kepco nitsa 1636r3 revised transmittal letter · 9/8/2011 · kepco, including the right to make...
TRANSCRIPT
September 8, 2011
The Honorable Kimberly D. BoseSecretary Federal Energy Regulatory Commission 888 First Street NEWashington, DC 20426
Re: Southwest Power Pool, Inc., Docket No. ER11-4148-___Submission of Amended Network Integration Transmission Service Agreement and Network Operating Agreement
Dear Secretary Bose:
Pursuant to section 205 of the Federal Power Act, 16 U.S.C. § 824d, and section 35.13 of the Federal Energy Regulatory Commission’s (“Commission”) regulations, 18 C.F.R. § 35.13, Southwest Power Pool, Inc. (“SPP”) amends its July 29, 2011 filing in this docket1 and submits: (1) an executed, amended Service Agreement for Network Integration Transmission Service (“Service Agreement”) between SPP as Transmission Provider and Kansas Electric Power Cooperative, Inc. (“KEPCO”) as Network Customer (“KEPCO Service Agreement”); and (2) a Network Operating Agreement (“NOA”) between SPP as Transmission Provider, KEPCO as Network Customer, and Westar Energy, Inc. (“Westar”) as Host Transmission Owner (“KEPCO NOA”).2 The KEPCO Agreements amend and replace the July 29 Agreements. Because the KEPCO Agreements have the same proposed effective date and are intended to replace and
1 See Submission of Network Integration Transmission Service Agreements of
Southwest Power Pool, Inc., Docket No. ER11-4148-000 (July 29, 2011) (“July 29 Filing”). The agreements in the July 29 Filing are referred to collectively as the “July 29 Agreements” and individually as the “July 29 Service Agreement” and the “July 29 NOA.”
2 The KEPCO Service Agreement and KEPCO NOA are referred to collectively as the “KEPCO Agreements,” and SPP, KEPCO, and Westar are referred to collectively as “the Parties.” The KEPCO Agreements are designated as Third Revised Service Agreement No. 1636.
The Honorable Kimberly D. BoseSeptember 8, 2011Page 2
substitute for the July 29 Agreements, the Commission need not act on the July 29 Agreements, but rather only accept for filing the KEPCO Agreements.3
I. Background
On July 29, 2011, SPP filed with the Commission the July 29 Agreements, which contained terms and conditions that do not conform to the standard forms of service agreements in the SPP Open Access Transmission Tariff (“Tariff”).4 SPP requested and effective date of June 1, 2011, for the July 29 Agreements.5 The July 29 Filing is currently pending before the Commission.
Since the July 29 Filing, the Parties have revised the July 29 Service Agreements to add the following sentence in Section 8.6 of Attachment 1: “The composite loss percentages in Section 28.5 shall exclude transmission losses.” This additional language clarifies that only distribution losses (and not transmission losses) will be replaced in accordance with Westar’s Open Access Transmission Tariff, which is on file with the Commission. Except for this revision, the KEPCO Agreements are identical to the July 29 Agreements.
II. Description of and Justification for the Non-Conforming Language in the KEPCO Agreements
In addition to the change to Section 8.6 of Attachment 1 described above, like the July 29 Agreements, the KEPCO Service Agreement contains language that does not conform to the pro forma Agreements.6 Section 8.6 of Attachment 1 of the KEPCO Service Agreement also specifies that “[t]he Network Customer shall replace all distribution losses in accordance with Westar Energy's Open Access Transmission Tariff, Section 28.5, based upon the location of each delivery point meter located on distribution 3 For the same reasons as stated above, to the extent required, SPP moves to
withdraw the July 29 Filing. Withdrawal is permitted because no Commission or delegated order has been issued on the July 29 Agreements, and the July 29 Agreements have not become effective. See 18 C.F.R. § 35.17(a)(1) (“A public utility may withdraw in its entirety a rate schedule, tariff or service agreement filing that has not become effective and upon which no Commission or delegated order has been issued by filing a withdrawal motion with the Commission.”).
4 See Tariff at Attachment F (“pro forma Service Agreement”) and Attachment G (“pro forma NOA”), collectively “the pro forma Agreements.”
5 See July 29 Filing at 4.
6 The KEPCO NOA does not contain any non-conforming language and conforms to the pro forma NOA.
The Honorable Kimberly D. BoseSeptember 8, 2011Page 3
facilities.”7 Section 8.6 of Attachment 1 of the pro forma Service Agreement contains a fill-in-the-blank provision for Real Power Losses – Distribution. Here, Parties added language to specify that the distribution losses would be replaced in accordance with Westar’s Open Access Transmission Tariff, which is on file with the Commission. The added language is just and reasonable and will benefit the Parties because it clarifies that distribution (and not transmission losses) will be calculated in accordance with a Commission-accepted tariff.
Section 7.0 of the KEPCO Service Agreement contains additional language to provide that either KEPCO or SPP may, without the need for consent from the other, transfer or assign the KEPCO Service Agreement to any person succeeding to all or substantially all of the assets of the assigning party, provided that all required regulatory approvals for such transfer or assignment, including approval of the Rural Utilities Service (“RUS”) as to KEPCO are obtained. Moreover, both KEPCO and SPP acknowledge and agree that KEPCO has assigned and pledged as security the KEPCO Service Agreement and all of its rights hereunder to the RUS. KEPCO and SPP further acknowledge and agree that the RUS will have the right, upon written notice to SPP, to assume all obligations of KEPCO, whereupon the RUS will succeed to all rights of KEPCO, including the right to make any subsequent assignment in accordance with Section 7.0 of the KEPCO Service Agreement.
The additional language in Section 7.0 of the KEPCO Service Agreement clarifies that certain actions by the Parties are subject to applicable regulatory oversight, but such oversight does not infringe upon the Commission’s exclusive jurisdiction. Furthermore, given that KEPCO continues to be a RUS borrower, it is reasonable to require RUS approval prior to a transfer or assignment of KEPCO’s assets. In addition, a previous iteration of the KEPCO Service Agreement, which the Commission accepted, contains identical language in Section 7.0.8
Section 8.9 of Attachment 1 of the KEPCO Service Agreement contains language specifying that the cost support and monthly charges for Wholesale Distribution Service Charges are detailed in a new, non-conforming Appendix 4 to the KEPCO Service Agreement. The inclusion of the cost support and monthly charges for Wholesale Distribution Service in Appendix 4 is consistent with Schedule 10 of the SPP Tariff, which requires cost support when Service Agreements containing Wholesale Distribution Charges are filed with the Commission.9 The Commission accepted a previous iteration
7 See KEPCO Service Agreement at Attachment 1, § 8.6.
8 See Sw. Power Pool, Inc., Letter Order, Docket No. ER11-3073-000 (May 11, 2011) (“May Letter Order”).
9 See SPP Tariff at Schedule 10 (“All rates and charges for Wholesale Distribution Service shall be on file with the appropriate agency as required by law or
(continued . . . )
The Honorable Kimberly D. BoseSeptember 8, 2011Page 4
of the KEPCO Service Agreement, which included similar non-conforming language in Section 8.9 and Appendix 4, in the May Letter Order.10
Appendix 3 of the Fourth Revised KEPCO Service Agreement, which identifies the pertinent delivery points located on Westar’s distribution facilities, also contains non-conforming language. Specifically, the Parties have included additional information beyond the name, ownership, and voltage of the delivery point contemplated by the chart in Appendix 3 of the pro forma Service Agreement. The additional information, which includes the SPP bus name and number and the delivery point numbers, is necessary and benefits the Parties because it provides additional detail on the distribution losses for the delivery points. The Commission previously has accepted agreements submitted by SPP with similar language.11
For the reasons stated in this transmittal letter and the July 29 Filing, the Commission should accept the KEPCO Agreements filed herein.
III. Effective Date and Waiver
Consistent with the effective date requested in the July 29 Filing, SPP requests an effective date of June 1, 2011 for the KEPCO Agreements. To permit such an effective date, SPP requests a waiver of the Commission’s 60-day notice requirement set forth at 18 C.F.R. § 35.3. Waiver is appropriate because the Parties have agreed to this effective date. In addition, new delivery points in the KEPCO Service Agreement became effective on June 1, 2011, and waiver will allow the KEPCO Service Agreement to become effective on the same day as the delivery points. The Commission granted a similar waiver with regard to previous KEPCO Agreements, which were filed on March 14, 2011, to permit them to become effective on October 1, 2010.12 The Commission likewise should grant the requested waiver here.
( . . . continued)
regulation. To the extent that a Service Agreement containing provisions for Wholesale Distribution Service is required to be filed with the Commission, the Transmission Provider, in consultation with the appropriate Transmission Owner, shall provide along with the filing, adequate cost support to justify the customer-specific rates and charges being assessed under this Schedule 10.”).
10 See supra note 8.
11 See Sw. Power Pool, Inc., Letter Order, Docket No. ER10-1698-000 (Aug. 20, 2010); Sw. Power Pool, Inc., Letter Order, Docket No. ER10-1688-000 (Aug. 20, 2010).
12 See May Letter Order.
The Honorable Kimberly D. BoseSeptember 8, 2011Page 5
IV. Additional Information
A. Information Required by Section 35.13 of the Commission’sRegulations, 18 C.F.R. § 35.13:(1) Documents submitted with this filing:
In addition to this transmittal letter, SPP includes the following:
(i) A clean copy of the KEPCO Agreements; and
(ii) A redlined copy of the KEPCO Agreements.
(2) Effective Date:
As discussed herein, SPP respectfully requests that the Commission accept the KEPCO Agreements with an effective date of June 1, 2011.
(3) Service:
SPP is serving a copy of this filing on all parties to the service list in ER11-4148, and to representatives for KEPCO and Westar listed in the KEPCO Agreements.
The Honorable Kimberly D. BoseSeptember 8, 2011Page 6
(4) Basis of Rate:
All charges will be determined in accordance with the SPP Tariff and the KEPCO Agreements.
B. Communications:
Copies of this filing have been served upon all parties to the KEPCO Agreements. Any correspondence regarding this matter should be directed to:
Heather Starnes, J.D.Manager – Regulatory PolicySouthwest Power Pool, Inc.415 North McKinley, #140 Plaza WestLittle Rock, AR 72205Telephone: (501) 614-3380Fax: (501) [email protected]
Carrie L. BumgarnerTyler R. BrownWRIGHT & TALISMAN, P.C.1200 G Street, N.W., Suite 600Washington, DC 20005-3802Telephone: (202) 393-1200Fax: (202) [email protected]@wrightlaw.com
V. Conclusion
For all the foregoing reasons, SPP respectfully requests that the Commission accept the KEPCO Agreements with an effective date of June 1, 2011.
Respectfully submitted,
/s/Tyler R. Brown_______Carrie L. BumgarnerTyler R. Brown
Attorneys for Southwest Power Pool, Inc.
K:\SPP\Service Agreement Filings\Transmission Service Agreement Filings\KEPCO NITSA 1636R3 REVISED Transmittal Letter.doc
CERTIFICATE OF SERVICE
I hereby certify that I have this day served the foregoing document upon each
person designated on the official service list compiled by the Secretary in these
proceedings.
Dated at Washington, DC, this 8th day of September, 2011.
Tyler R. BrownTyler R. Brown
Attorney for Southwest Power Pool, Inc.
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Southwest Power Pool, Inc. Third Revised Service Agreement No. 1636
SERVICE AGREEMENT FOR NETWORK INTEGRATION TRANSMISSION
SERVICE BETWEEN SOUTHWEST POWER POOL, INC. AND KANSAS
ELECTRIC POWER COOPERATIVE, INC.
This Network Integration Transmission Service Agreement ("Service Agreement") is
entered into this 1st day of June 2011, by and between Kansas Electric Power Cooperative, Inc.
("Network Customer" or “KEPCO”), and Southwest Power Pool, Inc. ("Transmission Provider").
The Network Customer and Transmission Provider shall be referred to individually as “Party”
and collectively as "Parties."
WHEREAS, the Transmission Provider has determined that the Network Customer has
made a valid request for Network Integration Transmission Service in accordance with the
Transmission Provider’s Open Access Transmission Tariff ("Tariff") filed with the Federal
Energy Regulatory Commission ("Commission") as it may from time to time be amended;
WHEREAS, the Transmission Provider administers Network Integration Transmission
Service for Transmission Owners within the SPP Region and acts as agent for the Transmission
Owners in providing service under the Tariff;
WHEREAS, the Network Customer has represented that it is an Eligible Customer under
the Tariff; and
WHEREAS, the Parties intend that capitalized terms used herein shall have the same
meaning as in the Tariff.
NOW, THEREFORE, in consideration of the mutual covenants and agreements herein,
the Parties agree as follows:
1.0 The Transmission Provider agrees during the term of this Service Agreement, as it may
be amended from time to time, to provide Network Integration Transmission Service in
accordance with the Tariff to enable delivery of power and energy from the Network
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Customer’s Network Resources that the Network Customer has committed to meet its
load.
2.0 The Network Customer agrees to take and pay for Network Integration Transmission
Service in accordance with the provisions of Parts I, III and V of the Tariff and this
Service Agreement with attached specifications.
3.0 The terms and conditions of such Network Integration Transmission Service shall be
governed by the Tariff, as in effect at the time this Service Agreement is executed by the
Network Customer, or as the Tariff is thereafter amended or by its successor tariff, if any.
The Tariff, as it currently exists, or as it is hereafter amended, is incorporated in this
Service Agreement by reference. In the case of any conflict between this Service
Agreement and the Tariff, the Tariff shall control. The Network Customer has been
determined by the Transmission Provider to have a Completed Application for Network
Integration Transmission Service under the Tariff. The completed specifications are
based on the information provided in the Completed Application and are incorporated
herein and made a part hereof as Attachment 1.
4.0 Service under this Service Agreement shall commence on such date as it is permitted to
become effective by the Commission. This Service Agreement shall be effective through
June 1st, 2013. Thereafter, it will continue from year to year unless terminated by the
Network Customer or the Transmission Provider by giving the other one-year advance
written notice or by the mutual written consent of the Transmission Provider and
Network Customer. Upon termination, the Network Customer remains responsible for
any outstanding charges including all costs incurred and apportioned or assigned to the
Network Customer under this Service Agreement.
5.0 The Transmission Provider and Network Customer have executed a Network Operating
Agreement as required by the Tariff.
6.0 Any notice or request made to or by either Party regarding this Service Agreement shall
be made to the representative of the other Party as indicated below. Such representative
and address for notices or requests may be changed from time to time by notice by one
Party or the other.
3 1431666 & 74318195
Southwest Power Pool, Inc. (Transmission Provider):
Carl Monroe
Executive Vice President and Chief Operating Officer
415 N. McKinley,140 Plaza West
Little Rock, AR 72205
Network Customer:
Mark Barbee
Vice President Engineering
Kansas Electric Power Cooperative Inc.
600 SW Corporate View
Topeka, KS 66615
7.0 This Service Agreement shall not be assigned by either Party without the prior written
consent of the other Party, which consent shall not be unreasonably withheld. However,
either Party may, without the need for consent from the other, transfer or assign this
Service Agreement to any person succeeding to all or substantially all of the assets of
such Party provided that all required regulatory approvals (if any), including approval of
the Rural Utilities Service (“RUS”) as to KEPCO, are obtained in connection with such
transfer or assignment. However, the assignee shall be bound by the terms and
conditions of this Service Agreement. The Parties acknowledge and agree that KEPCO
has assigned and pledged as security this Service Agreement and all of its rights
hereunder to RUS. The Parties further acknowledge and agree that RUS shall have the
right upon written notice to the Transmission Provider to assume all obligations of
KEPCO hereunder whereupon RUS shall succeed to all rights of KEPCO hereunder
(including the right to make any subsequent assignment in accordance with this section).
8.0 Nothing contained herein shall be construed as affecting in any way the Transmission
Provider’s or a Transmission Owner’s right to unilaterally make application to the
Federal Energy Regulatory Commission, or other regulatory agency having jurisdiction,
for any change in the Tariff or this Service Agreement under Section 205 of the Federal
4 1431666 & 74318195
Power Act, or other applicable statute, and any rules and regulations promulgated
thereunder; or the Network Customer's rights under the Federal Power Act and rules and
regulations promulgated thereunder.
9.0 By signing below, the Network Customer verifies that all information submitted to the
Transmission Provider to provide service under the Tariff is complete, valid and accurate,
and the Transmission Provider may rely upon such information to fulfill its
responsibilities under the Tariff.
IN WITNESS WHEREOF, the Parties have caused this Service Agreement to be
executed by their respective authorized officials.
TRANSMISSION PROVIDER NETWORK CUSTOMER
/s/ Carl Monroe /s/ Mark R. Barbee
Carl Monroe Mark BarbeeExecutive Vice President and Chief Vice President EngineeringOperating Officer Kansas Electric PowerSouthwest Power Pool, Inc. Cooperative, Inc.
7/28/2011 7/26/2011
Date Date
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ATTACHMENT 1 TO THE NETWORK INTEGRATION TRANSMISSION SERVICE
AGREEMENT
BETWEEN SOUTHWEST POWER POOL AND
SPECIFICATIONS FOR NETWORK INTEGRATION TRANSMISSION SERVICE
1.0 Network Resources
The Network Resources are listed in Appendix 1.
2.0 Network Loads
The Network Load consists of the bundled native load or its equivalent for Network
Customer load in the Westar Energy Control Area as listed in Appendix 3.
The Network Customer’s Network Load shall be measured on an hourly integrated basis,
by suitable metering equipment located at each connection and delivery point, and each
generating facility. The meter owner shall cause to be provided to the Transmission
Provider, Network Customer and applicable Transmission Owner, on a monthly basis
such data as required by Transmission Provider for billing. The Network Customer’s
load shall be adjusted, for settlement purposes, to include applicable Transmission Owner
transmission and distribution losses, as applicable, as specified in Sections 8.5 and 8.6,
respectively. For a Network Customer providing retail electric service pursuant to a state
retail access program, profiled demand data, based upon revenue quality non-IDR meters
may be substituted for hourly integrated demand data. Measurements taken and all
metering equipment shall be in accordance with the Transmission Provider’s standards
and practices for similarly determining the Transmission Provider’s load. The actual
hourly Network Loads, by delivery point, internal generation site and point where power
may flow to and from the Network Customer, with separate readings for each direction of
flow, shall be provided.
3.0 Affected Control Areas and Intervening Systems Providing Transmission Service
6 1431666 & 74318195
The affected control area is Westar Energy. The intervening systems providing
transmission service are _____none____
4.0 Electrical Location of Initial Sources
See Appendix 1.
5.0 Electrical Location of the Ultimate Loads
The loads of Network Customer identified in Section 2.0 hereof as the Network Load are
electrically located within the Westar Energy Control Area.
6.0 Delivery Points
The delivery points are the interconnection points identified in Section 2.0 as the
Network Load.
7.0 Receipt Points
The Points of Receipt are listed in Appendix 2.
8.0 Compensation
Service under this Service Agreement may be subject to some combination of the charges
detailed below. The appropriate charges for individual transactions will be determined in
accordance with the terms and conditions of the Tariff.
8.1 Transmission Charge
Monthly Demand Charge per Section 34 and Part V of the Tariff.
8.2 System Impact and/or Facility Study Charge
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Studies may be required in the future to assess the need for system
reinforcements in light of the ten-year forecast data provided. Future charges, if
required, shall be in accordance with Section 32 of the Tariff.
8.3 Direct Assignment Facilities Charge
8.4 Ancillary Service Charges
8.4.1 The following Ancillary Services are required under this Service
Agreement.
a) Scheduling, System Control and Dispatch Service per Schedule 1 of the
Tariff.
b) Tariff Administration Service per Schedule 1-A of the Tariff.
c) Reactive Supply and Voltage Control from Generation Sources Service
per Schedule 2 of the Tariff.
d) Regulation and Frequency Response Service per Schedule 3 of the
Tariff.
e) Energy Imbalance Service per Schedule 4 of the Tariff.
f) Operating Reserve - Spinning Reserve Service per Schedule 5 of the
Tariff.
g) Operating Reserve - Supplemental Reserve Service per Schedule 6 of the
Tariff.
The Ancillary Services may be self-supplied by the Network Customer or
provided by a third party in accordance with Sections 8.4.2 through 8.4.4, with
the exception of the Ancillary Services for Schedules 1, 1-A, and 2, which must
be purchased from the Transmission Provider.
8.4.2 In accordance with the Tariff, when the Network Customer elects to self-
supply or have a third party provide Ancillary Services, the Network
Customer shall indicate the source for its Ancillary Services to be in
effect for the upcoming calendar year in its annual forecasts. If the
Network Customer fails to include this information with its annual
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forecasts, Ancillary Services will be purchased from the Transmission
Provider in accordance with the Tariff.
8.4.3 When the Network Customer elects to self-supply or have a third party
provide Ancillary Services and is unable to provide its Ancillary
Services, the Network Customer will pay the Transmission Provider for
such services and associated penalties in accordance with the Tariff as a
result of the failure of the Network Customer’s alternate sources for
required Ancillary Services.
8.4.4 All costs for the Network Customer to supply its own Ancillary Services
shall be the responsibility of the Network Customer.
8.5 Real Power Losses – Transmission
The Network Customer shall replace losses in accordance with Attachment M of
the Tariff.
8.6 Real Power Losses – Distribution
The Network Customer shall replace all distribution losses in accordance with
Westar Energy's Open Access Transmission Tariff, Section 28.5, based upon the
location of each delivery point meter located on distribution facilities. The
composite loss percentages in Section 28.5 shall exclude transmission
losses.
8.7 Power Factor Correction Charge
8.8 Redispatch Charge
Redispatch charges shall be in accordance with Section 33.3 of the Tariff.
8.9 Wholesale Distribution Service Charge
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The Wholesale Distribution Service charge cost support and monthly charge is
detailed in Appendix 4.
8.10 Network Upgrade Charges
A. The Network Customer has confirmed the following supplemental
Network Resources requiring Network Upgrades:
1. Iatan 2 Generating Station, 30MW from POR-KCPL, Source –Iatan2 to POD
– WR, Sink-KEPCO.WR, as more specifically identified in transmission
request 1090416. Contingent upon the completion of required upgrades as
specified below, designation of the resource shall be effective June 1, 2010
and shall remain effective through June 1, 2030.
The requested service requires completion of the following aggregate study
SPP-2006-AG2 allocated network upgrades. The costs of these upgrades are
allocated to the Network Customer but are fully base plan fundable in
accordance with Section III.A. Attachment J of the Tariff.
Network upgrades on the American Electric Power Coffeyville Tap –
Dearing 138kV Ckt 1 facility required by June 1, 2011. This upgrade
consists of rebuilding 1.09 miles of this facility with 1590 ACSR
conductor.
Network upgrades on the Westar Energy Coffeyville Tap – Dearing
138kV Ckt 1 facility required by June 1, 2011. This upgrade consists of
rebuilding 3.93 miles of this facility with 1590 ACSR conductor.
Network upgrades on the Westar Energy Rose Hill 345/138kV
Transformer required by June 1, 2011. This upgrade consists of adding a
third 345/138kV transformer at Rose Hill.
2. Wolf Creek, 3MW from POR – WR, Source – KEPCOWC to POD – WR,
Sink Kepco , as more specifically identified in transmission request 1405798.
Contingent upon the completion of required upgrades as specified below,
designation of this network resource shall be effective on May 1, 2011 and
remain effective through May 1, 2018.
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The requested service depends on and is contingent on completion of the
following Reliability and Construction Pending upgrades. These upgrades costs
are not assignable to the Network Customer.
Reliability and Construction Upgrades for Wolf Creek
Upgrade Name Upgrade Description Transmission Owner
Date Required in Service
EAST MANHATTAN - NW MANHATTAN 230/115KV
Tap the Concordia - East Manhattan 230kV line and add a new substation"NW Manhattan"; Add a 230kV/115kV transformer and tap the KSU - Wildcat 115kV line into NW Manhattan
WERE 6/1/2010
East Manhattan to McDowell 230 kV
The East Manhattan-McDowell 115 kV is built as a 230 kV line, but is operated at 115 kV. Substation work will have to be performed in order to convert this line.
WERE 6/1/2010
STILWELL - WEST GARDNER 345KV CKT 1
Upgrade Stilwell terminal equipment to 2000 amps
KACP 6/1/2012
BURLINGTON JUNCTION - WOLF CREEK 69KV CKT 1
Rebuild 4.1 miles with 954 kcmil ACSR (138kV/69kV Operation)
WERE 6/1/2011
B. Upon completion of construction of the assigned upgrades, funding of their costs
shall be reconciled and trued-up against actual construction costs and requisite,
additional funding or refund of excess funding shall be made between the
Transmission Provider and the Network Customer.
C. Notwithstanding the term provisions of Section 4.0 of this Service Agreement,
Customer shall be responsible for paying all charges specified as its obligation in
this Section 8.10 of this Attachment 1, for the term specified herein for each
assigned upgrade.
8.11 Meter Data Processing Charge
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8.12 Other Charges
9.0 Credit for Network Customer-Owned Transmission Facilities
10.0 Designation of Parties Subject to Reciprocal Service Obligation
11.0 Other Terms and Conditions
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APPENDIX 1
Network Resources of
Kansas Electric Power Cooperative, Inc.
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APPENDIX 1
NETWORK RESOURCES
NETWORK RESOURCE
Maximum Net Dependable Capacity (MW) LOCATION
Summer Winter
Confirmation Agreement for WholesalePurchase and Sale of Capacity & Energy between Westar Energy, Inc (“Westar”)and Kansas Electric Power Cooperative, Inc.(“KEPCO”) dated March 6, 2003.
101 101
This purchase power contract uses the Westar Energy (“Westar”) fleet of generation to serve delivery points as listed in Appendix 3. WR will supply KEPCO with sufficient Energy to meet the delivery points’ hourly Energy demand and to account for the appropriate transmission and distribution losses associated with Energy deliveries from the Westar generation busses to the points of delivery. Westar agrees to sell KEPCO sufficient Capacity to meet the peak demand and planning reserve capacity. Westar shall supply KEPCO with Ancillary Services 3, 4, 5, and 6.
Unit delivery from ownership agreement for Wolf Creek Nuclear Generation Station Unit #1 dated December 28, 1981
69 69 Coffey Co. Kansas 66MW of firm transmission rights through 5/1/2011 and then 69MW of firm transmission rights thereafter
Power Sales Contract dated January 10, 1995 between Southwestern Power Administration (SPA) and KEPCO for Hydro Peaking Power and associated energy
94 94
Points of delivery shall be at the 161kv points of interconnection between SPA and KEPCO in SPA Switching station at Neosho, Newton Co., Mo. and SPA’s substation at Carthage, Jasper Co, Mo.
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NETWORK RESOURCE
Maximum Net Dependable Capacity (MW) LOCATION
Summer Winter
Unit delivery from Sharpe Generation Station pursuant to the Operating Agreement between Wolf Creek Nuclear Operating Cooperation and KEPCO dated July 1, 2002.
19 19 Coffey Co, Kansas
Iatan Unit 2 and Common Facilities Ownership Agreement dated May 19, 2006
The lesser of 3.53% of Net Generating Capacity or
30MW
The lesser of 3.53% of Net Generating Capacity or
30MW
Platte Co., MO.
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Appendix 2
Receipt Points of
Kansas Electric Power Cooperative, Inc.
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APPENDIX 2
RECEIPT POINTS
Tieline / Plant Name Ownership Voltage (kV)
Rating (MVA)
Westar Energy Network Resource Interconnection points on the Westar Energy Transmission System Westar varies
Wolf Creek Westar (KGE) 345
SPA Hydro Peaking Power, Neosho and Carthage Westar, EMDE 161
Sharpe Plant KEPCo 69
Iatan Unit 2 KCPL 345
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Appendix 3
Delivery Points of
Kansas Electric Power Cooperative, Inc.
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APPENDIX 3
DELIVERY POINTS
(a) (b) (c) (d)Voltage kV
(Meter) Location)
SPP Bus Number / Name
Delivery Point Name Delivery Point #
Ownership (Meter)
(1)
ARK VALLEY COOP533378SMOKYHL3 115 kV
MARQUETTE-LANGLEY 1307 Westar
12.5(Low Side)
533438WMCPHER3 115 kV MEDORA 1309 Westar 12.5(Bus)533411ARKVAL 3 115 kV SAND HILL 1313 Westar
12.5(Low Side)
533504CITYSVC2 69 kV YODER 1302 Westar
12.5(Low Side)
BLUESTEM COOP533339S ALMA3 115 kV ALMA 1703 Westar 12.5(Circuit)533332KNOB HL3 115 kV BLUE RAPIDS 2301 Westar 12.5(Bus)533323CLAYCTR3 115 kV CLAY CENTER 2304 Westar 12.5(Circuit)533334MATTERS3 115 kV FOSTORIA 1707 Westar 12.5(Circuit)
FOSTORIA DEDUCT (A) 1707A Westar 12.5(C)
533326EMANHAT3 115 kV HUNTER'S ISLAND 1705 Westar 12.5(Circuit)533330JCTCTY3 115 kV LEONARDVILLE 2305 Westar 34.5532852JEC 5 230 kV LOUISVILLE 1708 Westar 12.5(Circuit)532852JEC 6 230 kV PEDDICORD 1701 Westar 12.5(Circuit)533152CIRCLVL3 115 kV SOLDIER 1704 Westar 12.5(Circuit)533334MATTERS3 115 kV ST. GEORGE 1706 Westar 12.5(Circuit)533323CLAYCTR3 115 kV WAKEFIELD 2302 Westar 12.5(Bus)533339S ALMA3 115 kV
WAMEGO 1702 Westar 12.5(Bus)
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APPENDIX 3 – DELIVERY POINTS – Westar Energy System – Continues(a) (b) (c) (d)
Voltage (Meter)
(kV)
SPP Bus Number / Name
Delivery Point Name Delivery Point #
Ownership (Meter)
(1)BROWN-ATCHISON COOP533152CIRCLVL3 115 kV CIRCLEVILLE 1507 Westar
12.5(Circuit)
533212BROWNCO3 115 kV EAST FAIRVIEW 1505 Westar
12.5(Circuit)
533212BROWNCO3 115 kV EAST HIAWATHA 1506 Westar
12.5(Circuit)
533218PARALEL3 115 kV LANCASTER 1504 Westar
12.5(Circuit)
533480MUSCOTA2 69 kV MUSCOTAH 1508 Westar
12.5(Circuit)
533212BROWNCO3 115 kV NORTH HIAWATHA 1509 Westar
12.5(Circuit)
533481NORTONV2 69 kV NORTONVILLE 1503 Westar
12.5(Circuit)
533152CIRCLVL3 115 kV NETAWAKA 1501 Westar
12.5(Circuit)
533212BROWNCO3 115 kV SOUTH FAIRVIEW 1510 Westar 34.5533480MUSCOTA2 69 kV WILLIS 1502 Westar
12.5(Low Side)
21 1431666 & 74318195
APPENDIX 3 – DELIVERY POINTS – Westar Energy System – Continues(a) (b) (c) (d)
Voltage (Meter)
(kV)
SPP Bus Number / Name
Delivery Point Name Delivery Point #
Ownership (Meter)
(1)BUTLER COOP533585BU10BEN2 69 kV BENTON KBU10 Westar 12.5(Bus)533584BU6DEGR2 69 kV DE GRAFF KBU06 Westar 69533302EEUREKA3 115 kV EUREKA 2401 Westar
12.5 (Low Side)
533861BU5FURL2 69 kV FURLEY KBU05 Westar 69533586BU12KEI2 69 kV KEIGHLEY KBU12 Westar 12.5(Bus)533594LEON 2 69 kV LEON KBU01 Westar
12.5(Circuit)
533032BU11PON4 138 kV
LITTLE PONY MEADOWS KBU11A Westar 12.5(Bus)
533745NEWTON 2 69kV NEWTON KBU13 Westar 12.5
(Circuit)533032BU11PON4 138 kV PONY MEADOWS KBU11 Westar 12.5 (Bus)533601POTWIN 2 69 kV POTWIN KBU02 Westar
12.5(Circuit)
533550RICHLAN2 69 kV ROSE HILL KBU07 Westar
12.5(Circuit)
533595MAGNA 2 69 kV SMILEYBURG KBU08 Westar
12.5(Circuit)
533048HARRY 4 138 kV SPURRIER KBU04 Westar
12.5(Circuit)
533597MIDIAN2 69 kV TOWANDA KBU09 Westar
12.5(Circuit)
22 1431666 & 74318195
APPENDIX 3 – DELIVERY POINTS – Westar Energy System – Continues(a) (b) (c) (d)
Voltage (Meter) (kV)
SPP Bus Number / Name
Delivery Point Name Delivery Point #
Ownership (Meter)
(1)CANEY VALLEY COOP533557TIMBER 2 69 kV BURDEN KCV08 Westar
12.5(Circuit)
533686CV4CANY2 69 kV CANEY KCV04 Westar 12.5 (Bus)533691ELK RVR2 69 kV GRENOLA KCV01 Westar
12.5(Circuit)
533691ELK RVR2 69 kV HARSHMAN KCV09 Westar
23.5(Circuit)
533689ELK CTY2 69 kV LONGTON KCV02 Westar
12.5(Circuit)
533687CV7MCAL2 69 kV MCCALL KCV07 Westar 69533544CV5SEDA2 69 kV
SEDAN SWITCHING STATION KCV05 Westar 69
533542ARKCITY2 69 kV SILVERDALE KCV03 Westar
12.5(Circuit)
533557TIMBER 2 69 kV TISDALE KCV06 Westar
12.5(Circuit)
23 1431666 & 74318195
APPENDIX 3 – DELIVERY POINTS – Westar Energy System – Continues(a) (b) (c) (d)
Voltage (Meter) (kV)
SPP Bus Number / Name
Delivery Point Name Delivery Point #
Ownership (Meter)
(1)DS&O COOP533378SMOKYHL3 115 kV ASSARIA 1403 Westar 12.5 (Bus)533376SALINA 3 115 kV BENNINGTON 1408 Westar
12.5(Circuit)
533887AEC W 1 34.5 kV CHAPMAN 1416 Westar
12.5(Circuit)
533376SALINA 3 115 kV GYPSUM 1418 Westar
12.5(Circuit)
533329NCFOUND 3 115 kV K-18 1709 Westar 34.5533379SO GATE3 115 kV MAGNOLIA 1412 Westar
12.5(Circuit)
533378SMOKYHL3 115 kV MARQUETTE 2601 Westar
12.5(Low Side)
533330JCTCTY 3 115 kV MILFORD 1414 Westar 12.5 (Bus)533376SALINA 3 115 kV MINNEAPOLIS 1404 Westar 12.5 (Bus)533376SALINA 3 115 kV NORTH SALINA 1413 Westar 34.5533330JCTCTY3 115 kV NW JUNCTION CITY 1417 Westar
12.5 (Circuit)
533887AEC W 1 34.5 kV PEARL 1411 Westar 12.5 (Bus)533369HILSBOR3 115 kV RAMONA 1406 Westar 12.5 (Bus)533887AEC W 1 34.5 kV SOLOMON 1410 Westar 12.5 (Bus)533887AEC W 1 34.5 kV
SOUTHWEST ABILENE 1401 Westar
12.5(Circuit)
533887AEC W 1 34.5 kV TALMAGE #1 1409 Westar
12.5(Circuit)
533887AEC W 1 34.5 kV TALMAGE #2 1415 Westar
4.2(Low Side)
533323CLAYCTR3 115 kV UPLAND 1405 Westar 12.5 (Bus)533378 WEST LINDSBORG 2602 Westar 12.5 (Bus)
24 1431666 & 74318195
SMOKYHL3 115 kV533364CRAWFRD3 115 kV WEST SALINA 1402 Westar
12.5(Circuit)
25 1431666 & 74318195
APPENDIX 3 – DELIVERY POINTS – Westar Energy System – Continues(a) (b) (c) (d)
Voltage (Meter) (kV)
SPP Bus Number / Name
Delivery Point Name Delivery Point #
Ownership (Meter)
(1)FLINT HILLS COOP533340SMANHAT3 115 kV ALTA VISTA 708 Westar 34.5533340SMANHAT3 115 kV ALTA VISTA SOUTH 714 Westar
12.5(Circuit)
533309WEMPORI3 115 kV
COTTONWOOD FALLS 701 Westar 34.5
533305MORRIS 3 115 kV
COUNCIL GROVE EAST 704 Westar
12.5(Low Side)
533305MORRIS 3 115 kV
COUNCIL GROVE WEST 709 Westar
12.5(Circuit)
533369HILSBOR3 115 kV DURHAM 710 Westar
12.5(Low Side)
533366FLORENC3 115 kV FLORENCE 707 Westar
12.5(Circuit)
533369HILSBOR3 115 kV GOESSEL 712 Westar
12.5(Low Side)
533887AEC W 1 34.5 kV HERINGTON 706 Westar
12.5 (Low Side)
HERINGTON DEDUCT (A) 706A Westar 12.5(D)
533369HILSBOR3 115 kV HILLSBORO 703 Westar
12.5(Low Side)
533330JCTCTY 3 115 kV JUNCTION CITY 702 Westar 34.5533369HILSBOR3 115 kV LEHIGH 713 Westar
12.5(Circuit)
533366FLORENC3 115 kV MARION 711 Westar 12.5 (Bus)533599PEABODY2 69 kV PEABODY 705 Westar
12.5 (Circuit)
APPENDIX 3 – DELIVERY POINTS – Westar Energy System – Continues
26 1431666 & 74318195
(a) (b) (c) (d)Voltage (Meter)
(kV)
SPP Bus Number / Name
Delivery Point Name Delivery Point #
Ownership (Meter)
(1)HEARTLAND COOP532926BAKER 5 161 kV BAKER KSE02 Westar
12.5(Circuit)
532926BAKER 5 161 kV CHEROKEE KSE07 Westar
12.5(Circuit)
533651UN9CONG2 69 kV CONGER KUN09 Westar
12.5(Low Side)
533644SE4DEVO2 69 kV DEVON KSE04 Westar
12.5(Low Side)
533647UN1ELSM2 69 kV ELSMORE KUN01 Westar
12.5(Low Side)
533774SHEFFLD2 69 kV ENGLEVALE KSE05 Westar
12.5(Circuit)
533772SE1GREE2 69 kV GREENBUSH KSE01 Westar
12.5(Low Side)
533645SE9HIAT2 69 kV HIATTVILLE KSE09 Westar
12.5(Low Side)
533650UN8HUMB2 69 kV MAGELLAN KUN10 Westar 69533758CRAWFOR2 69 kV MC CUNE KSE06 Westar
12.5(Circuit)
533649UN7ROSE2 69 kV ROSE KUN07 Westar
12.5(Low Side)
533621ALLEN 2 69 KV SE HUMBOLDT KUN05 Westar
12.5(Circuit)
533648UN6URBA2 69 kV URBANA KUN06 Westar
12.5(Low Side)
27 1431666 & 74318195
APPENDIX 3 – DELIVERY POINTS – Westar Energy System – Continues(a) (b) (c) (d)
Voltage (Meter)
(kV)
SPP Bus Number / Name
Delivery Point Name Delivery Point #
Ownership (Meter)
(1)LEAVENWORTH-JEFFERSON COOP533164HTI 3 115 kV HOYT 609 Westar
12.5(Circuit)
533443COLINE 1 34.5 kV MAYETTA 605 Westar
12.5(Circuit)
533259NW LEAV3 115 kV NW LEAVENWORTH 601 Westar
12.5(Low Side)
533481NORTONV2 69 kV NORTONVILLE 607 Westar
12.5(Circuit)
533219TONGATP3 115 kV OSKALOOSA 610 Westar 34.5533458ROCKCRK2 69 kV ROCK CREEK 606 Westar
12.5(Circuit)
533219TONGATP3 115 kV STRANGER 603 Westar 34.5533219TONGATP3 115 kV TONGANOXIE 602 Westar 34.5533483VALLEY2 2 69 kV VALLEY FALLS 604 Westar
12.5(Circuit)
28 1431666 & 74318195
APPENDIX 3 – DELIVERY POINTS – Westar Energy System – Continues(a) (b) (c) (d)
Voltage (Meter) (kV) SPP Bus Number / Name
Delivery Point Name Delivery Point #
Ownership (Meter)
(1)LYON-COFFEY COOP533301EAST ST3 115 kV
AMERICUS - T. BIRD 1111 Westar 34.5
533628CC1BURL2 69 kV BURLINGTON KCC01 Westar 12.5(Bus) 533167KEENE 3 115 kV ESKRIDGE 1105 Westar
12.5(Circuit)
533301EAST ST3 115 kV HARTFORD 1102 Westar
12.5(Circuit)
533301EAST ST3 115 kV
MELVERN / BETO JUNCTION 1108 Westar
12.5(Circuit)
533308VAUGHN 3 115 kV OLPE 1112 Westar 12.5 (Bus) OLPE DEDUCT (A) 1112M Westar 12.5 (E)533306READING3 115 kV READING 1104 Westar
12.5(Circuit)
READING DEDUCT (A) 706B Westar 12.5 (Bus)
533302EEUREKA3 115 kV TORONTO 1004 Westar 12.5(Circuit)533631CC4VERN2 69 kV VERNON KCC04 Westar 12.5(Bus)533308VAUGHN 3 115 kV VIRGIL 1003 Westar 12.5(Circuit)533301EAST ST3 115 kV WAVERLY 1005 Westar 34.5533309WEMPORI3 115 kV WEST EMPORIA 1106 Westar
12.5(Low Side)
533630CC3WEST2 69 kV WESTPHALIA KCC03 Westar 12.5(Bus)533310 WILLIAMS 1113 Westar 4.2
29 1431666 & 74318195
WMBROS 3 115 kV (Low Side)533653WOLFCRK2 69 kV WOLF CREEK KCC06 Westar
12.5(Low Side)
APPENDIX 3 – DELIVERY POINTS – Westar Energy System – Continues(a) (b) (c) (d)
Voltage (Meter)
(kV)
SPP Bus Number / Name
Delivery Point Name Delivery Point #
Ownership (Meter)
(1)RADIANT COOP533674ALTOO W 2 69 kV ALTOONA KRA02 Westar
12.5(Circuit)
533707RA6BROO2 69 kV BROOKS KRA06 Westar
12.5(Low Side)
533708RA7CANY2 69 kV CANEY KRA07 Westar
12.5(Low Side)
533683COFFSUB2 69 kV COFFEYVILLE KRA09 Westar
12.5(Circuit)
533706RA5HIPR2 69 kV HIGH PRAIRIE KRA05 Westar 69533698MONTGOM2 69 kV INDEPENDENCE KRA03 Westar
12.5(Circuit)
533709RA10LOU2 69 kV LOUISBURG KRA10 Westar
12.5(Low Side)
533692FREDON 2 69 kV SEK PIPELINE KRA11A Westar 69533705RA1FRED2 69 kV STUDEBAKER KRA11B Westar
12.5(Low Side)
ROLLING HILLS COOP533376SALINA 3 115 kV NEW BEVERLY 2201 Westar
12.5(Low Side)
KEPCo SHARPE AUX533629CC2SHAR2 69 kV
SHARPE GEN AUXILLARY AUX Westar
0.48(Low Side)
30 1431666 & 74318195
APPENDIX 3 – DELIVERY POINTS – Westar Energy System – Continues(a) (b) (c) (d)
Voltage (Meter)
(kV)
SPP Bus Number / Name
Delivery Point Name Delivery Point #
Ownership (Meter)
(1)SEDGWICK COOP533872SG4ANDL2 69 kV ANDALE KSG04 Westar
12.5(Low Side)
533871SG1CHEN2 69 kV CHENEY KSG01 Westar
12.5(Low Side)
533785CHENEY 2 69 kV
CHENEY LAKE OZONE PLANT KSG14 Westar
0.48(Low Side)
533812LIN 2 69 kV CLEARWATER KSG05 Westar
12.5(Circuit)
533065SG12COL4 138 kV COLWICH KSG12 Westar 12.5 (Bus)533873SG8CRAG2 69 kV CRAIG KSG08 Westar
12.5(Low Side)
533844SUNSET-2 69 kV GARDEN PLAIN KSG02 Westar
12.5(Circuit)
533736HALSTED2 69 kV HALSTEAD KSG03 Westar
12.5(Circuit)
533795GILL E 2 69 kV HAYSVILLE KSG13 Westar
12.5(Circuit)
533875SG11KOC2 69 kV KOCH KSG11 Westar
2.4(Low Side)
533874SG9STMK2 69 kV ST MARKS KSG09 Westar
12.5(Low Side)
533794GALE 2 69 kV WATERLOO KSG07 Westar
12.5(Circuit)
31 1431666 & 74318195
APPENDIX 3 – DELIVERY POINTS – Westar Energy System – Continues(a) (b) (c) (d)
Voltage (Meter) (kV)
SPP Bus Number / Name
Delivery Point Name Delivery Point #
Ownership (Meter)
(1)SUMNER-COWLEY COOP533866SC9ANSN2 69 kV ANSON KSC09 Westar
12.5(Low Side)
533063SC10BEL4 138 kV BELLE PLAINE KSC10 Westar
12.5(Low Side)
533555SC7CRES2 69 kV CRESWELL KSC07 Westar
12.5(Low Side)
533549RAINBOW2 69 kV GEUDA KSC02 Westar
12.5(Circuit)
533551SC1KING2 69 kV KING KSC01 Westar
12.5(Low Side)
533552SC3MILL2 69 kV MILLER KSC03 Westar
12.5(Low Side)
532982OXFORD 4 138 kV OXFORD KSC11 Westar 12.5(Bus) 533783BELL 2 69 kV RIVERDALE KSC08 Westar
12.5(Circuit)
533553SC4ROME2 69 kV ROME KSC04 Westar 69533554SC5SILV2 69 kV SILVERDALE KSC05 Westar 69TWIN VALLEY COOP533008TV1MNDV4 138 kV MOUND VALLEY KTV01 Westar
13.2(Low Side)
533005NEPARSN4 138 kV NORTH PARSONS 802 Westar
13.2(Circuit)
533005NEPARSN4 138 kV
NORTHEAST PARSONS 803 Westar
13.2(Circuit)
533695LABETTE2 69 kV OSWEGO 804 Westar
13.2(Circuit)
533671ALTAMNT2 69 kV
SOUTH PARSONS (B) 801 Westar
13.2(Circuit)
FOOTNOTES:
(1)kV value where meter is physically located. (Location) = Meter located on Distribution. (Low Side) = Low Side of Transformer, (Bus) = Meter located on distribution bus after switch or voltage regulator, and (Circuit) = Meter located on distribution circuit.
32 1431666 & 74318195
(A) Deduct Meter: The deduct meter is a reduction to the KEPCo Delivery Point Meter in order to determine KEPCo Net Load.
(B)There is a proposed project to convert this delivery point to 138kV circuit 533009 in about 2012.
(C) Fostoria Deduct Meter is an offset to Fostoria DP. This meter measures Westar Energy’s load connected to Bluestem REC wires. Distribution Loss % equals 2.80% for Fostoria DP + 3.99% for use of Bluestem REC wires to Westar load, per agreement between parties.
(D) Herington Deduct Meter is an offset to Herington DP. This meter measures Westar Energy’s load connected to Flint Hill REC wires. Distribution Loss % equals 1.39% for Herington DP + 3.00% for use of Flint Hills REC wires to Westar load, per agreement between parties.
(E) Olpe & Reading Deduct Meters are offsets to Olpe and Reading DP, respectively. These meters measure Westar Energy’s load connected to Lyon-Coffey REC wires. Distribution Loss % is 5.00%, per agreement between parties.
33 1431666 & 74318195
Appendix 4
Wholesale Distribution Service Charges
34 1431666 & 74318195
Appendix 4
FOR DELIVERY POINTS CONNECTED TO WESTAR ENERGY’S SYSTEM ONLY
Total KEPCo Wholesale Distribution Service Charge (Monthly) = $ 61,487.04 – Effective June 1, 2011(Details per REC on following pages)
TRANSMISSION CUSTOMER LOAD EFFECTIVE
KEPCo - Ark Valley REC See list below Oct 1, 2010
Load Location NPPC %
Substation Distribution Plant
Dollars
Customer Allocation of Substation
Substation WDS Dollars
Circuit Distribution Plant Dollars
Customer Allocation of
Circuits Circuit WDS
Dollars Total WDS Dollars (a) (b) (c) (d) (e) (f) (g) (b*c*a) (e*f*a) (Total Cols d + g) Marquette-Langley 1.510% $ - 0.00% $ - $ - 0.00% $ - $ - Medora 1.510% $ - 0.00% $ - $ - 0.00% $ - $ - Sand Hill 1.510% $ - 0.00% $ - $ - 0.00% $ - $ - Yoder 1.510% $ - 0.00% $ - $ - 0.00% $ - $ -
Totals $ - $ - $ -
35 1431666 & 74318195
APPENDIX 4 – WHOLESALE DISTRIBUTION SERVICE CHARGE – Westar Energy System – Continues TRANSMISSION CUSTOMER LOAD EFFECTIVE
KEPCo - Bluestem REC See list below Oct 1, 2010
Load Location NPPC %
Substation Distribution Plant
Dollars
Customer Allocation of Substation
Substation WDS Dollars
Circuit Distribution Plant Dollars
Customer Allocation of
Circuits Circuit WDS
Dollars Total WDS Dollars (a) (b) (c) (d) (e) (f) (g) (b*c*a) (e*f*a) (Total Cols d + g) Alma 1.510% $ 107,841.97 21.57% $ 351.22 $ 212.65 100.00% $ 3.21 $ 354.43 Blue Rapids 1.510% $ 30,154.38 96.08% $ 437.50 $ - 0.00% $ - $ 437.50 Clay Center 1.510% $ 17,687.97 100.00% $ 267.09 $ 135.60 100.00% $ 2.05 $ 269.14 Fostoria 1.510% $ 35,196.46 13.83% $ 73.49 $ 91,255.72 13.83% $ 190.54 $ 264.03 Hunter's Island 1.510% $ 632,831.18 3.57% $ 341.10 $ 34,054.09 14.55% $ 74.80 $ 415.90 Louisville 1.510% $ 613,945.45 29.51% $ 2,736.11 $ 8,136.00 59.03% $ 72.52 $ 2,808.63 Leonardville 1.510% $ - 0.00% $ - $ - 0.00% $ - $ - Peddicord 1.510% $ 56,716.31 92.87% $ 795.32 $ - 0.00% $ - $ 795.32 Soldier 1.510% $ 25,203.33 66.50% $ 253.07 $ 382.15 66.50% $ 3.84 $ 256.91 St. George 1.510% $ 411,609.51 54.34% $ 3,377.38 $ 215.73 100.00% $ 3.26 $ 3,380.64 Wakefield 1.510% $ 66,909.68 5.53% $ 55.85 $ - 0.00% $ - $ 55.85 Wamego 1.510% $ 16,184.18 100.00% $ 244.38 $ - 0.00% $ - $ 244.38
Totals $ 8,932.51 $ 350.22 $ 9,282.73
36 1431666 & 74318195
APPENDIX 4 – WHOLESALE DISTRIBUTION SERVICE CHARGE – Westar Energy System – Continues TRANSMISSION CUSTOMER LOAD EFFECTIVE
KEPCo - Brown-Atchison REC See list below Oct 1, 2010
Load Location NPPC %
Substation Distribution Plant
Dollars
Customer Allocation of Substation
Substation WDS Dollars
Circuit Distribution Plant Dollars
Customer Allocation of
Circuits Circuit WDS
Dollars Total WDS Dollars (a) (b) (c) (d) (e) (f) (g) (b*c*a) (e*f*a) (Total Cols d + g) Circleville 1.510% $ 130,452.62 47.52% $ 936.03 $ 6,006.46 47.52% $ 43.10 $ 979.13 East Fairview 1.510% $ 63,046.00 21.34% $ 203.12 $ 16,694.21 21.34% $ 53.79 $ 256.91 East Hiawatha 1.510% $ 92,366.70 11.06% $ 154.31 $ 64,955.48 34.70% $ 340.34 $ 494.65 Lancaster 1.510% $ 26,903.38 52.75% $ 214.31 $ 18,053.29 52.75% $ 143.81 $ 358.12 Muscotah 1.510% $ 40,993.95 6.30% $ 38.97 $ 30,996.93 62.96% $ 294.70 $ 333.67 Netawaka 1.510% $ 58,563.88 56.58% $ 500.38 $ 4,289.89 100.00% $ 64.78 $ 565.16 North Hiawatha 1.510% $ 61,177.56 14.67% $ 135.52 $ 131,861.75 18.86% $ 375.55 $ 511.07
$ 76,887.11 20.79% $ 241.32 $ 18,241.28 31.18% $ 85.88 $ 1,026.95 Nortonville 1.510% $ 222,945.29 20.79% $ 699.75
South Fairview 1.510% $ - 0.00% $ - $ - 0.00% $ - $ - Willis 1.510% $ - 0.00% $ - $ - 0.00% $ - $ -
Totals $ 3,123.71 $ 1,401.95 $ 4,525.66
37 1431666 & 74318195
APPENDIX 4 – WHOLESALE DISTRIBUTION SERVICE CHARGE – Westar Energy System – Continues TRANSMISSION CUSTOMER LOAD EFFECTIVE
KEPCo - Butler REC See list below Oct 1, 2010
Load Location NPPC
%
Substation Distribution Plant
Dollars
Customer Allocation
of Substation
Substation WDS Dollars
Circuit Distribution Plant Dollars
Customer Allocation
of Circuits
Circuit WDS Dollars Total WDS Dollars
(a) (b) (c) (d) (e) (f) (g) (b*c*a) (e*f*a) (Total Cols d + g) Benton 1.510% $ - 0.00% $ - $ - 0.00% $ - $ - De Graff 1.510% $ - 0.00% $ - $ - 0.00% $ - $ - Eureka 1.510% $ - 0.00% $ - $ - 0.00% $ - $ - Furley 1.510% $ - 0.00% $ - $ - 0.00% $ - $ - Keighley 1.510% $ - 0.00% $ - $ - 0.00% $ - $ - Leon 1.510% $ 151,010.72 34.02% $ 775.75 $ 9,975.85 80.29% $ 120.94 $ 896.69 Little Pony Meadows 1.510% $ - 0.00% $ - $ - 0.00% $ - $ - Newton (A) 1.370% $ 340,990.81 1.97% $ 92.03 $ 66,996.00 10.18% $ 93.44 $ 185.47Pony Meadows 1.510% $ - 0.00% $ - $ - 0.00% $ - $ - Potwin 1.510% $ 14,095.36 15.41% $ 32.81 $ 554.73 51.38% $ 4.30 $ 37.11 Rose Hill 1.510% $ 77,545.00 23.79% $ 278.52 $ 7,399.45 30.24% $ 33.78 $ 312.30 Smileyburg 1.510% $ 23,928.86 47.07% $ 170.07 $ 7,747.69 47.07% $ 55.06 $ 225.13 Spurrier 1.510% $ 1,589,257.74 5.13% $ 1,231.37 $ 35,370.03 14.66% $ 78.30 $ 1,309.67 Towanda 1.510% $ 25,105.90 13.48% $ 51.09 $ 59,639.35 49.92% $ 449.52 $ 500.61
Totals $ 2,631.64 $ 835.34 $ 3,466.98
38 1431666 & 74318195
APPENDIX 4 – WHOLESALE DISTRIBUTION SERVICE CHARGE – Westar Energy System – Continues TRANSMISSION CUSTOMER LOAD EFFECTIVE
KEPCo - Caney Valley REC See list below Oct 1, 2010
Load Location NPPC %
Substation Distribution Plant
Dollars
Customer Allocation of Substation
Substation WDS Dollars
Circuit Distribution Plant Dollars
Customer Allocation of
Circuits Circuit WDS
Dollars Total WDS Dollars (a) (b) (c) (d) (e) (f) (g) (b*c*a) (e*f*a) (Total Cols d + g) Burden 1.510% $ 31,005.95 17.78% $ 83.23 $ 206,904.03 24.69% $ 771.42 $ 854.65 Caney 1.510% $ - 0.00% $ - $ - 0.00% $ - $ - Grenola 1.510% $ 190,243.35 16.26% $ 467.05 $ 97,986.41 66.12% $ 978.28 $ 1,445.33 Harshman 1.510% $ 190,243.35 10.44% $ 299.90 $ 32,448.46 53.07% $ 260.02 $ 559.92 Longton 1.510% $ 20,740.03 40.31% $ 126.24 $ 182,431.31 40.31% $ 1,110.44 $ 1,236.68 McCall 1.510% $ - 0.00% $ - $ - 0.00% $ - $ - Sedan Switching Station 1.510% $ - 0.00% $ - $ - 0.00% $ - $ - Silverdale 1.510% $ 214,461.23 4.13% $ 133.81 $ 147,927.27 14.42% $ 322.16 $ 455.97 Tisdale 1.510% $ 31,005.95 8.52% $ 39.88 $ 177,448.01 11.83% $ 317.01 $ 356.89
Totals $ 1,150.11 $ 3,759.33 $ 4,909.44
39 1431666 & 74318195
APPENDIX 4 – WHOLESALE DISTRIBUTION SERVICE CHARGE – Westar Energy System – Continues TRANSMISSION CUSTOMER LOAD EFFECTIVE
KEPCo - DS&O REC See list below Oct 1, 2010
Load Location NPPC %
Substation Distribution Plant
Dollars
Customer Allocation of Substation
Substation WDS Dollars
Circuit Distribution Plant Dollars
Customer Allocation of
Circuits Circuit WDS
Dollars Total WDS Dollars (a) (b) (c) (d) (e) (f) (g) (b*c*a) (e*f*a) (Total Cols d + g) Assaria 1.510% $ 7,763.96 100.00% $ 117.24 $ - 0.00% $ - $ 117.24 Bennington 1.510% $ 27,514.77 13.50% $ 56.10 $ 51,336.93 20.00% $ 155.07 $ 211.17 Chapman 1.510% $ 160,411.74 87.32% $ 2,114.99 $ 206.48 100.00% $ 3.12 $ 2,118.11 Gypsum 1.510% $ 85,943.67 40.16% $ 521.22 $ 17,350.64 94.93% $ 248.71 $ 769.93 K-18 1.510% $ - 0.00% $ - $ - 0.00% $ - $ - Magnolia 1.510% $ 304,123.10 9.85% $ 452.29 $ 24,836.37 36.61% $ 137.31 $ 589.60 Marquette 1.510% $ - 0.00% $ - $ - 0.00% $ - $ - Milford 1.510% $ - 0.00% $ - $ - 0.00% $ - $ - Minneapolis 1.510% $ 47,498.46 100.00% $ 717.23 $ - 0.00% $ - $ 717.23 North Salina 1.510% $ - 0.00% $ - $ - 0.00% $ - $ - NW Junction City 1.510% $ 23,854.26 19.11% $ 68.83 $ 8,191.47 100.00% $ 123.69 $ 192.52 Pearl 1.510% $ 48,899.40 97.47% $ 719.72 $ - 0.00% $ - $ 719.72 Ramona 1.510% $ 23,571.89 100.00% $ 355.94 $ - 0.00% $ - $ 355.94 Solomon 1.510% $ 24,638.63 100.00% $ 372.04 $ - 0.00% $ - $ 372.04 Southwest Abilene 1.510% $ 78,594.44 57.41% $ 681.30 $ 135.60 100.00% $ 2.05 $ 683.35 Talmage #1 1.510% $ 450,864.50 94.87% $ 6,458.58 $ 998.51 94.87% $ 14.30 $ 6,472.88 Talmage #2 1.510% $ - 0.00% $ - $ - 0.00% $ - $ - Upland 1.510% $ 182,399.37 70.24% $ 1,934.59 $ - 0.00% $ - $ 1,934.59 West Lindsborg 1.510% $ - 0.00% $ - $ - 0.00% $ - $ - West Salina 1.510% $ 757,361.06 8.84% $ 1,010.70 $ 14,872.85 47.24% $ 106.08 $ 1,116.78
Totals $15,580.77 $ 790.33 $ 16,371.10
40 1431666 & 74318195
APPENDIX 4 – WHOLESALE DISTRIBUTION SERVICE CHARGE – Westar Energy System – Continues TRANSMISSION CUSTOMER LOAD EFFECTIVE
KEPCo - Flint Hills REC See list below Oct 1, 2010
Load Location NPPC %
Substation Distribution Plant
Dollars
Customer Allocation
of Substation
Substation WDS Dollars
Circuit Distribution Plant Dollars
Customer Allocation of Circuits
Circuit WDS Dollars Total WDS Dollars
(a) (b) (c) (d) (e) (f) (g) (b*c*a) (e*f*a) (Total Cols d + g) Alta Vista 1.510% $ - 0.00% $ - $ - 0.00% $ - $ - Alta Vista South 1.510% $ 89,894.55 16.42% $ 222.83 $ 64,835.29 16.42% $ 160.72 $ 383.55 Cottonwood Falls 1.510% $ - 0.00% $ - $ - 0.00% $ - $ - Council Grove East 1.510% $ - 0.00% $ - $ - 0.00% $ - $ - Council Grove West 1.510% $ 63,961.49 10.50% $ 101.37 $ 76,922.18 37.95% $ 440.77 $ 542.14 Durham 1.510% $ - 0.00% $ - $ - 0.00% $ - $ - Florence 1.510% $ 13,146.39 27.92% $ 55.43 $ 95,567.18 27.92% $ 402.97 $ 458.40 Goessel 1.510% $ - 0.00% $ - $ - 0.00% $ - $ - Herington 1.510% $ 32,882.73 100.00% $ 496.53 $ - 0.00% $ - $ 496.53 Hillsboro 1.510% $ 6,535.61 100.00% $ 98.69 $ - 0.00% $ - $ 98.69 Junction City 1.510% $ - 0.00% $ - $ - 0.00% $ - $ - Lehigh 1.510% $ 87,267.25 59.88% $ 789.01 $ 104.78 100.00% $ 1.58 $ 790.59 Marion 1.510% $ 35,741.33 59.47% $ 320.95 $ - 0.00% $ - $ 320.95 Peabody 1.510% $ 7,088.83 19.19% $ 20.54 $ 921.46 19.19% $ 2.67 $ 23.21
Totals $ 2,105.35 $ 1,008.71 $ 3,114.06
41 1431666 & 74318195
APPENDIX 4 – WHOLESALE DISTRIBUTION SERVICE CHARGE – Westar Energy System – Continues TRANSMISSION CUSTOMER LOAD EFFECTIVE
KEPCo - Heartland REC See list below Oct 1, 2010
Load Location NPPC %
Substation Distribution Plant
Dollars
Customer Allocation of Substation
Substation WDS Dollars
Circuit Distribution Plant Dollars
Customer Allocation of
Circuits Circuit WDS
Dollars Total WDS Dollars (a) (b) (c) (d) (e) (f) (g) (b*c*a) (e*f*a) (Total Cols d + g) Baker 1.510% $ 94,268.77 13.65% $ 194.29 $ 46.23 100.00% $ 0.70 $ 194.99 Cherokee 1.510% $ 94,268.77 15.45% $ 219.91 $ 40,914.22 22.61% $ 139.68 $ 359.59 Conger 1.510% $ - 0.00% $ - $ - 0.00% $ - $ - Devon 1.510% $ - 0.00% $ - $ - 0.00% $ - $ - Elsmore 1.510% $ - 0.00% $ - $ - 0.00% $ - $ - Englevale 1.510% $ 111,887.79 30.77% $ 519.87 $ 119,207.81 37.61% $ 676.97 $ 1,196.84 Greenbush 1.510% $ - 0.00% $ - $ - 0.00% $ - $ - Hiattville 1.510% $ - 0.00% $ - $ - 0.00% $ - $ - Magellan 1.510% $ - 0.00% $ - $ - 0.00% $ - $ - McCune 1.510% $ 28,040.70 23.44% $ 99.26 $ 1,081.72 82.05% $ 13.40 $ 112.66 Rose 1.510% $ - 0.00% $ - $ - 0.00% $ - $ - SE Humboldt 1.510% $ 88,675.19 7.19% $ 96.25 $ 73,143.87 15.81% $ 174.66 $ 270.91 Urbana 1.510% $ - 0.00% $ - $ - 0.00% $ - $ -
Totals $ 1,129.58 $ 1,005.41 $ 2,134.99
42 1431666 & 74318195
APPENDIX 4 – WHOLESALE DISTRIBUTION SERVICE CHARGE – Westar Energy System – Continues TRANSMISSION CUSTOMER LOAD EFFECTIVE
KEPCo - Leavenworth-Jefferson REC See list below Oct 1, 2010
Load Location NPPC %
Substation Distribution Plant
Dollars
Customer Allocation of Substation
Substation WDS Dollars
Circuit Distribution Plant Dollars
Customer Allocation of
Circuits Circuit WDS
Dollars Total WDS Dollars (a) (b) (c) (d) (e) (f) (g) (b*c*a) (e*f*a) (Total Cols d + g) Hoyt 1.510% $ 450,153.91 41.11% $ 2,794.46 $ 27,329.56 47.44% $ 195.76 $ 2,990.22 Mayetta 1.510% $ 33,894.22 45.76% $ 234.19 $ 8,576.70 45.76% $ 59.26 $ 293.45 NW Leavenworth 1.510% $ - 0.00% $ - $ - 0.00% $ - $ -
$ 76,887.11 19.51% $ 226.50 $ 24,494.29 29.26% $ 108.24 $ 991.51 Nortonville 1.510% $ 222,945.29 19.51% $ 656.77
Oskaloosa 1.510% $ - 0.00% $ - $ - 0.00% $ - $ - Rock Creek 1.510% $ 241,920.54 38.79% $ 1,417.01 $ 40.06 100.00% $ 0.60 $ 1,417.61 Stranger 1.510% $ - 0.00% $ - $ - 0.00% $ - $ - Tonganoxie 1.510% $ - 0.00% $ - $ - 0.00% $ - $ - Valley Falls 1.510% $ 238,760.68 9.34% $ 336.91 $ 53,941.06 22.43% $ 182.68 $ 519.59
Totals $ 5,665.84 $ 546.54 $ 6,212.38
43 1431666 & 74318195
APPENDIX 4 – WHOLESALE DISTRIBUTION SERVICE CHARGE – Westar Energy System – Continues
TRANSMISSION CUSTOMER LOAD EFFECTIVE
KEPCo - Lyon-Coffey REC See list below Oct 1, 2010
Load Location NPPC %
Substation Distribution Plant
Dollars
Customer Allocation of Substation
Substation WDS Dollars
Circuit Distribution Plant Dollars
Customer Allocation of
Circuits Circuit WDS
Dollars Total WDS Dollars (a) (b) (c) (d) (e) (f) (g) (b*c*a) (e*f*a) (Total Cols d + g) Americus - T. Bird 1.510% $ - 0.00% $ - $ - 0.00% $ - $ - Melvern/Beto Junction 1.510% $ 17,625.21 37.99% $ 101.11 $ 67,713.71 75.98% $ 776.93 $ 878.04 Burlington 1.510% $ - 0.00% $ - $ - 0.00% $ - $ - Eskridge 1.510% $ 21,565.41 25.14% $ 81.86 $ 38,985.00 25.14% $ 147.98 $ 229.84 Hartford 1.510% $ 91,140.50 5.11% $ 70.32 $ 45,903.68 25.55% $ 177.09 $ 247.41 Olpe 1.510% $ 153,643.50 30.35% $ 704.23 $ - 0.00% $ - $ 704.23 Reading 1.510% $ 234,075.33 23.81% $ 841.66 $ 27.74 100.00% $ 0.42 $ 842.08 Toronto 1.510% $ 136,568.05 24.13% $ 497.61 $ 59,472.93 40.84% $ 366.72 $ 864.33 Vernon 1.510% $ - 0.00% $ - $ - 0.00% $ - $ - Virgil 1.510% $ 52,730.06 40.12% $ 319.47 $ 100,621.36 64.81% $ 984.79 $ 1,304.26 Waverly 1.510% $ - 0.00% $ - $ - 0.00% $ - $ - West Emporia 1.510% $ - 0.00% $ - $ - 0.00% $ - $ - Westphalia 1.510% $ - 0.00% $ - $ - 0.00% $ - $ - Williams 1.510% $ - 0.00% $ - $ - 0.00% $ - $ - Wolf Creek 1.510% $ - 0.00% $ - $ - 0.00% $ - $ -
Totals $ 2,616.26 $ 2,453.93 $ 5,070.19
44 1431666 & 74318195
APPENDIX 4 – WHOLESALE DISTRIBUTION SERVICE CHARGE – Westar Energy System – Continues
TRANSMISSION CUSTOMER LOAD EFFECTIVE
KEPCo - Radiant REC See list below Oct 1, 2010
Load Location NPPC %
Substation Distribution Plant
Dollars
Customer Allocation of Substation
Substation WDS Dollars
Circuit Distribution Plant Dollars
Customer Allocation of
Circuits Circuit WDS
Dollars Total WDS Dollars (a) (b) (c) (d) (e) (f) (g) (b*c*a) (e*f*a) (Total Cols d + g) Altoona 1.510% $ 7,970.84 34.75% $ 41.82 $ 41,358.00 34.75% $ 216.99 $ 258.81 Brooks 1.510% $ - 0.00% $ - $ - 0.00% $ - $ - Caney 1.510% $ - 0.00% $ - $ - 0.00% $ - $ - Coffeyville 1.510% $ 22,916.69 48.43% $ 167.60 $ 17,631.08 48.43% $ 128.94 $ 296.54 High Prairie 1.510% $ - 0.00% $ - $ - 0.00% $ - $ - Independence 1.510% $ 205,582.67 2.13% $ 66.19 $ 109,231.96 10.80% $ 178.18 $ 244.37 Louisburg 1.510% $ - 0.00% $ - $ - 0.00% $ - $ - SEK Pipeline 1.510% $ - 0.00% $ - $ - 0.00% $ - $ - Studebaker 1.510% $ - 0.00% $ - $ - 0.00% $ - $ -
Totals $ 275.61 $ 524.11 $ 799.72
45 1431666 & 74318195
APPENDIX 4 – WHOLESALE DISTRIBUTION SERVICE CHARGE – Westar Energy System – Continues TRANSMISSION CUSTOMER LOAD EFFECTIVE
KEPCo - Rolling Hills REC See list below Oct 1, 2010
Load Location NPPC % Substation Distribution
Plant Dollars
Customer Allocation of Substation
Substation WDS Dollars
Circuit Distribution Plant Dollars
Customer Allocation of
Circuits Circuit WDS
Dollars Total WDS Dollars (a) (b) (c) (d) (e) (f) (g) (b*c*a) (e*f*a) (Total Cols d + g) New Beverly 1.510% $ - 0.00% $ - $ - 0.00% $ - $ -
Totals $ - $ - $ -
TRANSMISSION CUSTOMER LOAD EFFECTIVEKEPCo - Sharpe Gen Aux See below list Oct 1, 2010
Load Location NPPC % Substation Distribution
Plant Dollars
Customer Allocation of Substation
Substation WDS Dollars
Circuit Distribution Plant Dollars
Customer Allocation of
Circuits Circuit WDS
Dollars Total WDS Dollars (a) (b) (c) (d) (e) (f) (g) (b*c*a) (e*f*a) (Total Cols d + g) Auxillary Load 1.510% $ - 0.00% $ - $ - 0.00% $ - $ -
Totals $ - $ - $ -
46 1431666 & 74318195
APPENDIX 4 – WHOLESALE DISTRIBUTION SERVICE CHARGE – Westar Energy System – Continues TRANSMISSION CUSTOMER LOAD EFFECTIVE
KEPCo - Sedgwick REC See list below Oct 1, 2010
Load Location NPPC % Substation Distribution
Plant Dollars
Customer Allocation of Substation
Substation WDS Dollars
Circuit Distribution Plant Dollars
Customer Allocation of
Circuits Circuit WDS
Dollars Total WDS Dollars (a) (b) (c) (d) (e) (f) (g) (b*c*a) (e*f*a) (Total Cols d + g) Andale 1.510% $ - 0.00% $ - $ - 0.00% $ - $ - Cheney 1.510% $ - 0.00% $ - $ - 0.00% $ - $ - Cheney Lake Ozone Plant 1.510% $ - 0.00% $ - $ - 0.00% $ - $ - Clearwater 1.510% $ 1,262,823.30 12.13% $ 2,313.36 $ 67,183.64 29.17% $ 295.96 $ 2,609.32 Colwich 1.510% $ - 0.00% $ - $ - 0.00% $ - $ - Craig 1.510% $ - 0.00% $ - $ - 0.00% $ - $ - Garden Plain 1.510% $ 34,582.20 4.61% $ 24.09 $ 456.11 100.00% $ 6.89 $ 30.98 Halstead 1.510% $ 38,406.29 12.05% $ 69.87 $ 47,493.90 45.56% $ 326.71 $ 396.58 Haysville 1.510% $ 45,337.48 43.75% $ 299.49 $ 44,732.59 43.75% $ 295.50 $ 594.99 Koch 1.510% $ - 0.00% $ - $ - 0.00% $ - $ - St. Marks 1.510% $ - 0.00% $ - $ - 0.00% $ - $ - Waterloo 1.510% $ 1,219.95 27.69% $ 5.10 $ 1,685.75 27.69% $ 7.05 $ 12.15
Totals $ 2,711.91 $ 932.11 $ 3,644.02
47 1431666 & 74318195
APPENDIX 4 – WHOLESALE DISTRIBUTION SERVICE CHARGE – Westar Energy System – Continues TRANSMISSION CUSTOMER LOAD EFFECTIVE
KEPCo - Sumner-Cowley REC See list below Oct 1, 2010
Load Location NPPC % Substation Distribution
Plant Dollars
Customer Allocation of Substation
Substation WDS Dollars
Circuit Distribution Plant Dollars
Customer Allocation of
Circuits Circuit WDS
Dollars Total WDS Dollars (a) (b) (c) (d) (e) (f) (g) (b*c*a) (e*f*a) (Total Cols d + g) Anson 1.510% $ - 0.00% $ - $ - 0.00% $ - $ - Belle Plaine 1.510% $ - 0.00% $ - $ - 0.00% $ - $ - Creswell 1.510% $ - 0.00% $ - $ - 0.00% $ - $ - Geuda 1.510% $ 23,848.77 9.75% $ 35.11 $ 65,994.05 13.65% $ 136.01 $ 171.12 King 1.510% $ - 0.00% $ - $ - 0.00% $ - $ - Miller 1.510% $ - 0.00% $ - $ - 0.00% $ - $ - Oxford 1.510% $ 117,290.11 20.45% $ 362.10 $ - 0.00% $ - $ 362.10 Riverdale 1.510% $ 30,956.86 12.23% $ 57.15 $ 123.27 100.00% $ 1.86 $ 59.01 Rome 1.510% $ - 0.00% $ - $ - 0.00% $ - $ - Silverdale 1.510% $ - 0.00% $ - $ - 0.00% $ - $ -
Totals $ 454.36 $ 137.87 $ 592.23
48 1431666 & 74318195
APPENDIX 4 – WHOLESALE DISTRIBUTION SERVICE CHARGE – Westar Energy System – Continues TRANSMISSION CUSTOMER LOAD EFFECTIVE
KEPCo - Twin Valley REC See list below Oct 1, 2010
Load Location NPPC %
Substation Distribution Plant
Dollars
Customer Allocation of Substation
Substation WDS Dollars
Circuit Distribution Plant Dollars
Customer Allocation of
Circuits Circuit WDS
Dollars Total WDS Dollars (a) (b) (c) (d) (e) (f) (g) (b*c*a) (e*f*a) (Total Cols d + g) Mound Valley 1.510% $ - 0.00% $ - $ - 0.00% $ - $ -
$ 327,071.49 7.05% $ 348.16 $ 40,569.05 26.74% $ 163.79 $ 581.92 North Parsons 1.510% $ 65,735.15 7.05% $ 69.97 $ 327,071.49 2.63% $ 130.05 $ 58,514.48 22.13% $ 195.56 $ 351.75 Northeast Parsons 1.510% $ 65,735.15 2.63% $ 26.14 $ 166,049.07 5.42% $ 135.97 $ 2,767.47 13.91% $ 5.81 $ 141.78 Oswego 1.510% $ - 0.00% $ - $ 65,434.98 28.41% $ 280.70 $ 782.78 62.50% $ 7.39 $ 288.09 South Parsons 1.510% $ - 0.00% $ -
Totals $ 990.99 $ 372.55 $ 1,363.54
NOTES:
A Butler REC, Newton Delivery Point WDS Effective June 1, 2011
49 1431666 & 74318195
ATTACHMENT G
Network Operating Agreement
This Network Operating Agreement ("Operating Agreement") is entered into this 1st day
of June, 2011, by and between Kansas Electric Power Cooperative, Inc. ("Network Customer"),
Southwest Power Pool, Inc. ("Transmission Provider") and Westar Energy, Inc. ("Host
Transmission Owner"). The Network Customer, Transmission Provider and Host Transmission
Owner shall be referred to individually as a “Party” and collectively as "Parties."
WHEREAS, the Transmission Provider has determined that the Network Customer has
made a valid request for Network Integration Transmission Service in accordance with the
Transmission Provider’s Open Access Transmission Tariff ("Tariff") filed with the Federal
Energy Regulatory Commission ("Commission");
WHEREAS, the Transmission Provider administers Network Integration Transmission
Service for Transmission Owners within the SPP Region and acts as an agent for these
Transmission Owners in providing service under the Tariff;
WHEREAS, the Host Transmission Owner owns the transmission facilities to which the
Network Customer’s Network Load is physically connected or is the Control Area to which the
Network Load is dynamically scheduled;
WHEREAS, the Network Customer has represented that it is an Eligible Customer under
the Tariff;
WHEREAS, the Network Customer and Transmission Provider have entered into a
Network Integration Transmission Service Agreement (“Service Agreement”) under the Tariff;
and
WHEREAS, the Parties intend that capitalized terms used herein shall have the same
meaning as in the Tariff, unless otherwise specified herein.
NOW, THEREFORE, in consideration of the mutual covenants and agreements herein,
the Parties agree as follows:
1.0 Network Service
This Operating Agreement sets out the terms and conditions under which the
Transmission Provider, Host Transmission Owner, and Network Customer will cooperate
50 1431666 & 74318195
and the Host Transmission Owner and Network Customer will operate their respective
systems and specifies the equipment that will be installed and operated. The Parties shall
operate and maintain their respective systems in a manner that will allow the Host
Transmission Owner and the Network Customer to operate their systems and Control
Area and the Transmission Provider to perform its obligations consistent with Good
Utility Practice. The Transmission Provider may, on a non-discriminatory basis, waive
the requirements of Section 4.1 and Section 8.3 to the extent that such information is
unknown at the time of application or where such requirement is not applicable.
2.0 Designated Representatives of the Parties
2.1 Each Party shall designate a representative and alternate ("Designated
Representative(s)") from their respective company to coordinate and implement,
on an ongoing basis, the terms and conditions of this Operating Agreement,
including planning, operating, scheduling, redispatching, curtailments, control
requirements, technical and operating provisions, integration of equipment,
hardware and software, and other operating considerations.
2.2 The Designated Representatives shall represent the Transmission Provider, Host
Transmission Owner, and Network Customer in all matters arising under this
Operating Agreement and which may be delegated to them by mutual agreement
of the Parties hereto.
2.3 The Designated Representatives shall meet or otherwise confer at the request of
any Party upon reasonable notice, and each Party may place items on the meeting
agenda. All deliberations of the Designated Representatives shall be conducted
by taking into account the exercise of Good Utility Practice. If the Designated
Representatives are unable to agree on any matter subject to their deliberation,
that matter shall be resolved pursuant to Section 12.0 of the Tariff, or otherwise,
as mutually agreed by the Parties.
3.0 System Operating Principles
3.1 The Network Customer must design, construct, and operate its facilities safely
and efficiently in accordance with Good Utility Practice, NERC, SPP, or any
51 1431666 & 74318195
successor requirements, industry standards, criteria, and applicable
manufacturer’s equipment specifications, and within operating physical parameter
ranges (voltage schedule, load power factor, and other parameters) required by the
Host Transmission Owner and Transmission Provider.
3.2 The Host Transmission Owner and Transmission Provider reserve the right to
inspect the facilities and operating records of the Network Customer upon
mutually agreeable terms and conditions.
3.3 Electric service, in the form of three phase, approximately sixty hertz alternating
current, shall be delivered at designated delivery points and nominal voltage(s)
listed in the Service Agreement. When multiple delivery points are provided to a
specific Network Load identified in Appendix 3 of the Service Agreement, they
shall not be operated in parallel by the Network Customer without the approval of
the Host Transmission Owner and Transmission Provider. The Designated
Representatives shall establish the procedure for obtaining such approval. The
Designated Representatives shall also establish and monitor standards and
operating rules and procedures to assure that transmission system integrity and the
safety of customers, the public and employees are maintained or enhanced when
such parallel operations is permitted either on a continuing basis or for
intermittent switching or other service needs. Each Party shall exercise due
diligence and reasonable care in maintaining and operating its facilities so as to
maintain continuity of service.
3.4 The Host Transmission Owner and Network Customer shall operate their systems
and delivery points in continuous synchronism and in accord with applicable
NERC Standards, SPP Criteria, and Good Utility Practice.
3.5 If the function of any Party’s facilities is impaired or the capacity of any delivery
point is reduced, or synchronous operation at any delivery point(s) becomes
interrupted, either manually or automatically, as a result of force majeure or
maintenance coordinated by the Parties, the Parties will cooperate to remove the
cause of such impairment, interruption or reduction, so as to restore normal
operating conditions expeditiously.
52 1431666 & 74318195
3.6 The Transmission Provider and Host Transmission Owner, if applicable, reserve
the sole right to take any action necessary during an actual or imminent
emergency to preserve the reliability and integrity of the Transmission System,
limit or prevent damage, expedite restoration of service, ensure safe and reliable
operation, avoid adverse effects on the quality of service, or preserve public
safety.
3.7 In an emergency, the reasonable judgment of the Transmission Provider and Host
Transmission Owner, if applicable, in accordance with Good Utility Practice,
shall be the sole determinant of whether the operation of the Network Customer
loads or equipment adversely affects the quality of service or interferes with the
safe and reliable operation of the transmission system. The Transmission
Provider or Host Transmission Owner, if applicable, may discontinue
transmission service to such Network Customer until the power quality or
interfering condition has been corrected. Such curtailment of load, redispatching,
or load shedding shall be done on a non-discriminatory basis by Load Ratio
Share, to the extent practicable. The Transmission Provider or Host Transmission
Owner, if applicable, will provide reasonable notice and an opportunity to
alleviate the condition by the Network Customer to the extent practicable.
4.0 System Planning & Protection
4.1 No later than October 1 of each year, the Network Customer shall provide the
Transmission Provider and Host Transmission Owner the following information:
a) A ten (10) year projection of summer and winter peak demands with the
corresponding power factors and annual energy requirements on an
aggregate basis for each delivery point. If there is more than one delivery
point, the Network Customer shall provide the summer and winter peak
demands and energy requirements at each delivery point for the normal
operating configuration;
b) A ten (10) year projection by summer and winter peak of planned
generating capabilities and committed transactions with third parties
53 1431666 & 74318195
which resources are expected to be used by the Network Customer to
supply the peak demand and energy requirements provided in (a);
c) A ten (10) year projection by summer and winter peak of the estimated
maximum demand in kilowatts that the Network Customer plans to
acquire from the generation resources owned by the Network Customer,
and generation resources purchased from others; and
d) A projection for each of the next ten (10) years of transmission facility
additions to be owned and/or constructed by the Network Customer which
facilities are expected to affect the planning and operation of the
transmission system within the Host Transmission Owner’s Control Area.
This information is to be delivered to the Transmission Provider’s and Host
Transmission Owner’s Designated Representatives pursuant to Section 2.0.
4.2 Information exchanged by the Parties under this article will be used for system
planning and protection only, and will not be disclosed to third parties absent
mutual consent or order of a court or regulatory agency.
4.3 The Host Transmission Owner, and Transmission Provider, if applicable, will
incorporate this information in its system load flow analyses performed during the
first half of each year. Following completion of these analyses, the Transmission
Provider or Host Transmission Owner will provide the following to the Network
Customer:
a) A statement regarding the ability of the Host Transmission Owner’s
transmission system to meet the forecasted deliveries at each of the
delivery points;
b) A detailed description of any constraints on the Host Transmission
Owner’s system within the five (5) year horizon that will restrict
forecasted deliveries; and
c) In the event that studies reveal a potential limitation of the Transmission
Provider’s ability to deliver power and energy to any of the delivery
points, a Designated Representative of the Transmission Provider will
coordinate with the Designated Representatives of the Host Transmission
Owner and the Network Customer to identify appropriate remedies for
54 1431666 & 74318195
such constraints including but not limited to: construction of new
transmission facilities, upgrade or other improvements to existing
transmission facilities or temporary modification to operating procedures
designed to relieve identified constraints. Any constraints within the
Transmission System will be remedied pursuant to the procedures of
Attachment O of the Tariff.
For all other constraints the Host Transmission Owner, upon
agreement with the Network Customer and consistent with Good Utility
Practice, will endeavor to construct and place into service sufficient
capacity to maintain reliable service to the Network Customer.
An appropriate sharing of the costs to relieve such constraints will
be determined by the Parties, consistent with the Tariff and with the
Commission’s rules, regulations, policies, and precedents then in effect. If
the Parties are unable to agree upon an appropriate remedy or sharing of
the costs, the Transmission Provider shall submit its proposal for the
remedy or sharing of such costs to the Commission for approval consistent
with the Tariff.
4.4 The Host Transmission Owner and the Network Customer shall coordinate with
the Transmission Provider: (1) all scheduled outages of generating resources and
transmission facilities consistent with the reliability of service to the customers of
each Party, and (2) additions or changes in facilities which could affect another
Party’s system. Where coordination cannot be achieved, the Designated
Representatives shall intervene for resolution.
4.5 The Network Customer shall coordinate with the Host Transmission Owner
regarding the technical and engineering arrangements for the delivery points,
including one line diagrams depicting the electrical facilities configuration and
parallel generation, and shall design and build the facilities to avoid interruptions
on the Host Transmission Owner’s transmission system.
4.6 The Network Customer shall provide for automatic and underfrequency load
shedding of the Network Customer Network Load in accordance with the SPP
Criteria related to emergency operations.
55 1431666 & 74318195
5.0 Maintenance of Facilities
5.1 The Network Customer shall maintain its facilities necessary to reliably receive
capacity and energy from the Host Transmission Owner’s transmission system
consistent with Good Utility Practice. The Transmission Provider or Host
Transmission Owner, as appropriate, may curtail service under this Operating
Agreement to limit or prevent damage to generating or transmission facilities
caused by the Network Customer’s failure to maintain its facilities in accordance
with Good Utility Practice, and the Transmission Provider or Host Transmission
Owner may seek as a result any appropriate relief from the Commission.
5.2 The Designated Representatives shall establish procedures to coordinate the
maintenance schedules, and return to service, of the generating resources and
transmission and substation facilities, to the greatest extent practical, to ensure
sufficient transmission resources are available to maintain system reliability and
reliability of service.
5.3 The Network Customer shall obtain: (1) concurrence from the Transmission
Provider before beginning any scheduled maintenance of facilities which could
impact the operation of the Transmission System over which transmission service
is administered by Transmission Provider; and (2) clearance from the
Transmission Provider when the Network Customer is ready to begin
maintenance on a transmission line or substation. The Transmission Provider
shall coordinate clearances with the Host Transmission Owner. The Network
Customer shall notify the Transmission Provider and the Host Transmission
Owner as soon as practical at the time when any unscheduled or forced outages
occur and again when such unscheduled or forced outages end.
6.0 Scheduling Procedures
6.1 Prior to the beginning of each week, the Network Customer shall provide to the
Transmission Provider expected hourly energy schedules for that week for all
energy flowing into the Transmission System administered by Transmission
Provider.
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6.2 In accordance with Section 36 of the Tariff, the Network Customer shall provide
to the Transmission Provider the Network Customer’s hourly energy schedules
for the next calendar day for all energy flowing into the Transmission System
administered by the Transmission Provider. The Network Customer may modify
its hourly energy schedules up to twenty (20) minutes before the start of the next
clock hour provided that the Delivering Party and Receiving Party also agree to
the schedule modification. The hourly schedule must be stated in increments of
1000 kW per hour. The Network Customer shall submit, or arrange to have
submitted, to the Transmission Provider a NERC transaction identification Tag
where required by NERC Standard INT-001. These hourly energy schedules shall
be used by the Transmission Provider to determine whether any Energy
Imbalance Service charges, pursuant to Schedule 4 of the Tariff apply.
7.0 Ancillary Services
7.1 The Network Customer must make arrangements in appropriate amounts for all of
the required Ancillary Services described in the Tariff. The Network Customer
must obtain these services from the Transmission Provider or Host Transmission
Owner or, where applicable, self-supply or obtain these services from a third
party.
7.2 Where the Network Customer elects to self-supply or have a third party provide
Ancillary Services, the Network Customer must demonstrate to the Transmission
Provider that it has either acquired the Ancillary Services from another source or
is capable of self-supplying the services.
7.3 The Network Customer must designate the supplier of Ancillary Services.
8.0 Metering
8.1 The Network Customer shall provide for the installation of meters, associated
metering equipment and telemetering equipment. The Network Customer shall
permit (or provide for, if the Network Customer is not the meter owner) the
Transmission Provider’s and Host Transmission Owner’s representative to have
access to the equipment at all reasonable hours and for any reasonable purpose,
57 1431666 & 74318195
and shall not permit unauthorized persons to have access to the space housing the
equipment. Network Customer shall provide to (or provide for, if the Network
Customer is not the meter owner) the Host Transmission Owner access to load
data and other data available from any delivery point meter. If the Network
Customer does not own the meter, the Host Transmission Owner shall make
available, upon request, all load data and other data obtained by the Host
Transmission Owner from the relevant delivery point meter, if available utilizing
existing equipment. The Network Customer will cooperate on the installation of
advanced technology metering in place of the standard metering equipment at a
delivery point at the expense of the requestor; provided, however, that meter
owner shall not be obligated to install, operate or maintain any meter or related
equipment that is not approved for use by the meter owner and/or Host
Transmission Owner, and provided that such equipment addition can be
accomplished in a manner that does not interfere with the operation of the meter
owner’s equipment or any Party’s fulfillment of any statutory or contractual
obligation.
8.2 The Network Customer shall provide for the testing of the metering equipment at
suitable intervals and its accuracy of registration shall be maintained in
accordance with standards acceptable to the Transmission Provider and consistent
with Good Utility Practice. At the request of the Transmission Provider or Host
Transmission Owner, a special test shall be made, but if less than two percent
inaccuracy is found, the requesting Party shall pay for the test. Representatives of
the Parties may be present at all routine or special tests and whenever any
readings for purposes of settlement are taken from meters not having an
automated record. If any test of metering equipment discloses an inaccuracy
exceeding two percent, the accounts of the Parties shall be adjusted. Such
adjustment shall apply to the period over which the meter error is shown to have
been in effect or, where such period is indeterminable, for one-half the period
since the prior meter test. Should any metering equipment fail to register, the
amounts of energy delivered shall be estimated from the best available data.
58 1431666 & 74318195
8.3 If the Network Customer is supplying energy to retail load that has a choice in its
supplier, the Network Customer shall be responsible for providing all information
required by the Transmission Provider for billing purposes. Metering information
shall be available to the Transmission Provider either by individual retail
customer or aggregated retail energy information for that load the Network
Customer has under contract during the billing month. For the retail load that has
interval demand metering, the actual energy used by interval must be supplied.
For the retail load using standard kWh metering, the total energy consumed by
meter cycle, along with the estimated demand profile must be supplied. All rights
and limitations between Parties granted in Sections 8.1, and 8.2 are applicable in
regards to retail metering used as the basis for billing the Network Customer.
9.0 Connected Generation Resources
9.1 The Network Customer’s connected generation resources that have automatic
generation control and automatic voltage regulation shall be operated and
maintained consistent with regional operating standards, and the Network
Customer or the operator shall operate, or cause to be operated, such resources to
avoid adverse disturbances or interference with the safe and reliable operation of
the transmission system.
9.2 For all Network Resources of the Network Customer, the following generation
telemetry readings to the Host Transmission Owner are required:
1) Analog MW;
2) Integrated MWHRS/HR;
3) Analog MVARS; and
4) Integrated MVARHRS/HR.
10.0 Redispatching, Curtailment and Load Shedding
10.1 In accordance with Section 33 of the Tariff, the Transmission Provider may
require redispatching of generation resources or curtailment of loads to relieve
existing or potential transmission system constraints. The Network Customer
shall submit verifiable incremental and decremental cost data from its Network
59 1431666 & 74318195
Resources to the Transmission Provider. These costs will be used as the basis for
least-cost redispatch. Information exchanged by the Parties under this article will
be used for system redispatch only, and will not be disclosed to third parties
absent mutual consent or order of a court or regulatory agency. The Network
Customer shall respond immediately to requests for redispatch from the
Transmission Provider. The Transmission Provider will bill or credit the Network
Customer as appropriate.
10.2 The Parties shall implement load-shedding procedures to maintain the reliability
and integrity for the Transmission System as provided in Section 33.1 of the
Tariff and in accordance with applicable NERC and SPP requirements and Good
Utility Practice. Load shedding may include (1) automatic load shedding, (2)
manual load shedding, and (3) rotating interruption of customer load. When
manual load shedding or rotating interruptions are necessary, the Host
Transmission Owner shall notify the Network Customer’s dispatcher or
schedulers of the required action and the Network Customer shall comply
immediately.
10.3 The Network Customer will coordinate with the Host Transmission Owner to
ensure sufficient load shedding equipment is in place on their respective systems
to meet SPP requirements. The Network Customer and the Host Transmission
Owner shall develop a plan for load shedding which may include manual load
shedding by the Network Customer.
11.0 Communications
11.1 The Network Customer shall, at its own expense, install and maintain
communication link(s) for scheduling. The communication link(s) shall be used
for data transfer and for voice communication.
11.2 A Network Customer self-supplying Ancillary Services or securing Ancillary
Services from a third-party shall, at its own expense, install and maintain
telemetry equipment communicating between the generating resource(s)
providing such Ancillary Services and the Host Transmission Owner's Control
Area.
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12.0 Cost Responsibility
12.1 The Network Customer shall be responsible for all costs incurred by the Network
Customer, Host Transmission Owner, and Transmission Provider to implement
the provisions of this Operating Agreement including, but not limited to,
engineering, administrative and general expenses, material and labor expenses
associated with the specification, design, review, approval, purchase, installation,
maintenance, modification, repair, operation, replacement, checkouts, testing,
upgrading, calibration, removal, and relocation of equipment or software, so long
as the direct assignment of such costs is consistent with Commission policy.
12.2 The Network Customer shall be responsible for all costs incurred by Network
Customer, Host Transmission Owner, and Transmission Provider for on-going
operation and maintenance of the facilities required to implement the provisions
of this Operating Agreement so long as the direct assignment of such costs is
consistent with Commission policy. Such work shall include, but is not limited
to, normal and extraordinary engineering, administrative and general expenses,
material and labor expenses associated with the specifications, design, review,
approval, purchase, installation, maintenance, modification, repair, operation,
replacement, checkouts, testing, calibration, removal, or relocation of equipment
required to accommodate service provided under this Operating Agreement.
13.0 Billing and Payments
Billing and Payments shall be in accordance with Section 7 of the Tariff.
14.0 Dispute Resolution
Any dispute among the Parties regarding this Operating Agreement shall be resolved
pursuant to Section 12 of the Tariff, or otherwise, as mutually agreed by the Parties.
15.0 Assignment
This Operating Agreement shall inure to the benefit of and be binding upon the Parties
and their respective successors and assigns, but shall not be assigned by any Party, except
61 1431666 & 74318195
to successors to all or substantially all of the electric properties and assets of such Party,
without the written consent of the other Parties. Such written consent shall not be
unreasonably withheld.
16.0 Choice of Law
The interpretation, enforcement, and performance of this Operating Agreement shall be
governed by the laws of the State of Arkansas, except laws and precedent of such
jurisdiction concerning choice of law shall not be applied, except to the extent governed
by the laws of the United States of America.
17.0 Entire Agreement
The Tariff and Service Agreement, as they are amended from time to time, are
incorporated herein and made a part hereof. To the extent that a conflict exists between
the terms of this Operating Agreement and the terms of the Tariff, the Tariff shall control.
18.0 Unilateral Changes and Modifications
Nothing contained in this Operating Agreement or any associated Service Agreement
shall be construed as affecting in any way the right of the Transmission Provider or a
Transmission Owner unilaterally to file with the Commission, or make application to the
Commission for, changes in rates, charges, classification of service, or any rule,
regulation, or agreement related thereto, under section 205 of the Federal Power Act and
pursuant to the Commission’s rules and regulations promulgated thereunder, or under
other applicable statutes or regulations.
Nothing contained in this Operating Agreement or any associated Service
Agreement shall be construed as affecting in any way the ability of any Network
Customer receiving Network Integration Transmission Service under the Tariff to
exercise any right under the Federal Power Act and pursuant to the Commission’s rules
and regulations promulgated thereunder; provided, however, that it is expressly
recognized that this Operating Agreement is necessary for the implementation of the
Tariff and Service Agreement. Therefore, no Party shall propose a change to this
62 1431666 & 74318195
Operating Agreement that is inconsistent with the rates, terms and conditions of the Tariff
and/or Service Agreement.
19.0 Term
This Operating Agreement shall become effective on the date assigned by the
Commission (“Effective Date”), and shall continue in effect until the Tariff or the
Network Customer’s Service Agreement is terminated, whichever shall occur first.
20.0 Notice
20.1 Any notice that may be given to or made upon any Party by any other Party under
any of the provisions of this Operating Agreement shall be in writing, unless
otherwise specifically provided herein, and shall be considered delivered when
the notice is personally delivered or deposited in the United States mail, certified
or registered postage prepaid, to the following:
[Transmission Provider]Southwest Power Pool, Inc.Carl MonroeExecutive Vice President and Chief Operating Officer415 North McKinley, #140 Plaza WestLittle Rock, AR 72205-3020501-614-3218 phone 501-664-9553 [email protected]
[Host Transmission Owner]Westar Energy, Inc.Kelly HarrisonVice President, Transmission Operations and Environmental Services818 S. Kansas AvenueTopeka, KS 66612 785-575-1636 phone 785-575-8061 fax [email protected]
[Network Customer]Kansas Electric Power Cooperative, Inc.
63 1431666 & 74318195
Mark BarbeeVice President Engineering600 SW Corporate ViewTopeka, KS 66615785-273-7010 phone 785-271-4888 fax [email protected]
Any Party may change its notice address by written notice to the other Parties in
accordance with this Article 20.
20.2 Any notice, request, or demand pertaining to operating matters may be delivered
in writing, in person or by first class mail, e-mail, messenger, or facsimile
transmission as may be appropriate and shall be confirmed in writing as soon as
reasonably practical thereafter, if any Party so requests in any particular instance.
64 1431666 & 74318195
21.0 Execution in Counterparts
This Operating Agreement may be executed in any number of counterparts with the same
effect as if all Parties executed the same document. All such counterparts shall be
construed together and shall constitute one instrument.
IN WITNESS WHEREOF, the Parties have caused this Operating Agreement to be
executed by their respective authorized officials, and copies delivered to each Party, to become
effective as of the Effective Date.
TRANSMISSION PROVIDER HOST TRANSMISSION OWNER
_/s/ Carl Monroe__________ _/s/ Kelly B. Harrison__________________Signature Signature
_Carl Monroe____________ _Kelly B. Harrison____________________Printed Name Printed Name
_EVP & COO____________ _VP-Transmission Ops. & Environmental Svcs.___Title Title
_07/28/2011_____________ _July 28, 2011______________________Date Date
NETWORK CUSTOMER
__/s/ Mark R. Barbee______Signature
_Mark R. Barbee_________Printed Name
_VP of Engineering_______Title
_7/26/2011______________Date
1 1431666 & 74318195
Southwest Power Pool, Inc.
Third Revised Service Agreement No. 1636
SERVICE AGREEMENT FOR NETWORK INTEGRATION TRANSMISSION
SERVICE BETWEEN SOUTHWEST POWER POOL, INC. AND KANSAS
ELECTRIC POWER COOPERATIVE, INC.
This Network Integration Transmission Service Agreement ("Service Agreement") is
entered into this 1st day of June 2011, by and between Kansas Electric Power Cooperative, Inc.
("Network Customer" or “KEPCO”), and Southwest Power Pool, Inc. ("Transmission Provider").
The Network Customer and Transmission Provider shall be referred to individually as “Party”
and collectively as "Parties."
WHEREAS, the Transmission Provider has determined that the Network Customer has
made a valid request for Network Integration Transmission Service in accordance with the
Transmission Provider’s Open Access Transmission Tariff ("Tariff") filed with the Federal
Energy Regulatory Commission ("Commission") as it may from time to time be amended;
WHEREAS, the Transmission Provider administers Network Integration Transmission
Service for Transmission Owners within the SPP Region and acts as agent for the Transmission
Owners in providing service under the Tariff;
WHEREAS, the Network Customer has represented that it is an Eligible Customer under
the Tariff; and
WHEREAS, the Parties intend that capitalized terms used herein shall have the same
meaning as in the Tariff.
NOW, THEREFORE, in consideration of the mutual covenants and agreements herein,
the Parties agree as follows:
1.0 The Transmission Provider agrees during the term of this Service Agreement, as it may
be amended from time to time, to provide Network Integration Transmission Service in
accordance with the Tariff to enable delivery of power and energy from the Network
2 1431666 & 74318195
Customer’s Network Resources that the Network Customer has committed to meet its
load.
2.0 The Network Customer agrees to take and pay for Network Integration Transmission
Service in accordance with the provisions of Parts I, III and V of the Tariff and this
Service Agreement with attached specifications.
3.0 The terms and conditions of such Network Integration Transmission Service shall be
governed by the Tariff, as in effect at the time this Service Agreement is executed by the
Network Customer, or as the Tariff is thereafter amended or by its successor tariff, if any.
The Tariff, as it currently exists, or as it is hereafter amended, is incorporated in this
Service Agreement by reference. In the case of any conflict between this Service
Agreement and the Tariff, the Tariff shall control. The Network Customer has been
determined by the Transmission Provider to have a Completed Application for Network
Integration Transmission Service under the Tariff. The completed specifications are
based on the information provided in the Completed Application and are incorporated
herein and made a part hereof as Attachment 1.
4.0 Service under this Service Agreement shall commence on such date as it is permitted to
become effective by the Commission. This Service Agreement shall be effective through
June 1st, 2013. Thereafter, it will continue from year to year unless terminated by the
Network Customer or the Transmission Provider by giving the other one-year advance
written notice or by the mutual written consent of the Transmission Provider and
Network Customer. Upon termination, the Network Customer remains responsible for
any outstanding charges including all costs incurred and apportioned or assigned to the
Network Customer under this Service Agreement.
5.0 The Transmission Provider and Network Customer have executed a Network Operating
Agreement as required by the Tariff.
6.0 Any notice or request made to or by either Party regarding this Service Agreement shall
be made to the representative of the other Party as indicated below. Such representative
and address for notices or requests may be changed from time to time by notice by one
Party or the other.
3 1431666 & 74318195
Southwest Power Pool, Inc. (Transmission Provider):
Carl Monroe
Executive Vice President and Chief Operating Officer
415 N. McKinley,140 Plaza West
Little Rock, AR 72205
Network Customer:
Mark Barbee
Vice President Engineering
Kansas Electric Power Cooperative Inc.
600 SW Corporate View
Topeka, KS 66615
7.0 This Service Agreement shall not be assigned by either Party without the prior written
consent of the other Party, which consent shall not be unreasonably withheld. However,
either Party may, without the need for consent from the other, transfer or assign this
Service Agreement to any person succeeding to all or substantially all of the assets of
such Party provided that all required regulatory approvals (if any), including approval of
the Rural Utilities Service (“RUS”) as to KEPCO, are obtained in connection with such
transfer or assignment. However, the assignee shall be bound by the terms and
conditions of this Service Agreement. The Parties acknowledge and agree that KEPCO
has assigned and pledged as security this Service Agreement and all of its rights
hereunder to RUS. The Parties further acknowledge and agree that RUS shall have the
right upon written notice to the Transmission Provider to assume all obligations of
KEPCO hereunder whereupon RUS shall succeed to all rights of KEPCO hereunder
(including the right to make any subsequent assignment in accordance with this section).
8.0 Nothing contained herein shall be construed as affecting in any way the Transmission
Provider’s or a Transmission Owner’s right to unilaterally make application to the
Federal Energy Regulatory Commission, or other regulatory agency having jurisdiction,
for any change in the Tariff or this Service Agreement under Section 205 of the Federal
4 1431666 & 74318195
Power Act, or other applicable statute, and any rules and regulations promulgated
thereunder; or the Network Customer's rights under the Federal Power Act and rules and
regulations promulgated thereunder.
9.0 By signing below, the Network Customer verifies that all information submitted to the
Transmission Provider to provide service under the Tariff is complete, valid and accurate,
and the Transmission Provider may rely upon such information to fulfill its
responsibilities under the Tariff.
IN WITNESS WHEREOF, the Parties have caused this Service Agreement to be
executed by their respective authorized officials.
TRANSMISSION PROVIDER NETWORK CUSTOMER
/s/ Carl Monroe /s/ Mark R. Barbee
Carl Monroe Mark Barbee
Executive Vice President and Chief Vice President Engineering
Operating Officer Kansas Electric Power Southwest Power Pool, Inc. Cooperative, Inc.
7/28/2011 7/26/2011
Date Date
5 1431666 & 74318195
ATTACHMENT 1 TO THE NETWORK INTEGRATION TRANSMISSION SERVICE
AGREEMENT
BETWEEN SOUTHWEST POWER POOL AND
SPECIFICATIONS FOR NETWORK INTEGRATION TRANSMISSION SERVICE
1.0 Network Resources
The Network Resources are listed in Appendix 1.
2.0 Network Loads
The Network Load consists of the bundled native load or its equivalent for Network
Customer load in the Westar Energy Control Area as listed in Appendix 3.
The Network Customer’s Network Load shall be measured on an hourly integrated basis,
by suitable metering equipment located at each connection and delivery point, and each
generating facility. The meter owner shall cause to be provided to the Transmission
Provider, Network Customer and applicable Transmission Owner, on a monthly basis
such data as required by Transmission Provider for billing. The Network Customer’s
load shall be adjusted, for settlement purposes, to include applicable Transmission Owner
transmission and distribution losses, as applicable, as specified in Sections 8.5 and 8.6,
respectively. For a Network Customer providing retail electric service pursuant to a state
retail access program, profiled demand data, based upon revenue quality non-IDR meters
may be substituted for hourly integrated demand data. Measurements taken and all
metering equipment shall be in accordance with the Transmission Provider’s standards
and practices for similarly determining the Transmission Provider’s load. The actual
hourly Network Loads, by delivery point, internal generation site and point where power
may flow to and from the Network Customer, with separate readings for each direction of
flow, shall be provided.
3.0 Affected Control Areas and Intervening Systems Providing Transmission Service
6 1431666 & 74318195
The affected control area is Westar Energy. The intervening systems providing
transmission service are _____none____
4.0 Electrical Location of Initial Sources
See Appendix 1.
5.0 Electrical Location of the Ultimate Loads
The loads of Network Customer identified in Section 2.0 hereof as the Network Load are
electrically located within the Westar Energy Control Area.
6.0 Delivery Points
The delivery points are the interconnection points identified in Section 2.0 as the
Network Load.
7.0 Receipt Points
The Points of Receipt are listed in Appendix 2.
8.0 Compensation
Service under this Service Agreement may be subject to some combination of the charges
detailed below. The appropriate charges for individual transactions will be determined in
accordance with the terms and conditions of the Tariff.
8.1 Transmission Charge
Monthly Demand Charge per Section 34 and Part V of the Tariff.
8.2 System Impact and/or Facility Study Charge
7 1431666 & 74318195
Studies may be required in the future to assess the need for system
reinforcements in light of the ten-year forecast data provided. Future charges, if
required, shall be in accordance with Section 32 of the Tariff.
8.3 Direct Assignment Facilities Charge
8.4 Ancillary Service Charges
8.4.1 The following Ancillary Services are required under this Service
Agreement.
a) Scheduling, System Control and Dispatch Service per Schedule 1 of the
Tariff.
b) Tariff Administration Service per Schedule 1-A of the Tariff.
c) Reactive Supply and Voltage Control from Generation Sources Service
per Schedule 2 of the Tariff.
d) Regulation and Frequency Response Service per Schedule 3 of the
Tariff.
e) Energy Imbalance Service per Schedule 4 of the Tariff.
f) Operating Reserve - Spinning Reserve Service per Schedule 5 of the
Tariff.
g) Operating Reserve - Supplemental Reserve Service per Schedule 6 of the
Tariff.
The Ancillary Services may be self-supplied by the Network Customer or
provided by a third party in accordance with Sections 8.4.2 through 8.4.4, with
the exception of the Ancillary Services for Schedules 1, 1-A, and 2, which must
be purchased from the Transmission Provider.
8.4.2 In accordance with the Tariff, when the Network Customer elects to self-
supply or have a third party provide Ancillary Services, the Network
Customer shall indicate the source for its Ancillary Services to be in
effect for the upcoming calendar year in its annual forecasts. If the
Network Customer fails to include this information with its annual
8 1431666 & 74318195
forecasts, Ancillary Services will be purchased from the Transmission
Provider in accordance with the Tariff.
8.4.3 When the Network Customer elects to self-supply or have a third party
provide Ancillary Services and is unable to provide its Ancillary
Services, the Network Customer will pay the Transmission Provider for
such services and associated penalties in accordance with the Tariff as a
result of the failure of the Network Customer’s alternate sources for
required Ancillary Services.
8.4.4 All costs for the Network Customer to supply its own Ancillary Services
shall be the responsibility of the Network Customer.
8.5 Real Power Losses – Transmission
The Network Customer shall replace losses in accordance with Attachment M of
the Tariff.
8.6 Real Power Losses – Distribution
The Network Customer shall replace all distribution losses in accordance with
Westar Energy's Open Access Transmission Tariff, Section 28.5, based upon the
location of each delivery point meter located on distribution facilities. The
composite loss percentages in Section 28.5 shall exclude transmission
losses.
8.7 Power Factor Correction Charge
8.8 Redispatch Charge
Redispatch charges shall be in accordance with Section 33.3 of the Tariff.
8.9 Wholesale Distribution Service Charge
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The Wholesale Distribution Service charge cost support and monthly charge is
detailed in Appendix 4.
8.10 Network Upgrade Charges
A. The Network Customer has confirmed the following supplemental
Network Resources requiring Network Upgrades:
1. Iatan 2 Generating Station, 30MW from POR-KCPL, Source –Iatan2 to POD
– WR, Sink-KEPCO.WR, as more specifically identified in transmission
request 1090416. Contingent upon the completion of required upgrades as
specified below, designation of the resource shall be effective June 1, 2010
and shall remain effective through June 1, 2030.
The requested service requires completion of the following aggregate study
SPP-2006-AG2 allocated network upgrades. The costs of these upgrades are
allocated to the Network Customer but are fully base plan fundable in
accordance with Section III.A. Attachment J of the Tariff.
Network upgrades on the American Electric Power Coffeyville Tap –
Dearing 138kV Ckt 1 facility required by June 1, 2011. This upgrade
consists of rebuilding 1.09 miles of this facility with 1590 ACSR
conductor.
Network upgrades on the Westar Energy Coffeyville Tap – Dearing
138kV Ckt 1 facility required by June 1, 2011. This upgrade consists of
rebuilding 3.93 miles of this facility with 1590 ACSR conductor.
Network upgrades on the Westar Energy Rose Hill 345/138kV
Transformer required by June 1, 2011. This upgrade consists of adding a
third 345/138kV transformer at Rose Hill.
2. Wolf Creek, 3MW from POR – WR, Source – KEPCOWC to POD – WR,
Sink Kepco , as more specifically identified in transmission request 1405798.
Contingent upon the completion of required upgrades as specified below,
designation of this network resource shall be effective on May 1, 2011 and
remain effective through May 1, 2018.
10 1431666 & 74318195
The requested service depends on and is contingent on completion of the
following Reliability and Construction Pending upgrades. These upgrades costs
are not assignable to the Network Customer.
Reliability and Construction Upgrades for Wolf Creek
Upgrade Name Upgrade Description Transmission
Owner
Date Required
in Service
EAST MANHATTAN -
NW MANHATTAN
230/115KV
Tap the Concordia - East Manhattan
230kV line and add a new
substation"NW Manhattan"; Add a
230kV/115kV transformer and tap the
KSU - Wildcat 115kV line into NW
Manhattan
WERE 6/1/2010
East Manhattan to
McDowell 230 kV
The East Manhattan-McDowell 115 kV
is built as a 230 kV line, but is operated
at 115 kV. Substation work will have to
be performed in order to convert this
line.
WERE 6/1/2010
STILWELL - WEST
GARDNER 345KV
CKT 1
Upgrade Stilwell terminal equipment to
2000 amps
KACP
6/1/2012
BURLINGTON
JUNCTION - WOLF
CREEK 69KV CKT 1
Rebuild 4.1 miles with 954 kcmil ACSR
(138kV/69kV Operation)
WERE
6/1/2011
B. Upon completion of construction of the assigned upgrades, funding of their costs
shall be reconciled and trued-up against actual construction costs and requisite,
additional funding or refund of excess funding shall be made between the
Transmission Provider and the Network Customer.
C. Notwithstanding the term provisions of Section 4.0 of this Service Agreement,
Customer shall be responsible for paying all charges specified as its obligation in
this Section 8.10 of this Attachment 1, for the term specified herein for each
assigned upgrade.
8.11 Meter Data Processing Charge
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8.12 Other Charges
9.0 Credit for Network Customer-Owned Transmission Facilities
10.0 Designation of Parties Subject to Reciprocal Service Obligation
11.0 Other Terms and Conditions
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APPENDIX 1
Network Resources of
Kansas Electric Power Cooperative, Inc.
13 1431666 & 74318195
APPENDIX 1
NETWORK RESOURCES
NETWORK
RESOURCE
Maximum Net Dependable
Capacity (MW) LOCATION
Summer Winter
Confirmation
Agreement for
Wholesale
Purchase and Sale of
Capacity & Energy
between Westar
Energy, Inc
(“Westar”)and
Kansas Electric
Power Cooperative,
Inc.(“KEPCO”) dated
March 6, 2003.
101
101
This purchase power contract uses the Westar
Energy (“Westar”) fleet of generation to serve
delivery points as listed in Appendix 3. WR
will supply KEPCO with sufficient Energy to
meet the delivery points’ hourly Energy demand
and to account for the appropriate transmission
and distribution losses associated with Energy
deliveries from the Westar generation busses to
the points of delivery. Westar agrees to sell
KEPCO sufficient Capacity to meet the peak
demand and planning reserve capacity. Westar
shall supply KEPCO with Ancillary Services 3,
4, 5, and 6.
Unit delivery from
ownership agreement
for Wolf Creek
Nuclear Generation
Station Unit #1 dated
December 28, 1981
69 69 Coffey Co. Kansas
66MW of firm transmission rights through
5/1/2011 and then 69MW of firm transmission
rights thereafter
Power Sales Contract
dated January 10,
1995 between
Southwestern Power
Administration (SPA)
and KEPCO for
Hydro Peaking Power
and associated energy
94 94
Points of delivery shall be at the 161kv points of
interconnection between SPA and KEPCO in
SPA Switching station at Neosho, Newton Co.,
Mo. and SPA’s substation at Carthage, Jasper
Co, Mo.
14 1431666 & 74318195
NETWORK
RESOURCE
Maximum Net Dependable
Capacity (MW) LOCATION
Summer Winter
Unit delivery from
Sharpe Generation
Station pursuant to
the Operating
Agreement between
Wolf Creek Nuclear
Operating
Cooperation and
KEPCO dated July 1,
2002.
19 19 Coffey Co, Kansas
Iatan Unit 2 and
Common Facilities
Ownership
Agreement dated
May 19, 2006
The lesser of
3.53% of Net
Generating
Capacity or
30MW
The lesser of
3.53% of Net
Generating
Capacity or
30MW
Platte Co., MO.
15 1431666 & 74318195
Appendix 2
Receipt Points of
Kansas Electric Power Cooperative, Inc.
16 1431666 & 74318195
APPENDIX 2
RECEIPT POINTS
Tieline / Plant Name Ownership Voltage
(kV)
Rating
(MVA)
Westar Energy Network Resource Interconnection
points on the Westar Energy Transmission System Westar varies
Wolf Creek Westar (KGE) 345
SPA Hydro Peaking Power, Neosho and Carthage Westar, EMDE 161
Sharpe Plant KEPCo 69
Iatan Unit 2 KCPL 345
17 1431666 & 74318195
Appendix 3
Delivery Points of
Kansas Electric Power Cooperative, Inc.
18 1431666 & 74318195
APPENDIX 3
DELIVERY POINTS
(a) (b) (c) (d)
SPP Bus
Number / Name
Delivery Point Name Delivery
Point #
Ownership
(Meter)
Voltage kV
(Meter)
Location)
(1)
ARK VALLEY COOP
533378
MARQUETTE-
LANGLEY 1307 Westar
12.5
(Low Side)
SMOKYHL3 115
kV
533438
MEDORA 1309 Westar 12.5(Bus)
WMCPHER3 115
kV
533411
SAND HILL 1313 Westar
12.5
(Low Side) ARKVAL 3 115 kV
533504
YODER 1302 Westar
12.5
(Low Side) CITYSVC2 69 kV
BLUESTEM COOP
533339
ALMA 1703 Westar 12.5(Circuit) S ALMA3 115 kV
533332
BLUE RAPIDS 2301 Westar 12.5(Bus) KNOB HL3 115 kV
533323
CLAY CENTER 2304 Westar 12.5(Circuit) CLAYCTR3 115 kV
533334
FOSTORIA 1707 Westar 12.5(Circuit) MATTERS3 115 kV
FOSTORIA DEDUCT
(A) 1707A Westar 12.5(C)
533326
HUNTER'S ISLAND 1705 Westar 12.5(Circuit)
EMANHAT3 115
kV
533330
LEONARDVILLE 2305 Westar 34.5 JCTCTY3 115 kV
532852
LOUISVILLE 1708 Westar 12.5(Circuit) JEC 5 230 kV
532852
PEDDICORD 1701 Westar 12.5(Circuit) JEC 6 230 kV
533152
SOLDIER 1704 Westar 12.5(Circuit) CIRCLVL3 115 kV
533334
ST. GEORGE 1706 Westar 12.5(Circuit) MATTERS3 115 kV
533323
WAKEFIELD 2302 Westar 12.5(Bus) CLAYCTR3 115 kV
19 1431666 & 74318195
533339
WAMEGO 1702 Westar 12.5(Bus) S ALMA3 115 kV
20 1431666 & 74318195
APPENDIX 3 – DELIVERY POINTS – Westar Energy System – Continues
(a) (b) (c) (d)
SPP Bus
Number / Name
Delivery Point Name Delivery
Point #
Ownership
(Meter)
Voltage
(Meter)
(kV)
(1)
BROWN-ATCHISON COOP
533152
CIRCLEVILLE 1507 Westar
12.5
(Circuit) CIRCLVL3 115 kV
533212
EAST FAIRVIEW 1505 Westar
12.5
(Circuit)
BROWNCO3 115
kV
533212
EAST HIAWATHA 1506 Westar
12.5
(Circuit)
BROWNCO3 115
kV
533218
LANCASTER 1504 Westar
12.5
(Circuit) PARALEL3 115 kV
533480
MUSCOTAH 1508 Westar
12.5
(Circuit) MUSCOTA2 69 kV
533212
NORTH HIAWATHA 1509 Westar
12.5
(Circuit)
BROWNCO3 115
kV
533481
NORTONVILLE 1503 Westar
12.5
(Circuit) NORTONV2 69 kV
533152
NETAWAKA 1501 Westar
12.5
(Circuit) CIRCLVL3 115 kV
533212
SOUTH FAIRVIEW 1510 Westar 34.5
BROWNCO3 115
kV
533480
WILLIS 1502 Westar
12.5
(Low Side) MUSCOTA2 69 kV
21 1431666 & 74318195
APPENDIX 3 – DELIVERY POINTS – Westar Energy System – Continues
(a) (b) (c) (d)
SPP Bus
Number / Name
Delivery Point Name Delivery
Point #
Ownership
(Meter)
Voltage
(Meter)
(kV)
(1)
BUTLER COOP
533585
BENTON KBU10 Westar 12.5(Bus) BU10BEN2 69 kV
533584
DE GRAFF KBU06 Westar 69 BU6DEGR2 69 kV
533302
EUREKA 2401 Westar
12.5
(Low Side) EEUREKA3 115 kV
533861
FURLEY KBU05 Westar 69 BU5FURL2 69 kV
533586
KEIGHLEY KBU12 Westar 12.5(Bus) BU12KEI2 69 kV
533594
LEON KBU01 Westar
12.5
(Circuit) LEON 2 69 kV
533032 LITTLE PONY
MEADOWS KBU11A Westar 12.5(Bus) BU11PON4 138 kV
533745
NEWTON 2 69kV NEWTON KBU13 Westar
12.5
(Circuit)
533032
PONY MEADOWS KBU11 Westar 12.5 (Bus) BU11PON4 138 kV
533601
POTWIN KBU02 Westar
12.5
(Circuit) POTWIN 2 69 kV
533550
ROSE HILL KBU07 Westar
12.5
(Circuit) RICHLAN2 69 kV
533595
SMILEYBURG KBU08 Westar
12.5
(Circuit) MAGNA 2 69 kV
533048
SPURRIER KBU04 Westar
12.5
(Circuit) HARRY 4 138 kV
533597
TOWANDA KBU09 Westar
12.5
(Circuit) MIDIAN2 69 kV
22 1431666 & 74318195
APPENDIX 3 – DELIVERY POINTS – Westar Energy System – Continues
(a) (b) (c) (d)
SPP Bus
Number / Name
Delivery Point Name Delivery
Point #
Ownership
(Meter)
Voltage
(Meter) (kV)
(1)
CANEY VALLEY COOP
533557
BURDEN KCV08 Westar
12.5
(Circuit) TIMBER 2 69 kV
533686
CANEY KCV04 Westar 12.5 (Bus) CV4CANY2 69 kV
533691
GRENOLA KCV01 Westar
12.5
(Circuit) ELK RVR2 69 kV
533691
HARSHMAN KCV09 Westar
23.5
(Circuit) ELK RVR2 69 kV
533689
LONGTON KCV02 Westar
12.5
(Circuit) ELK CTY2 69 kV
533687
MCCALL KCV07 Westar 69
CV7MCAL2 69
kV
533544 SEDAN SWITCHING
STATION KCV05 Westar 69 CV5SEDA2 69 kV
533542
SILVERDALE KCV03 Westar
12.5
(Circuit) ARKCITY2 69 kV
533557
TISDALE KCV06 Westar
12.5
(Circuit) TIMBER 2 69 kV
23 1431666 & 74318195
APPENDIX 3 – DELIVERY POINTS – Westar Energy System – Continues
(a) (b) (c) (d)
SPP Bus
Number / Name
Delivery Point Name Delivery
Point #
Ownership
(Meter)
Voltage
(Meter) (kV)
(1)
DS&O COOP
533378
ASSARIA 1403 Westar 12.5 (Bus)
SMOKYHL3 115
kV
533376
BENNINGTON 1408 Westar
12.5
(Circuit) SALINA 3 115 kV
533887
CHAPMAN 1416 Westar
12.5
(Circuit) AEC W 1 34.5 kV
533376
GYPSUM 1418 Westar
12.5
(Circuit) SALINA 3 115 kV
533329
K-18 1709 Westar 34.5
NCFOUND 3 115
kV
533379
MAGNOLIA 1412 Westar
12.5
(Circuit)
SO GATE3 115
kV
533378
MARQUETTE 2601 Westar
12.5
(Low Side)
SMOKYHL3 115
kV
533330
MILFORD 1414 Westar 12.5 (Bus) JCTCTY 3 115 kV
533376
MINNEAPOLIS 1404 Westar 12.5 (Bus) SALINA 3 115 kV
533376
NORTH SALINA 1413 Westar 34.5 SALINA 3 115 kV
533330
NW JUNCTION CITY 1417 Westar
12.5
(Circuit) JCTCTY3 115 kV
533887
PEARL 1411 Westar 12.5 (Bus) AEC W 1 34.5 kV
533369
RAMONA 1406 Westar 12.5 (Bus)
HILSBOR3 115
kV
533887
SOLOMON 1410 Westar 12.5 (Bus) AEC W 1 34.5 kV
533887 SOUTHWEST
ABILENE 1401 Westar
12.5
(Circuit) AEC W 1 34.5 kV
533887
TALMAGE #1 1409 Westar
12.5
(Circuit) AEC W 1 34.5 kV
533887
TALMAGE #2 1415 Westar
4.2
(Low Side) AEC W 1 34.5 kV
533323
UPLAND 1405 Westar 12.5 (Bus)
CLAYCTR3 115
kV
24 1431666 & 74318195
533378
WEST LINDSBORG 2602 Westar 12.5 (Bus)
SMOKYHL3 115
kV
533364
WEST SALINA 1402 Westar
12.5
(Circuit)
CRAWFRD3 115
kV
25 1431666 & 74318195
APPENDIX 3 – DELIVERY POINTS – Westar Energy System – Continues
(a) (b) (c) (d)
SPP Bus
Number / Name
Delivery Point Name Delivery
Point #
Ownership
(Meter)
Voltage
(Meter) (kV)
(1)
FLINT HILLS COOP
533340
ALTA VISTA 708 Westar 34.5
SMANHAT3 115
kV
533340
ALTA VISTA SOUTH 714 Westar
12.5
(Circuit)
SMANHAT3 115
kV
533309
COTTONWOOD
FALLS 701 Westar 34.5
WEMPORI3 115
kV
533305
COUNCIL GROVE
EAST 704 Westar
12.5
(Low Side)
MORRIS 3 115
kV
533305
COUNCIL GROVE
WEST 709 Westar
12.5
(Circuit)
MORRIS 3 115
kV
533369
DURHAM 710 Westar
12.5
(Low Side)
HILSBOR3 115
kV
533366
FLORENCE 707 Westar
12.5
(Circuit)
FLORENC3 115
kV
533369
GOESSEL 712 Westar
12.5
(Low Side)
HILSBOR3 115
kV
533887
HERINGTON 706 Westar
12.5
(Low Side) AEC W 1 34.5 kV
HERINGTON DEDUCT
(A) 706A Westar 12.5(D)
533369
HILLSBORO 703 Westar
12.5
(Low Side)
HILSBOR3 115
kV
533330
JUNCTION CITY 702 Westar 34.5 JCTCTY 3 115 kV
533369
LEHIGH 713 Westar
12.5
(Circuit)
HILSBOR3 115
kV
533366
MARION 711 Westar 12.5 (Bus)
FLORENC3 115
kV
533599
PEABODY 705 Westar
12.5
(Circuit)
PEABODY2 69
kV
26 1431666 & 74318195
APPENDIX 3 – DELIVERY POINTS – Westar Energy System – Continues
(a) (b) (c) (d)
SPP Bus
Number / Name
Delivery Point Name Delivery
Point #
Ownership
(Meter)
Voltage
(Meter)
(kV)
(1)
HEARTLAND COOP
532926
BAKER KSE02 Westar
12.5
(Circuit) BAKER 5 161 kV
532926
CHEROKEE KSE07 Westar
12.5
(Circuit) BAKER 5 161 kV
533651
CONGER KUN09 Westar
12.5
(Low Side) UN9CONG2 69 kV
533644
DEVON KSE04 Westar
12.5
(Low Side) SE4DEVO2 69 kV
533647
ELSMORE KUN01 Westar
12.5
(Low Side) UN1ELSM2 69 kV
533774
ENGLEVALE KSE05 Westar
12.5
(Circuit) SHEFFLD2 69 kV
533772
GREENBUSH KSE01 Westar
12.5
(Low Side) SE1GREE2 69 kV
533645
HIATTVILLE KSE09 Westar
12.5
(Low Side) SE9HIAT2 69 kV
533650
MAGELLAN KUN10 Westar 69 UN8HUMB2 69 kV
533758
MC CUNE KSE06 Westar
12.5
(Circuit) CRAWFOR2 69 kV
533649
ROSE KUN07 Westar
12.5
(Low Side) UN7ROSE2 69 kV
533621
SE HUMBOLDT KUN05 Westar
12.5
(Circuit) ALLEN 2 69 KV
533648
URBANA KUN06 Westar
12.5
(Low Side) UN6URBA2 69 kV
27 1431666 & 74318195
APPENDIX 3 – DELIVERY POINTS – Westar Energy System – Continues
(a) (b) (c) (d)
SPP Bus
Number / Name
Delivery Point Name Delivery
Point #
Ownership
(Meter)
Voltage
(Meter)
(kV)
(1)
LEAVENWORTH-JEFFERSON COOP
533164
HOYT 609 Westar
12.5
(Circuit) HTI 3 115 kV
533443
MAYETTA 605 Westar
12.5
(Circuit)
COLINE 1 34.5
kV
533259
NW LEAVENWORTH 601 Westar
12.5
(Low Side)
NW LEAV3 115
kV
533481
NORTONVILLE 607 Westar
12.5
(Circuit)
NORTONV2 69
kV
533219
OSKALOOSA 610 Westar 34.5
TONGATP3 115
kV
533458
ROCK CREEK 606 Westar
12.5
(Circuit)
ROCKCRK2 69
kV
533219
STRANGER 603 Westar 34.5
TONGATP3 115
kV
533219
TONGANOXIE 602 Westar 34.5
TONGATP3 115
kV
533483
VALLEY FALLS 604 Westar
12.5
(Circuit)
VALLEY2 2 69
kV
28 1431666 & 74318195
APPENDIX 3 – DELIVERY POINTS – Westar Energy System – Continues
(a) (b) (c) (d)
SPP Bus
Number / Name
Delivery Point Name Delivery
Point #
Ownership
(Meter)
Voltage (Meter) (kV)
(1)
LYON-COFFEY COOP
533301
AMERICUS - T.
BIRD 1111 Westar 34.5
EAST ST3 115
kV
533628
BURLINGTON KCC01 Westar 12.5(Bus)
CC1BURL2 69
kV
533167
ESKRIDGE 1105 Westar
12.5
(Circuit)
KEENE 3 115
kV
533301
HARTFORD 1102 Westar
12.5
(Circuit)
EAST ST3 115
kV
533301
MELVERN / BETO
JUNCTION 1108 Westar
12.5
(Circuit)
EAST ST3 115
kV
533308
OLPE 1112 Westar 12.5 (Bus)
VAUGHN 3 115
kV
OLPE DEDUCT (A) 1112M Westar 12.5 (E)
533306
READING 1104 Westar
12.5
(Circuit)
READING3 115
kV
READING
DEDUCT (A) 706B Westar 12.5 (Bus)
533302
TORONTO 1004 Westar 12.5(Circuit)(Circuit)
EEUREKA3 115
kV
533631
VERNON KCC04 Westar 12.5(Bus)
CC4VERN2 69
kV
533308
VIRGIL 1003 Westar 12.5(Circuit)
VAUGHN 3 115
kV
533301
WAVERLY 1005 Westar 34.5
EAST ST3 115
kV
533309
WEST EMPORIA 1106 Westar
12.5
(Low Side)
WEMPORI3 115
kV
533630
WESTPHALIA KCC03 Westar 12.5(Bus)
CC3WEST2 69
kV
29 1431666 & 74318195
533310
WILLIAMS 1113 Westar
4.2
(Low Side)
WMBROS 3 115
kV
533653
WOLF CREEK KCC06 Westar
12.5
(Low Side)
WOLFCRK2 69
kV
APPENDIX 3 – DELIVERY POINTS – Westar Energy System – Continues
(a) (b) (c) (d)
SPP Bus
Number / Name
Delivery Point Name Delivery
Point #
Ownership
(Meter)
Voltage
(Meter)
(kV)
(1)
RADIANT COOP
533674
ALTOONA KRA02 Westar
12.5
(Circuit)
ALTOO W 2 69
kV
533707
BROOKS KRA06 Westar
12.5
(Low Side) RA6BROO2 69 kV
533708
CANEY KRA07 Westar
12.5
(Low Side) RA7CANY2 69 kV
533683
COFFEYVILLE KRA09 Westar
12.5
(Circuit) COFFSUB2 69 kV
533706
HIGH PRAIRIE KRA05 Westar 69 RA5HIPR2 69 kV
533698
INDEPENDENCE KRA03 Westar
12.5
(Circuit)
MONTGOM2 69
kV
533709
LOUISBURG KRA10 Westar
12.5
(Low Side) RA10LOU2 69 kV
533692
SEK PIPELINE KRA11A Westar 69 FREDON 2 69 kV
533705
STUDEBAKER KRA11B Westar
12.5
(Low Side) RA1FRED2 69 kV
ROLLING HILLS COOP
533376
NEW BEVERLY 2201 Westar
12.5
(Low Side) SALINA 3 115 kV
KEPCo SHARPE AUX
533629 SHARPE GEN
AUXILLARY AUX Westar
0.48
(Low Side) CC2SHAR2 69 kV
30 1431666 & 74318195
APPENDIX 3 – DELIVERY POINTS – Westar Energy System – Continues
(a) (b) (c) (d)
SPP Bus
Number / Name
Delivery Point Name Delivery
Point #
Ownership
(Meter)
Voltage
(Meter)
(kV)
(1)
SEDGWICK COOP
533872
ANDALE KSG04 Westar
12.5
(Low Side) SG4ANDL2 69 kV
533871
CHENEY KSG01 Westar
12.5
(Low Side) SG1CHEN2 69 kV
533785 CHENEY LAKE
OZONE PLANT KSG14 Westar
0.48
(Low Side) CHENEY 2 69 kV
533812
CLEARWATER KSG05 Westar
12.5
(Circuit) LIN 2 69 kV
533065
COLWICH KSG12 Westar 12.5 (Bus)
SG12COL4 138
kV
533873
CRAIG KSG08 Westar
12.5
(Low Side) SG8CRAG2 69 kV
533844
GARDEN PLAIN KSG02 Westar
12.5
(Circuit) SUNSET-2 69 kV
533736
HALSTEAD KSG03 Westar
12.5
(Circuit) HALSTED2 69 kV
533795
HAYSVILLE KSG13 Westar
12.5
(Circuit) GILL E 2 69 kV
533875
KOCH KSG11 Westar
2.4
(Low Side) SG11KOC2 69 kV
533874
ST MARKS KSG09 Westar
12.5
(Low Side) SG9STMK2 69 kV
533794
WATERLOO KSG07 Westar
12.5
(Circuit) GALE 2 69 kV
31 1431666 & 74318195
APPENDIX 3 – DELIVERY POINTS – Westar Energy System – Continues
(a) (b) (c) (d)
SPP Bus
Number / Name
Delivery Point Name Delivery
Point #
Ownership
(Meter)
Voltage
(Meter) (kV)
(1)
SUMNER-COWLEY COOP
533866
ANSON KSC09 Westar
12.5
(Low Side) SC9ANSN2 69 kV
533063
BELLE PLAINE KSC10 Westar
12.5
(Low Side) SC10BEL4 138 kV
533555
CRESWELL KSC07 Westar
12.5
(Low Side) SC7CRES2 69 kV
533549
GEUDA KSC02 Westar
12.5
(Circuit) RAINBOW2 69 kV
533551
KING KSC01 Westar
12.5
(Low Side) SC1KING2 69 kV
533552
MILLER KSC03 Westar
12.5
(Low Side) SC3MILL2 69 kV
532982
OXFORD KSC11 Westar 12.5(Bus) OXFORD 4 138 kV
533783
RIVERDALE KSC08 Westar
12.5
(Circuit) BELL 2 69 kV
533553
ROME KSC04 Westar 69 SC4ROME2 69 kV
533554
SILVERDALE KSC05 Westar 69 SC5SILV2 69 kV
TWIN VALLEY COOP
533008
MOUND VALLEY KTV01 Westar
13.2
(Low Side)
TV1MNDV4 138
kV
533005
NORTH PARSONS 802 Westar
13.2
(Circuit)
NEPARSN4 138
kV
533005
NORTHEAST
PARSONS 803 Westar
13.2
(Circuit)
NEPARSN4 138
kV
533695
OSWEGO 804 Westar
13.2
(Circuit) LABETTE2 69 kV
533671 SOUTH PARSONS
(B) 801 Westar
13.2
(Circuit) ALTAMNT2 69 kV
FOOTNOTES:
(1) kV value where meter is physically located. (Location) = Meter located on Distribution. (Low Side) = Low Side of Transformer, (Bus) = Meter located on distribution bus after switch or voltage regulator, and (Circuit) = Meter located on distribution circuit.
32 1431666 & 74318195
(A) Deduct Meter: The deduct meter is a reduction to the KEPCo Delivery Point Meter in order to determine KEPCo Net Load.
(B) There is a proposed project to convert this delivery point to 138kV circuit 533009 in about 2012.
(C)
Fostoria Deduct Meter is an offset to Fostoria DP. This meter measures Westar Energy’s load connected to Bluestem REC wires. Distribution Loss % equals 2.80% for Fostoria DP + 3.99% for use of Bluestem REC wires to Westar load, per agreement between parties.
(D)
Herington Deduct Meter is an offset to Herington DP. This meter measures Westar Energy’s load connected to Flint Hill REC wires. Distribution Loss % equals 1.39% for Herington DP + 3.00% for use of Flint Hills REC wires to Westar load, per agreement between parties.
(E)
Olpe & Reading Deduct Meters are offsets to Olpe and Reading DP, respectively. These meters measure Westar Energy’s load connected to Lyon-Coffey REC wires. Distribution Loss % is 5.00%, per agreement between parties.
33 1431666 & 74318195
Appendix 4
Wholesale Distribution Service Charges
34 1431666 & 74318195
Appendix 4
FOR DELIVERY POINTS CONNECTED TO WESTAR ENERGY’S SYSTEM ONLY
Total KEPCo Wholesale Distribution Service Charge (Monthly) = $ 61,487.04 – Effective June 1, 2011
(Details per REC on following pages)
TRANSMISSION CUSTOMER LOAD EFFECTIVE
KEPCo - Ark Valley REC See list below Oct 1, 2010
Load Location NPPC %
Substation Distribution Plant
Dollars
Customer Allocation of Substation
Substation WDS Dollars
Circuit Distribution Plant Dollars
Customer Allocation of
Circuits Circuit WDS
Dollars Total WDS Dollars
(a) (b) (c) (d) (e) (f) (g)
(b*c*a) (e*f*a) (Total Cols d + g)
Marquette-Langley 1.510% $ - 0.00% $ - $ - 0.00% $ - $ -
Medora 1.510% $ - 0.00% $ - $ - 0.00% $ - $ -
Sand Hill 1.510% $ - 0.00% $ - $ - 0.00% $ - $ -
Yoder 1.510% $ - 0.00% $ - $ - 0.00% $ - $ -
Totals $ - $ - $ -
35 1431666 & 74318195
APPENDIX 4 – WHOLESALE DISTRIBUTION SERVICE CHARGE – Westar Energy System – Continues
TRANSMISSION CUSTOMER LOAD EFFECTIVE
KEPCo - Bluestem REC See list below Oct 1, 2010
Load Location NPPC %
Substation Distribution Plant
Dollars
Customer Allocation of Substation
Substation WDS Dollars
Circuit Distribution Plant Dollars
Customer Allocation of
Circuits Circuit WDS
Dollars Total WDS Dollars
(a) (b) (c) (d) (e) (f) (g)
(b*c*a) (e*f*a) (Total Cols d + g)
Alma 1.510% $ 107,841.97 21.57% $ 351.22 $ 212.65 100.00% $ 3.21 $ 354.43
Blue Rapids 1.510% $ 30,154.38 96.08% $ 437.50 $ - 0.00% $ - $ 437.50
Clay Center 1.510% $ 17,687.97 100.00% $ 267.09 $ 135.60 100.00% $ 2.05 $ 269.14
Fostoria 1.510% $ 35,196.46 13.83% $ 73.49 $ 91,255.72 13.83% $ 190.54 $ 264.03
Hunter's Island 1.510% $ 632,831.18 3.57% $ 341.10 $ 34,054.09 14.55% $ 74.80 $ 415.90
Louisville 1.510% $ 613,945.45 29.51% $ 2,736.11 $ 8,136.00 59.03% $ 72.52 $ 2,808.63
Leonardville 1.510% $ - 0.00% $ - $ - 0.00% $ - $ -
Peddicord 1.510% $ 56,716.31 92.87% $ 795.32 $ - 0.00% $ - $ 795.32
Soldier 1.510% $ 25,203.33 66.50% $ 253.07 $ 382.15 66.50% $ 3.84 $ 256.91
St. George 1.510% $ 411,609.51 54.34% $ 3,377.38 $ 215.73 100.00% $ 3.26 $ 3,380.64
Wakefield 1.510% $ 66,909.68 5.53% $ 55.85 $ - 0.00% $ - $ 55.85
Wamego 1.510% $ 16,184.18 100.00% $ 244.38 $ - 0.00% $ - $ 244.38
Totals $ 8,932.51 $ 350.22 $ 9,282.73
36 1431666 & 74318195
APPENDIX 4 – WHOLESALE DISTRIBUTION SERVICE CHARGE – Westar Energy System – Continues
TRANSMISSION CUSTOMER LOAD EFFECTIVE
KEPCo - Brown-Atchison REC See list below Oct 1, 2010
Load Location NPPC %
Substation Distribution Plant
Dollars
Customer Allocation of Substation
Substation WDS Dollars
Circuit Distribution Plant Dollars
Customer Allocation of
Circuits Circuit WDS
Dollars Total WDS Dollars
(a) (b) (c) (d) (e) (f) (g)
(b*c*a) (e*f*a) (Total Cols d + g)
Circleville 1.510% $ 130,452.62 47.52% $ 936.03 $ 6,006.46 47.52% $ 43.10 $ 979.13
East Fairview 1.510% $ 63,046.00 21.34% $ 203.12 $ 16,694.21 21.34% $ 53.79 $ 256.91
East Hiawatha 1.510% $ 92,366.70 11.06% $ 154.31 $ 64,955.48 34.70% $ 340.34 $ 494.65
Lancaster 1.510% $ 26,903.38 52.75% $ 214.31 $ 18,053.29 52.75% $ 143.81 $ 358.12
Muscotah 1.510% $ 40,993.95 6.30% $ 38.97 $ 30,996.93 62.96% $ 294.70 $ 333.67
Netawaka 1.510% $ 58,563.88 56.58% $ 500.38 $ 4,289.89 100.00% $ 64.78 $ 565.16
North Hiawatha 1.510% $ 61,177.56 14.67% $ 135.52 $ 131,861.75 18.86% $ 375.55 $ 511.07
Nortonville 1.510% $ 76,887.11 20.79% $ 241.32 $ 18,241.28 31.18% $ 85.88 $ 1,026.95
$ 222,945.29 20.79% $ 699.75
South Fairview 1.510% $ - 0.00% $ - $ - 0.00% $ - $ -
Willis 1.510% $ - 0.00% $ - $ - 0.00% $ - $ -
Totals $ 3,123.71 $ 1,401.95 $ 4,525.66
37 1431666 & 74318195
APPENDIX 4 – WHOLESALE DISTRIBUTION SERVICE CHARGE – Westar Energy System – Continues
TRANSMISSION CUSTOMER LOAD EFFECTIVE
KEPCo - Butler REC See list below Oct 1, 2010
Load Location NPPC
%
Substation Distribution Plant
Dollars
Customer Allocation
of Substation
Substation WDS Dollars
Circuit Distribution Plant Dollars
Customer Allocation
of Circuits
Circuit WDS Dollars Total WDS Dollars
(a) (b) (c) (d) (e) (f) (g)
(b*c*a) (e*f*a) (Total Cols d + g)
Benton 1.510% $ - 0.00% $ - $ - 0.00% $ - $ -
De Graff 1.510% $ - 0.00% $ - $ - 0.00% $ - $ -
Eureka 1.510% $ - 0.00% $ - $ - 0.00% $ - $ -
Furley 1.510% $ - 0.00% $ - $ - 0.00% $ - $ -
Keighley 1.510% $ - 0.00% $ - $ - 0.00% $ - $ -
Leon 1.510% $ 151,010.72 34.02% $ 775.75 $ 9,975.85 80.29% $ 120.94 $ 896.69
Little Pony Meadows 1.510% $ - 0.00% $ - $ - 0.00% $ - $ -
Newton (A) 1.370% $ 340,990.81 1.97% $ 92.03 $ 66,996.00 10.18% $ 93.44 $ 185.47
Pony Meadows 1.510% $ - 0.00% $ - $ - 0.00% $ - $ -
Potwin 1.510% $ 14,095.36 15.41% $ 32.81 $ 554.73 51.38% $ 4.30 $ 37.11
Rose Hill 1.510% $ 77,545.00 23.79% $ 278.52 $ 7,399.45 30.24% $ 33.78 $ 312.30
Smileyburg 1.510% $ 23,928.86 47.07% $ 170.07 $ 7,747.69 47.07% $ 55.06 $ 225.13
Spurrier 1.510% $ 1,589,257.74 5.13% $ 1,231.37 $ 35,370.03 14.66% $ 78.30 $ 1,309.67
Towanda 1.510% $ 25,105.90 13.48% $ 51.09 $ 59,639.35 49.92% $ 449.52 $ 500.61
Totals $ 2,631.64 $ 835.34 $ 3,466.98
38 1431666 & 74318195
APPENDIX 4 – WHOLESALE DISTRIBUTION SERVICE CHARGE – Westar Energy System – Continues
TRANSMISSION CUSTOMER LOAD EFFECTIVE
KEPCo - Caney Valley REC See list below Oct 1, 2010
Load Location NPPC %
Substation Distribution Plant
Dollars
Customer Allocation of Substation
Substation WDS Dollars
Circuit Distribution Plant Dollars
Customer Allocation of
Circuits Circuit WDS
Dollars Total WDS Dollars
(a) (b) (c) (d) (e) (f) (g)
(b*c*a) (e*f*a) (Total Cols d + g)
Burden 1.510% $ 31,005.95 17.78% $ 83.23 $ 206,904.03 24.69% $ 771.42 $ 854.65
Caney 1.510% $ - 0.00% $ - $ - 0.00% $ - $ -
Grenola 1.510% $ 190,243.35 16.26% $ 467.05 $ 97,986.41 66.12% $ 978.28 $ 1,445.33
Harshman 1.510% $ 190,243.35 10.44% $ 299.90 $ 32,448.46 53.07% $ 260.02 $ 559.92
Longton 1.510% $ 20,740.03 40.31% $ 126.24 $ 182,431.31 40.31% $ 1,110.44 $ 1,236.68
McCall 1.510% $ - 0.00% $ - $ - 0.00% $ - $ -
Sedan Switching Station 1.510% $ - 0.00% $ - $ - 0.00% $ - $ -
Silverdale 1.510% $ 214,461.23 4.13% $ 133.81 $ 147,927.27 14.42% $ 322.16 $ 455.97
Tisdale 1.510% $ 31,005.95 8.52% $ 39.88 $ 177,448.01 11.83% $ 317.01 $ 356.89
Totals $ 1,150.11 $ 3,759.33 $ 4,909.44
39 1431666 & 74318195
APPENDIX 4 – WHOLESALE DISTRIBUTION SERVICE CHARGE – Westar Energy System – Continues
TRANSMISSION CUSTOMER LOAD EFFECTIVE
KEPCo - DS&O REC See list below Oct 1, 2010
Load Location NPPC %
Substation Distribution Plant
Dollars
Customer Allocation of Substation
Substation WDS Dollars
Circuit Distribution Plant Dollars
Customer Allocation of
Circuits Circuit WDS
Dollars Total WDS Dollars
(a) (b) (c) (d) (e) (f) (g)
(b*c*a) (e*f*a) (Total Cols d + g)
Assaria 1.510% $ 7,763.96 100.00% $ 117.24 $ - 0.00% $ - $ 117.24
Bennington 1.510% $ 27,514.77 13.50% $ 56.10 $ 51,336.93 20.00% $ 155.07 $ 211.17
Chapman 1.510% $ 160,411.74 87.32% $ 2,114.99 $ 206.48 100.00% $ 3.12 $ 2,118.11
Gypsum 1.510% $ 85,943.67 40.16% $ 521.22 $ 17,350.64 94.93% $ 248.71 $ 769.93
K-18 1.510% $ - 0.00% $ - $ - 0.00% $ - $ -
Magnolia 1.510% $ 304,123.10 9.85% $ 452.29 $ 24,836.37 36.61% $ 137.31 $ 589.60
Marquette 1.510% $ - 0.00% $ - $ - 0.00% $ - $ -
Milford 1.510% $ - 0.00% $ - $ - 0.00% $ - $ -
Minneapolis 1.510% $ 47,498.46 100.00% $ 717.23 $ - 0.00% $ - $ 717.23
North Salina 1.510% $ - 0.00% $ - $ - 0.00% $ - $ -
NW Junction City 1.510% $ 23,854.26 19.11% $ 68.83 $ 8,191.47 100.00% $ 123.69 $ 192.52
Pearl 1.510% $ 48,899.40 97.47% $ 719.72 $ - 0.00% $ - $ 719.72
Ramona 1.510% $ 23,571.89 100.00% $ 355.94 $ - 0.00% $ - $ 355.94
Solomon 1.510% $ 24,638.63 100.00% $ 372.04 $ - 0.00% $ - $ 372.04
Southwest Abilene 1.510% $ 78,594.44 57.41% $ 681.30 $ 135.60 100.00% $ 2.05 $ 683.35
Talmage #1 1.510% $ 450,864.50 94.87% $ 6,458.58 $ 998.51 94.87% $ 14.30 $ 6,472.88
Talmage #2 1.510% $ - 0.00% $ - $ - 0.00% $ - $ -
Upland 1.510% $ 182,399.37 70.24% $ 1,934.59 $ - 0.00% $ - $ 1,934.59
West Lindsborg 1.510% $ - 0.00% $ - $ - 0.00% $ - $ -
West Salina 1.510% $ 757,361.06 8.84% $ 1,010.70 $ 14,872.85 47.24% $ 106.08 $ 1,116.78
Totals $15,580.77 $ 790.33 $ 16,371.10
40 1431666 & 74318195
APPENDIX 4 – WHOLESALE DISTRIBUTION SERVICE CHARGE – Westar Energy System – Continues
TRANSMISSION CUSTOMER LOAD EFFECTIVE
KEPCo - Flint Hills REC See list below Oct 1, 2010
Load Location NPPC %
Substation Distribution Plant
Dollars
Customer Allocation
of Substation
Substation WDS Dollars
Circuit Distribution Plant Dollars
Customer Allocation of Circuits
Circuit WDS Dollars Total WDS Dollars
(a) (b) (c) (d) (e) (f) (g)
(b*c*a) (e*f*a) (Total Cols d + g)
Alta Vista 1.510% $ - 0.00% $ - $ - 0.00% $ - $ -
Alta Vista South 1.510% $ 89,894.55 16.42% $ 222.83 $ 64,835.29 16.42% $ 160.72 $ 383.55
Cottonwood Falls 1.510% $ - 0.00% $ - $ - 0.00% $ - $ -
Council Grove East 1.510% $ - 0.00% $ - $ - 0.00% $ - $ -
Council Grove West 1.510% $ 63,961.49 10.50% $ 101.37 $ 76,922.18 37.95% $ 440.77 $ 542.14
Durham 1.510% $ - 0.00% $ - $ - 0.00% $ - $ -
Florence 1.510% $ 13,146.39 27.92% $ 55.43 $ 95,567.18 27.92% $ 402.97 $ 458.40
Goessel 1.510% $ - 0.00% $ - $ - 0.00% $ - $ -
Herington 1.510% $ 32,882.73 100.00% $ 496.53 $ - 0.00% $ - $ 496.53
Hillsboro 1.510% $ 6,535.61 100.00% $ 98.69 $ - 0.00% $ - $ 98.69
Junction City 1.510% $ - 0.00% $ - $ - 0.00% $ - $ -
Lehigh 1.510% $ 87,267.25 59.88% $ 789.01 $ 104.78 100.00% $ 1.58 $ 790.59
Marion 1.510% $ 35,741.33 59.47% $ 320.95 $ - 0.00% $ - $ 320.95
Peabody 1.510% $ 7,088.83 19.19% $ 20.54 $ 921.46 19.19% $ 2.67 $ 23.21
Totals $ 2,105.35 $ 1,008.71 $ 3,114.06
41 1431666 & 74318195
APPENDIX 4 – WHOLESALE DISTRIBUTION SERVICE CHARGE – Westar Energy System – Continues
TRANSMISSION CUSTOMER LOAD EFFECTIVE
KEPCo - Heartland REC See list below Oct 1, 2010
Load Location NPPC %
Substation Distribution Plant
Dollars
Customer Allocation of Substation
Substation WDS Dollars
Circuit Distribution Plant Dollars
Customer Allocation of
Circuits Circuit WDS
Dollars Total WDS Dollars
(a) (b) (c) (d) (e) (f) (g)
(b*c*a) (e*f*a) (Total Cols d + g)
Baker 1.510% $ 94,268.77 13.65% $ 194.29 $ 46.23 100.00% $ 0.70 $ 194.99
Cherokee 1.510% $ 94,268.77 15.45% $ 219.91 $ 40,914.22 22.61% $ 139.68 $ 359.59
Conger 1.510% $ - 0.00% $ - $ - 0.00% $ - $ -
Devon 1.510% $ - 0.00% $ - $ - 0.00% $ - $ -
Elsmore 1.510% $ - 0.00% $ - $ - 0.00% $ - $ -
Englevale 1.510% $ 111,887.79 30.77% $ 519.87 $ 119,207.81 37.61% $ 676.97 $ 1,196.84
Greenbush 1.510% $ - 0.00% $ - $ - 0.00% $ - $ -
Hiattville 1.510% $ - 0.00% $ - $ - 0.00% $ - $ -
Magellan 1.510% $ - 0.00% $ - $ - 0.00% $ - $ -
McCune 1.510% $ 28,040.70 23.44% $ 99.26 $ 1,081.72 82.05% $ 13.40 $ 112.66
Rose 1.510% $ - 0.00% $ - $ - 0.00% $ - $ -
SE Humboldt 1.510% $ 88,675.19 7.19% $ 96.25 $ 73,143.87 15.81% $ 174.66 $ 270.91
Urbana 1.510% $ - 0.00% $ - $ - 0.00% $ - $ -
Totals $ 1,129.58 $ 1,005.41 $ 2,134.99
42 1431666 & 74318195
APPENDIX 4 – WHOLESALE DISTRIBUTION SERVICE CHARGE – Westar Energy System – Continues
TRANSMISSION CUSTOMER LOAD EFFECTIVE
KEPCo - Leavenworth-Jefferson REC See list below Oct 1, 2010
Load Location NPPC %
Substation Distribution Plant
Dollars
Customer Allocation of Substation
Substation WDS Dollars
Circuit Distribution Plant Dollars
Customer Allocation of
Circuits Circuit WDS
Dollars Total WDS Dollars
(a) (b) (c) (d) (e) (f) (g)
(b*c*a) (e*f*a) (Total Cols d + g)
Hoyt 1.510% $ 450,153.91 41.11% $ 2,794.46 $ 27,329.56 47.44% $ 195.76 $ 2,990.22
Mayetta 1.510% $ 33,894.22 45.76% $ 234.19 $ 8,576.70 45.76% $ 59.26 $ 293.45
NW Leavenworth 1.510% $ - 0.00% $ - $ - 0.00% $ - $ -
Nortonville 1.510% $ 76,887.11 19.51% $ 226.50 $ 24,494.29 29.26% $ 108.24 $ 991.51
$ 222,945.29 19.51% $ 656.77
Oskaloosa 1.510% $ - 0.00% $ - $ - 0.00% $ - $ -
Rock Creek 1.510% $ 241,920.54 38.79% $ 1,417.01 $ 40.06 100.00% $ 0.60 $ 1,417.61
Stranger 1.510% $ - 0.00% $ - $ - 0.00% $ - $ -
Tonganoxie 1.510% $ - 0.00% $ - $ - 0.00% $ - $ -
Valley Falls 1.510% $ 238,760.68 9.34% $ 336.91 $ 53,941.06 22.43% $ 182.68 $ 519.59
Totals $ 5,665.84 $ 546.54 $ 6,212.38
43 1431666 & 74318195
APPENDIX 4 – WHOLESALE DISTRIBUTION SERVICE CHARGE – Westar Energy System – Continues
TRANSMISSION CUSTOMER LOAD EFFECTIVE
KEPCo - Lyon-Coffey REC See list below Oct 1, 2010
Load Location NPPC %
Substation Distribution Plant
Dollars
Customer Allocation of Substation
Substation WDS Dollars
Circuit Distribution Plant Dollars
Customer Allocation of
Circuits Circuit WDS
Dollars Total WDS Dollars
(a) (b) (c) (d) (e) (f) (g)
(b*c*a) (e*f*a) (Total Cols d + g)
Americus - T. Bird 1.510% $ - 0.00% $ - $ - 0.00% $ - $ -
Melvern/Beto Junction 1.510% $ 17,625.21 37.99% $ 101.11 $ 67,713.71 75.98% $ 776.93 $ 878.04
Burlington 1.510% $ - 0.00% $ - $ - 0.00% $ - $ -
Eskridge 1.510% $ 21,565.41 25.14% $ 81.86 $ 38,985.00 25.14% $ 147.98 $ 229.84
Hartford 1.510% $ 91,140.50 5.11% $ 70.32 $ 45,903.68 25.55% $ 177.09 $ 247.41
Olpe 1.510% $ 153,643.50 30.35% $ 704.23 $ - 0.00% $ - $ 704.23
Reading 1.510% $ 234,075.33 23.81% $ 841.66 $ 27.74 100.00% $ 0.42 $ 842.08
Toronto 1.510% $ 136,568.05 24.13% $ 497.61 $ 59,472.93 40.84% $ 366.72 $ 864.33
Vernon 1.510% $ - 0.00% $ - $ - 0.00% $ - $ -
Virgil 1.510% $ 52,730.06 40.12% $ 319.47 $ 100,621.36 64.81% $ 984.79 $ 1,304.26
Waverly 1.510% $ - 0.00% $ - $ - 0.00% $ - $ -
West Emporia 1.510% $ - 0.00% $ - $ - 0.00% $ - $ -
Westphalia 1.510% $ - 0.00% $ - $ - 0.00% $ - $ -
Williams 1.510% $ - 0.00% $ - $ - 0.00% $ - $ -
Wolf Creek 1.510% $ - 0.00% $ - $ - 0.00% $ - $ -
Totals $ 2,616.26 $ 2,453.93 $ 5,070.19
44 1431666 & 74318195
APPENDIX 4 – WHOLESALE DISTRIBUTION SERVICE CHARGE – Westar Energy System – Continues
TRANSMISSION CUSTOMER LOAD EFFECTIVE
KEPCo - Radiant REC See list below Oct 1, 2010
Load Location NPPC %
Substation Distribution Plant
Dollars
Customer Allocation of Substation
Substation WDS Dollars
Circuit Distribution Plant Dollars
Customer Allocation of
Circuits Circuit WDS
Dollars Total WDS Dollars
(a) (b) (c) (d) (e) (f) (g)
(b*c*a) (e*f*a) (Total Cols d + g)
Altoona 1.510% $ 7,970.84 34.75% $ 41.82 $ 41,358.00 34.75% $ 216.99 $ 258.81
Brooks 1.510% $ - 0.00% $ - $ - 0.00% $ - $ -
Caney 1.510% $ - 0.00% $ - $ - 0.00% $ - $ -
Coffeyville 1.510% $ 22,916.69 48.43% $ 167.60 $ 17,631.08 48.43% $ 128.94 $ 296.54
High Prairie 1.510% $ - 0.00% $ - $ - 0.00% $ - $ -
Independence 1.510% $ 205,582.67 2.13% $ 66.19 $ 109,231.96 10.80% $ 178.18 $ 244.37
Louisburg 1.510% $ - 0.00% $ - $ - 0.00% $ - $ -
SEK Pipeline 1.510% $ - 0.00% $ - $ - 0.00% $ - $ -
Studebaker 1.510% $ - 0.00% $ - $ - 0.00% $ - $ -
Totals $ 275.61 $ 524.11 $ 799.72
45 1431666 & 74318195
APPENDIX 4 – WHOLESALE DISTRIBUTION SERVICE CHARGE – Westar Energy System – Continues
TRANSMISSION CUSTOMER LOAD EFFECTIVE
KEPCo - Rolling Hills REC See list below Oct 1, 2010
Load Location NPPC % Substation Distribution
Plant Dollars
Customer Allocation of Substation
Substation WDS Dollars
Circuit Distribution Plant Dollars
Customer Allocation of
Circuits Circuit WDS
Dollars Total WDS Dollars
(a) (b) (c) (d) (e) (f) (g)
(b*c*a) (e*f*a) (Total Cols d + g)
New Beverly 1.510% $ - 0.00% $ - $ - 0.00% $ - $ -
Totals $ - $ - $ -
TRANSMISSION CUSTOMER LOAD EFFECTIVE
KEPCo - Sharpe Gen Aux See below list Oct 1, 2010
Load Location NPPC % Substation Distribution
Plant Dollars
Customer Allocation of Substation
Substation WDS Dollars
Circuit Distribution Plant Dollars
Customer Allocation of
Circuits Circuit WDS
Dollars Total WDS Dollars
(a) (b) (c) (d) (e) (f) (g)
(b*c*a) (e*f*a) (Total Cols d + g)
Auxillary Load 1.510% $ - 0.00% $ - $ - 0.00% $ - $ -
Totals $ - $ - $ -
46 1431666 & 74318195
APPENDIX 4 – WHOLESALE DISTRIBUTION SERVICE CHARGE – Westar Energy System – Continues
TRANSMISSION CUSTOMER LOAD EFFECTIVE
KEPCo - Sedgwick REC See list below Oct 1, 2010
Load Location NPPC % Substation Distribution
Plant Dollars
Customer Allocation of Substation
Substation WDS Dollars
Circuit Distribution Plant Dollars
Customer Allocation of
Circuits Circuit WDS
Dollars Total WDS Dollars
(a) (b) (c) (d) (e) (f) (g)
(b*c*a) (e*f*a) (Total Cols d + g)
Andale 1.510% $ - 0.00% $ - $ - 0.00% $ - $ -
Cheney 1.510% $ - 0.00% $ - $ - 0.00% $ - $ -
Cheney Lake Ozone Plant 1.510% $ - 0.00% $ - $ - 0.00% $ - $ -
Clearwater 1.510% $ 1,262,823.30 12.13% $ 2,313.36 $ 67,183.64 29.17% $ 295.96 $ 2,609.32
Colwich 1.510% $ - 0.00% $ - $ - 0.00% $ - $ -
Craig 1.510% $ - 0.00% $ - $ - 0.00% $ - $ -
Garden Plain 1.510% $ 34,582.20 4.61% $ 24.09 $ 456.11 100.00% $ 6.89 $ 30.98
Halstead 1.510% $ 38,406.29 12.05% $ 69.87 $ 47,493.90 45.56% $ 326.71 $ 396.58
Haysville 1.510% $ 45,337.48 43.75% $ 299.49 $ 44,732.59 43.75% $ 295.50 $ 594.99
Koch 1.510% $ - 0.00% $ - $ - 0.00% $ - $ -
St. Marks 1.510% $ - 0.00% $ - $ - 0.00% $ - $ -
Waterloo 1.510% $ 1,219.95 27.69% $ 5.10 $ 1,685.75 27.69% $ 7.05 $ 12.15
Totals $ 2,711.91 $ 932.11 $ 3,644.02
47 1431666 & 74318195
APPENDIX 4 – WHOLESALE DISTRIBUTION SERVICE CHARGE – Westar Energy System – Continues
TRANSMISSION CUSTOMER LOAD EFFECTIVE
KEPCo - Sumner-Cowley REC See list below Oct 1, 2010
Load Location NPPC % Substation Distribution
Plant Dollars
Customer Allocation of Substation
Substation WDS Dollars
Circuit Distribution Plant Dollars
Customer Allocation of
Circuits Circuit WDS
Dollars Total WDS Dollars
(a) (b) (c) (d) (e) (f) (g)
(b*c*a) (e*f*a) (Total Cols d + g)
Anson 1.510% $ - 0.00% $ - $ - 0.00% $ - $ -
Belle Plaine 1.510% $ - 0.00% $ - $ - 0.00% $ - $ -
Creswell 1.510% $ - 0.00% $ - $ - 0.00% $ - $ -
Geuda 1.510% $ 23,848.77 9.75% $ 35.11 $ 65,994.05 13.65% $ 136.01 $ 171.12
King 1.510% $ - 0.00% $ - $ - 0.00% $ - $ -
Miller 1.510% $ - 0.00% $ - $ - 0.00% $ - $ -
Oxford 1.510% $ 117,290.11 20.45% $ 362.10 $ - 0.00% $ - $ 362.10
Riverdale 1.510% $ 30,956.86 12.23% $ 57.15 $ 123.27 100.00% $ 1.86 $ 59.01
Rome 1.510% $ - 0.00% $ - $ - 0.00% $ - $ -
Silverdale 1.510% $ - 0.00% $ - $ - 0.00% $ - $ -
Totals $ 454.36 $ 137.87 $ 592.23
48 1431666 & 74318195
APPENDIX 4 – WHOLESALE DISTRIBUTION SERVICE CHARGE – Westar Energy System – Continues
TRANSMISSION CUSTOMER LOAD EFFECTIVE
KEPCo - Twin Valley REC See list below Oct 1, 2010
Load Location NPPC %
Substation Distribution Plant
Dollars
Customer Allocation of Substation
Substation WDS Dollars
Circuit Distribution Plant Dollars
Customer Allocation of
Circuits Circuit WDS
Dollars Total WDS Dollars
(a) (b) (c) (d) (e) (f) (g)
(b*c*a) (e*f*a) (Total Cols d + g)
Mound Valley 1.510% $ - 0.00% $ - $ - 0.00% $ - $ -
North Parsons 1.510% $ 327,071.49 7.05% $ 348.16 $ 40,569.05 26.74% $ 163.79 $ 581.92
$ 65,735.15 7.05% $ 69.97
Northeast Parsons 1.510% $ 327,071.49 2.63% $ 130.05 $ 58,514.48 22.13% $ 195.56 $ 351.75
$ 65,735.15 2.63% $ 26.14
Oswego 1.510% $ 166,049.07 5.42% $ 135.97 $ 2,767.47 13.91% $ 5.81 $ 141.78
$ - 0.00% $ -
South Parsons 1.510% $ 65,434.98 28.41% $ 280.70 $ 782.78 62.50% $ 7.39 $ 288.09
$ - 0.00% $ -
Totals $ 990.99 $ 372.55 $ 1,363.54
NOTES:
A Butler REC, Newton Delivery Point WDS Effective June 1, 2011
49 1431666 & 74318195
ATTACHMENT G
Network Operating Agreement
This Network Operating Agreement ("Operating Agreement") is entered into this 1st day
of June, 2011, by and between Kansas Electric Power Cooperative, Inc. ("Network Customer"),
Southwest Power Pool, Inc. ("Transmission Provider") and Westar Energy, Inc. ("Host
Transmission Owner"). The Network Customer, Transmission Provider and Host Transmission
Owner shall be referred to individually as a “Party” and collectively as "Parties."
WHEREAS, the Transmission Provider has determined that the Network Customer has
made a valid request for Network Integration Transmission Service in accordance with the
Transmission Provider’s Open Access Transmission Tariff ("Tariff") filed with the Federal
Energy Regulatory Commission ("Commission");
WHEREAS, the Transmission Provider administers Network Integration Transmission
Service for Transmission Owners within the SPP Region and acts as an agent for these
Transmission Owners in providing service under the Tariff;
WHEREAS, the Host Transmission Owner owns the transmission facilities to which the
Network Customer’s Network Load is physically connected or is the Control Area to which the
Network Load is dynamically scheduled;
WHEREAS, the Network Customer has represented that it is an Eligible Customer under
the Tariff;
WHEREAS, the Network Customer and Transmission Provider have entered into a
Network Integration Transmission Service Agreement (“Service Agreement”) under the Tariff;
and
WHEREAS, the Parties intend that capitalized terms used herein shall have the same
meaning as in the Tariff, unless otherwise specified herein.
NOW, THEREFORE, in consideration of the mutual covenants and agreements herein,
the Parties agree as follows:
1.0 Network Service
This Operating Agreement sets out the terms and conditions under which the
Transmission Provider, Host Transmission Owner, and Network Customer will cooperate
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and the Host Transmission Owner and Network Customer will operate their respective
systems and specifies the equipment that will be installed and operated. The Parties shall
operate and maintain their respective systems in a manner that will allow the Host
Transmission Owner and the Network Customer to operate their systems and Control
Area and the Transmission Provider to perform its obligations consistent with Good
Utility Practice. The Transmission Provider may, on a non-discriminatory basis, waive
the requirements of Section 4.1 and Section 8.3 to the extent that such information is
unknown at the time of application or where such requirement is not applicable.
2.0 Designated Representatives of the Parties
2.1 Each Party shall designate a representative and alternate ("Designated
Representative(s)") from their respective company to coordinate and implement,
on an ongoing basis, the terms and conditions of this Operating Agreement,
including planning, operating, scheduling, redispatching, curtailments, control
requirements, technical and operating provisions, integration of equipment,
hardware and software, and other operating considerations.
2.2 The Designated Representatives shall represent the Transmission Provider, Host
Transmission Owner, and Network Customer in all matters arising under this
Operating Agreement and which may be delegated to them by mutual agreement
of the Parties hereto.
2.3 The Designated Representatives shall meet or otherwise confer at the request of
any Party upon reasonable notice, and each Party may place items on the meeting
agenda. All deliberations of the Designated Representatives shall be conducted
by taking into account the exercise of Good Utility Practice. If the Designated
Representatives are unable to agree on any matter subject to their deliberation,
that matter shall be resolved pursuant to Section 12.0 of the Tariff, or otherwise,
as mutually agreed by the Parties.
3.0 System Operating Principles
3.1 The Network Customer must design, construct, and operate its facilities safely
and efficiently in accordance with Good Utility Practice, NERC, SPP, or any
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successor requirements, industry standards, criteria, and applicable
manufacturer’s equipment specifications, and within operating physical parameter
ranges (voltage schedule, load power factor, and other parameters) required by the
Host Transmission Owner and Transmission Provider.
3.2 The Host Transmission Owner and Transmission Provider reserve the right to
inspect the facilities and operating records of the Network Customer upon
mutually agreeable terms and conditions.
3.3 Electric service, in the form of three phase, approximately sixty hertz alternating
current, shall be delivered at designated delivery points and nominal voltage(s)
listed in the Service Agreement. When multiple delivery points are provided to a
specific Network Load identified in Appendix 3 of the Service Agreement, they
shall not be operated in parallel by the Network Customer without the approval of
the Host Transmission Owner and Transmission Provider. The Designated
Representatives shall establish the procedure for obtaining such approval. The
Designated Representatives shall also establish and monitor standards and
operating rules and procedures to assure that transmission system integrity and the
safety of customers, the public and employees are maintained or enhanced when
such parallel operations is permitted either on a continuing basis or for
intermittent switching or other service needs. Each Party shall exercise due
diligence and reasonable care in maintaining and operating its facilities so as to
maintain continuity of service.
3.4 The Host Transmission Owner and Network Customer shall operate their systems
and delivery points in continuous synchronism and in accord with applicable
NERC Standards, SPP Criteria, and Good Utility Practice.
3.5 If the function of any Party’s facilities is impaired or the capacity of any delivery
point is reduced, or synchronous operation at any delivery point(s) becomes
interrupted, either manually or automatically, as a result of force majeure or
maintenance coordinated by the Parties, the Parties will cooperate to remove the
cause of such impairment, interruption or reduction, so as to restore normal
operating conditions expeditiously.
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3.6 The Transmission Provider and Host Transmission Owner, if applicable, reserve
the sole right to take any action necessary during an actual or imminent
emergency to preserve the reliability and integrity of the Transmission System,
limit or prevent damage, expedite restoration of service, ensure safe and reliable
operation, avoid adverse effects on the quality of service, or preserve public
safety.
3.7 In an emergency, the reasonable judgment of the Transmission Provider and Host
Transmission Owner, if applicable, in accordance with Good Utility Practice,
shall be the sole determinant of whether the operation of the Network Customer
loads or equipment adversely affects the quality of service or interferes with the
safe and reliable operation of the transmission system. The Transmission
Provider or Host Transmission Owner, if applicable, may discontinue
transmission service to such Network Customer until the power quality or
interfering condition has been corrected. Such curtailment of load, redispatching,
or load shedding shall be done on a non-discriminatory basis by Load Ratio
Share, to the extent practicable. The Transmission Provider or Host Transmission
Owner, if applicable, will provide reasonable notice and an opportunity to
alleviate the condition by the Network Customer to the extent practicable.
4.0 System Planning & Protection
4.1 No later than October 1 of each year, the Network Customer shall provide the
Transmission Provider and Host Transmission Owner the following information:
a) A ten (10) year projection of summer and winter peak demands with the
corresponding power factors and annual energy requirements on an
aggregate basis for each delivery point. If there is more than one delivery
point, the Network Customer shall provide the summer and winter peak
demands and energy requirements at each delivery point for the normal
operating configuration;
b) A ten (10) year projection by summer and winter peak of planned
generating capabilities and committed transactions with third parties
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which resources are expected to be used by the Network Customer to
supply the peak demand and energy requirements provided in (a);
c) A ten (10) year projection by summer and winter peak of the estimated
maximum demand in kilowatts that the Network Customer plans to
acquire from the generation resources owned by the Network Customer,
and generation resources purchased from others; and
d) A projection for each of the next ten (10) years of transmission facility
additions to be owned and/or constructed by the Network Customer which
facilities are expected to affect the planning and operation of the
transmission system within the Host Transmission Owner’s Control Area.
This information is to be delivered to the Transmission Provider’s and Host
Transmission Owner’s Designated Representatives pursuant to Section 2.0.
4.2 Information exchanged by the Parties under this article will be used for system
planning and protection only, and will not be disclosed to third parties absent
mutual consent or order of a court or regulatory agency.
4.3 The Host Transmission Owner, and Transmission Provider, if applicable, will
incorporate this information in its system load flow analyses performed during the
first half of each year. Following completion of these analyses, the Transmission
Provider or Host Transmission Owner will provide the following to the Network
Customer:
a) A statement regarding the ability of the Host Transmission Owner’s
transmission system to meet the forecasted deliveries at each of the
delivery points;
b) A detailed description of any constraints on the Host Transmission
Owner’s system within the five (5) year horizon that will restrict
forecasted deliveries; and
c) In the event that studies reveal a potential limitation of the Transmission
Provider’s ability to deliver power and energy to any of the delivery
points, a Designated Representative of the Transmission Provider will
coordinate with the Designated Representatives of the Host Transmission
Owner and the Network Customer to identify appropriate remedies for
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such constraints including but not limited to: construction of new
transmission facilities, upgrade or other improvements to existing
transmission facilities or temporary modification to operating procedures
designed to relieve identified constraints. Any constraints within the
Transmission System will be remedied pursuant to the procedures of
Attachment O of the Tariff.
For all other constraints the Host Transmission Owner, upon
agreement with the Network Customer and consistent with Good Utility
Practice, will endeavor to construct and place into service sufficient
capacity to maintain reliable service to the Network Customer.
An appropriate sharing of the costs to relieve such constraints will
be determined by the Parties, consistent with the Tariff and with the
Commission’s rules, regulations, policies, and precedents then in effect. If
the Parties are unable to agree upon an appropriate remedy or sharing of
the costs, the Transmission Provider shall submit its proposal for the
remedy or sharing of such costs to the Commission for approval consistent
with the Tariff.
4.4 The Host Transmission Owner and the Network Customer shall coordinate with
the Transmission Provider: (1) all scheduled outages of generating resources and
transmission facilities consistent with the reliability of service to the customers of
each Party, and (2) additions or changes in facilities which could affect another
Party’s system. Where coordination cannot be achieved, the Designated
Representatives shall intervene for resolution.
4.5 The Network Customer shall coordinate with the Host Transmission Owner
regarding the technical and engineering arrangements for the delivery points,
including one line diagrams depicting the electrical facilities configuration and
parallel generation, and shall design and build the facilities to avoid interruptions
on the Host Transmission Owner’s transmission system.
4.6 The Network Customer shall provide for automatic and underfrequency load
shedding of the Network Customer Network Load in accordance with the SPP
Criteria related to emergency operations.
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5.0 Maintenance of Facilities
5.1 The Network Customer shall maintain its facilities necessary to reliably receive
capacity and energy from the Host Transmission Owner’s transmission system
consistent with Good Utility Practice. The Transmission Provider or Host
Transmission Owner, as appropriate, may curtail service under this Operating
Agreement to limit or prevent damage to generating or transmission facilities
caused by the Network Customer’s failure to maintain its facilities in accordance
with Good Utility Practice, and the Transmission Provider or Host Transmission
Owner may seek as a result any appropriate relief from the Commission.
5.2 The Designated Representatives shall establish procedures to coordinate the
maintenance schedules, and return to service, of the generating resources and
transmission and substation facilities, to the greatest extent practical, to ensure
sufficient transmission resources are available to maintain system reliability and
reliability of service.
5.3 The Network Customer shall obtain: (1) concurrence from the Transmission
Provider before beginning any scheduled maintenance of facilities which could
impact the operation of the Transmission System over which transmission service
is administered by Transmission Provider; and (2) clearance from the
Transmission Provider when the Network Customer is ready to begin
maintenance on a transmission line or substation. The Transmission Provider
shall coordinate clearances with the Host Transmission Owner. The Network
Customer shall notify the Transmission Provider and the Host Transmission
Owner as soon as practical at the time when any unscheduled or forced outages
occur and again when such unscheduled or forced outages end.
6.0 Scheduling Procedures
6.1 Prior to the beginning of each week, the Network Customer shall provide to the
Transmission Provider expected hourly energy schedules for that week for all
energy flowing into the Transmission System administered by Transmission
Provider.
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6.2 In accordance with Section 36 of the Tariff, the Network Customer shall provide
to the Transmission Provider the Network Customer’s hourly energy schedules
for the next calendar day for all energy flowing into the Transmission System
administered by the Transmission Provider. The Network Customer may modify
its hourly energy schedules up to twenty (20) minutes before the start of the next
clock hour provided that the Delivering Party and Receiving Party also agree to
the schedule modification. The hourly schedule must be stated in increments of
1000 kW per hour. The Network Customer shall submit, or arrange to have
submitted, to the Transmission Provider a NERC transaction identification Tag
where required by NERC Standard INT-001. These hourly energy schedules shall
be used by the Transmission Provider to determine whether any Energy
Imbalance Service charges, pursuant to Schedule 4 of the Tariff apply.
7.0 Ancillary Services
7.1 The Network Customer must make arrangements in appropriate amounts for all of
the required Ancillary Services described in the Tariff. The Network Customer
must obtain these services from the Transmission Provider or Host Transmission
Owner or, where applicable, self-supply or obtain these services from a third
party.
7.2 Where the Network Customer elects to self-supply or have a third party provide
Ancillary Services, the Network Customer must demonstrate to the Transmission
Provider that it has either acquired the Ancillary Services from another source or
is capable of self-supplying the services.
7.3 The Network Customer must designate the supplier of Ancillary Services.
8.0 Metering
8.1 The Network Customer shall provide for the installation of meters, associated
metering equipment and telemetering equipment. The Network Customer shall
permit (or provide for, if the Network Customer is not the meter owner) the
Transmission Provider’s and Host Transmission Owner’s representative to have
access to the equipment at all reasonable hours and for any reasonable purpose,
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and shall not permit unauthorized persons to have access to the space housing the
equipment. Network Customer shall provide to (or provide for, if the Network
Customer is not the meter owner) the Host Transmission Owner access to load
data and other data available from any delivery point meter. If the Network
Customer does not own the meter, the Host Transmission Owner shall make
available, upon request, all load data and other data obtained by the Host
Transmission Owner from the relevant delivery point meter, if available utilizing
existing equipment. The Network Customer will cooperate on the installation of
advanced technology metering in place of the standard metering equipment at a
delivery point at the expense of the requestor; provided, however, that meter
owner shall not be obligated to install, operate or maintain any meter or related
equipment that is not approved for use by the meter owner and/or Host
Transmission Owner, and provided that such equipment addition can be
accomplished in a manner that does not interfere with the operation of the meter
owner’s equipment or any Party’s fulfillment of any statutory or contractual
obligation.
8.2 The Network Customer shall provide for the testing of the metering equipment at
suitable intervals and its accuracy of registration shall be maintained in
accordance with standards acceptable to the Transmission Provider and consistent
with Good Utility Practice. At the request of the Transmission Provider or Host
Transmission Owner, a special test shall be made, but if less than two percent
inaccuracy is found, the requesting Party shall pay for the test. Representatives of
the Parties may be present at all routine or special tests and whenever any
readings for purposes of settlement are taken from meters not having an
automated record. If any test of metering equipment discloses an inaccuracy
exceeding two percent, the accounts of the Parties shall be adjusted. Such
adjustment shall apply to the period over which the meter error is shown to have
been in effect or, where such period is indeterminable, for one-half the period
since the prior meter test. Should any metering equipment fail to register, the
amounts of energy delivered shall be estimated from the best available data.
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8.3 If the Network Customer is supplying energy to retail load that has a choice in its
supplier, the Network Customer shall be responsible for providing all information
required by the Transmission Provider for billing purposes. Metering information
shall be available to the Transmission Provider either by individual retail
customer or aggregated retail energy information for that load the Network
Customer has under contract during the billing month. For the retail load that has
interval demand metering, the actual energy used by interval must be supplied.
For the retail load using standard kWh metering, the total energy consumed by
meter cycle, along with the estimated demand profile must be supplied. All rights
and limitations between Parties granted in Sections 8.1, and 8.2 are applicable in
regards to retail metering used as the basis for billing the Network Customer.
9.0 Connected Generation Resources
9.1 The Network Customer’s connected generation resources that have automatic
generation control and automatic voltage regulation shall be operated and
maintained consistent with regional operating standards, and the Network
Customer or the operator shall operate, or cause to be operated, such resources to
avoid adverse disturbances or interference with the safe and reliable operation of
the transmission system.
9.2 For all Network Resources of the Network Customer, the following generation
telemetry readings to the Host Transmission Owner are required:
1) Analog MW;
2) Integrated MWHRS/HR;
3) Analog MVARS; and
4) Integrated MVARHRS/HR.
10.0 Redispatching, Curtailment and Load Shedding
10.1 In accordance with Section 33 of the Tariff, the Transmission Provider may
require redispatching of generation resources or curtailment of loads to relieve
existing or potential transmission system constraints. The Network Customer
shall submit verifiable incremental and decremental cost data from its Network
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Resources to the Transmission Provider. These costs will be used as the basis for
least-cost redispatch. Information exchanged by the Parties under this article will
be used for system redispatch only, and will not be disclosed to third parties
absent mutual consent or order of a court or regulatory agency. The Network
Customer shall respond immediately to requests for redispatch from the
Transmission Provider. The Transmission Provider will bill or credit the Network
Customer as appropriate.
10.2 The Parties shall implement load-shedding procedures to maintain the reliability
and integrity for the Transmission System as provided in Section 33.1 of the
Tariff and in accordance with applicable NERC and SPP requirements and Good
Utility Practice. Load shedding may include (1) automatic load shedding, (2)
manual load shedding, and (3) rotating interruption of customer load. When
manual load shedding or rotating interruptions are necessary, the Host
Transmission Owner shall notify the Network Customer’s dispatcher or
schedulers of the required action and the Network Customer shall comply
immediately.
10.3 The Network Customer will coordinate with the Host Transmission Owner to
ensure sufficient load shedding equipment is in place on their respective systems
to meet SPP requirements. The Network Customer and the Host Transmission
Owner shall develop a plan for load shedding which may include manual load
shedding by the Network Customer.
11.0 Communications
11.1 The Network Customer shall, at its own expense, install and maintain
communication link(s) for scheduling. The communication link(s) shall be used
for data transfer and for voice communication.
11.2 A Network Customer self-supplying Ancillary Services or securing Ancillary
Services from a third-party shall, at its own expense, install and maintain
telemetry equipment communicating between the generating resource(s)
providing such Ancillary Services and the Host Transmission Owner's Control
Area.
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12.0 Cost Responsibility
12.1 The Network Customer shall be responsible for all costs incurred by the Network
Customer, Host Transmission Owner, and Transmission Provider to implement
the provisions of this Operating Agreement including, but not limited to,
engineering, administrative and general expenses, material and labor expenses
associated with the specification, design, review, approval, purchase, installation,
maintenance, modification, repair, operation, replacement, checkouts, testing,
upgrading, calibration, removal, and relocation of equipment or software, so long
as the direct assignment of such costs is consistent with Commission policy.
12.2 The Network Customer shall be responsible for all costs incurred by Network
Customer, Host Transmission Owner, and Transmission Provider for on-going
operation and maintenance of the facilities required to implement the provisions
of this Operating Agreement so long as the direct assignment of such costs is
consistent with Commission policy. Such work shall include, but is not limited
to, normal and extraordinary engineering, administrative and general expenses,
material and labor expenses associated with the specifications, design, review,
approval, purchase, installation, maintenance, modification, repair, operation,
replacement, checkouts, testing, calibration, removal, or relocation of equipment
required to accommodate service provided under this Operating Agreement.
13.0 Billing and Payments
Billing and Payments shall be in accordance with Section 7 of the Tariff.
14.0 Dispute Resolution
Any dispute among the Parties regarding this Operating Agreement shall be resolved
pursuant to Section 12 of the Tariff, or otherwise, as mutually agreed by the Parties.
15.0 Assignment
This Operating Agreement shall inure to the benefit of and be binding upon the Parties
and their respective successors and assigns, but shall not be assigned by any Party, except
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to successors to all or substantially all of the electric properties and assets of such Party,
without the written consent of the other Parties. Such written consent shall not be
unreasonably withheld.
16.0 Choice of Law
The interpretation, enforcement, and performance of this Operating Agreement shall be
governed by the laws of the State of Arkansas, except laws and precedent of such
jurisdiction concerning choice of law shall not be applied, except to the extent governed
by the laws of the United States of America.
17.0 Entire Agreement
The Tariff and Service Agreement, as they are amended from time to time, are
incorporated herein and made a part hereof. To the extent that a conflict exists between
the terms of this Operating Agreement and the terms of the Tariff, the Tariff shall control.
18.0 Unilateral Changes and Modifications
Nothing contained in this Operating Agreement or any associated Service Agreement
shall be construed as affecting in any way the right of the Transmission Provider or a
Transmission Owner unilaterally to file with the Commission, or make application to the
Commission for, changes in rates, charges, classification of service, or any rule,
regulation, or agreement related thereto, under section 205 of the Federal Power Act and
pursuant to the Commission’s rules and regulations promulgated thereunder, or under
other applicable statutes or regulations.
Nothing contained in this Operating Agreement or any associated Service
Agreement shall be construed as affecting in any way the ability of any Network
Customer receiving Network Integration Transmission Service under the Tariff to
exercise any right under the Federal Power Act and pursuant to the Commission’s rules
and regulations promulgated thereunder; provided, however, that it is expressly
recognized that this Operating Agreement is necessary for the implementation of the
Tariff and Service Agreement. Therefore, no Party shall propose a change to this
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Operating Agreement that is inconsistent with the rates, terms and conditions of the Tariff
and/or Service Agreement.
19.0 Term
This Operating Agreement shall become effective on the date assigned by the
Commission (“Effective Date”), and shall continue in effect until the Tariff or the
Network Customer’s Service Agreement is terminated, whichever shall occur first.
20.0 Notice
20.1 Any notice that may be given to or made upon any Party by any other Party under
any of the provisions of this Operating Agreement shall be in writing, unless
otherwise specifically provided herein, and shall be considered delivered when
the notice is personally delivered or deposited in the United States mail, certified
or registered postage prepaid, to the following:
[Transmission Provider]
Southwest Power Pool, Inc.
Carl Monroe
Executive Vice President and Chief Operating Officer
415 North McKinley, #140 Plaza West
Little Rock, AR 72205-3020
501-614-3218 phone
501-664-9553 fax
[Host Transmission Owner]
Westar Energy, Inc.
Kelly Harrison
Vice President, Transmission Operations and Environmental Services
818 S. Kansas Avenue
Topeka, KS 66612
785-575-1636 phone
785-575-8061 fax
[Network Customer]
Kansas Electric Power Cooperative, Inc.
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Mark Barbee
Vice President Engineering
600 SW Corporate View
Topeka, KS 66615
785-273-7010 phone
785-271-4888 fax
Any Party may change its notice address by written notice to the other Parties in
accordance with this Article 20.
20.2 Any notice, request, or demand pertaining to operating matters may be delivered
in writing, in person or by first class mail, e-mail, messenger, or facsimile
transmission as may be appropriate and shall be confirmed in writing as soon as
reasonably practical thereafter, if any Party so requests in any particular instance.
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21.0 Execution in Counterparts
This Operating Agreement may be executed in any number of counterparts with the same
effect as if all Parties executed the same document. All such counterparts shall be
construed together and shall constitute one instrument.
IN WITNESS WHEREOF, the Parties have caused this Operating Agreement to be
executed by their respective authorized officials, and copies delivered to each Party, to become
effective as of the Effective Date.
TRANSMISSION PROVIDER HOST TRANSMISSION OWNER
_/s/ Carl Monroe__________ _/s/ Kelly B. Harrison__________________
Signature Signature
_Carl Monroe____________ _Kelly B. Harrison____________________
Printed Name Printed Name
_EVP & COO____________ _VP-Transmission Ops. & Environmental Svcs.___
Title Title
_07/28/2011_____________ _July 28, 2011______________________
Date Date
NETWORK CUSTOMER
__/s/ Mark R. Barbee______
Signature
_Mark R. Barbee_________
Printed Name
_VP of Engineering_______
Title
_7/26/2011______________
Date