by Joseph McClelland, who has been Director of
the Office of Electric Reliability since its formation in 2006.
October
Mr. Clarey congratulated SPP and its Members and noted that at the October Open Meeting, FERC
conditionally accepted SPP’s Integrated Marketplace tariff filing including day-ahead and real-time
energy and operating reserve markets.
The Chairman announced that current FERC General Counsel Michael Bardee will be the new head
of the Office of Electric Reliability. David Morneoff will step-in as acting General Counsel.
BUSINESS MEETING
Election of Officers for 2013
President Reeves requested nominations for the annual election of officers. Kevin Gunn nominated the
following RSC officers for 2013: Tom Wright for President, Dana Murphy for Vice President and
Donna Nelson for Secretary/Treasurer. Michael Siedschlag seconded the motion, which passed
unanimously.
Approval of 2013 RSC Budget
Paul Suskie presented the 2013 RSC Budget for approval (20113 Budget – Attachment 4). Dana Murphy
moved to approve the 2013 RSC budget and that the RSC establish a subcommittee of RSC members
to look at consultant contacts on a go forward basis to deal with various upcoming issues facing the
RSC. Tom Wright seconded the motion; the motion passed unanimously. President Reeves
assigned a subcommittee to consist of: Dana Murphy, Tom Wright and Michael Siedschlag.
REPORTS/PRESENTATIONS
Cost Allocation Working Group Report
Pat Mosier provided the Cost Allocation Working Group report (CAWG Report – Attachment 5). Ms. Mosier
presented an overview of the group’s activities. She then presented the following recommendations:
2
October 29, 2012
•
In order to provide the best support for each rotating President of the RSC, the CAWG considered
and recommends that:
The CAWG Chairman position be appointed each year by the RSC, such that, the Chairman
of the CAWG is from the same state as that of the President of the RSC. Tom Wright moved
to approve; Kevin Gunn seconded the motion. The motion passed unanimously.
•
An observation was made at the July RSC meeting that Attachment J is very unclear as to when
the required 15 days notice for a waiver of the Safe Harbor Limits is to occur. The CAWG
therefore recommends approval of BPR 25 as amended by the Markets and Operations Policy
Committee (MOPC):
A customer may submit a waiver request for waiver of the Safe Harbor Limit, pursuant to
Attachment J Section III.C.1, at any time after the posting of the first iteration of the
aggregate study, but not later than 15 days after being notified that the aggregate study is
final. Kevin Gunn moved to approve BPR 25 as amended; Dana Murphy seconded the
motion. The motion passed unanimously.
•
MOPC directed the Business Practices Working Group (BPWG) to identify a non-discriminatory
method that the Transmission Provider will use to calculate the amount of costs that are eligible for
consideration for waivers to the Safe Harbor provisions of Attachment J. Addressing the five-year
commitment period, the CAWG recommends the BPR 32 recommendation for calculation:
...by multiplying the number of years which the Duration of the Transmission Customer’s
commitment to the new or changed Designated Resource exceeds the five year minimum
commitment period, by 2.5%, multiplied by $180,000 per MW. Tom Wright moved to
approve BPR 32; Kevin Gunn seconded the motion. The motion passed unanimously.
Ms. Mosier provided an update of the RSC position of support regarding the SPP Order 1000 filing.
RSC issued a letter specifically supporting SPP’s regional filing as well as providing individual state
support.
Order 1000 Regional Update
Paul Suskie provided an update of Order 1000 analysis of both regional and interregional requirements
(Order 1000 Update – Attachment 6). Mr. Suskie also provided information regarding the elimination of the
Right of First Refusal (ROFR) and as a result, 4 limitations that would be added to Commission approved
tariffs and agreements.
Order 1000 Regional Compliance Filing
Mr. Suskie reviewed TRR 077 revisions for the SPP Regional Compliance Filing for Order 1000, which
will be presented to the SPP Board of Directors for approval on October 30, 2012. The filing will be
submitted in two weeks.
Order 1000 Interregional Update
Seams Steering Committee (SSC) Update
Paul Malone presented a SSC update including an overview of responsibilities, SPP’s proposed
interregional coordinated planning process, and a compliance timeline (SSC Report – Attachment 7).
Interregional Cost Allocation Task Force Update
Sam Loudenslager reported on interregional cost allocation efforts of the Interregional Cost Allocation
Task Force (ICATF Efforts – Attachment 8). The group approved principles and guidelines to use in
discussions with seams neighbors, developed projects and will try to reach agreement with neighbors.
3
October 29, 2012
CAWG’s Recommendation of Cost Allocation of Interregional Project Costs
Pat Mosier provided CAWG background regarding interregional cost allocation and offered cost
assignment options presented to the CAWG as: 1) Assign all seams costs to the Regional Rate (i.e.
Highway) and 2) Allocate seams costs pursuant to currently approved allocation methods (i.e.
Highway/Byway dependent upon voltage of Seams Project) (CAWG’s Interregional Cost Allocation
Recommendation – Attachment 9). Ms. Mosier stated that the CAWG passed the following
recommendation with New Mexico and Texas voting against: CAWG recommends that the Regional
State Committee adopt a 100% Regional allocation of costs related to interregional projects selected
pursuant to interregional planning processes.
Following much discussion, Patrick Lyons moved to approve:
Adopt current Highway/Byway treatment of SPP’s portion of costs for interregional projects,
with the option to seek waiver of that treatment if the interregional project can be shown to
provide regional benefits. Donna Nelson seconded the motion, which failed with New Mexico
and Texas for and five votes against.
Kevin Gunn moved to approve the CAWG recommendation:
CAWG recommends that the Regional State Committee adopt a 100% Regional allocation of
costs related to interregional projects selected pursuant to interregional planning processes.
Tom Wright seconded the motion. All voted in favor with New Mexico and Texas against.
Michael Siedschlag requested that the CAWG continue to monitor cost allocation and that the RSC
revisit at the January 2013 meeting if circumstances warrant.
Waiver Request
Lanny Nickell provided an overview of the transformer waiver process and presented background for the
Nebraska Public Power District’s Neligh Waiver Request (NPPD Waiver Request – Attachment 10). Mr.
Nickell stated that the MOPC recommends approval of the NPPD Neligh Transformer Waiver Request.
CAWG’s Recommendation on Waiver Requests
Pat Mosier reviewed the CAWG discussion and recommendation regarding the NPPD waiver
request. She then requested the following for endorsement from the RSC:
The CAWG recommends that the RSC endorse the recommendation for the SPP Board to
approve the NPPD Neligh Transformer Waiver Request. Tom Wright moved to endorse; Kevin
Gunn seconded the motion. The motion passed unanimously.
Update on Balanced Portfolio
Lanny Nickell provided an update on the Balanced Portfolio (Balanced Portfolio – Attachment 11).
Special Studies Update for the Mississippian
Dana Murphy provided information regarding the Mississippian oil play (Mississippian – Attachment 12). Ms.
Murphy stressed that it is extremely important to bridge the gap between producers, utilities, the Oklahoma
and Kansas Corporation Commissions and SPP. Ms. Murphy thanked Carl Monroe, Paul Suskie and Tom
Wright in helping with this effort. Mr. Monroe provided information on provisions for abnormal load growth in
the SPP Tariff (Load Growth – Attachment 13).
Integrated Marketplace Update
Bruce Rew provided an update on the Integrated Marketplace (IM Report – Attachment 14). Mr. Rew stated
that there is an Integrated Market Forum on November 7 for state regulators.
4
October 29, 2012
Future RSC Matters
President Reeves thanked everyone for their help during his tenure as President of the RSC. This will be his
last meeting as President.
Scheduling of Next Regular Meeting, Special Meetings or Events:
President Reeves noted that the next regularly scheduled meeting is on January 28, 2013, in New Orleans.
With no further business, the meeting adjourned at 4:45 p.m.
Respectfully Submitted,
Paul Suskie
5
For the Twleve Months Ending December 31, 2012
Budget vs. Actual
YTD Actuals
YTD Budget
Income
Other Income
Total Income
438,705
438,705
303,300
303,300
135,405
135,405
Expense
Travel
Meetings
Audit
Administrative Costs
RSC Consultant
Technical Conference
Seams Cost Allocation
Total Expense
163,104
16,842
2,988
56,712
199,059
438,705
110,000
25,000
2,300
1,000
115,000
50,000
303,300
53,104
(8,158)
688
(1,000)
(58,288)
(50,000)
199,059
135,405
Net Income (Loss)
-
-
* The Seams Consultant was in the 2011 Budget and a carry over to 2012.
Variance
-
*
January 28, 2013
I.
II.
III.
IV.
V.
Public
P
bli P
Policy
li P
Projects/Mandates/Goals
j
/M d
/G l
Cost Allocation – Seams projects
Crediting Process for certain non-base plan
funded upgrades
Financial Transmission Rights
CAWG 2013 Issues
I
List
Li t
2
1
`October
RSC Meeting –Agenda-related discussion on how
projects driven by Public Policy mandates/goals are
considered in the SPP Planning process.
process
`RSC requested a clear explanation of SPP’s current
planning process and the inclusion of projects driven by
Public Policy Needs with any difference between goals and
mandates explained.
Answer:
This is “unfinished
unfinished business
business”…varying
varying definitions or lack of
clarity – public policy mandates, public policy goals, public
policy needs, targets, etc. In general, SPP Planning makes
no distinction between mandates and goals.
3
`
`
`
October 2012, RSC adopted a 100% regional allocation
of costs related to inter-regional projects selected
pursuant to inter
inter-regional
regional planning processes. [All
voltage levels] (5-2 vote)
RSC requested that the CAWG continue to monitor
seams cost allocation and that the RSC revisit at the
January 2013 meeting if circumstances warrant.
Tariff revisions will be required – RSC review of
revisions is not automatic.
4
2
`
`
Transmission Customers paying Directly Assigned Upgrade
Costs for Service Upgrades or that are in excess of the Safe
Harbor Cost Limit for Network Upgrades associated with new
or changed Designated Resources and Project Sponsors
paying Directly Assigned Upgrade Costs for Sponsored
Upgrades shall receive revenue credits [refunds]in accordance
with this Attachment Z2.
Generation Interconnection Customers paying for Network
U
Upgrades
d shall
h ll receive
i credits
dit [refunds]
[ f d ] ffor new ttransmission
i i
service using the facility as specified in Attachment Z1.
5
`
`
`
No process implemented upon tariff approval.
RTWG chartered Crediting Process Task Force (CPTF) to develop
and
d recommend
d specific
ifi processes and
d methods
th d tto calculate
l l t
revenue credits.
SPP Staff is working with Vendor on software: OATI
◦ Planned delivery of software is the end of the first quarter
◦ Will start calculating credits with 2008 and move forward
◦ Will not have a measure on the amount of credits due until the end of the 2nd
quarter
`
`
`
`
MOPC agreed
g
with the direction of the CPTF in April
p 2012.
CPTF has completed its work in November.
RTWG is reviewing the Tariff language.
Tariff language to MOPC in April.
6
3
`
`
Requirement that Transmission Organizations with
Organized Transmission Markets offer long-term firm
transmission rights.
RSC By-laws point to the RSC:
“…determination of FTR allocations where a locational price
methodology is used; determination of the transition mechanism to
be used to assure that existing firm customers receive FTRs
equivalent to the customers’ existing firm rights (If the RSC reaches
a decision on the methodology that would be used, SPP would file
this methodology pursuant to Section 205 of the FPA.
FPA SPP can also
file its own proposal pursuant to Section 205);…”
`
SPP Staff is coordinating formation of a joint task force
between MWG and CAWG. On February CAWG
agenda.
7
`
Agendas –
`
Special Emphasis –
`
Recurring Reports –
◦ Show ACTION ITEMS and include draft motion(s) with the
background material
◦ Limit topics to issues related to RSC/CAWG authority or focus
◦ Long-Term Financial Transmission Rights (FTR)
◦ Standard rate impact methodology for all ITP project proposals
and futures
◦ Order 1000 ROFR - final determinations on cost allocation
methodology – tariff revisions
◦ Possible need to revisit Base Plan Allocation Method (H/B)
◦ Seams Issues – Order 1000 or any other seams issues
◦ Crediting Process Task Force – monthly
◦ Project Cost Working Group (PCWG) – quarterly
◦ CAWG member monthly WG and TF reports. (8-10/mo.)
8
4
Tom DeBaun
CAWG Chairman
Sr. Energy Engineer
Kansas Corporation Commission
t.debaun@kcc.ks.gov
785-271-3135
9
5
Order 1000 Presentation
on SPP’s Regional
Compliance Filing & Issue
November, 2012
1
1
O de 000 equ e e ts a ys s
Order 1000 Requirements Analysis
• Analysis divides requirements into:
y
q
(1) Regional (RTO) Requirements
(2) Interregional Requirements
(2) Interregional Requirements 2
2
O de 000 eg o a ( O) equ e e ts
Order 1000 Regional (RTO) Requirements
3
3
O de 000 te eg o a equ e e ts
Order 1000 Interregional Requirements
4
4
Regional Compliance Filing at FERC
• November 7, 8, & 9 RSC & SPP Delegation to Met with FERC Commissioners as a Pre‐Filing g
Visit for SPP Order 1000 Regional Filing
– Chairman Nelson (PUCT)
Chairman Nelson (PUCT)
– Commissioner Reeves (APSC)
– Chairman Siedschlag (NPRB)
• November
November 13, 2012 SPP made Order 1000 13, 2012 SPP made Order 1000
Regional Compliance filing.
• SPP is awaiting Order from FERC
SPP i
iti O d f
FERC
5
5
Interregional Compliance Filing at FERC
• April 11, 2013 Compliance Filing Deadline
April 11 2013 Compliance Filing Deadline
• SPP is filing to seek a 30 day extension for the Interregional Compliance Filing. Expect g
p
g
p
support from our Seams Partners.
6
6
SSC Order 1000 Interregional
Update
January 28, 2013
Paul Malone
FERC Order 1000
Regional
Interregional
Coordinated Planning
Cost Allocation
2
1
Compliance Efforts
•
3 Neighbors for Order 1000 Purposes
–
MISO, AECI, & WAPA
,
,
•
Currently negotiating modifications to the SPP‐MISO JOA to be Order 1000 compliant
•
WAPA compliance through MAPP region
•
AECI intends to participate through the Southeastern Regional Transmission Planning Group (SERTP)
Regional Transmission Planning Group (SERTP)
•
Anticipate compliance filing in May 2013
3
Order 1000 Interregional Policy Development
•
Seams FERC Order 1000 Task Force
–
Met from March ‘12 – December ’12 to develop policy pp y
paper
–
Task Force included 3 SSC members, 1 TWG member, and 1 ESWG member
•
Received input from ESWG, TWG, SSC, CAWG members, other stakeholders, and neighboring regions
•
Policy paper approved by SSC in December and approved by MOPC in January
4
2
Proposed Process
5
Proposed Process cont.
6
3
Proposed Process cont.
7
Project Applicability and Cost Allocation (SPP‐MISO)
Criteria
Interregional Cost
Allocation Proposal
MISO’s Regional
Approval Criteria
SPP’s Regional Approval
Criteria
Project Cost Threshold
$5 million
$5 million
No project cost threshold
Voltage Threshold
Outstanding issue
Primarily
y 345 kV facilities
(50% or more of project
cost)
No voltage threshold
Minimum Benefits
Threshold
Minimum of 5% benefits to
either MISO or SPP
NA
NA
Number of Futures used in
evaluation
At least one
Multiple Future Scenarios
At least one
Benefit/Cost Ratio
Threshold
NA – each region uses its
own regional criteria
1.25
1.0
Timeframe included in
benefits calculation
20 years ffrom project’s
j t’ iinservice year (used only to
determine cost allocation)
20 years from project’s
project s in
inservice year, but not to
exceed 25 years from
approval year
40 years from project’s inservice year
Benefit metrics
APC Savings (used to
determine cost allocation
for economic projects)
APC Savings
Multiple Benefit Metrics
Project Drivers
Outstanding Issue (only
agreement on economic
projects)
Economic
Economic, Reliability,
Public Policy
8
4
MAPP and SERTP Cost Allocation
•
Both MAPP and SERTP propose to use regional project replacement and/or deferment as the only benefit metric for interregional projects
•
Have not proposed thresholds for voltage or project cost
9
5
STATUS REPORT
SPP Regional Cost Allocation Review
January 28, 2013
1
Content
A. Introduction
p
B. Overview of Report
C. Cost and Status of Benefits Analysis
D. Next Steps
2
2
Background
•
In January 2012 the MOPC, RSC, and BODs/MC endorsed the Report of the Regional Allocation Review Task Force Report (RARTF). In the Report, the RARTF recommended that an expanded list of transmission benefits be evaluated by the Economic Studies Working Group (ESWG) for the purpose of the RCAR process
•
In February 2012, the ESWG initiated the Metrics Task Force (MTF) with the specific purpose of developing tangible monetized transmission benefit metrics for use in the economic evaluations identified in the RARTF report
•
In September 2012, the MTF completed its report and containing a list of recommended transmission benefit metrics, including approaches to estimate the dollar value of these benefits
•
MTF Report: http://www.spp.org/publications/20120913%20MTF%20Report_approved.pdf
•
In October 2012, the MOPC, BODs/MC, approved the metrics developed by the MTF for the Regional Cost Allocation Review (RCAR)
for the Regional Cost Allocation Review (RCAR).
•
This presentation is the status report on SPP’s effort to implement the RARTF and MTF recommendations to monetize transmission benefits for the RCAR process
•
RARTF Report: http://www.spp.org/publications/FINAL%20RARTF%20Report%20011012.pdf
3
3
Establishment of the RARTF
stab s e t o t e
• Charter Finalized June 9, 2011
• RARTF Members Jointly‐appointed by
MOPC (Bill Dowling) & RSC (Jeff Davis)
• Members Announced June 10,
10 2011
• Final Report Approved Jan. 3, 2012
4
4
RARTF Members
e be s
RARTF Members
Chairman Michael Siedschlag
Nebraska Public Review Board
Vice-Chairman Richard Ross
American Electric Power
Commissioner Thomas Wright
Kansas Corporation Commission
Commissioner Olan Reeves
Arkansas Public Service Commission
Bary Warren
Empire District Electric
Philip Crissup
Oklahoma Gas & Electric
Harry Skilton
SPP Board of Director
5
5
RCAR Methodology
C
et odo ogy
•
Two studies will show the benefits and cost by zone of
1. Projects that have received an NTC since June 2010
2. Projects that have received an NTC since June 2010 and projects with an ATP project in‐service within 10‐years
j
i h ATP
j i
i
i hi 10
•
Utilize a 40‐year assessment of these projects
•
Treat projects with NTCs with greater weight than those with ATPs
•
Utilize the most up‐to‐date assumptions and ATRR for each zone
•
Calculate benefits using metrics approved by ESWG, MOPC, SPP BODs
6
6
Annual CapEx for NTC and ATP Projects p
j
Evaluated costs for two sets of transmission projects
1. Projects with Notification to Construct (NTCs): All SPP projects that have been j
(
)
p j
issued an NTC since June 2010; and
2. NTCs and ATPs: All SPP projects that have been issued an NTC since June 2010 and all projects that have received an Authorization to Plan (ATP) that have an in‐service date of 2023 or earlier (ten years or less from issuance of RCAR report)
in‐service date of 2023 or earlier (ten years or less from issuance of RCAR report)
Capital Cost of NTC Projects
Capital Cost of NTCs and ATPs
By Type and In‐Service Year
By In‐Service Year
7
7
Benefit Metrics
Benefit Metrics
ITP Metric
MTF Considered
Metric in this effort?
h ff ?
Adjusted Production Cost (APC)
9
Yes
Emission Rates and Values
9
Yes
Ancillary Service Needs and Production Costs
9
Yes
Avoided or Delayed Reliability Projects
9
Yes
Capacity Cost Savings due to Reduced On‐Peak Transmission Losses
d
d d
k
9
Yes
Mitigation of Transmission Outage Costs
9
Yes
Benefit of Mandated Reliability Projects
9
Yes
Benefits of Public Policy Goals
9
Yes
Increased Wheeling Through and Out Revenues
9
TBD
Reducing the Cost of Extreme Events
9
TBD
Capital Savings due to Reduction of Members’ Minimum Required Margin
9
No
Reduced Loss of Load Probability
9
No
Marginal Energy Losses Benefits
9
No
8
8
Timeline Update
e e Update
9
9
Report Remedies
epo t e ed es
Remedy
Entity with Authority/Duty to Implement
(1) Acceleration of planned upgrades;
(1) Acceleration of planned upgrades; SPP BOD
SPP BOD
(2) Issuance of NTCs for selected new upgrades;
SPP BOD
(3) Apply Highway funding to one or (3)
Apply Highway funding to one or
more Byway Projects; RSC, SPP BOD & FERC
(4) Apply Highway funding to one or more Seams Projects;
more Seams Projects;
RSC, SPP BOD & FERC
(5) Zonal Transfers (similar to Balanced Portfolio Transfers) to offset costs or a lack of benefits to a zone;
RSC, SPP BOD & FERC
(6) Exemptions from cost associated with the next set of projects; RSC, SPP BOD & FERC
((7) Change Cost Allocation Percentages.
)
g
g
,
RSC, SPP BOD & FERC
10
10
Balanced Portfolio Balanced
Portfolio
Update
January 28, 2013
Lanny Nickell
Vice President, Engineering
1
Q 0 3 Update Su
Q1 2013 Update Summary
ay
•
•
•
Total portfolio cost down 1%
Q4 2012
Q4 2012 Q1 2013
Q1 2013 Variance
% Change
% Change
$856,231,896 $846,718,603 ($9,513,293)
‐1.11%
One significant cost estimate change
g
g
–
Sooner – Cleveland 345 kV decreased 16.9%
–
Decrease due to lower than expected construction costs
p
345 kV line from Spearville – Post Rock – Axtell placed in‐
service 12/15/2012
–
223 new miles
–
Original estimated in‐service date 6/2013
–
Latest estimate $207,194,981 down 12% from original estimate
2
2
Portfolio 3‐E Adjusted
j
19
0%
19.0%
‐12.4%
Post Rock (
)
‐3.9%
45.5%
$692M 86.5%
46.2%
36.5%
)
(
Gracemont
3
3
Balanced Portfolio Estimate Trend
a a ced o t o o st ate e d
Total ($M)
$950.0 $896
7
$896.7 $900.0 $850.0 FERC
Filing
$800.0 $855.3 $846.7 $786.2 $750.0 $700.0 $691.2
$698.5 $650.0 $600.0 BP Original Q4 Q1 Q2
Report NTCs 2009 2010
6/09
Q3
Q4
Q1 Q2
2011
Q3
Q4
Q1 Q2
2012
Q3
Q4
Q1 2013
4
4
Balanced Portfolio Estimate Trend
a a ced o t o o st ate e d
Per Project ($M)
$400.0
$350.0
$333.0
FERC
Filing
$300.0
Tuco ‐ Woodward
Spearville Post Spearville ‐
Post
Rock ‐ Axtell
$250.0 $236.6
$200.0
$227.7
$207.2
$176.1
Seminole ‐
Muskogee
Iatan ‐ Nashua
$150.0 $129.0
Sooner ‐ Cleveland
$100.0
$54.4
$
$50.0 $33.5
$8.0
$0.0 $2.0
$64.8
$48.8
$14.9
Gracemont Substation
Swissvale ‐ Stilwell Tap
$1.9
5
5
Balanced Portfolio Committed Costs
a a ced o t o o Co
tted Costs
53.3%
$350,000,000 $300,000,000 $250,000,000 100%
68.7%
$200,000,000 Latest Estimate
$150,000,000 $100,000,000 48.6%
100%
$50,000,000 100%
Committed Dollars (as of 1/18/2013)
100%
$0 Gracemont Spearville ‐ Swissvale ‐ Sooner ‐
Sub
Post Rock ‐ Stilwell Tap Cleveland
Axtell
Seminole ‐
Tuco –
Muskogee Woodward
Iatan ‐
Nashua
6
6
Balanced Portfolio Estimated Completion
a a ced o t o o st ated Co p et o
% of Completion by Estimated Cost
100.00%
100.0%
92.3%
80.0%
60.0%
54.9%
Current
40.0%
34.1%
26.2%
20.0%
11.5%
0.0%
Q3 Q4
2011
Q1 Q2
2012
Q3
Q4
Q1 Q2
2013
Q3
Q4
Q1 Q2
2014
Q3
Q4
Q1 Q2
2015
Q3
7
7
Balanced Portfolio Balanced
Portfolio
Review
Paul Suskie
Paul Suskie
January 2013 ‐ Board of Directors
8
8
Balanced Portfolio (“BP”) Cost Allocation a a ced o t o o (
) Cost ocat o
Overview
(1) Update on BP Transfer Estimates base upon current Cost Estimates.
(2) Status of SPP’s Filing at FERC related to the BP.
9
9
(2) UPDATE ON BP TRANSFER ESTIMATES ESTIMATES
10
10
B/C Ratios Before and After Transfers
Balanced Portfolio PV$ Over 10 Years ATRR Costs (in millions)
2009 BP Report
SPP 2012 Filing
Current 10 Year ATRR Cost
Estimates
Z
Zone
B/C
B f
Before
Transfers
B/C After
Transfers
B/C
B f
Before
Transfers
B/C After
Transfers
B/C
B f
Before
Transfers
B/C After
Transfers
AEPW
EMDE
GRDA
KCPL
MIDW
MIPU
MKEC
OKGE
SPRM
SUNC
SWPS
WEFA
WRI
NPPD
OPPD
LES
1.5
(0.1)
0.5
1.1
18.7
(0.3)
11.1
2.0
(0.1)
3.6
5.1
2.7
1.3
0.7
0.4
(1.7)
1.1
1.0
1.0
1.0
14.1
1.0
8.3
1.5
1.0
2.7
3.9
2.0
1.0
1.0
1.0
1.0
1.1
(0.1)
0.4
0.9
14.8
(0.3)
8.6
1.5
(0.1)
2.5
3.9
2.0
1.0
0.6
0.3
(1.5)
1.0
1.0
1.0
1.0
8.1
1.0
4.7
1.0
1.0
1.4
2.2
1.0
1.0
1.0
1.0
1.0
1.2
(0.1)
0.4
0.9
15.7
(0.3)
9.2
1.6
(0.1)
2.7
4.2
2.2
1.1
0.6
0.3
(1.6)
1.0
1.0
1.0
1.0
9.8
1.0
5.7
1.0
1.0
1.7
2.6
1.3
1.0
1.0
1.0
1.0
Total
1.9
1.9
1.4
1.4
1.5
1.5
11
11
Balance Portfolio PV over 10 Year ATRR Cost Estimates and Transfers 2009 BP Report
Estimates and Transfers ‐
2009 BP Report
(in millions)
Allocation of Net Benefit
Transfer
Regional
after
ATRR Cost
ATRR
Allocation off
from Zones to
Transfers to
ATRR
Region
Zones
Transfers
Zone
Portfolio
Benefits
Portfolio 10
Year ATRR
Costs
B/C
Before
f
Transfers
AEPW
EMDE
GRDA
KCPL
MIDW
MIPU
MKEC
OKGE
SPRM
SUNC
SWPS
WEFA
WRI
NPPD
OPPD
LES
$224.1
($2 5)
($2.5)
$6.2
$60.8
$92.7
($9.6)
$
$85.5
$192.9
($0.7)
$26.8
$406.5
$57.8
$103.0
$39.8
$16.3
($22.4)
$154.5
$18 1
$18.1
$13.4
$53.1
$4.9
$
$27.8
$7.7
$97.5
$10.7
$7.3
$79.4
$21.7
$79.4
$55.1
$42.7
$13.2
1.5
(0 1)
(0.1)
0.5
1.1
18.7
(0.3)
11.1
2.0
(0.1)
3.6
5.1
2.7
1.3
0.7
0.4
(1.7)
$0.0
$26 5
$26.5
$11.7
$9.8
$0.0
$
$46.6
$0.0
$0.0
$14.9
$0.0
$0.0
$0.0
$2.6
$33.4
$40.5
$39.9
$50.8
$6 0
$6.0
$4.4
$17.5
$1.6
$
$9.2
$2.5
$32.1
$3.5
$2.4
$26.1
$7.1
$26.1
$18.1
$14.1
$4.3
$18.8
$0 0
$0.0
$0.0
$0.0
$86.2
$
$0.0
$75.2
$63.4
$0.0
$17.0
$301.1
$28.9
$0.0
$0.0
$0.0
$0.0
1.1
10
1.0
1.0
1.0
14.1
1.0
8.3
1.5
1.0
2.7
3.9
2.0
1.0
1.0
1.0
1.0 12
Total
$1,277.3
$686.8
1.9
$225.9
$225.9
$590.5
1.9
B/C After
Transfers
12
Phase‐in Transfers at 20% per year over five p y
years per BP Report
Years 6‐10
True Up
3rd
2nd Year
•
4th Year
Year
•
5th Year
• $31M
• $24.8
$24 8M
$18.6M
$12.4M
$
1st Year
• $6.2M
13
13
Balance Portfolio PV over 10 Year ATRR Cost Estimates and Transfers SPP 2012 Filing
SPP 2012 Filing
(in millions)
Transfer
Regional
after
ATRR Cost
ATRR
Allocation of
from Zones to
Transfers to
ATRR
Region
Zones
Transfers
Zone
Portfolio
Benefits
Portfolio 10
Year ATRR
Costs
B/C
Before
Transfers
AEPW
EMDE
GRDA
KCPL
MIDW
MIPU
MKEC
OKGE
SPRM
SUNC
SWPS
WEFA
WRI
NPPD
OPPD
LES
$
$224.2
($2.5)
$6.2
$60.8
$95.7
($11.7)
$86.9
$193.1
($1.0)
$24.2
$406.8
$57.9
$106.7
$40.3
$15.9
($25.3)
$
$201.6
$23.6
$17.5
$69.3
$6.55
$36.3
$10.1
$127.2
$13.9
$9.6
$103.6
$28.4
$103.6
$71.9
$55.7
$17.2
1.1
(0.1)
0.4
0.9
14.8
(0.3)
8.6
1.5
(0.1)
2.5
3.9
2.0
1.0
0.6
0.3
(1.5)
$
$144.8
$45.7
$25.9
$66.0
$0.0
$78.1
$0.0
$39.7
$26.5
$0.0
$0.0
$0.0
$82.9
$91.3
$86.1
$56.8
$
$167.4
$19.6
$14.6
$57.5
$5.4
$30.1
$8.3
$105.6
$11.5
$8.0
$86.0
$23.5
$86.0
$59.7
$46.3
$14.3
$
$0.0
$0.0
$0.0
$0.0
$83.9
$0.0
$68.5
$0.0
$0.0
$6.7
$217.3
$6.0
$0.0
$0.0
$0.0
$0.0
1.0
1.0
1.0
1.0
8.1
1.0
4.7
1.0
1.0
1.4
2.2
1.0
1.0
1.0
1.0
1.0 14
Total
$1,278.4
$896.1
1.4
$743.7
$743.7
$382.3
1.4
B/C After
Transfers
14
years per SPP 2012 Filing
Years 6‐10
True Up
3rd
2nd Year
1st Year
4th Year
Year
5th Year
• $102.6M
• $82M
• $61.5M
• $41M
• $20.5M
15
15
Balance Portfolio PV over 10 Year ATRR Cost Estimates and Transfers ‐ Current Cost Estimates
Current Cost Estimates
(in millions)
Transfer
Regional
after
ATRR Cost
ATRR
Allocation of
from Zones to
Transfers to
ATRR
Region
Zones
Transfers
Zone
Portfolio
Benefits
Portfolio 10
Year ATRR
Costs
B/C
Before
Transfers
AEPW
EMDE
GRDA
KCPL
MIDW
MIPU
MKEC
OKGE
SPRM
SUNC
SWPS
WEFA
WRI
NPPD
OPPD
LES
$
$224.2
($2.5)
$6.2
$60.8
$95.7
($11.7)
$86.9
$193.1
($1.0)
$24.2
$406.8
$57.9
$106.7
$40.3
$15.9
($25.3)
$
$190.4
$22.3
$16.6
$65.4
$6.1
$34.3
$9.5
$120.1
$13.1
$9.0
$97.8
$26.8
$97.8
$67.9
$52.6
$16.3
1.2
(0.1)
0.4
0.9
15.7
(0.3)
9.2
1.6
(0.1)
2.7
4.2
2.2
1.1
0.6
0.3
(1.6)
$
$81.3
$38.3
$20.4
$44.2
$0.0
$66.7
$0.0
$0.0
$22.1
$0.0
$0.0
$0.0
$50.3
$68.7
$68.5
$51.4
$
$115.2
$13.5
$10.0
$39.6
$3.7
$20.7
$5.7
$72.6
$7.9
$5.5
$59.1
$16.2
$59.2
$41.1
$31.8
$9.8
$
$0.0
$0.0
$0.0
$0.0
$86.0
$0.0
$71.7
$0.3
$0.0
$9.7
$249.9
$14.9
$0.0
$0.0
$0.0
$0.0
1.0
1.0
1.0
1.0
9.8
1.0
5.7
1.0
1.0
1.7
2.6
1.3
1.0
1.0
1.0
1.0 16
Total
$1,278.4
$846.0
1.5
$511.7
$511.7
$432.6
1.5
B/C After
Transfers
16
years per Current Estimate of Costs
Years 6‐10
True Up
3rd
2nd
Year
4th Year
Year
5th Year
• $56.5
$56 5M
• $70.6M
• $42.4M
• $28.2M
1st Year
•
$14.1M
17
17
(2) STATUS OF SPP’S FERC FILING RELATED TO BP
18
18
Regulatory Filings
•
August 2, 2012 – Docket No. ER12‐2387
–
•
Year One Balanced Portfolio Transfer filing, using cost estimates provided by May 25, 2012. Cost estimates are fluid. Current estimates reflect lower costs than included in the August 22 2012
estimates reflect lower costs than included in the August 22, 2012 filing. November 20, 2012 – Docket No. ER12‐2387
–
Order accepting Year One Balanced Portfolio Transfers effective October 1, 2012.
19
19
Regulatory Filings
g
y
g
•
December 5, 2012, ER13‐515
–
Submission of Tariff Revisions to Attachment J,
Section IV.(A)(2) to Clarify the required true-up of
the Approved Balanced Portfolio reallocated
revenue requirements will include additional
amounts to compensate Transmission Owners
f the
for
th reduced
d
d zonall reallocations
ll
ti
which
hi h are a
result of phased-in transfers from the first five
years of the ten-year period.
–
An effective date of February 4, 2013 was
requested.
20
20
Integrated Marketplace
System Update
Regional State Committee/
Board of Directors
January 2013
Bruce Rew, PE
Bruce Rew, PE
Market Participant Milestones
2
1
Integrated Marketplace Program Summary
•
Target mass has scheduled connectivity testing
•
Market System software phase 3 to be delivered in y
p
March‐ Key software delivery
•
Structured Market Trials to begin in June
•
Budget tracking near target
•
Regulatory impacts progressing
•
On Schedule for March 1, 2014 implementation
3
INTEGRATED MARKETPLACE SYSTEM UPDATE
4
2
Summary of Key special attention areas •
Markets ‐ YELLOW
–
•
Settlements ‐ Green
–
•
Delayed FAT now complete, monitoring SAT
Registration ‐ Green
–
•
More PM rigor, 3 release plan, March release key
g ,
p ,
y
Completed SAT and launched registration on 1/7/13
Integration Services (Interface Delivery) ‐ YELLOW
–
Continuing first of 3 waves
5
INTEGRATED MARKETPLACE MARKET PARTICIPANT UPDATE
6
3
Participant Engagement Activity Status
Data as of January 11, 2013
Date
Participant Activity
May 31, 2012
• ENG.002 ‐ Technical Specifications Reviewed (Markets, Settlements, TCR)
June 1, 2012
• ENG.001 ‐ Participant System Design Underway
June 1, 2012
• ENG.003 ‐ Registration Packet Returned
June 29, ,
2012
• ENG.004 ‐ Participant Interface p
Design Complete
Aug 1, 2012
• ENG.005 ‐ Participant Interface Build Underway
High
Priorityy
Status
Y
Red
Required to achieve Target Mass
g
•
Western Farmers
Green
N/A
Y
Green
N/A*
Y
G
Green
Yellow
N/A
•
Western Farmers
* Target Mass met, but SPP has not received registration packets from 2 current EIS MPs
7
Date
Aug 31, 2012
• ENG.006 ‐ Complete Participation in TCR Mock Phase 2
Sept 28,
2012
• ENG.007 ‐ Participant System Design Complete
High
Priorityy
Status
Required to achieve g
Target Mass
Green
N/A
Red
•
•
Empire
Western Farmers
• ENG.008 ‐ MP Approach Completed for TCR Market Trials
Red
•
•
•
Empire
SPS
Western Farmers
Oct 7, 2012
• ENG.009 ‐ MP Approach Completed for Market Trials Connectivity Testing
Red
•
•
•
Empire
SPS
Western Farmers
Nov 1, 2012
• ENG.011 ‐ Participant System Build Underway
Sept 30, 2012
Y
Green
N/A
8
4
High Priority
Status
Required to achieve Target Mass
• ENG.022 ‐ Participant TCR Interfaces Ready for Connectivity
Y
Green
N/A
Nov 9, 2012
• ENG.026 ‐ TCR Accelerated Connectivity Test Scheduled
Y
Green
N/A
Nov 30, 2012
• ENG.010 ‐ MP/TO Testing with the MCST tool
Green
N/A
Dec 21, 2012
• ENG.015 ‐ Market Trials Connectivity Test Scheduled
Test Scheduled
Y
Green
N/A
Dec 28, 2012
• ENG.012 ‐ Participant Interfaces Ready for Connectivity (excluding TCR)
Y
Yellow
Date
Nov 9, 2012
Jan 11, 2013
• ENG.014 – TCR Market Trials Resources Trained
•
•
Green
SPS
Western Farmers
N/A
9
INTEGRATED MARKETPLACE INTERNAL READINESS UPDATE
10
5
Current Status: SPP Internal Readiness
SPP Overall Internal Readiness Status
The Internal Readiness Status for SPP is currently green.
Department
Internal readiness activities in each department are currently on track. • NS indicates the related Readiness activities have not started.
• N/A indicates the readiness area is not applicable .
• Blue (B) indicates activities for a readiness area are complete.
Engineering ‐ TCR
IT Applications
Operations Engineering
Operations Support
Settlements Accounting/Purchasing
Compliance Credit and Risk Management
Customer Relations Customer Training
Engineering
Internal Audit
IT Enterprise Operations
Market Design
Market Monitoring
Regulatory/Legal
Business Process Improvement
Communications
Corporate Services Project Management
Regional Entity Reliability Standards
G
Influence
Overall Status
H
H
H
H
H
M
M
M
M
M
M
M
M
M
M
M
L
L
L
L
L
L
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
People Process Technology
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
G
B
G
G
G
G
G
N/A
G
G
G
G
G
G
N/A
G
G
G
G
G
G
G
G
N/A
G
NS
G
G
B
N/A
G
N/A
G
N/A
G
G
11
Day in the Life Timeline
The graphic below outlines the high level timeline for the Day in the Life Effort. Departments are currently preparing for their Departmental Day in the Life workshops and detailed planning continues.
SSPP Wide Departmental Daay in the Life Day in the Life
Oct‐12
Nov‐12
Dec‐12
Jan‐13
Feb‐13
Mar‐13
Apr‐13
May‐13
Jun‐13
Jul‐13
Aug‐13
Sep‐13
Departments Prep for Departmental Day in the Life Worshops
Initial Planning Activities
Detailed Planning Activities
Departmental Day in the Life Workshops
Prep for SPP‐Wide Day in the Life Workshops
Ad Hoc Workshops as needed
SPP‐Wide Day in the Life Workshops
(i nitial "Normal" day + s pecific s cenario workshops)
Ad Hoc Workshops as needed
12
6
Market Participant Milestones
13
7
Southwest Power Pool, Inc.
FIRST QUARTERLY
PROJECT TRACKING REPORT
JANUARY 2013
Southwest Power Pool, Inc.
FIRST QUARTERLY PROJECT TRACKING REPORT
January 2013
I.
Project Tracking, Current SPP Process:
SPP actively monitors and supports the progress of transmission expansion projects,
emphasizing the importance of maintaining accountability for areas such as grid regional
reliability standards, firm transmission commitments and tariff cost recovery.
Each quarter SPP staff solicits feedback from the project owners to determine the
progress of each approved transmission project. This quarterly report charts the progress
of all SPP Transmission Expansion Plan (STEP) projects approved either directly by the
Board of Directors or through a FERC filed service agreement under the SPP Open
Access Transmission Tariff (OATT).
In this First Quarterly Report of 2013, the reporting period is September 1, 2012 through
November 30, 2012.
II.
Project Summary:
Figure 1 represents the summary of active projects for this quarter. Figure 1 reflects all
upgrades, including transmission lines, transformers, substations, and devices. There
were four Notifications to Construct, containing 13 network upgrades, issued this quarter.
Three of these were for transmission service, and NTC 200198 represented the first NTC
issued from the Attachment AQ study process.
Figure 2 shows the total miles of transmission lines currently planned within the portfolio,
as well as miles by project voltage. Figure 3 reflects the percentage cost of each project
type in the total active portfolio.
2
4th Quarter 2012 Project Tracking Summary
Upgrade Type
Number of
Upgrades
Cost
Estimate
Regional Reliability
248
$1,486,276,929
Regional Reliability - Non
OATT
14
$46,612,000
Zonal Reliability
10
$30,758,195
Transmission Service
60
$437,626,835
Generation Interconnect
23
$160,895,964
Balanced Portfolio
18
$846,718,603
High Priority
22
$1,392,114,533
ITP10
27
$1,141,793,310
Other Sponsored
Upgrades
48
$293,132,461
TOTALS
470
$5,835,928,831
Figure 1: 2013 1st Quarter Project Summary
4th Quarter Total Active Portfolio Transmission Miles
Voltage
69
Number of Upgrades
57
New Miles
17.8
Reconductor
Miles
186.7
115
80
277.8
191.5
469.3
138
69
73.2
285.2
358.4
161
25
27.1
51.1
78.2
230
16
164.4
40.0
204.4
345
54
2,411.3
0.0
2,411.3
301
2,971.5
754.4
3,726.0
Totals
Total Miles
204.5
Figure 2: Project Mileage within the Portfolio
3
Figure 3: Breakdown of Project Categories on Cost Basis
III.
Regional Reliability Project Summary:
Regional reliability projects include all tariff signatory projects identified in an SPP study
to meet regional reliability criteria for which NTC letters have been issued. Figure 4
shows the breakdown of the regional reliability projects.
There were four upgrades, with latest Engineering and Construction (E&C) cost
estimates of $3 million completed in the timeframe of the 4th Quarter of 2012. Three
projects scheduled to complete have been delayed until later in the month of December.
There are 52 upgrades, with latest E&C cost estimates of $374.1 million, on schedule to
be completed within the next four years. 131 upgrades, with latest E&C cost estimates of
$747.3 million, are in a delayed status with mitigation.
4
IV.
Transmission Service/Generation Interconnection (TSR/GI) Project
Summary:
This category contains upgrades identified as needed to support new Transmission
Service (TSR) and Generation Interconnection (GI) service agreements. Figure 4 shows
the details of the Transmission Service and Generation Interconnect projects.
No Transmission Service upgrades were completed in the 4th Quarter of 2012.
Oklahoma Gas and Electric Co.’s Hugo-Sunnyside 345 kV project, totaling 120 new
miles and $157 million, was reported complete in this quarter although the in-service date
was earlier this year, which is outside this reporting period. There are seven
Transmission Service upgrades, with estimated E&C costs of $23.3 million, on schedule
to be completed within the next four years. Two Generation Interconnect upgrades, with
a total cost of $7.2 million, were completed this quarter. There are 11 Generation
Interconnect upgrades, at an estimated E&C cost of $74.9 million, scheduled to be
completed in the next four years.
Figure 4: Project Status
5
V.
Completed Projects Summary:
Figure 5 shows the number and costs for the projects completed over the last 12 month
period. The 4th Quarter of 2012 produced 7 projects that were completed with a total
estimated cost of $11.1 million. Western Farmers Electric Cooperative’s Balanced
Portfolio Anadarko-Washita 138 kV project completed this quarter at $966,210. ITCGreat Plains is expected to report the Axtell-Post Rock-Spearville 345 kV projects
completed in December. These projects total $207 million and will add 223 miles of new
345 kV into the footprint.
Previous quarter’s updated results are listed as the Transmission Owners may make
adjustments to final costs and status of projects completed during the year. Corrections
are listed for those projects reported complete after the 4th Quarter reporting period had
ended.
Projects Completed By Quarter
Figure 5: Completed Project Summary through 4th Quarter 2012
6
4th Quarter Total Transmission Miles and Devices Completed
69
Number of
Upgrades
2
New
Miles
0.0
Reconductor
Miles
3.7
Total
Miles
3.7
Estimated Cost
$1,770,750
115
2
0.0
0.0
0.0
$1,896,368
138
3
7.0
0.0
7.0
$5,931,756
161
0
0.0
0.0
0.0
$0
230
0
0.0
0.0
0.0
$0
345
0
0.0
0.0
0.0
$0
Totals
7
7.0
3.7
10.7
$9,598,874
Voltage
Figure 6: Completed Transmission for 4th Quarter 2012
VI.
Future Projections:
1st Quarter 2013:
The 1st Quarter of 2013, ending February 28, 2013, is scheduled to have 42 projects
completed across all project types at an estimated cost of $382.3 million. As reported
above, the ITC-Great Plains Axtell-Post Rock-Spearville 345 kV projects will complete in
December, and 24 regional reliability upgrades are scheduled to complete in December.
Figure 7 shows the 1st Quarter estimated completed projects broken out by Project
Type.
There are 241 miles of new transmission scheduled to be completed in the next quarter,
along with 108 miles of reconductored transmission added to the footprint. Figure 8
shows the details of the estimated transmission miles to be completed in the 1st Quarter.
7
December 2012 through November 2013:
The next 12 months are scheduled to have a total of 101 upgrades completed at an
estimated cost of $652 million. Figure 7 shows the next 12 months estimated completed
projects broken out by Project Type.
There are scheduled to be 291 miles of new transmission added to the system during the
next 12 month period. 169 miles of 345 kV transmission lines are still scheduled to be
completed. There will also be 316 miles of reconductored transmission placed into the
system. Figure 9 shows the details of the estimated transmission miles to be completed
over the next 12 months.
Scheduled Complete
Next Quarter
Scheduled Complete
Next 12 Months
First day of
Quarter
Last Day of
Quarter
First day of
Reporting Year
12/1/2012
2/28/2013
28
$162,805,209
12/1/2012
Reliability
ReliabilityNon OATT
Zonal
Reliability
Transmission
Service
Generation
Interconnect
Balanced
Portfolio
Zonal
Sponsored
ITP10
Total
1
$3,937,500
4
$18,526,302
5
$24,576,406
0
$0
4
$172,489,681
3
$12,129,200
0
$0
42
$382,335,098
Reliability
ReliabilityNon OATT
Zonal
Reliability
Transmission
Service
Generation
Interconnect
Balanced
Portfolio
Zonal
Sponsored
ITP10
Total
Last Day of
Reporting
Year
11/30/2013
73
$365,161,307
1
$3,937,500
6
$20,357,423
15
$72,135,888
0
$0
6
$190,165,161
11
$69,106,898
0
$0
101
$651,757,279
Figure 7: Upgrades Scheduled to Complete Next Quarter/Next 12 Months
8
1st Quarter Projected Transmission Miles Complete
69
Number of
Upgrades
4
New Miles
0.0
Reconductor
Miles
42.5
Total
Miles
42.5
115
15
15.7
36.3
52.0
138
8
7.0
23.7
30.7
161
5
14.6
5.6
20.2
230
1
35.0
0.0
35.0
345
7
169.0
0.0
169.0
Totals
40
241.3
108.1
349.4
Voltage
Figure 8: Transmission Miles Scheduled to Complete 1st Quarter
Projected Transmission Miles Complete Next 12 Months
69
Number of
Upgrades
20
New Miles
0
Reconductor
Miles
92.06
Total
Miles
92.06
115
31
23.77
102.97
126.74
138
22
27.2
96.03
123.23
161
10
16.1
25
41.1
230
3
55
0
55
345
9
169
0
169
Totals
95
291.07
316.06
607.13
Voltage
Figure 9: Transmission Miles Scheduled to Complete Next 12 Months
9
SPP 1st Quarter 2013 Project Tracking List
COMPLETE
ON SCHEDULE <4
ON SCHEDULE >4
Complete.
On Schedule 4 Year Horizon.
On Schedule beyond 4 Year Horizon.
Behind schedule, interim mitigation provided or project may change but time permits the implementation
of project.
DELAY - MITIGATION
DELAY - MITIGATION
*
Behind Schedule, Mitgation Plan provided by SPP
RE-EVALUATION
Behind schedule, require re-evaluation due to anticipated load forecast changes.
NTC-COMMITMENT WINDOW
NTC issued, still within the 90 day written commitment to construct window and no commitment received
12/31/14
06/30/10
$25,250,000
$25,250,000
$46,764,321
$46,764,321
$94,410,174
$94,410,174
$ ,
,
$6,585,986
$5,776,280
$65,000,000
$65,000,000
ON SCHEDULE < 4
COMPLETE
ON SCHEDULE > 4
ON SCHEDULE > 4
ON SCHEDULE > 4
ON SCHEDULE < 4
ON SCHEDULE < 4
ON SCHEDULE < 4
ON SCHEDULE < 4
ON SCHEDULE < 4
ON SCHEDULE < 4
ON SCHEDULE < 4
ON SCHEDULE < 4
ON SCHEDULE < 4
ON SCHEDULE < 4
ON SCHEDULE < 4
ON SCHEDULE < 4
ON SCHEDULE < 4
ON SCHEDULE < 4
ON SCHEDULE < 4
ON SCHEDULE < 4
ON SCHEDULE < 4
$12,000,000
ON SCHEDULE < 4
$43,116,469
$12,715,142
$172,000,000
$97,427,500
$10,800,000
$201,221,000
$ ,
,
$4,379,000
$4,727,306
$145,040,000
$150,700,000
20040
10927
GRDA
Line - Sooner – Cleveland 345 kV (GRDA)
Balanced Portfolio
12/31/12
06/19/09
$17,000,000
$2,780,000
ON SCHEDULE < 4
20041
10929
OGE
Line - Sooner - Cleveland 345 kV (OGE)
Balanced Portfolio
12/31/12
06/19/09
$17,000,000
$46,000,000
ON SCHEDULE < 4
20041
20041
20041
10930
10932
10933
OGE
OGE
OGE
Line - Seminole - Muskogee 345 kV
Multi - Tuco - Woodward 345 kV (OGE)
Balanced Portfolio
Balanced Portfolio
Balanced Portfolio
12/31/13
05/19/14
05/19/14
06/19/09
06/19/09
06/19/09
$131,000,000
$64,000,000
$15,000,000
$176,100,000
ON SCHEDULE < 4
ON SCHEDULE < 4
ON SCHEDULE < 4
20043
10937
OGE
Balanced Portfolio
05/19/14
06/19/09
$14,880,000
20042
10934
KCPL
Tap - Swissvale - Stilwell
Balanced Portfolio
03/31/13
06/19/09
$2,000,000
$1,922,840
ON SCHEDULE < 4
20042
200189
10945
50499
KCPL
GMO
Multi - Iatan - Nashua 345 kV
Balanced Portfolio
Balanced Portfolio
06/01/15
06/01/15
06/19/09
04/17/12
$4,620,000
$4,230,820
$48,438,919
ON SCHEDULE < 4
ON SCHEDULE < 4
$147,000,000
$49,824,000
ON SCHEDULE < 4
200188
10935
KCPL
Balanced Portfolio
06/01/15
04/17/12
$12,130,261
ON SCHEDULE < 4
20043
20084
20044
20046
20065
20046
20047
10936
11085
10938
10940
10941
10943
10942
SPS
SPS
WFEC
ITCGP
ITCGP
ITCGP
NPPD
Multi - Tuco - Woodward 345 kV (SPS)
Multi - Tuco - Woodward 345 kV (SPS)
Tap Anadarko - Washita 138 kV line into Gracemont 345 kV
Multi - Axtell - Post Rock - Spearville 345 kV
Line - Axtell - Kansas Border 345 kV (NPPD)
Balanced Portfolio
Balanced Portfolio
Balanced Portfolio
Balanced Portfolio
Balanced Portfolio
Balanced Portfolio
Balanced Portfolio
05/19/14
03/31/13
10/12/12
06/18/12
06/18/12
12/15/12
12/15/12
06/19/09
02/08/10
06/19/09
06/19/09
11/06/09
06/19/09
06/19/09
$122,597,500
$11,250,000
$2,000,000
$96,000,000
$3,000,000
$66,000,000
$71,377,000
$170,247,072
$15,752,640
$966,210
$79,136,700
$4,348,600
$64,514,700
$59,194,981
ON SCHEDULE < 4
DELAY - MITIGATION
COMPLETE
COMPLETE
COMPLETE
COMPLETE
COMPLETE
20041
10946
OGE
Sub - Gracemont
Balanced Portfolio
12/31/11
06/19/09
$8,000,000
$13,954,860
COMPLETE
20015
10460
AECC
Line - Hope - Fulton 115 kV Recond
06/08/11
04/01/12
01/16/09
$440,000
$1,512,000
$640,645
COMPLETE
20015
10461
AECC
Line - Hope - Fulton 115 kV Recond
06/08/11
04/01/12
01/16/09
$1,512,000
$440,000
$18,899
COMPLETE
20015
50151
AECC
Line - McNab - Turk 115 kV
11/07/11
04/01/12
01/16/09
$165,000
$165,000
$417,349
COMPLETE
06/01/12
Project Status
Comments
High Priority
$238,122,033
$127,995,000
$960,895
$231,600,000
$152,640,000
$19,796,666
Project Status
Line - Thistle - Wichita 345 kV dbl Ckt
$131,451,250
$842,847
$174,500,000
$114,500,000
$12,029,091
$8,883,760
Final Cost
06/30/10
06/30/10
07/23/10
07/23/10
06/30/10
06/30/10
06/30/10
06/30/10
06/30/10
06/30/10
11/22/10
11/22/10
07/29/11
07/29/11
07/29/11
07/29/11
07/29/11
07/29/11
07/29/11
07/29/11
07/29/11
07/29/11
Current Cost Estimate
WR
05/01/15
06/10/11
06/01/17
06/01/17
06/01/17
06/30/14
06/30/14
06/30/14
06/30/14
06/30/14
12/31/14
12/31/14
12/31/14
12/31/14
12/31/14
12/31/14
12/31/14
12/31/14
12/31/14
12/31/14
12/31/14
12/31/14
Original Cost Estimate
11497
High Priority
High Priority
High Priority
High Priority
High Priority
High Priority
High Priority
High Priority
High Priority
High Priority
High Priority
High Priority
High Priority
High Priority
High Priority
High Priority
High Priority
High Priority
g Priorityy
High
High Priority
High Priority
High Priority
Letter of Notification to
Construct Issue Date
20103
Line - Valliant - NW Texarkana 345 kV
Tulsa Power Station 138 kV reactor
Multi - Nebraska City - Maryville - Sibley 345 kV (GMO)
Multi - Nebraska City - Maryville - Sibley 345 kV (GMO)
Line - Nebraska City - Maryville 345 kV (OPPD)
Multi - Hitchland - Woodward 345 kV (SPS)
Line - Hitchland - Woodward 345 kV dbl Ckt (OGE)
Line - Hitchland - Woodward 345 kV dbl Ckt (OGE)
Line - Thistle - Woodward 345 kV dbl Ckt (OGE)
Line - Thistle - Woodward 345 kV dbl Ckt (OGE)
Line - Thistle - Woodward 345 kV dbl Ckt (PW)
Line - Thistle - Woodward 345 kV dbl Ckt (PW)
Line - Spearville - Clark Co - Thistle 345 kV dbl Ckt
p
Line - Spearville
- Clark Co - Thistle 345 kV dbl Ckt
RTO Determined Need
Date
AEP
AEP
GMO
GMO
OPPD
SPS
SPS
SPS
OGE
OGE
OGE
OGE
PW
PW
ITCGP
ITCGP
ITCGP
ITCGP
ITCGP
ITCGP
PW
PW
Project Owner Indicated
In-Service Date
Project Owner
11236
11237
11238
11239
11240
11241
11242
11243
11244
11245
11246
11247
11248
11249
11252
11253
11254
11255
11260
50384
11258
11259
Project Type
UID
20096
20096
20097
20097
20098
20099
20099
20099
20100
20100
20121
20121
200163
200163
200162
200162
200162
200162
200162
200162
200163
200163
Project Name
NTC_ID
Project types "zonal - sponsored" and "regional reliability - non OATT" do not receive NTCs and are not filed at FERC but are being tracked because they are expected to be built in the near term
Delayed
Complete 6/10/2011
currently in contract negotiations for line routing and siting.
currently in contract negotiations for line routing and siting.
Construction cost estimates came in lower than expected.
Project milage increased
UID 11258 and 11259 were revised to separate out terminal
equipment at Wichita Sustation and uid 11497 was added to include
this equipment
Original Estimate Revised 8/16/2012
Cost reduced to account for lower construction costs than expected.
Build midpoint reactor station at interception point of Woodward to
Tuco line. Cost already included in above two projects. Original
SPS project.
project delayed due to delay in obtaining substation steel; project
delayed to 1st quarter 2013 due to sending construction staff to East
Coast for Hurricane Sandy restoration work.
KCPL will construct 345/161kV, 650Mva transformer addition at
GMO will construct Iatan-Nashua transmission line ~31 miles 345kV;
KCPL will construct line terminals and substation additions at Iatan &
Nashua
This is the SPS current cost estimate for the transmission line from
Q4-2012 Cost Estimate remains valid. MN-9/19/12. Q1-2013 Cost
Updated mileage for filed route; reactor added at Post Rock (55
In-service
Final cost Still being compiled
Full BPF-In service-Waiting on final paper work
Full BPF-In service-Waiting on final paper work
Full BPF - In service - cost not final - NTC not closed out
10367
AECI
Multi - Blackberry - Chouteau - GRDA 1
Inter-regional
04/01/13
ON SCHEDULE < 4
10368
AECI
Inter-regional
02/01/11
COMPLETE
10369
AECI
Inter-regional
02/01/11
COMPLETE
$57,000,000
$100,000,000
10781
AECI
Inter-regional
02/01/11
COMPLETE
10916
AECI
Inter-regional
02/01/11
COMPLETE
20000
10140
AEP
Multi - Wallace Lake - Port Robson - RedPoint 138 kV
04/16/12
06/01/12
02/13/08
20000
10141
AEP
06/01/12
02/13/08
10296
AEP
Line - Turk - SE Texarkana - 138 kV
10374
AEP
Line - Valliant Substation - Install 345 kV terminal equipment
10446
AEP
10447
AEP
10448
03/01/12
Generation Interconnection
03/12/12
04/17/12
Multi - McNab REC - Turk 115 kV
12/01/11
12/01/11
AEP
10451
AEP
10452
10455
AEP
AEP
200161
10456
AEP
20000
10457
10505
AEP
AEP
Line - Riverside - Okmulgee 138 kV
20122
10509
AEP
Line - Lone Star South - Pittsburg 138kV Ckt 1
20027
20027
20048
20000
20000
20000
10510
10575
10578
10582
10584
10585
AEP
AEP
AEP
AEP
AEP
AEP
Line - Howell - Kilgore 69 kV
Line - Osborne - Osborne Tap
Line - Coffeyville Tap - North Bartleville 138 kV
Multi - Flint Creek – Centerton 345 kV and Centerton- East Centerton
20027
10586
AEP
XFR - Whitney 138/69 kV
20048
10588
AEP
Line - Bartlesville Southeast - North Bartlesville 138 kV
200167
10647
AEP
20016
$24,000,000
$0
$26,850,000
$7,810,000
COMPLETE
$9,670,000
$11,431,000
COMPLETE
12/01/11
$1,520,000
$1,773,000
COMPLETE
12/01/11
$3,400,000
$3,266,000
COMPLETE
12/01/11
12/01/11
$9,190,000
$0
$8,170,000
$11,250,000
COMPLETE
COMPLETE
06/30/12
05/11/12
05/07/12
06/01/13
05/11/11
06/01/14
06/01/14
06/01/14
04/01/12
$3,840,000
COMPLETE
COMPLETE
$8,100,000
12/01/11
03/01/12
01/16/09
$19,482,000
$25,590,000
COMPLETE
COMPLETE
04/01/12
$9,480,000
$3,840,000
As of 10/11/12 Clearing 100% complete. All structures laid out &
framed. Construction: Sec1 (157 structures) 100% complete. Sec2
09/18/09
$7,310,000
$7,310,000
COMPLETE
06/01/12
02/13/08
$9,110,000
$125,000
$7,806,000
$125,000
COMPLETE
COMPLETE
06/01/12
02/14/11
$300,000
$300,000
06/01/09
06/01/13
06/01/11
06/01/14
06/01/14
06/01/14
01/27/09
01/27/09
09/18/09
02/13/08
02/13/08
02/13/08
$2,000,000
$6,000,000
$13,100,000
$3,986,000
$2,000,000
$13,100,000
$11,962,000
$13,104,000
$34,085,000
06/01/11
06/01/11
01/27/09
$350,000
$350,000
COMPLETE
05/11/11
06/01/11
09/18/09
$8,400,000
$8,400,000
COMPLETE
Line - Northwest Henderson - Poynter 69 kV
06/01/14
06/01/14
04/09/12
$7,214,837
$7,815,833
ON SCHEDULE < 4
$926,970
200167
10648
AEP
Line - Diana - Perdue 138 kV
06/01/14
06/01/13
04/09/12
20000
10656
AEP
Multi - Centerton - Osage Creek 345 kV
06/01/16
06/01/16
02/13/08
20000
10659
AEP
06/01/16
06/01/16
02/13/08
20000
10660
AEP
06/01/16
06/01/16
20000
10786
AEP
06/01/11
20027
20073
20073
10853
11011
11012
AEP
AEP
AEP
Line - Lone Star-Locust Grove 115 kV
Multi - Canadian River - McAlester City - Dustin 138 kV
regional reliability
20064
11015
AEP
Line - Ashdown - Craig Junction 138 kV Rebuild
$35,185,000
Replacement not needed in 2009 due to re-rating, but replacement
needed in 2011 due to voltage conversion associated with Turk.
Turk commercial operation date delayed until late 2012; Complete
06/30/2012
COMPLETE
COMPLETE
ON SCHEDULE < 4
COMPLETE
ON SCHEDULE < 4
ON SCHEDULE < 4
ON SCHEDULE < 4
$1,004,187
DELAY - MITIGATION
$11,000,000
ON SCHEDULE < 4
$24,500,000
ON SCHEDULE < 4
02/13/08
$65,500,000
ON SCHEDULE < 4
06/01/12
02/13/08
$11,988,400
COMPLETE
06/01/14
06/01/13
06/01/13
06/01/14
06/01/10
06/01/10
01/27/09
02/08/10
02/08/10
$2,150,000
$17,000,000
$8,500,000
$2,150,000
$24,965,000
$9,513,000
ON SCHEDULE < 4
DELAY - MITIGATION
DELAY - MITIGATION
06/01/13
06/01/13
11/02/09
$2,500,000
$2,500,000
ON SCHEDULE < 4
ON SCHEDULE < 4
$57,500,000
Notification received from the SPP concurring with the new in-service
date due to the delay of the Turk plant. 73% BPF. Completed 4/17/12
Complete 5/11/11
C
Complete
6/1/2011
/ /
Complete 5/11/11
Complete 6/1/2011
200167
11171
AEP
Line - Carthage - Rock Hill 69 kV Ckt 1 rebuild
06/01/14
06/01/14
04/09/12
$13,500,000
$11,830,128
20073
11183
AEP
05/16/12
06/01/10
02/08/10
$2,900,000
$4,096,000
COMPLETE
20073
11184
AEP
06/01/13
06/01/10
02/08/10
$2,900,000
$4,096,000
DELAY - MITIGATION
11185
AEP
Line - Lone Oak - EnoGex Wilberton 138 kV
Zonal - Sponsored
03/11/11
$0
$1,456,000
COMPLETE
Complete 3/11/2011
20066
11199
AEP
Line - Coffeyville Tap - South Coffeyville City 138 kV
06/28/11
06/01/11
01/13/10
$6,000,000
$6,000,000
COMPLETE
20066
11208
AEP
Line - Coffeyville Farmland - South Coffeyville City 138 kV
05/22/11
06/01/11
01/13/10
$2,200,000
$2,200,000
COMPLETE
Complete 5/22/2011
20104
11261
AEP
Line - Broken Arrow North South Tap - Oneta 138 kV Ckt 1
200167
11331
AEP
Line - Diana - Perdue 138 kV Reconductor
20112
11347
AEP
20112
20122
20016
20016
20016
20122
20016
20016
20016
20016
20122
20122
20135
20135
20135
20135
11348
11421
50148
50149
50150
50156
50160
50163
50164
50165
50334
50336
50363
50364
50365
50375
AEP
AEP
AEP
AEP
AEP
AEP
AEP
AEP
AEP
AEP
AEP
AEP
AEP
AEP
AEP
AEP
200165
06/01/15
06/01/15
08/25/10
$4,400,000
$5,060,000
06/01/14
06/01/14
04/09/12
$17,359,447
$18,805,489
ON SCHEDULE < 4
Line - Southwest Shreveport - Springridge REC 138 kV
06/01/13
06/01/12
12/09/10
$7,200,000
$7,200,000
DELAY - MITIGATION
Line - Eastex - Whitney 138 kV Accelerated
Line - Hooks - Lone Star Ordinance 69 kV Ckt 1
Line - Turk - NW Texarkana 345 kV
Line - Bann - Lone Star Ordinance 69 kV Ckt 1
Line - Linwood - Powell Street 138 kV
Line - Okay - Tollette 69 kV
Line - SE Texarkana - Texarkana Plant 69 kV
Line - South Texarkana REC - Texarkana Plant 69 kV
Device - Winnsboro 138 kV
Device - Logansport 138 kV
Line - Easton Rec - Knox Lee 138 kV ckt 1
Line - Easton Rec - Pirkey 138 kV ckt 1
Line - Pirkey - Whitney 115 kV ckt 1
XFR - Diana 345/138 kV ckt 3
06/01/13
06/01/13
08/28/12
08/28/12
08/28/12
06/01/13
06/01/12
12/01/11
03/01/12
05/30/12
06/01/16
06/01/16
12/31/12
12/31/12
06/01/13
06/01/13
06/01/12
06/01/13
04/01/12
04/01/12
04/01/12
06/01/13
06/01/12
04/01/12
04/01/12
04/01/12
06/01/16
06/01/16
06/01/12
06/01/12
06/01/13
06/01/13
12/09/10
02/14/11
01/16/09
01/16/09
01/16/09
02/14/11
01/16/09
01/16/09
01/16/09
01/16/09
02/14/11
02/14/11
05/27/11
05/27/11
05/27/11
05/27/11
$2,800,000
$2,100,000
$57,530,000
$0
$0
$4,225,000
$456,000
$80,000
$35,000
$2,800,000
$2,100,000
$6,600,000
$456,000
$80,000
$128,000
$8,193,000
$1,166,400
$1,166,400
$150,000
$500,000
$900,000
$5,500,000
DELAY - MITIGATION
ON SCHEDULE < 4
COMPLETE
COMPLETE
COMPLETE
ON SCHEDULE < 4
COMPLETE
COMPLETE
COMPLETE
COMPLETE
ON SCHEDULE < 4
ON SCHEDULE < 4
DELAY - MITIGATION
DELAY - MITIGATION
ON SCHEDULE < 4
ON SCHEDULE < 4
DELAY - MITIGATION
$150,000
$500,000
$900,000
$5,500,000
$44,200,000
50387
AEP
Line - Clinton Junction 138 kV relay (AEP)
06/30/12
$150,000
$150,000
50392
50393
50394
AEP
AEP
AEP
Sub - Cornville 138 kV
Zonal - Sponsored
Zonal - Sponsored
Zonal - Sponsored
12/31/14
12/31/14
12/31/14
$0
$0
$0
$9,585,000
$4,770,000
$911,250
ON SCHEDULE < 4
ON SCHEDULE < 4
ON SCHEDULE < 4
50395
AEP
Zonal - Sponsored
12/31/14
$0
$3,155,625
ON SCHEDULE < 4
200167
50405
AEP
Device - Coweta 69 kV Capacitor
06/01/14
200183
50413
AEP
Multi - Elk City - Gracemont 345 kV
200183
50414
AEP
200167
50438
AEP
XFR - Cocodrie 230/138 kV
08/02/11
$4,750,000
ON SCHEDULE < 4
06/01/14
04/09/12
$1,428,440
$1,428,440
ON SCHEDULE < 4
ITP10
03/01/18
04/09/12
$81,514,845
$81,514,845
ON SCHEDULE > 4
ITP10
03/01/18
04/09/12
$18,060,547
$18,060,547
ON SCHEDULE > 4
12/31/14
06/01/12
04/09/12
$19,998,928
$21,664,838
DELAY - MITIGATION
10272
CLEC
Regional Reliability - Non OATT
06/01/12
06/01/09
$0
$5,000,000
ON SCHEDULE < 4
50136
10373
10834
CUS
DETEC
DETEC
Device - Twin Oaks 69 kV
Line - Etoile - Chireno
Line - Chireno-Martinsville 138 kV
Zonal - Sponsored
Zonal - Sponsored
Zonal - Sponsored
06/01/17
06/01/14
06/01/15
06/01/18
$0
$0
$0
$875,000
$8,864,000
$8,894,000
ON SCHEDULE > 4
ON SCHEDULE < 4
ON SCHEDULE < 4
10849
DETEC
Line - Martinsville - Timpson 138 kV conversion
Zonal - Sponsored
06/01/14
$0
20123
20123
19970
10850
10851
10852
10548
10608
10644
DETEC
DETEC
DETEC
EDE
EDE
EDE
Multi - Nichols 170 - Republic 345 - Republic 451 - Republic 359 69 kV
Line - Explorer Spring City Tap - Joplin Southwest 69 kV Ckt 1
XFR - Oronogo 161/69 kV
Zonal - Sponsored
Zonal - Sponsored
Zonal - Sponsored
06/01/14
06/01/14
06/01/14
06/01/15
06/01/14
06/01/11
06/01/15
06/01/14
06/01/11
02/14/11
02/14/11
01/10/08
$0
$0
$0
$2,973,000
$1,550,000
$4,000,000
19970
10730
EDE
Line - Oronogo Junction - Riverton 161 kV Recond
06/01/11
06/01/11
01/10/08
20075
20123
10839
10891
EDE
EDE
Line - Sub 170 Nichols - Sub 80 Sedalia 69 kV
Multi - Stateline - Joplin - Reinmiller conversion
05/01/12
06/01/18
06/01/10
06/01/18
20123
10894
EDE
06/01/18
In mid 2011, this project was replaced with Springhill - Perdue 138 kV
$4,286,188
$5,750,000
$5,750,000
$3,324,960
02/08/10
02/14/11
$3,520,000
$3,591,000
$4,500,000
$3,591,000
COMPLETE
ON SCHEDULE > 4
06/01/18
02/14/11
$2,011,500
$2,011,500
ON SCHEDULE > 4
*
COMPLETE
20036
50073
EDE
Device - Quapaw Cap 69 kV
06/01/18
06/01/18
01/27/09
$0
$1,500,000
ON SCHEDULE > 4
20123
50316
EDE
Multi - Monett South
06/01/17
06/01/17
02/14/11
$468,000
$468,000
ON SCHEDULE > 4
20123
50322
EDE
06/01/18
06/01/18
02/14/11
$1,647,000
$1,647,000
ON SCHEDULE > 4
20123
50323
EDE
06/01/18
06/01/18
02/14/11
$1,201,500
$1,201,500
ON SCHEDULE > 4
20123
20123
20123
20123
20123
20123
20123
50324
50325
50326
50348
50350
50352
50353
10370
10243
10431
EDE
EDE
EDE
EDE
EDE
EDE
EDE
EES
GMO
GMO
Line - Grandview - Osage
Line - Grandview - Martin City 161 kV
Line - Lone Jack - Greenwood 161 kV
Inter-regional
Zonal - Sponsored
06/01/18
06/01/18
06/01/17
06/01/15
06/01/17
06/01/15
06/01/17
12/31/11
06/01/18
06/01/18
06/01/17
06/01/15
06/01/17
06/01/15
06/01/17
06/01/09
06/01/09
02/14/11
02/14/11
02/14/11
02/14/11
02/14/11
02/14/11
02/14/11
$749,250
$4,968,000
$2,250,000
$1,100,500
$324,000
$476,500
$4,149,000
$0
$150,000
$0
$749,250
$4,968,000
$2,250,000
$1,100,500
$324,000
$476,500
$4,149,000
$6,000,000
$50,000
$7,096,402
ON SCHEDULE > 4
ON SCHEDULE > 4
ON SCHEDULE > 4
ON SCHEDULE < 4
ON SCHEDULE > 4
ON SCHEDULE < 4
ON SCHEDULE > 4
COMPLETE
COMPLETE
ON SCHEDULE < 4
20034
10830
GMO
Multi - Loma Vista - Montrose 161 kV - Tap into K.C. South
12/31/12
06/01/09
01/27/09
$2,369,625
$2,369,625
DELAY - MITIGATION
20034
10847
GMO
XFR - Clinton 161/69 kV
11/01/13
06/01/13
01/27/09
$2,000,000
$2,000,000
DELAY - MITIGATION
20034
10854
GMO
Multi - South Harper 161 kV cut-in to Stilwell-Archie Junction 161 kV lin
12/28/12
06/01/09
01/27/09
$2,259,673
$2,559,673
DELAY - MITIGATION
20087
20124
10952
11263
GMO
GMO
Line - Glenare - Liberty 69 kV Ckt 1
Line - Nashua - Smithville 161 kV Ckt 1
06/01/13
06/01/13
06/01/11
02/08/10
02/14/11
$200,000
$150,000
$800,000
$150,000
20008
02/13/08
06/01/15
$5,709
$24,897
ON SCHEDULE < 4
COMPLETE
Mitigation is redispatch
Mitigation is redispatch
This project is on hold by Windfarm 66 LLC
Delayed
Delayed
Delayed
Build new 345kV/230kV station with 3 breaker ring on 230 kV, 1
ON SCHEDULE < 4
ON SCHEDULE < 4
ON SCHEDULE < 4
ON SCHEDULE < 4
ON SCHEDULE < 4
COMPLETE
$2,973,000
$1,550,000
$4,000,000
Change PID and UID (old PID 349 and old UID 10453)Turk
Full BPF. SPP to provided revised NTC
Full BPF
Full BPF
Full BPF Turk commercial operation date delayed to 7/01/2012
Full BPF Turk commercial operation date delayed to 7/01/2012
Delayed
ON SCHEDULE < 4
$11,454,960
Interim redispatch required
Interim redispatch required
The scope of this work involves building a new breaker and a half
station adjacent to the existing Cornville station. 15kV distribution
and 69kV will remain located in the existing yard and lines will be run
to them to connect. Remote ends listed above will be upgraded.
Cost estimate is for entire project.
EDE would like to request that this project need be re-evaluated.
95.1% of costs BPF
Project under study. Distribution transformer taps to be adjusted
accordingly to serve load adequately until the project can be
Part of Multi Line upgrade @ Monett.
Part of Multi Line upgrade @ Monett. This 547510-547511 xfmr
Preliminary design has begun.
Project completed and in service; costs finalized
project is an alternative to replace the reconductor projects of the
Duncan Rd - Blue Spring East and Martin City-Grandview East 161 kV
cost estimate increase due to poor condition of structures
Project completed and in service; costs not finalized
50424
GMO
XFR - Eastowne 345/161 kV
Zonal - Sponsored
04/15/13
$0
$12,809,443
ON SCHEDULE < 4
50501
GMO
Device - Clinton Plant 69 kV Cap
Zonal - Sponsored
06/01/13
$0
$1,100,000
ON SCHEDULE < 4
20021
20021
50502
10385
10386
GMO
GRDA
GRDA
Device - Alabama 161 kV Cap
Multi - Kansas Tap - Siloam City 161KV
Multi - Kansas Tap - Siloam City 161KV
Zonal - Sponsored
04/01/12
08/01/13
08/01/13
06/01/12
06/01/12
01/16/09
01/16/09
$0
$4,212,500
$1,700,000
$1,500,000
$4,372,000
$1,831,000
20001
10388
GRDA
XFR - Sallisaw 161/69 kV Auto #2
07/15/12
06/01/08
02/13/08
10389
GRDA
Multi - Toneece - Siloam City 161 kV
Zonal - Sponsored
01/01/13
10390
GRDA
Multi - Toneece - Siloam City 161 kV
Zonal - Sponsored
01/01/13
20076
10511
GRDA
XFR - Afton 161/69 kV Ckt 2
08/01/13
06/01/10
02/08/10
20050
10512
GRDA
Line - Pensacola - Kerr 161 kV
06/01/11
06/01/11
200168
10698
GRDA
Line - Maid - Pryor Foundry South 69 kV
06/01/13
06/01/12
$875,977
COMPLETE
DELAY - MITIGATION
DELAY - MITIGATION
$3,000,000
COMPLETE
$3,210,200
ON SCHEDULE < 4
$8,019,000
ON SCHEDULE < 4
$750,000
$8,020,000
DELAY - MITIGATION
09/18/09
$10,450,000
$10,450,000
04/09/12
$1,064,300
$1,374,534
$2,000,000
Construction started
project to replace UID 331 PID 10428
capacitor bank is in service; costs not finalized
GRDA would could reduce generation at Kerr Hydro to relieve loading.
GRDA would could reduce generation at Kerr Hydro to relieve loading.
Utilizing LTCs on GRDA transformers in this area increases voltages
within criteria limits.
This project didn't come from any RTO reliability studies.
$9,509,623
COMPLETE
DELAY - MITIGATION
200168
10699
GRDA
Line - Maid - Redden 69 kV
06/01/13
06/01/12
04/09/12
$1,092,500
$1,419,469
DELAY - MITIGATION
20028
50080
GRDA
Device - Tahlequah West 69 Cap kV
07/01/12
06/01/09
01/27/09
$0
$779,000
DELAY - MITIGATION
20001
50092
GRDA
Device - Jay Cap 69 kV
06/01/11
02/13/08
$0
$800,000
20018
50459
50460
10955
10956
10840
10405
GRDA
GRDA
GRIS
GRIS
INDN
ITCGP
SUB - PAWNEE 138 KV
LINE - FAIRFAX - PAWNEE 138 KV
Line - Sub F - St. Libory 115 kV
Line - Sub H - Sub E upgrade
Line - Blue Valley Plant - Sub M 161 kV
Line - Valliant - Hugo 345 kV
$2,500,000
$11,900,000
$3,937,500
$200,000
$2,625,000
$22,230,000
ON SCHEDULE < 4
ON SCHEDULE < 4
ON SCHEDULE < 4
COMPLETE
COMPLETE
COMPLETE
20018
10406
ITCGP
$6,328,605
COMPLETE
06/25/12
12/31/13
06/30/14
12/01/12
04/01/12
06/01/12
06/08/12
10/01/09
04/01/12
01/16/09
$0
$0
$0
$0
$0
$11,000,000
XFR - Hugo 345/138 kV
06/30/12
04/01/12
01/16/09
$5,000,000
$1,013,318
20018
50173
ITCGP
Line - Hugo - Sunnyside 345 kV
06/08/12
04/01/12
01/16/09
$45,000,000
$6,620,096
COMPLETE
50425
50426
ITCGP
ITCGP
Multi - Elm Creek - Summit 345 kV
ITP10
ITP10
03/01/18
03/01/18
03/01/18
03/01/18
04/09/12
04/09/12
$28,580,803
$5,403,707
$28,580,803
$5,403,707
ON SCHEDULE > 4
ON SCHEDULE > 4
200187
50427
ITCGP
ITP10
03/01/18
03/01/18
04/09/12
$8,015,964
$8,015,964
ON SCHEDULE > 4
200187
50428
ITCGP
ITP10
03/01/18
03/01/18
04/09/12
$697,163
$697,163
ON SCHEDULE > 4
10363
KCPL
Line - Craig - Lenexa 161 kV
Zonal - Sponsored
06/01/12
$0
$112,449
11376
KCPL
Line - Olathe - Switzer 161 kV
Zonal - Sponsored
06/01/13
$0
$2,963,000
200169
20009
11498
50083
KCPL
KCPL
Line - Loma Vista East - Winchester Junction North 161kV Ckt 1
Device - Craig Cap 161 kV
Zonal Reliability
12/31/12
05/18/11
04/09/12
02/13/08
$190,860
$0
$190,860
$1,316,500
20116
50329
KCPL
Line - Stillwell - West Gardner 345 kV Ckt 1
12/31/12
09/03/10
$150,000
$150,000
ON SCHEDULE < 4
50468
KCPL
Line - Merriam - Overland Park 161 kV
Zonal - Sponsored
12/31/14
$0
$1,518,750
ON SCHEDULE < 4
50500
KCPL
Device - West Gardner 12 kV Reactor
Zonal - Sponsored
12/31/12
$0
$900,000
ON SCHEDULE < 4
50604
KCPL
Line - Overland Park - Brookridge 161 kV
Zonal - Sponsored
12/31/13
$500,000
ON SCHEDULE < 4
11086
LEA
Multi - ERF-Gaines 115 kV Ckt 1
06/01/12
06/01/12
$0
$1,000,000
ON SCHEDULE < 4
11087
LEA
06/01/12
06/01/12
$0
$1,000,000
ON SCHEDULE < 4
11088
LEA
06/01/12
06/01/12
$0
$1,000,000
ON SCHEDULE < 4
200171
#N/A
COMPLETE
ON SCHEDULE < 4
$1,469,151
DELAY - MITIGATION
COMPLETE
11215
LES
Line - Sheldon - Folsom 115 KV Ckt 1
Zonal - Sponsored
05/31/11
$0
$380,000
COMPLETE
11216
LES
Line - Sheldon - Folsom 115 KV Ckt 2
Zonal - Sponsored
05/31/11
$0
$380,000
COMPLETE
11217
LES
Line - 2nd & N - 20th & PIO 115 KV Ckt 1
Zonal - Sponsored
05/31/11
$0
$100,000
COMPLETE
11218
11230
11447
50388
LES
LES
LES
LES
Line - Folsom - 20th & PIO 115 KV Ckt 1
XFR - Folsom 115/12.5 KV Ckt 1
Line - Folsom - Rokeby 115 KV Ckt 1
Line - 17th & Holdrege - 30th & A 115 kV Ckt 1
Zonal - Sponsored
Zonal - Sponsored
Zonal - Sponsored
Zonal - Sponsored
05/31/11
05/31/11
05/31/11
09/13/13
$0
$0
$0
$0
$100,000
$150,000
$17,318,000
COMPLETE
COMPLETE
COMPLETE
ON SCHEDULE < 4
50389
LES
Line - 30th & A - 56th & Everett 115 kV Ckt 1
Zonal - Sponsored
09/13/13
$0
$9,980,000
ON SCHEDULE < 4
50390
LES
Line - 57 & Garland - 84 & Leighton 115 kV Ckt 1
Zonal - Sponsored
05/31/12
$0
$2,372,000
COMPLETE
50391
LES
Line - SW 7 & Bennet - 40th & Rokeby 115 kV Ckt 1
Zonal - Sponsored
05/31/15
$0
$7,675,000
ON SCHEDULE < 4
50403
LES
Line - Folsom & Pleasant Hill - Sheldon 115 kV Ckt 2
05/15/13
$6,480,000
$6,382,777
DELAY - MITIGATION
01/01/12
04/09/12
1590 ACSR: Normal Rating=152 MVA, 1275 Amps @ 85C,
Emergency Rating=185 MVA, 1550 Amps @100C, NTC Upgrade
1590 ACSR: Normal Rating=152 MVA, 1275 Amps @85C,
Emergency Rating=185 MVA, 1550 Amps @ 100C, NTC Upgrade
Replaces Tahlequah City #1 and City #2 Cap 69. In the event of a
COMPLETE
200187
200187
06/01/12
06/01/08
This project didn't come from any RTO reliability studies.
GRDA and NEO will perform switching at the 13kV level to avoid
dropping any load
Original In-Service Date was 12/31/2013. Per Construction Update
Energized 6/8/12
Direct assigned to Network Customer; Transformer installation
scheduled to be complete by 4/1/12 - Tie into 138 kV bus to be
constructed by WFEC delayed due to Hugo Plant outage schedule
Energized 6/8/12
Bus cost includes $3,052,177 for 30 Mvar switched reactor to be
located on bus or line terminal
project complete and in service; costs not finalized.
construction started
project is tied to NTC 20034 which has an in-service date 12/31/12.
Project placed in service 5/18/11. Costs finalized.
project delayed due to delay in obtaining substation steel
In progress; old conductor is in dollies
Complete
Complete
Complete
Complete
Complete
Complete
No additional substation equipment is expected.
Uprate complete. New ratings Rate A = 83 MVA, Rate B = 99 MVA
20139
20089
10410
11209
MIDW
MIDW
Line - Hays Plant - South Hayes 115 kV Ckt 1
Multi - North Ellinwood - City of Ellinwood 69 kV
transmission service
06/01/12
01/01/11
06/01/12
06/01/09
05/27/11
03/31/10
$35,000
$825,000
$35,000
$825,000
COMPLETE
COMPLETE
20089
11210
MIDW
01/01/11
06/01/09
03/31/10
$530,000
$530,000
COMPLETE
20089
11211
MIDW
01/01/11
06/01/09
03/31/10
$325,000
$325,000
20126
11311
MIDW
XFR - Colby 69/34.5 kV TrXFR - Colby 115/34.5 kV Transformer Ckt 4
12/31/12
06/01/11
02/14/11
$2,000,000
$2,000,000
DELAY - MITIGATION
20106
11312
MIDW
Line - MIDW Heizer - Mullergren 115kV
12/31/12
06/01/11
08/25/10
$400,000
$507,000
DELAY - MITIGATION
20078
20078
50184
50197
MIDW
MIDW
Device - Kinsley Capacitor 115 kV
Device-Pawnee 115 kV
06/27/12
12/07/12
06/01/11
06/01/11
02/08/10
02/08/10
$907,563
$620,000
COMPLETE
DELAY - MITIGATION
#N/A
#N/A
COMPLETE
200172
50411
MIDW
Multi - Ellsworth - Bushton - Rice 115 kV
09/28/12
06/01/12
04/09/12
$3,351,728
$938,708
COMPLETE
200172
50448
MIDW
07/10/12
06/01/12
04/09/12
$16,107,869
$3,163,676
COMPLETE
50464
MIDW
MULTI - RICE - CIRCLE 230KV CONVERSION
11/07/12
$0
$11,156,686
ON SCHEDULE < 4
50466
50467
MIDW
MIDW
LINE - RICE COUNTY - LYONS 115KV
04/01/13
10/01/12
$0
$0
$6,390,000
$2,473,404
ON SCHEDULE < 4
COMPLETE
50511
MIDW
Sub - Wheatland 115 kV
12/31/12
$88,126
ON SCHEDULE < 4
50549
MIDW
06/01/15
20079
10858
MKEC
Line - Pratt - St. John 115 kV rebuild
20067
10994
MKEC
XFR - Medicine Lodge 138/115 kV
#N/A
06/01/12
$0
$1,459,629
Installation will occur after summer peak loads.
Construction underway.
In service as of 6/27/12. Final cost TBD. Original project scope
Original project scope did not contemplate addition of interconnection
This estimate includes the segment from the existing Rice Co.
substation up to the new Rice Co. substation, and on to the new
Date Updated as of 9/14/12. Estimate includes 230/115 sub (minus
xfmr costs) - $10,900,000-2,473,404, Circle 230 line conversion
Updated as of September 2012 prior to construction bid.
Date per executed GIA. Installed cost of 230/115 transformer only.
DELAY - MITIGATION
03/01/14
06/01/13
02/08/10
$9,239,000
$15,582,071
DELAY - MITIGATION
02/01/13
01/01/10
01/13/10
$5,625,000
$8,627,726
DELAY - MITIGATION
20067
11200
MKEC
Line - Clifton - Greenleaf 115 kV
01/31/13
06/01/11
01/13/10
$3,600,000
$6,063,189
DELAY - MITIGATION
20067
20067
20067
11201
11202
11203
MKEC
MKEC
MKEC
Line - Flatridge - Medicine Lodge 138 kV
Line - Flatridge - Harper 138 kV
Line - Medicine Lodge - Pratt 115 kV
12/31/13
06/15/13
06/15/14
01/01/10
01/01/10
01/01/10
01/13/10
01/13/10
01/13/10
$2,012,500
$6,037,500
$6,500,000
$4,004,423
$11,048,967
$11,277,390
DELAY - MITIGATION
DELAY - MITIGATION
DELAY - MITIGATION
20107
11323
MKEC
Line - Heizer - Mullergren 115kV
20107
20119
20007
20107
11342
11440
50104
50337
MKEC
MKEC
MKEC
MKEC
Line - Greenleaf - Knob Hill 115kV Ckt 1
PRATT - ST JOHN 115 KV CKT 1
Device - Plainville Cap 115 kV
Line - Jewell - Smith Center 115kV Ckt 1
200173
50396
MKEC
200173
50409
MKEC
200173
200173
50410
50449
*
Project timing anticipated to coordinate with MKEC construction of
115 kV line to Ellsworth. Initial cost estimate based on conceptual
design; detailed design to be completed at a later date. Note AFUDC
included in this updated estimate. (Midwest is not required to submit
an interim mitigation for this project since MKEC's system needs this
project for its reliability.)
99% COMPLETE - 2 spans remain & interconnect into River Road
Substation
On schedule for indicated In-Service date
12/31/12
06/01/11
08/25/10
$750,000
$771,129
01/31/13
03/01/14
03/01/13
06/01/18
06/01/13
06/01/11
06/01/12
06/01/18
08/25/10
12/09/10
02/13/08
08/25/10
$5,887,242
$100,000
$0
$60,000
$5,354,646
$100,000
$1,500,000
$150,000
DELAY - MITIGATION
ON SCHEDULE < 4
DELAY - MITIGATION
DELAY - MITIGATION
ON SCHEDULE > 4
Line - Haggard - Ingalls 115 kV Ckt 1
06/01/15
06/01/12
04/09/12
$12,530,103
$23,377,556
DELAY - MITIGATION
SPP notified Sunflower that NTC will be withdrawn
06/01/15
06/01/12
04/09/12
$13,151,512
$13,151,512
DELAY - MITIGATION
MKEC
MKEC
06/01/15
06/01/15
06/01/12
06/01/12
04/09/12
04/09/12
$5,914,221
$2,669,385
$5,914,221
$2,669,385
50508
MKEC
GEN-2008-079 POI
05/21/12
$0
$665,522
DELAY
DELAY
ON SCHEDULE < 4
50509
50510
MKEC
MKEC
Line - Ft Dodge - N Ft. Dodge - Spearville CKT 2
XFR - Spearville 345/115kV CKT 1
11/08/14
11/08/14
$0
$0
$15,389,639
$19,612,658
ON SCHEDULE < 4
ON SCHEDULE < 4
*
*
MITIGATION*
MITIGATION*
20080
10986
NPPD
Line - Maloney - North Platte 115 kV
06/01/12
06/01/12
02/08/10
$2,000,000
$1,749,395
COMPLETE
200170
11078
NPPD
Line - Albion - Genoa 115 kV
06/01/14
06/01/14
04/09/12
$1,240,000
$1,240,000
ON SCHEDULE < 4
20080
11079
NPPD
Line - Albion - Spalding 115 kV
06/01/13
06/01/13
02/08/10
$1,000,000
$1,977,010
ON SCHEDULE < 4
20080
11080
NPPD
Line - Loup City - North Loup 115 kV
06/01/12
06/01/12
02/08/10
$1,000,000
$1,828,267
COMPLETE
20080
20117
NPPD
NPPD
NPPD
NPPD
Line - Twin Church - S. Sioux City 115 kV
Line - Canaday - Lexington 115Kv Ckt 1
Device - Oneill 69 kV
Device - Petersburg North 115 kV
Zonal - Sponsored
12/01/12
06/01/13
06/01/12
06/01/11
06/01/12
12/01/10
11/01/12
11/01/12
02/08/10
12/09/10
20080
11151
11438
50206
50207
02/08/10
$33,000,000
$3,500,000
$0
$0
$34,874,505
$3,500,000
$364,500
$429,332
DELAY - MITIGATION
DELAY - MITIGATION
COMPLETE
COMPLETE
20080
50208
NPPD
Device - Clarks 115 kV
11/01/12
02/08/10
$0
$700,000
DELAY - MITIGATION
20080
50209
NPPD
Device - Ainsworth 115 kV
11/01/12
02/08/10
$0
$50,000
DELAY - MITIGATION
20080
50210
NPPD
Device - Oneill 115 kV
11/01/12
02/08/10
$0
$700,000
DELAY - MITIGATION
20080
50211
NPPD
Device - Valentine 115 kV
06/01/11
06/01/11
02/08/10
$0
$630,255
COMPLETE
20080
50213
NPPD
Device - Gordon 115 kV
06/01/12
06/01/13
02/08/10
$0
$673,574
COMPLETE
20080
200170
20117
20127
200170
50248
50249
50319
50320
50400
NPPD
NPPD
NPPD
NPPD
NPPD
Device - Kearney 115 kV
Device - Holdrege 115 kV
XFR - Ogallala 230/115kV Replacement
Multi - Stegall 345/230 kV Transformer Ckt 2
Multi - Stegall 345/230 kV Transformer Ckt 2
06/01/12
06/01/14
06/01/14
06/01/15
06/01/15
06/01/12
06/01/14
06/01/10
06/01/15
06/01/15
02/08/10
04/09/12
12/09/10
02/14/11
04/09/12
$0
$1,193,000
$5,000,000
$8,000,000
$5,239,000
$786,495
$1,193,000
$5,645,881
$8,000,000
$5,239,000
COMPLETE
ON SCHEDULE < 4
DELAY - MITIGATION
ON SCHEDULE < 4
ON SCHEDULE < 4
200186
50440
NPPD
Multi - Hoskins - Neligh 345 kV
ITP10
03/01/19
03/01/19
04/09/12
$61,205,000
$61,205,000
ON SCHEDULE > 4
$364,898
SEPC Portion ONLY. On schedule for indicated In-Service date
Going to be done as part of project 653. On schedule for indicated InOn schedule for indicated In-Service date
This is an Option to Build LGIA. This cost is only for MKEC's part.
Sunflower's Consultant (Power Engineers) is confirming dollars to the
Sunflower's Consultant (Power Engineers) is confirming dollars to the
Network upgrade complete. Awaiting project close-out to determine
final cost.
Substation terminal work will be completed by 6/1/2013, and is being
Network upgrade complete. Awaiting project close-out to determine
final cost.
Project delayed to Fall 2012 due to load forecast changes. Project
Post-contingency loading issues on this line would be managed
Project Complete.
NPPD has suspended the project. Mitigation plan not required due to
load delay.
load delay.
load delay.
Project Complete. Awaiting project close out to determine final cost.
Project requires the re-termination of Transmission Line 1242 to allow
Project is on schedule according to the in-service date listed on the
This estimate will include 8 crossings of other lines. This estimate
Estimate includes expansion of Hoskins Substation to accommodate
new Neligh 345 kV Terminal. Also includes cost to swap the line bay
200186
50441
NPPD
Multi - Hoskins - Neligh 345 kV
ITP10
03/01/19
03/01/19
04/09/12
$35,497,400
$35,497,400
ON SCHEDULE > 4
200186
50442
NPPD
Multi - Gentleman - Cherry - Holt 345 kV
ITP10
01/01/18
01/01/18
04/09/12
$92,660,000
$92,660,000
ON SCHEDULE > 4
200186
200186
50443
50444
NPPD
NPPD
ITP10
ITP10
01/01/18
01/01/18
01/01/18
01/01/18
04/09/12
04/09/12
$1,380,000
$6,000,000
$1,380,000
$6,000,000
ON SCHEDULE > 4
ON SCHEDULE > 4
200186
50445
NPPD
ITP10
01/01/18
01/01/18
04/09/12
$172,360,000
$172,360,000
ON SCHEDULE > 4
200186
50446
NPPD
ITP10
01/01/18
01/01/18
04/09/12
$16,880,000
$16,880,000
ON SCHEDULE > 4
50469
NPPD
XFR - Cooper 345/161 kV Ckt 2
Zonal - Sponsored
04/01/12
$0
$9,000,000
ON SCHEDULE < 4
10300
OGE
Line - Fort Smith - Colony 161 kV 2
06/01/13
06/01/13
02/08/10
$2,500,000
$2,100,000
ON SCHEDULE < 4
10391
OGE
Line - Razorback - Short Mountain 161 kV
Zonal - Sponsored
01/19/11
$0
COMPLETE
10392
OGE
Zonal - Sponsored
12/19/11
$0
COMPLETE
10393
10394
10395
10396
10398
10400
OGE
OGE
OGE
OGE
OGE
OGE
Zonal - Sponsored
Zonal - Sponsored
Zonal - Sponsored
Zonal - Sponsored
Zonal - Sponsored
Zonal - Sponsored
02/28/11
12/19/11
02/10/11
12/19/11
03/31/11
08/18/11
$0
$0
$0
$0
$0
$0
COMPLETE
COMPLETE
COMPLETE
COMPLETE
COMPLETE
COMPLETE
20081
20002
$32,975,000
11334
OGE
Zonal - Sponsored
04/01/11
$0
COMPLETE
11335
OGE
Zonal - Sponsored
04/01/11
$0
COMPLETE
11336
OGE
Zonal - Sponsored
04/01/11
$0
COMPLETE
10514
OGE
Breaker - Bodle 138 kV
01/15/11
06/01/12
02/13/08
$1,000,000
$850,000
20002
10663
OGE
Line - HSL East - HSL West 69 kV
06/01/16
06/01/16
02/13/08
$250,000
$250,000
20055
20081
10668
10701
OGE
OGE
Line - Rose Hill - Sooner 345 kV (OGE)
Multi - Johnson - Massard 161 kV
06/01/12
12/28/12
06/01/12
06/01/12
09/18/09
02/08/10
$45,000,000
$44,700,000
20081
10837
OGE
Multi - Johnson - Massard 161 kV
09/01/12
06/01/12
02/08/10
$8,700,000
COMPLETE
DELAY - MITIGATION
DELAY - MITIGATION
OGE
Multi - Johnston County Project
Zonal - Sponsored
06/01/11
$0
10732
10733
10734
10735
OGE
OGE
OGE
OGE
Multi - Johnston County
Project
Project
Project
Project
Zonal - Sponsored
Zonal - Sponsored
Zonal - Sponsored
Zonal - Sponsored
06/01/11
06/01/11
06/01/11
06/01/11
$0
$0
$0
$0
10820
OGE
Zonal - Sponsored
06/01/11
$0
COMPLETE
10821
OGE
Zonal - Sponsored
06/01/11
$0
COMPLETE
10747
OGE
Multi - Arcadia Tap - Round Barn Sub
Zonal - Sponsored
07/01/12
$0
COMPLETE
OGE
Multi - Arcadia Tap - Round Barn Sub
Zonal - Sponsored
07/01/12
$0
10792
OGE
Multi: Dover-Twin Lake-Crescent-Cottonwood conversion 138 kV
06/01/14
06/01/10
01/27/09
$27,069,913
COMPLETE
COMPLETE
COMPLETE
COMPLETE
06/01/13
06/01/13
01/27/09
$10,000
$10,000
06/01/12
06/01/15
08/25/10
$13,500,000
$10,900,000
$6,330,000
NOTE: Initial costs include distribution
Original Costs included distribution
Original Costs included distribution. Cost of entire project reflected
on UID 10701
Multi-upgrade project for new arc furnance near Arbuckle (on upgrade
in device tab - Cap bank at Madill)
NOTE:
Initial costs include distribution
O
ON SCHEDULE < 4
$8,100,000
DELAY - MITIGATION
20029
10843
OGE
Line - Kilgore - VBI 69 kV
20110
10876
OGE
XFR - 3rd Arcadia 345/138 kV
200198
11129
OGE
Multi - Cushing Area 138 kV
06/01/14
11/20/12
NTC - COMMITMENT WINDOW
200198
11130
OGE
06/01/14
11/20/12
200198
11131
OGE
06/01/14
11/20/12
200198
11132
OGE
06/01/14
11/20/12
ON SCHEDULE < 4
COMPLETE
$15,000,000
ON SCHEDULE < 4
10748
$5,404,250
COMPLETE
10731
$31,683,453
ON SCHEDULE < 4
$6,200,000
$1,900,000
20029
$695,395
This option creates a new 345/115 kV Substation east of Neligh, as
there is not adequate space to add a 345 kV section at the existing
This is one of multiple components of the "rPLAN" project cost;
Component 2 of 8. (Estimate includes 2 line reactors, 1 each for GGS
This is one of the multiple components of the "rPLAN" project cost;
Component 4 of 8. This cost estimate includes 2 line reactors, 1 for
345 kV Cherry County terminal and 1 for 345 kV Holt County terminal.
Component 5 of 8, (Line Reactor costs are included in the Cherry
County-Holt County 345kV Line and Holt County-Hokins Line - one
$15,000,000
200198
11133
OGE
03/01/13
11/20/12
200198
11134
OGE
03/01/13
11/20/12
Revised cost estimate due to a delay in the project in service date.
Distribution costs were removed from the estimate as well.
Majority of project is removal only
Cost estimated reduced due to lower material costs and no
scheduling issues occurred with project
Original costs included distribution capital assets. New cost does
not. Also 69 kV GOAB switch replaced by a 138 kV GOAB switch on
another project. Total cost of project including distribution assets is
$18,400,000
$18,400,000
$18,400,000
200198
20081
20110
20110
50594
OGE
03/01/13
11/20/12
06/01/10
02/08/10
11182
OGE
Sub - Canadian River Substation
02/15/13
$5,500,000
$7,100,000
11188
11189
OGE
OGE
Multi - Keystone West - Bell Cow - Warwick 138 kV Ckt 1
Multi - Keystone West - Bell Cow - Warwick 138 kV Ckt 1
Zonal - Sponsored
Zonal - Sponsored
05/30/11
05/30/11
$0
$0
$14,665,000
$12,494,000
COMPLETE
COMPLETE
11190
OGE
Line - Stonewall - Remington Park 138 kV
Zonal - Sponsored
04/01/11
$0
$1,300,000
$1,539,871
COMPLETE
11191
OGE
Multi - 36 & Meridian - WRAirport - Pennsylvania 138 kV Ckt 1
Zonal - Sponsored
06/01/12
$0
$510,000
11192
OGE
Multi - 36 & Meridian - WRAirport - Pennsylvania 138 kV Ckt 1
Zonal - Sponsored
06/01/12
$0
11207
OGE
Line - Bryant - Memorial 138 kV
06/01/19
11228
OGE
Line - Cushing - Pumping Station 32 138 kV
Zonal - Sponsored
03/01/13
11343
OGE
Line - Arcadia - Redbud 345 kV Ckt 3
06/01/19
06/01/19
06/01/19
08/25/10
08/25/10
DELAY - MITIGATION
Cost increase is partially due to location of site of new substation
COMPLETE
Transmission assets associated with project - Costs are still being
compiled
COMPLETE
Transmission assets associated with project - Costs are still being
compiled
$250,000
$225,000
ON SCHEDULE > 4
$0
$6,700,000
ON SCHEDULE < 4
$19,000,000
$18,000,000
ON SCHEDULE > 4
20128
11439
OGE
Line - OGE Alva - WFEC Alva 69 kV Ckt 1
07/15/12
06/01/11
02/14/11
$112,500
$392,000
20137
200174
11496
50098
OGE
OGE
XFR - Northwest 345/138 kV Ckt 3
Device - Kolache 69 kV Capacitor
06/01/17
07/15/13
06/01/17
06/01/12
05/27/11
04/09/12
$15,000,000
$523,888
$15,000,000
$523,888
COMPLETE
20017
50166
OGE
Line - Ardmore - Rocky Point 69 kV
06/01/11
06/01/11
01/16/09
$1,627,500
$1,400,000
20017
50167
OGE
Line - Dillard - Healdton Tap 138 kV
06/01/11
06/01/11
01/16/09
$300,000
$300,000
20017
50168
OGE
XFR - Ft Smith 500/161 kV Ckt 3
06/01/17
06/01/17
01/16/09
$11,000,000
$14,000,000
ON SCHEDULE > 4
20017
50169
OGE
Multi - Hugo - Sunnyside 345 kV (OGE)
04/01/12
04/01/12
01/16/09
$75,000,000
$157,000,000
COMPLETE
20017
20017
20017
200174
50170
50171
50172
50346
OGE
OGE
OGE
OGE
Line - Sunnyside - Uniroyal 138 kV
Multi - Hugo - Sunnyside 345 kV (OGE)
Line - VBI - VBI North 69 kV
XFR - Paoli 138/69 kV
06/01/11
04/01/12
06/01/17
05/10/13
06/01/11
04/01/12
06/01/17
06/01/12
01/16/09
01/16/09
01/16/09
04/09/12
$50,000
$6,750,000
$100,000
$2,020,094
$50,000
12/01/11
Customer driven in-service date delayed - New in-service date - Costs
In-service delay due to material delivery
ON SCHEDULE > 4
DELAY - MITIGATION
$983,224
COMPLETE
COMPLETE
Full BPF - Scope of project was reduced - Rebuilt fewer miles Portion of reported cost is distribution.
Full BPF Handled on O&M
Full BPF
20128
50347
OGE
Device - Little
Little River
River Lake 69 kV
200164
50385
OGE
Line - Gracemont 138kV line terminal addition
200174
50408
OGE
Device - Lula 69 kV
200185
50419
OGE
200185
200185
200185
200185
200194
200194
20105
50420
50421
50456
50458
50461
50577
50585
11262
OGE
OGE
OGE
OGE
OGE
OGE
OGE
OMPA
Multi - Woodward EHV - Tatonga - Matthewson - Cimarron 345 kV
SUB - SHIDLER 138KV OG&E Osage Sub work
Line - El Reno - Service PL El Reno 69 kV CKT 1
XFR - Northwest 345/138 kV transformer CKT 3 accelerated
Line - Arcadia - OMPA Edmond Garber 138 kV Ckt 1
20082
10924
OPPD
Multi - S1341 161 kV
20082
20082
10925
10926
11001
11002
10275
10214
OPPD
OPPD
OPPD
OPPD
Rayburn
SEPC
Line - Rebuild 902-983
Line - Sub 1221 - Sub 1255 161 kV
Line - Ben Wheeler - Barton's Chapel (Rayburn) 138 kV Ckt 1
Line - Phillipsburg - Rhoades 115 kV Ckt 1
Regional
Reliability
10/01/12
10/15/11
06/01/13
06/01/12
04/09/12
ITP10
03/01/18
03/01/18
04/09/12
ITP10
ITP10
ITP10
ITP10
03/01/21
03/01/21
03/01/21
03/01/21
02/14/13
06/01/17
03/01/21
03/01/21
03/01/21
03/01/21
04/09/12
04/09/12
04/09/12
04/09/12
06/01/12
06/01/17
06/01/12
06/01/10
11/20/12
11/20/12
08/25/10
$71,876,622
$82,139,900
$32,780,617
$20,169,602
$0
$10,000
$2,260,299
$30,000
09/13/11
12/31/11
02/08/10
Zonal - Sponsored
Zonal - Sponsored
Zonal - Sponsored
09/13/11
09/13/11
01/28/11
11/10/12
04/30/12
07/01/11
12/31/11
12/31/11
02/08/10
02/08/10
$74,982
$100,000
$2,090,660
02/14/11
$0
$352,350
08/02/11
$871,896
$871,896
COMPLETE
$377,797
$377,797
DELAY - MITIGATION
$75,486,000
$75,486,000
ON SCHEDULE > 4
$71,876,622
$82,139,900
$32,780,617
$20,169,602
$399,000
$10,000
$2,260,299
$30,000
ON SCHEDULE > 4
ON SCHEDULE > 4
ON SCHEDULE > 4
ON SCHEDULE > 4
ON SCHEDULE < 4
DELAY - MITIGATION
COMPLETE
$3,000,000 reduction due to better cost information
Project was performed on holiday at customer's request
Full BPF
Full BPF - Reviewing metering CT - May be able to increase rating to
Expect to meet schedule. Project is complete.
Final Cost Still being compiled
OG&E will construct the east half of the ~93 miles of 345kv line and
complete the substation work at Gracemont Substation which will
It is assumed that the Woodward District EHV upgrade will be
It is assumed that a terminal space is available at Tatonga. This
It is assumed that Cimarron will be converted to a breaker and one
It is assumed that Cimarron will be converted to a breaker and one
Cost of OG&E portion of project in Osage Sub
COMPLETE
$16,300,000
$0
$0
$0
$0
11/10/12
$522,000
COMPLETE
COMPLETE
ON SCHEDULE > 4
DELAY - MITIGATION
$16,987,625
$7,617,744
$2,900,000
$675,523
$4,218,750
$9,929,844
COMPLETE
COMPLETE
COMPLETE
ON SCHEDULE < 4
ON SCHEDULE < 4
COMPLETE
20007
10215
SEPC
Line - Holcomb - Plymell 115 kV
06/01/12
06/01/08
02/13/08
$1,980,000
$3,986,076
COMPLETE
20014
20138
20083
10480
11195
50246
SEPC
SEPC
SEPC
Line - Plymell - Pioneer Tap 115 kV
Line - Holcomb - Fletcher 115 kV Ckt 1
Device - Johnson Corner 115 kV Capacitor
06/01/12
12/31/13
05/23/12
06/01/09
06/01/13
06/01/10
09/18/08
05/27/11
02/08/10
$2,380,000
$4,000,000
$0
$5,534,364
$6,025,790
$740,000
COMPLETE
DELAY - MITIGATION
COMPLETE
20083
50247
SEPC
Device - Johnson Corner 115 kV 2nd Capacitor
05/23/12
06/01/11
02/08/10
$0
$370,000
200166
20004
20004
20031
10195
10200
10201
10326
SPS
SPS
SPS
SPS
XFR - Tuco 115/69 kV Transformer Ckt 3
Multi - Hitchland - Texas Co. 230 kV and 115 kV
06/01/14
05/20/11
05/20/11
06/08/12
06/01/12
06/01/08
06/01/09
06/01/10
04/09/12
02/13/08
02/13/08
01/27/09
$2,917,852
$3,450,000
$3,780,000
$16,094,371
$2,633,003
$5,132,829
$31,915,701
$36,926,444
COMPLETE
$973,612
$9,329,355
20004
10327
SPS
05/20/11
04/01/09
02/13/08
$8,400,000
$12,577,500
$6,219,570
COMPLETE
20004
10328
SPS
05/20/11
06/01/09
02/13/08
$3,450,000
$15,848,000
$7,606,406
COMPLETE
20084
10329
SPS
05/20/11
06/01/09
02/08/10
$10,771,825
$14,524,255
$14,524,255
COMPLETE
DELAY - MITIGATION
COMPLETE
COMPLETE
COMPLETE
The purpose of this project is to address maintenance-related issues,
Rayburn Country Project. Rayburn confirm project In Service Date is
COMPLETE - Project in Service, final financials are in progress.
COMPLETE - Project in Service, final closeout Letter to SPP in
progress.
progress.
Estimate does not include breaker and a half expansion of the 115kV
This line was formally circuit T-88 and now re configured in & out of
This is the final cost of the 230/115 kV portion of the Hitchland
This project will be placed in-service the week of June 4, 2012. Q4This is the final cost of the 345 kV portion of the Hitchland substation.
The total cost of the Hitchland substation was $15,548,925. Q4-2012
This line was formally V-30 and now re configured in & out of
The line from Dallam to Sherman is currently in-service. The current
cost estimate amount was changed to the original NTC cost amount
20111
10330
SPS
02/01/13
06/01/09
08/09/10
$19,687,500
$18,712,349
DELAY - MITIGATION
20111
10331
SPS
02/01/13
06/01/09
08/09/10
$1,500,000
$7,812,964
DELAY - MITIGATION
10407
SPS
Line - Roosevelt County Interchange 115 kV - Curry County Interchang
Regional reliability
10/01/10
06/01/15
$0
$200,000
10597
SPS
Line - Curry - Bailey 115kV
06/01/15
06/01/12
04/09/12
$9,132,270
$35,099,588
200166
COMPLETE
DELAY - MITIGATION
20031
10704
SPS
Multi: Dallam - Channing - Tascosa -Potter
08/10/11
06/01/09
01/27/09
$27,452,677
$16,665,675
20031
10705
SPS
06/01/12
06/01/09
01/27/09
$0
$9,130,978
$9,130,978
COMPLETE
COMPLETE
$3,102,202
DELAY - MITIGATION
20031
10757
SPS
Line - Ocotillo sub conversion 115 kV
02/28/12
06/01/09
01/27/09
$3,375,000
$3,175,596
20004
10800
SPS
Multi - Wheeler County Project - Tap 230 kV line - Two new XFs - new
06/01/10
06/01/08
02/13/08
$0
$2,000,000
20031
10822
SPS
Multi: Legacy Interchange 69 kV Tap - 115/69 transformer -2 new lines
08/18/11
06/01/09
01/27/09
$10,406,250
$4,646,250
$4,676,493
COMPLETE
20031
20031
20031
20031
20031
20031
20031
20130
20130
20084
20084
20084
10823
10824
10825
10826
10827
10828
10829
11007
11009
11019
11020
11021
SPS
SPS
SPS
SPS
SPS
SPS
SPS
SPS
SPS
SPS
SPS
SPS
Multi: Eagle Creek 115 and 69 kV Taps - 116/69 XF - 3 new lines
Line - Chaves Co - Roswell Int 69/115 kV Voltage Conversion
XFR - Happy County 115/69 kV Transformers
XFR - Happy County 115/69 kV Transformers
Multi - Cherry Sub add 230kV source and 115 kV Hastings Conversion
07/29/11
07/29/11
06/22/11
06/16/11
06/16/11
12/31/13
06/01/13
06/01/14
06/01/14
12/30/13
06/30/13
06/30/13
06/01/09
06/01/09
06/01/09
06/01/09
06/01/09
06/01/09
06/01/09
06/01/12
06/01/12
06/01/10
06/01/10
06/01/10
01/27/09
01/27/09
01/27/09
01/27/09
01/27/09
01/27/09
01/27/09
02/14/11
02/14/11
02/08/10
02/08/10
02/08/10
$0
$0
$5,197,500
$0
$0
$0
$4,716,000
$1,890,000
$1,890,000
$112,500
$4,905,000
$5,062,500
$2,514,338
$2,875,000
$4,727,194
$325,538
$335,417
$2,000,000
$7,000,000
$2,400,000
$2,400,000
$679,000
$8,515,623
$5,062,500
$2,790,800
$3,348,949
$4,727,194
$450,538
$335,417
COMPLETE
COMPLETE
COMPLETE
COMPLETE
COMPLETE
DELAY - MITIGATION
DELAY - MITIGATION
DELAY - MITIGATION
DELAY - MITIGATION
DELAY - MITIGATION
DELAY - MITIGATION
DELAY - MITIGATION
20084
11023
SPS
12/31/13
06/01/10
02/08/10
$1,700,000
$1,700,000
DELAY - MITIGATION
DELAY - MITIGATION
20084
11029
SPS
Line - Maddox - Sanger SW 115 kV
05/31/12
06/01/10
02/08/10
$3,000,000
$330,957
DELAY - MITIGATION
20084
11033
SPS
XFR - Install 2nd Randall 230/115 kV transformer
04/30/13
06/01/10
02/08/10
$11,250,000
$7,357,000
DELAY - MITIGATION
20084
11036
SPS
Line - Maddox Station - Monument 115 kV Ckt 1
11/30/12
06/01/11
02/08/10
$1,417,500
$1,701,000
DELAY - MITIGATION
20084
11038
SPS
Line - Brasher Tap - Roswell Interchange 115 kV
12/31/13
06/01/12
02/08/10
$114,000
$289,000
DELAY - MITIGATION
20084
11040
SPS
Multi - New Hart Interchange 230/115 kV
04/30/15
06/01/10
02/08/10
$11,250,000
$11,980,445
DELAY - MITIGATION
20084
11041
SPS
04/30/15
06/01/10
02/08/10
$16,031,250
$13,464,382
DELAY - MITIGATION
20084
11042
SPS
04/30/15
06/01/10
02/08/10
$10,125,000
$15,086,485
DELAY - MITIGATION
20084
11043
SPS
04/30/15
06/01/10
02/08/10
$13,500,000
$15,632,544
DELAY - MITIGATION
20084
11044
SPS
04/30/15
06/01/10
02/08/10
$2,250,000
$2,010,780
DELAY - MITIGATION
DELAY - MITIGATION
20084
11045
SPS
04/30/15
06/01/10
02/08/10
$8,438,000
$13,266,452
20130
11046
SPS
Line - Cunningham - Buckey Tap 115 kV reconductor
06/01/13
06/01/13
02/14/11
$3,607,000
$3,607,000
ON SCHEDULE < 4
20084
11052
SPS
Multi - Pleasant Hill- Potter 345 kV Ckt 1
12/30/14
06/01/11
02/08/10
$11,250,000
$19,349,122
DELAY - MITIGATION
20084
11053
SPS
12/30/14
06/01/11
02/08/10
$13,500,000
$14,805,472
20084
11054
SPS
12/30/14
06/01/11
02/08/10
$21,937,500
$20,612,670
*
*
DELAY - MITIGATION*
200166
11067
SPS
Multi - Bowers - Howard 115 kV Ckt 1
06/01/16
06/01/16
04/09/12
$4,120,585
$2,980,329
ON SCHEDULE > 4
DELAY MITIGATION
20084
11096
SPS
XFR - Kingsmill 115/69 kV Ckt 2
05/31/13
06/01/11
02/08/10
$1,935,000
$5,200,000
DELAY - MITIGATION
20130
11100
SPS
XFR - Northeast Hereford 115/69 kV Transformer Ckt 2
06/01/14
06/01/11
02/14/11
$1,890,000
$2,000,000
DELAY - MITIGATION
20084
11101
SPS
Line - Portales - Zodiac 69 kV to 115 kV Conversion
06/01/14
06/01/13
02/08/10
$3,487,500
$5,000,000
DELAY - MITIGATION
20088
11102
SPS
Multi - Move Load from East Clovis 69 kV to East Clovis 115 kV
06/01/14
06/01/14
05/07/10
$2,500,000
$2,500,000
ON SCHEDULE < 4
The estimated ISD is 02/01/2013. Q4-2012 Cost Estimate updated.
MN-9/19/12. Q1-2013 Cost estimate updated. TA 11/15/12
This large project is underway and portions of this project will be
complete after the Summer of 2009. The estimated ISD is 2/1/2013.
Q4-2012 Cost Estimate updated. MN-9/19/12. Q11-2013 Cost
estimate updated TA 11/15/12
Will need additional study
Assumes relay replacements are required at remote ends of Bailey
and Curry substations. Escalation included in the Contingency cost.
Contingency - $3,871,763; Escalation $2,774,325. Q4-2012 Cost
Estimate remains valid. MN-9/19/12. Mitigation plan submitted. 9/28/12 MN. Q1-2013 All costs remain valid. TA 11/15/12
Project is in-service but all associated costs are not yet final. Should
have final cost in 2nd quarter report.Q4-2012 Cost Estimate updated.
This line goes from Channing to Potter and does not go in and out of
Tascasa sub. Tascosa is served by a 34.5 kV line from Channing
Q4-2012 Current Cost Estimate and final costs remain valid. MN9/19/12. Q1-2013 All Costs remain valid. TA-11/15/12
The earliest that any portion of the Wheeler County Interchange
project can be in-service will be 6/1/2010. NTC should be modified to
This project is the fix for the Gaines Co. Auto STEP project. Q4-2012
final costs updated. MN-9/19/12. Q1-2013 Final costs updated.
Q4-2012 Cost Estimate updated. MN-9/19/12. Q1-2013 Cost Estimate
Q4-2012 Current Cost Estimate remains valid. MN-9/19/12. Q1-2013
Q4-2012 Current Cost Estimate remains valid. MN-9/19/12. Q1-2013
Mitigation will not be needed. The 115 kV potion of this project is 100
This project is the replacement for adding a 3rd XF at the Roswell
Alternative 1: Swap Swisher Co-op load onto Kress Interchange, bus
Alternative 1: Swap Swisher Co-op load onto Kress Interchange, bus
Mitigation plan has been provided to and accepted by SPP for this
project. Q4-2012 updated ISD: current cost estimate remains valid.
Project has scope change from reconductor to a wreckout/rebuild due
to structure inability to support upgraded conductor. Q4-2012 Cost
project. Q4-2012 current cost estimate remains valid. MN 9/19/12. Q1Mitigation plan has been provided to and accepted by SPP for this
project. Q4-2012 updated ISD: current cost estimate remains valid.
MN-9/19/12.
/ /
Mitigation plan entered into TAGIT/SCERT
G /SC
system 9/28/12 MN. Q1-2013 Current cost updated. TA 11/15/12.
Mitigation will not be needed for this line. Using the newest model,
2012MDWGB1_FINAL-13S.sav, the Chaves to Urton contingency will
project.Q$-2012 current cost estimate remains valid. MN 9/19/12. Q1Mitigation plan has been provided to and accepted by SPP for this
project.Q4-2012 Cost Estimate updated. MN-9/19/12. Q1-2013 Costs
project.Q4-2012 Cost Estimate updated. MN-9/19/12. Q1-2013 All
Q4-2012 current cost estimate remains valid. MN-9/19/12. Q1-2013
All costs remain valid. TA 11//15/12
project. Q4-2012 Cost Estimate remains valid. MN-9/19/12. Q1-2013
All cost remain valid. TA 11/15/12
This line will go from Newhart to Lampton. There will be a tap from
this line to Hart Industrial sub, not an in-and -out. The current cost
Q4-2012 Cost Estimate remains valid. MN-9/17/12; Q1-2013 Cost
Q4-2012 Cost Estimate remains valid. MN-9/19/12. Mitigation plan
updated. 9/28/12; Q1-2013 all remains valid - TA 11/05/2012
Q4-2012 Cost Estimate remains valid. MN-9/19/12. Updated
Q4-2012 Cost Estimate remains valid. MN-9/19/12. Mitigation plan
updated. MN 9/28/12; Q1-2013 All remains valid. TA 11/05/2012
Estimate includes re-routing of the Kingsmill 69kV line to the south
side of the subustation. Assumes Bowers was converted to threeMitigation plan has been provided to and accepted by SPP for this
project. Q4-2012 ISD and Cost Estimate updated. MN-9/19/12.
OPEN 69 kV tie NE-Hereford – Hereford by OPEN Breaker 5704
Q4-2012 updated ISD; Cost Estimate remains valid. MN-9/19/12.
Mitigation information entered. 9/25/12. Q1-2013 Cost estimate
Q4-2012 Cost Estimate remains valid. MN-9/19/12; Q1-2013 All
*
200166
11104
SPS
Sub - Convert Muleshoe East 69 kV to 115 kV
11/28/15
06/01/12
04/09/12
$1,634,119
$2,917,236
200166
200166
11107
11109
SPS
SPS
Multi - Kress Interchange - Kiser - Cox 115 kV
11/30/14
02/28/14
06/01/14
06/01/14
04/09/12
04/09/12
$14,737,500
$7,762,500
$13,856,881
$5,848,405
DELAY - MITIGATION
ON SCHEDULE < 4
20084
11121
SPS
Line - Harrington - Randall County 230 kV
04/30/13
06/01/10
02/08/10
$225,000
$271,440
DELAY - MITIGATION
DELAY - MITIGATION
11128
SPS
06/01/12
$0
$4,500,000
ON SCHEDULE < 4
200166
11173
SPS
XFR - Eddy County 230/115 kV Transformer Ckt 2
06/01/14
06/01/14
04/09/12
$6,761,086
$4,863,725
ON SCHEDULE < 4
20084
11177
SPS
Line - Randall - Amarillo S 230 kV Ckt 1
04/30/13
06/01/10
02/08/10
$27,450,000
$18,000,000
DELAY - MITIGATION
200193
20130
11314
11315
SPS
SPS
Line - Jones Station Bus#2 - Lubbock South Interchange 230 kV
Line - Osage Station and Line Re-termination
12/30/14
06/01/15
06/01/13
06/01/16
11/20/12
02/14/11
$345,942
$1,680,000
$345,942
$2,349,200
ON SCHEDULE < 4
20130
11316
SPS
Line - OXY Permian Sub - Sanger SW Station 115 kV Ckt 1 Reconduc
06/01/12
06/01/16
02/14/11
$295,313
$295,313
200166
11317
SPS
XFR - Grassland 230/115 kV Transformer Ckt 1
06/01/15
06/01/15
04/09/12
$3,961,322
$3,914,401
$220,090
Escalation included in contingency costs. Contingency - $329,131;
Escalation - $105,493. Q4-2012 Cost Estimate remains valid. MN-
COMPLETE
20130
11318
SPS
XFR - Swisher 230/115 kV Transformer Ckt 1 Upgrade
06/30/17
06/01/16
02/14/11
$5,953,500
$4,762,800
DELAY - MITIGATION
20130
11319
SPS
Line - Wolford-Yuma 115 kV Ckt 1 Wave Trap
12/31/12
06/01/12
02/14/11
$945,000
$945,000
DELAY - MITIGATION
20118
11321
SPS
06/01/12
06/01/09
11/15/10
$26,043,761
$18,262,290
COMPLETE
11322
SPS
06/01/12
06/01/09
11/15/10
$0
$3,410,040
COMPLETE
20113
11349
SPS
CHERRY - HARRINGTON STATION EAST BUS 230KV CKT 1
12/30/13
06/01/13
12/09/10
$500,000
$500,000
DELAY - MITIGATION
20130
11353
SPS
Convert Lynn load to 115 kV
12/31/13
06/01/12
02/14/11
$100,000
$4,489,314
DELAY - MITIGATION
200166
11358
SPS
Line - Randall - South Georgia 115 kV reconductor
07/31/15
06/01/17
04/09/12
$6,921,313
$3,618,651
ON SCHEDULE < 4
DELAY - MITIGATION
200166
11359
SPS
Line - Hereford - Northeast Hereford 115 kV Ckt 1
06/01/13
06/01/12
04/09/12
$2,362,500
$4,139,406
20130
11372
11374
11378
SPS
SPS
SPS
Line - Soncy convert load to 115 kV
Line - Eagle Creek - Seven Rivers Interchange 115 kV Ckt 1
Zonal - Sponsored
06/01/15
07/31/11
12/30/13
06/01/15
02/14/11
02/14/11
$596,071
$
$12,462,188
$1,771,875
$10,594,373
06/01/13
$500,000
$
$0
$1,771,875
ON SCHEDULE < 4
COMPLETE
DELAY - MITIGATION
11379
SPS
Multi - Randall County Interchange - Palo Duro Sub 115 kV Ckt 1 Reco
Zonal - Sponsored
12/31/11
$0
$5,094,140
$5,094,140
COMPLETE
11380
SPS
Zonal - Sponsored
02/28/12
$0
$10,498,360
$10,498,360
COMPLETE
11381
SPS
Zonal - Sponsored
03/31/12
$0
$3,277,970
$3,277,970
COMPLETE
$4,562,580
20130
11382
SPS
Zonal - Sponsored
04/30/11
$0
$4,562,580
20130
11383
SPS
Line - North Plainview line tap 115 kV
12/31/14
06/01/15
02/14/11
$150,000
$225,000
20130
20130
11384
11388
SPS
SPS
Line - Kress Rural line tap 115 kV
Line - Lighthouse - North Plainview 69 kV Ckt 1
12/31/14
12/31/11
06/01/15
06/01/11
02/14/11
02/14/11
$150,000
$50,000
$200,000
$56,275
20130
11389
SPS
12/31/12
06/01/11
02/14/11
$1,181,400
$1,622,862
DELAY - MITIGATION
11390
SPS
XFR - Deaf Smith 230/115/13.2 kV Auto Ckt 1
Zonal - Sponsored
06/01/13
$0
$4,632,000
ON SCHEDULE < 4
11502
SPS
Multi - Tuco - Stanton 345 kV
200184
ITP10
06/01/18
04/09/12
Q4-2012 updated ISD; Current cost estimate remains valid. MN9/19/12. Mitigation plan submitted - 9/28/12 MN; Current cost
This line goes from Channing to Potter and does not go in and out of
Tascasa sub. Tascosa is served by a 34.5 kV line from Channing
Q4-2012 Updated ISD; Cost Estimate remains valid. MN-9/19/12.
Mitigation plan submitted. 9/28/12 MN; Q1-2013 All remains valid. TA
Alternative 1: CLOSE N.O. tie 6846 Garza, bus 526622. OPEN switch
6736 LG-Central, bus 526666. Alternative 2: CLOSE switch 6745 LS,
The 115kV yard at Randall County Interchange will need to be
converted to a breaker-and-half, which was not included in this
NE Hereford substation 115 kV yard will be converted to ring bus.
Relay upgrades required at Deaf Smith and Hereford Interchange.
Q4-2012 Cost
Estimate updated. MN-9/19/12.
Q1-2013
Cost
Estimate
Q
C
/ /
Q
C
Q4-2012 ISD change. MN-9/17/12; Q1-2013 no changes. TA-
COMPLETE
ON SCHEDULE < 4
$62,154
project. Q4-2012 Cost Estimate remains valid. MN-9/19/12. Q1-2013
Cost estimate updated. TA 11/15/12.
Escalation costs are included in Contingency costs: Contingency:
Q4-2012 Cost Estimate remains valid. MN-9/17/12. Qi-2013 Cost
Q4-2012 Final Costs updated. MN-9/19/12
The existing transformer foundation will be replaced. The existing
equipment ratings are sufficient for this upgrade. Escalation included
ON SCHEDULE < 4
20118
The Valley Substation will be replaced with a 115/13.2kV transformer
which will feed a 13.2/2.4kV transformer at East Muleshoe. Escalation
included in Contingency cost. Contingency - $532,180; Escalation $273,122. Mitigation Plan entered 9/28/12 zt; Q4-2012 Cost Estimate
remains valid. MN-9/19/12. SCERT estimate revised to remove
distribution transformer costs that were erroneously included in
original SCERT estimate. MN-10/15/12. Q1-2013 Costs reman valid.
TA 11/15/12
Cost for Kiser substation included on Network Upgrade ID #50450.
Cost for Kiser substation included on Network Upgrade ID #50450.
project.. Q4-2012 Cost Estimate remains valid. MN-9/19/12. Q1-2013
Cost estimate remains valid. TA 11/15/12
ON SCHEDULE < 4
DELAY - MITIGATION
Q4-2012 updated ISD: Current Cost Estimate remains valid. MN9/19/12. Q1-2013 Cost Estimate increased. TA-11/15/12.
Q4-2012 updated ISD; Current Cost Estimate remains valid. MNMitigation not required for 2011. Future TEMPORARY MITIGATION:
Revised load forecast in the most recent 2011 MDWG Build 2 models
do not show any violations.
ON SCHEDULE > 4
$37,490,796
$37,490,796
200184
11503
SPS
ITP10
06/01/18
04/09/12
200184
11504
SPS
ITP10
06/01/18
04/09/12
200166
11505
SPS
XFR - Spearman 115/69/13.2 Ckt 1 Upgrade
06/30/14
06/01/13
04/09/12
$2,394,495
$2,351,378
200166
50093
SPS
Device - Bushland Interchange 230 kV Capacitor
12/30/13
06/01/12
04/09/12
$1,714,505
$1,714,505
DELAY - MITIGATION
50354
SPS
Device - Norton Reactor 115 kV
Zonal - Sponsored
06/01/13
$0
$1,475,255
ON SCHEDULE < 4
ON SCHEDULE > 4
ON SCHEDULE > 4
200166
50379
SPS
Device - Drinkard 115 kV Capacitor
06/01/15
06/01/15
04/09/12
$2,225,089
$2,225,089
200166
50401
SPS
Device - Crosby 115 kV Capacitor
03/30/14
06/01/12
04/09/12
$985,519
$985,519
DELAY MITIGATION
*
*
ON SCHEDULE < 4
DELAY - MITIGATION
Escalation included in Contingency costs. Contingency - $235,733;
Estimate assumes capacitor banks will be installed off of existing
main 230kV bus. Escalation is included in Contingency costs.
Estimate includes the substation scope and the transmission line
reroute and retermination (Circuit T84). Escalation included in
Contingency costs. Contingency - $178,678; Escalation - $124,206.
estimate remains valid. TA 11/15/12
Bus will be expanded. Will require additional land to the north of the
200166
50402
SPS
Sub - Move lines from Lea Co 230/115 kV sub to Hobbs Interchange 2
200184
50404
SPS
Line - Grassland - Wolfforth 230 kV
200166
200166
50406
50407
SPS
SPS
Multi - Cedar Lake Interchange 115 kV
Multi - Cedar Lake Interchange 115 kV
200184
50447
SPS
Multi - Tuco - Amoco - Hobbs 345 kV
200184
50451
SPS
200184
200184
200166
50452
50457
50450
SPS
SPS
SPS
ITP10
ITP10
200166
50453
SPS
Multi - Bowers - Howard 115 kV Ckt 1
200193
50515
SPS
XFR - Deaf Smith County Interchange 230/115 kV transformer CKT 1
50562
SPS
Line(s) - Harrington - Nichols 230kV DBL CKT
10125
SWPA
10576
Escalation - $307,258. Q4-2012 Cost Estimate remains valid. MN9/19/12. Q1-2013 Cost Estimate remains valid. TA-11/05/12
12/31/13
01/01/14
04/09/12
$8,270,297
$10,608,509
ON SCHEDULE < 4
ITP10
03/01/18
03/01/18
04/09/12
$50,068,309
$50,068,309
ON SCHEDULE > 4
06/30/15
06/30/15
06/01/12
06/01/12
04/09/12
04/09/12
$3,914,970
$6,112,772
$5,524,876
$7,699,644
DELAY - MITIGATION
DELAY - MITIGATION
ITP10
01/01/20
04/09/12
ITP10
01/01/20
04/09/12
02/28/14
01/01/20
01/01/20
06/01/14
04/09/12
04/09/12
04/09/12
$4,500,000
$6,500,705
ON SCHEDULE > 4
ON SCHEDULE > 4
ON SCHEDULE < 4
05/31/14
06/01/16
04/09/12
$13,286,935
$22,577,591
ON SCHEDULE < 4
06/01/12
11/20/12
$4,273,633
$4,273,633
$0
$1,738,502
ON SCHEDULE < 4
04/01/09
$0
$3,000,000
06/01/15
$0
$660,000
ON SCHEDULE < 4
ON SCHEDULE > 4
$181,415,883
$181,415,883
ON SCHEDULE > 4
03/01/15
12/31/12
XFR - Eufaula 161/138 kV
03/30/11
SWPA
Line - Nixa - Nixa DT Rebuild
10645
SWPA
XFR - Springfield 161/69kV #3
06/01/17
06/01/17
$0
$2,250,000
ON SCHEDULE > 4
10741
10819
10836
SWPA
SWPA
SWPA
XFR - Paragould 161/69 kV Auto 1 & 2
Line - Asherville - Idalia 161 kV Reconductor
Line - Asherville - Poplar Bluff 161 kV
11/30/11
06/26/12
06/01/14
12/01/11
06/01/14
06/01/15
$0
$0
$0
$3,150,000
$10,095,750
$4,500,000
COMPLETE
COMPLETE
ON SCHEDULE < 4
10856
SWPA
XFR - Carthage 161/69 kV Transformers 1 & 2
06/01/14
$0
$5,625,000
ON SCHEDULE < 4
10944
SWPA
Line - Dardanelle - Russellville South 161 kV
05/25/11
06/01/10
$0
$165,000
20030
20003
20003
20003
19985
10173
10174
10175
10176
10179
WFEC
WFEC
WFEC
WFEC
WFEC
Multi - Lindsay - Lindsay SW and Bradley-Rush Springs
Line - Meeker - Hammett 138 kV
Line - Wakita - Hazelton 69 kV
Line - OGE Woodward - WFEC Woodward 69 kV
Line - ACME - W Norman 69 kV
12/05/12
12/01/13
12/01/12
12/01/13
12/01/13
06/01/10
06/01/08
04/01/09
04/01/09
06/01/08
01/27/09
02/13/08
02/13/08
02/13/08
02/02/07
$3,577,500
$
$5,250,000
$5,670,000
$0
$0
$2,328,750
$
$6,674,000
$8,000,000
$1,050,000
$912,000
20003
10303
WFEC
Line - Atoka - WFEC Tupelo - Lane 138 kV
06/01/13
06/01/12
02/13/08
20003
20030
10304
10305
WFEC
WFEC
Line - Atoka - WFEC Tupelo - Lane 138 kV
Line - WFEC Snyder - AEP Snyder
06/01/11
03/01/12
06/01/12
06/01/09
02/13/08
01/27/09
$3,373,000
$839,770
20003
10307
WFEC
Line - Anadarko - Georgia Tap 138 kV
12/01/14
06/01/09
02/13/08
$750,000
$2,000,000
DELAY - MITIGATION
20003
10308
WFEC
Line - Elmore - Paoli 69 kV
12/02/14
06/01/09
02/13/08
$3,240,000
$3,240,000
DELAY - MITIGATION
20003
10309
WFEC
Multi - OU SW - Goldsby - Canadian SW 138 kV
12/31/12
06/01/09
02/13/08
$9,087,500
$2,753,800
DELAY - MITIGATION
20003
20003
20003
20003
20003
19951
20003
20003
20003
10310
10311
10401
10402
10403
10467
10471
10519
10520
WFEC
WFEC
WFEC
WFEC
WFEC
WFEC
WFEC
WFEC
WFEC
Multi - Franklin SW - Acme - Norman - OU SW Conversion 138 kV
XFR - Anadarko 138/69 kV
Line - Fletcher - Marlow Jct 69 kV
Line - Lindsay - Wallville 69 kV
Line - Pharoah - Weleetka 138 kV
12/31/12
12/31/12
12/31/14
12/31/13
12/31/15
09/30/12
06/01/14
06/01/15
09/28/12
06/01/09
06/01/09
06/01/10
06/01/10
06/01/10
06/01/11
06/01/11
06/01/12
06/01/12
02/13/08
02/13/08
02/13/08
02/13/08
02/13/08
01/02/07
02/13/08
02/13/08
02/13/08
$0
$0
$3,646,594
$0
$1,577,000
$2,000,000
$2,000,000
$1,347,000
$100,000
$2,250,000
$5,000,000
$2,065,000
$1,601,000
$1,577,000
$2,000,000
$2,000,000
$1,347,000
$225,000
DELAY - MITIGATION
DELAY - MITIGATION
DELAY - MITIGATION
DELAY - MITIGATION
DELAY - MITIGATION
$50,000
20003
10521
WFEC
Line - WFEC Russell - AEP Altus Jct Tap 138 kV
06/01/12
06/01/12
02/13/08
20003
10522
WFEC
Multi - Granfield - Cache SW 138 kV
06/01/13
06/01/12
02/13/08
20003
10523
WFEC
06/01/13
06/01/12
02/13/08
20003
10524
WFEC
06/01/13
06/01/12
02/13/08
The new Sulphur-KC 115kV transmission line has one mile of new
$8,265,000
$18,182,800
$8,265,000
$50,000
The four transmission line estimates are reterminations of existing
Transmission line estimate assumes the existing single circuit Y62
(Bowers to Howard) 69kV circuit will be wrecked out and rebuilt on the
new 115kV as double circuit. This will minimize the impact to
landowners and the Lesser Prairie Chicken. Costs for removing the
existing circuit, installing new conductor and taller structures will be
funded by Xcel Energy ($10.1M). Escalation is included in
Contingency Costs. Contingency - $1,239,528; Escalation $1,848,099. Q4-2012 Cost Estimate remains valid. MN-9/19/12. Q12013 all costs remain valid. TA 11/15/12
Escalation costs are included in Contingency costs: Contingency:
$279,658; Escalation: $164,370
COMPLETE
Project complete. Xfmr 1 was replaced and put in service 3/26/2011.
Should be assigned to City of Carthage
COMPLETE
COMPLETE
DELAY - MITIGATION
DELAY - MITIGATION
DELAY - MITIGATION
DELAY - MITIGATION
COMPLETE
Project is complete
This project is complete and in service.
Temporary op guide provided.
Mitigation Plan under review by SPP. Defered in latest SPP
AEP's station cost is $1.665M. WFEC's construction cost is $6.6M.
An interconnection agreement has been executed between WFEC
and AEP.
COMPLETE
COMPLETE
line converted but energized @ 69kV
line converted but energized @ 69kV
in construction
built at 138kV but energized @ 69kV
built at 138kV but energized @ 69kV
*
DELAY MITIGATION
DELAY - MITIGATION
DELAY - MITIGATION
COMPLETE
COMPLETE
$1,125,000
DELAY - MITIGATION
$7,306,000
DELAY - MITIGATION
$5,000,000
DELAY - MITIGATION
Loading of facility shows mitigation not needed before summer 2015.
Field Verified that Pharoah – Weleetka CT is 800:5 and has thermal
20030
10794
WFEC
Multi: WFEC-Dover-Twin Lake_Cresent-Cottonwood conversion 138 k
12/31/12
06/01/10
01/27/09
$0
$5,765,600
DELAY - MITIGATION
20030
10795
WFEC
12/31/13
06/01/10
01/27/09
$0
$5,315,700
DELAY - MITIGATION
20030
10796
WFEC
12/31/13
06/01/10
01/27/09
$0
$3,164,000
DELAY - MITIGATION
20030
10797
WFEC
12/31/12
06/01/10
01/27/09
$0
$3,937,500
DELAY - MITIGATION
20030
10798
WFEC
Line - Carter Jct-Lake Creek 69 kV
09/15/11
06/01/10
01/27/09
$150,000
$150,000
20030
10799
WFEC
Multi - Lindsay - Lindsay SW and Bradley-Rush Springs
09/01/12
06/01/10
01/27/09
$0
$1,248,750
COMPLETE
20132
10865
WFEC
Line - Reeding - Twin Lakes Switchyard conversion to 138 kV
04/01/13
06/01/12
02/14/11
$1,971,000
$1,971,000
DELAY - MITIGATION
20085
20132
20085
20132
20132
10878
10879
11114
11115
11116
WFEC
WFEC
WFEC
WFEC
WFEC
Line - El Reno - El Reno SW 69 kV
Line - Bradley - Lindsay 69 kV Ckt 1 reconductor
Line - Snyder - Tipton 69 kV CT
Multi - Anadarko - Blanchard - OU SW 138 kV Ckt 1
Multi - Anadarko - Blanchard - OU SW 138 kV Ckt 1
06/01/12
12/31/12
06/01/11
12/01/14
12/01/15
06/01/12
06/01/15
06/01/11
06/01/12
06/01/12
02/08/10
02/14/11
02/08/10
02/14/11
02/14/11
$1,950,000
$3,712,500
$225,000
$14,737,500
$1,125,000
$1,950,000
$3,712,500
$225,000
$14,737,500
$1,125,000
COMPLETE
ON SCHEDULE < 4
COMPLETE
DELAY - MITIGATION
DELAY - MITIGATION
DELAY - MITIGATION
20132
11117
WFEC
Line - Wakita - Nash 69 kV Ckt 1
20114
20114
11350
11351
WFEC
WFEC
ALTUS SW - NAVAJO 69KV CKT 1
G03-05T - PARADISE 138KV CKT 1
20132
11424
WFEC
20132
11429
20030
COMPLETE
Use Dover-Twin Lakes op guide for temporary mitigation
built at 138kV but energized @ 69kV; Use Dover-Twin Lakes op guide
for temporary mitigation
built at 138kV but energized @ 69kV; Use Dover-Twin Lakes op guide
for temporary mitigation
Use Dover-Twin Lakes op guide for temporary mitigation; under
construction
CT's upgraded to 600 amp effective 9/15/11. NO cost for this
construction complete, ready for energization Nov. 20, 2012.
06/01/14
06/01/11
02/14/11
$6,705,000
$6,705,000
06/01/13
06/01/15
06/01/10
06/01/15
12/09/10
12/09/10
$150,000
$150,000
$150,000
$150,000
Line - Alva - Freedom 69 kV Ckt 1
06/01/13
06/01/11
02/14/11
$6,243,750
$6,243,750
WFEC
Line - Criner - Lindsay 69 kV Ckt 1
06/01/13
06/01/11
02/14/11
$50,000
$50,000
DELAY - MITIGATION
50045
WFEC
Device - Esquandale Cap 69 kV
06/01/14
06/01/14
01/27/09
$0
$243,000
ON SCHEDULE < 4
19985
50047
WFEC
Device - Comanche
06/01/12
06/01/12
02/02/07
$0
$350,000
COMPLETE
20003
50050
WFEC
Device - Gypsum Cap 69 kV
06/01/11
04/01/08
02/13/08
$0
$150,000
DELAY - MITIGATION
in construction 95% complete awaiting outage to finish.
Temporary operating guide provided.
COMPLETE
ON SCHEDULE < 4
DELAY - MITIGATION
20003
50085
WFEC
Device - Carter Cap 69 kV
20003
20030
20085
20136
20136
50099
50180
50186
50366
50367
WFEC
WFEC
WFEC
WFEC
WFEC
Device - Latta Cap 138 kV
Device Eagle Chief 69 kV Capacitor
Device - Electra 69 kV Capacitor
Line - Canton - Taloga 69 kV ckt 1
XFR - Taloga 138/69 kV ckt 1
50462
WFEC
20006
20006
19986
20059
20033
50463
10220
10221
10229
10231
10349
WFEC
WR
WR
WR
WR
WR
20086
10350
WR
20086
10351
WR
*
WFEC will move ahead line project: Cache to Grandfield to mitigate
voltage problem. Short term mitigation until line can be built will be
Shed load at Loco Substation (up to 3.5MW in 2007 Summer Peak)
Shed load at Empire Substation (up to 5MW in 2007 Summer Peak).
06/01/12
06/01/10
02/13/08
$0
$324,000
Regional reliability
06/01/12
06/01/10
08/31/12
06/01/13
06/01/13
06/01/12
06/01/09
06/01/11
06/01/11
06/01/11
02/13/08
01/27/09
02/08/10
05/27/11
05/27/11
$0
$0
$0
$4,800,000
$1,000,000
$324,000
$300,000
$240,000
$4,800,000
$1,000,000
COMPLETE
Line - Washita - Gracemont 138 kv ckt 2
10/12/12
$0
$4,740,546
COMPLETE
SUB - SLICK HILLS 138KV
Line - Weaver - Rose Hill 69 kV
Line - Tecumseh Energy Center - Midland 115 kV
Line - Stranger Creek - Thornton Street 115 kV Addition
Line - Chase - White Junction 69 kV
Line - Circle - HEC GT 115 kV Rebuild
02/01/12
01/27/11
06/01/13
02/24/11
06/01/13
03/17/11
06/01/08
06/01/12
06/01/07
06/01/10
06/01/11
02/13/08
02/13/08
02/02/07
09/18/09
01/27/09
$0
$1,350,000
$2,000,000
$2,500,000
$5,184,701
$300,000
$1,500,000
$2,676,185
$5,423,701
$9,206,570
$6,066,000
$1,256,055
COMPLETE
COMPLETE
DELAY - MITIGATION
COMPLETE
DELAY - MITIGATION
COMPLETE
Line - Halstead - Mud Creek Jct. - 69 kV
12/30/11
06/01/11
02/08/10
$2,500,000
$5,718,375
COMPLETE
02/24/12
06/01/11
02/08/10
$360,000
$764,190
COMPLETE
*
DELAY MITIGATION
DELAY - MITIGATION
COMPLETE
DELAY - MITIGATION
DELAY - MITIGATION
$2,627,677
$9,231,495
$1,242,102
20086
10352
WR
05/23/12
06/01/11
02/08/10
$1,300,000
$3,011,613
COMPLETE
20006
10417
WR
Line - Oaklawn - Oliver 69 kV
07/25/12
06/01/10
02/13/08
$483,000
$2,686,996
COMPLETE
200181
10425
WR
XFR - Moundridge 138/115 kV
12/01/14
12/01/14
04/09/12
$12,197,900
$18,063,183
ON SCHEDULE < 4
20140
10487
WR
Line - Creswell - Oak 69 kV Ckt 1
12/31/13
06/01/11
05/27/11
$1,500,000
$1,500,000
DELAY - MITIGATION
19964
10488
WR
XFR - Rose Hill 345/138 kV Ckt 3
06/01/13
06/01/11
06/27/07
$5,000,000
$10,387,399
DELAY - MITIGATION
20086
10603
WR
Line - Gill - Interstate 138 kV
12/01/13
06/01/13
02/08/10
$50,000
$118,341
DELAY - MITIGATION
20033
10638
WR
Line - Jarbalo - Stranger Creek
08/11/11
06/01/10
01/27/09
$8,050,000
$5,228,040
$3,755,915
$4,141,799
Interim redispatch under service agreement
Interim redispatch under service agreement
O
In service date expected around October
12, 2012. Percent
completion of construction is 80 – 85% to date. We lack connecting
on both ends
Redispatch TEC generation.
In-Service - Cost Not Final
Interim mitigation is application of existing Transmission Operating
UVLS operational in Newton Division. Adjustment of CTs at Halstead
and Newton to increase line rating is interim mitigation.
The mitigation is to open the Halstead-Burrton 69 kV line and close
the Burrton line to Yoder Junction and switch Burrton load to be
served from Hutchinson.
Substation Scope: Install 2nd 138/115 Transformer at Moundridge.
The substation will be reconfigured to allow installation of a 2nd
138/115kV transformer. Initial design will be a ring bus on both the
Interim redispatch under service agreement. The mitigation is to run
the City of Winfield/Wellington generation.
Displacement need to make filing for displacement $
20033
10639
WR
Line - Jarbalo - Stranger Creek
04/26/11
06/01/10
01/27/09
$0
$4,536,005
20059
20086
10674
10679
WR
WR
Line - Rose Hill - Sooner 345 kV Ckt 1 (WR)
XFR - Halstead South 138/69 kV Ckt 1
04/27/12
06/01/14
01/01/13
06/01/11
09/18/09
02/08/10
$84,669,696
$1,700,000
$84,379,298
$3,205,323
20063
10713
WR
Multi - Litchfield - Aquarius - Hudson Jct. 69 kV Uprate
20033
20033
10767
10806
WR
WR
Line - 27th & Croco - 41st & California 115 kV
Multi - NW Manhattan
06/01/13
06/01/13
11/02/09
$75,000
$154,336
03/21/11
05/11/12
06/01/09
06/01/10
01/27/09
01/27/09
$2,752,000
$3,654,556
$3,650,576
$17 437 500
COMPLETE
COMPLETE
COMPLETE
DELAY - MITIGATION
Mitigation is to re-dispatch Gill and Evans in the Wichita area.
In-Service - Cost not final
In-Service - Cost Not final
Project costs are for Westar Energy portion only; Public hearing held;
ON SCHEDULE < 4
COMPLETE
COMPLETE
Currently 230/115kV dollars are combined. Will break apart for Q3
20033
20059
200175
20033
20086
20063
10808
10810
10812
10813
10866
10870
WR
WR
WR
WR
WR
WR
Multi - NW Manhattan
Line - Richland - Rose Hill Junction 69 kV
Line - Fort Junction - West Junction City 115 kV
Line - Rebuild Chisolm - Ripley 69 kV
Line - Gill - Clearwater 138 kV
Line - GEC West - Waco 138 kV
Zonal Reliability
03/19/12
11/03/11
06/01/13
06/01/11
04/27/11
12/01/12
06/01/10
06/01/11
06/01/15
06/01/10
06/01/11
06/01/10
01/27/09
09/18/09
04/09/12
01/27/09
02/08/10
11/02/09
20086
11082
WR
Line - Gill Energy Center East - MacArthur 69 kV
06/01/14
06/01/13
20068
11204
WR
Line - Macarthur - Oatville 69 kV Ckt 1
03/12/12
20131
11344
WR
Multi - Craig - 87th - Stranger 345 kV Ckt 1
20131
11345
WR
20131
11346
WR
$17,437,500
$2,815,000
$6,969,136
$2,255,250
$3,324,375
$1,000,000
$23,493,424
$3,782,279
$6,969,136
$3,962,701
$8,466,466
$4,857,641
COMPLETE
COMPLETE
ON SCHEDULE < 4
COMPLETE
COMPLETE
DELAY - MITIGATION
02/08/10
$2,200,000
$4,373,843
DELAY - MITIGATION
06/01/12
01/13/10
$40,000
$50,200
12/31/12
06/01/11
02/14/11
12/31/12
06/01/11
02/14/11
12/31/12
06/01/11
02/14/11
$26,825,000
COMPLETE
$9,866,277
DELAY - MITIGATION
$15,119,789
DELAY - MITIGATION
$12,277,385
DELAY - MITIGATION
20131
11411
WR
Multi - Mulberry - Franklin - Sheffield 161 kV
06/01/14
06/01/13
02/14/11
20131
11412
WR
06/01/14
06/01/13
02/14/11
06/01/13
02/14/11
$8,750,767
$11,471,091
$6,867,000
$3,897,955
$278,558
02/14/11
$0
$0
COMPLETE
DELAY - MITIGATION
$0
$625,000
$847,064
COMPLETE
$7,347,754
$4,981,988
DELAY - MITIGATION
$5,701,631
DELAY - MITIGATION
20131
11413
WR
06/01/14
20131
11441
11444
WR
WR
Caney River Wind Project
09/13/11
06/01/14
11445
WR
Caney River Wind Project
09/13/11
20091
50228
WR
Multi - Green - Coffey County No. 3 - Burlington Junction - Wolf Creek
12/31/12
06/01/12
03/31/10
$3,921,591
$4,380,845
DELAY - MITIGATION
20059
20059
20059
20091
50229
50230
50231
50232
WR
WR
WR
WR
Device - Allen 69 kV Capacitor
Device - Altoona East 69 kV Capacitor
Device - Athens 69 kV Capacitor
05/31/12
06/01/14
12/01/13
05/25/11
06/01/12
06/01/14
06/01/13
04/01/11
09/18/09
09/18/09
09/18/09
03/31/10
$0
$0
$0
$1,960,795
$954,830
$1,045,000
$1,026,734
$3,993,819
COMPLETE
ON SCHEDULE < 4
DELAY - MITIGATION
COMPLETE
20091
50233
WR
06/01/14
07/01/13
03/31/10
$4,575,190
$2,848,705
DELAY - MITIGATION
06/01/13
Current cost estimate for UID 10806 is sufficient for both 230/115kV
Line energized 4/27/11, however breaker change out at Gill will not be
Mitigation is to re-dispatch Gill and Evans in the Wichita area.
All terminal equipment meets minimum NTC requirement. No field
Mitigiation is to re-dispatch LEC generation and/or open Wakarusa JctEudora 115 kV
Distribution Capacitor banks are in-service to improve the PF on
Marmaton-Litchfield 69 kV.
Distribution Capacitor banks are in-service to improve the PF on
DELAY - MITIGATION
Costs to be incurred by wind farm owner.
Costs to be incurred by wind farm owner.
Mitigation is to re-dispatch generation in the (Chanute, Erie, and Iola).
$2,855,297
20091
50234
WR
06/01/13
01/01/13
03/31/10
$2,614,395
$3,458,116
DELAY - MITIGATION
20091
50236
WR
12/15/13
04/01/14
03/31/10
$5,882,387
$6,024,876
ON SCHEDULE < 4
20091
20091
50239
50240
WR
WR
12/14/11
03/29/12
12/01/11
11/01/13
03/31/10
03/31/10
$5,555,588
$653,598
$2,996,364
$1,693,501
COMPLETE
COMPLETE
20059
50241
WR
Line - Neosho - Northeast Parsons 138 kV
06/01/11
06/01/11
09/18/09
$250,000
$114,269
$114,269
20059
20059
20091
20068
50243
50244
50245
50284
50290
50327
50328
50368
50369
50370
50371
WR
WR
WR
WR
WR
WR
WR
WR
WR
WR
WR
Device - Timber Jct 138 kV Capacitor
Device - Tioga 69 kV Capacitor
Device - Dearing 138 kV Capacitor
Device - Benton Cap #2
Line - East Manhattan - NW Manhattan 230 kV Ckt 1
Line - Halstead South - Sedgwick 138 kV
Sub - Chapman Junction 115 kV
Sub - Clay Center Junction 115 kV
Device - Chapman Junction 115 kV Capacitor
Line - Clay Center Junction - Clay Center Switching Station 115 kV
Zonal - Sponsored
Zonal Reliability
Zonal Reliability
Zonal Reliability
Zonal Reliability
08/16/11
07/05/11
03/03/11
06/01/13
06/01/14
03/19/12
06/01/16
12/31/12
12/31/12
10/01/13
12/31/12
06/01/11
06/01/11
01/01/11
06/01/12
09/18/09
09/18/09
03/31/10
01/13/10
08/25/10
08/25/10
05/27/11
05/27/11
05/27/11
05/27/11
$1,637,096
$732,398
$2,777,239
$1,215,000
$3,072,000
$700,000
$700,000
$5,425,273
$2,849,367
$873,461
$7,476,811
$1,637,096
$584,242
$1,976,966
06/01/19
06/01/19
10/01/12
10/01/12
10/01/12
10/01/13
$0
$0
$3,267,992
$0
$0
$700,000
$700,000
$4,877,550
$2,849,367
$0
$6,790,959
Bring on cap banks at Allen and Tioga. Dispatch Chanute/Erie/Iola
COMPLETE
Jumper was replaced with bundled 266 ACSR wire rated at 192MVA.
20108
20108
20140
20140
20140
20140
$199,416
COMPLETE
COMPLETE
COMPLETE
DELAY - MITIGATION
ON SCHEDULE < 4
COMPLETE
ON SCHEDULE > 4
DELAY - MITIGATION
DELAY - MITIGATION
DELAY - MITIGATION
DELAY - MITIGATION
20140
50372
WR
Line - Clay Center Switching Station - TC Riley 115 kV ckt 1
Zonal Reliability
06/01/14
10/01/12
05/27/11
$4,549,942
$7,472,511
DELAY - MITIGATION
20140
50373
WR
Sub - Clay Center Switching Station 115 kV
Zonal Reliability
12/31/12
10/01/12
05/27/11
$4,877,550
$2,774,851
DELAY - MITIGATION
20140
50374
WR
Sub - TC Riley 115 kV
Zonal Reliability
06/01/14
10/01/12
05/27/11
$850,000
$963,441
DELAY - MITIGATION
200175
200175
50382
50383
WR
WR
Device - Wheatland 115 kV Capacitor
Device - Northwest Manhattan 115 kV Capacitor
Zonal Reliability
Zonal Reliability
06/01/13
10/10/12
06/01/12
06/01/14
04/09/12
04/09/12
$957,660
$957,660
$957,660
$957,660
DELAY - MITIGATION
COMPLETE
200175
50386
WR
Mund - Pentagon 115 kV
12/01/12
04/09/12
$278,300
$278,300
ON SCHEDULE < 4
200175
50397
WR
Line - Cowskin - Centennial 138 kV rebuild
06/01/12
04/09/12
$3,676,071
$3,676,071
06/01/13
DELAY - MITIGATION
Clay Center did not provide Westar with construction easement. This
Due to uncertainty of Presidential Permit, TransCanada has extended
their in-service date to June 2014. Load will not be in-service until
June, 2014. No mitigation is needed. The RTO date needs to be
changed according to en email that was sent to Steve Purdy.
Clay Center did not provide Westar with construction easement. This
required redesign and will extend construction by one month.
Mitigation is to serve the load at existing Delivery Point for an extra
month.
Due to uncertainty of Presidential Permit, TransCanada has extended
their in-service date to June 2014. Load will not be in-service until
June, 2014. No mitigation is needed. The RTO date needs to be
changed according to an email that was sent to Steve Purdy.
After substation review, equipment in the sub already meets NTC
requirements.
200179
50398
WR
XFR - Auburn Road 230/115 kV Transformer Ckt 1
200175
50399
WR
Device - Elk River 69 kV Capacitor
200182
200176
200197
50429
50465
50470
50471
50472
50498
WR
WR
WR
WR
WR
WR
Multi - Creswell - BellePlain 138 kV
Line - Greenleaf - Knob Hill 115 kV CKT 1 WR
200197
50526
WR
Line - El Paso - Farber 138kV CKT 1
06/01/14
06/01/14
04/09/12
Zonal Reliability
12/01/14
06/01/12
04/09/12
03/01/18
04/09/12
01/16/12
06/01/17
06/01/14
ITP10
Zonal - Sponsored
Zonal - Sponsored
Zonal - Sponsored
11/15/12
06/01/12
06/01/12
06/01/12
06/01/17
$25,845,600
$29,507,894
ON SCHEDULE < 4
$1,007,160
$1,007,160
DELAY - MITIGATION
11/20/12
$62,110,152
$5,095,881
$0
$0
$0
$456,403
$62,110,152
$5,095,881
$6,581,250
$885,938
$3,075,469
$456,403
ON SCHEDULE > 4
ON SCHEDULE < 4
COMPLETE
COMPLETE
ON SCHEDULE < 4
11/20/12
$5,561,163
$5,561,163
Substation Scope: This will be a "greenfield" substation requiring land
acquisition and site prep. The 230kV portion of the sub will be
constructed to 345kV standards in anticipation of future requirements.
The transformer will be purchased as a dual voltage high side at
230/345kV.
There is an existing capacitor bank at Elk River substation.
Installation of a second cap bank will require control & switching
upgrades on the existing bank.
Substation Scope: Rebuild the 138kV line between El Paso and
Farber substations. Substation equipment will be upgraded to a
minimum 1200A capacity. Work at Farber will be limited to jumper
upgrades. El Paso will require two breaker replacements based on
the existing breakers becoming overdutied after the line rebuild.

Dear Chairman Wood and Commissioners Brownell, Kelly and

Transcription

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