the honorable kimberly d. bose the fourth revised kepco agreements. · 2019-02-08 · the honorable...
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. ER11-4172-___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 August 1, 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 (“Fourth Revised 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 (“Fourth Revised KEPCO NOA”).2 The Fourth Revised KEPCO Agreements amend and replace the August 1 Agreements. Because the Fourth Revised KEPCO Agreements have the same proposed effective date and are intended to replace and substitute for the August 1 Agreements, the
1 See Submission of Network Integration Transmission Service Agreements of
Southwest Power Pool, Inc., Docket No. ER11-4172-000 (Aug. 1, 2011) (“August 1 Filing”). The agreements in the August 1 Filing are referred to collectively as the “August 1 Agreements” and individually as the “August 1 Service Agreement” and the “August 1 NOA.”
2 The KEPCO Service Agreement and KEPCO NOA are referred to collectively as the “Fourth Revised KEPCO Agreements,” and SPP, KEPCO, and Westar are referred to collectively as “the Parties.” The KEPCO Agreements are designated as Fourth Revised Service Agreement No. 1636.
The Honorable Kimberly D. BoseSeptember 8, 2011Page 2
Commission need not act on the August 1 Agreements, but rather only accept for filing the Fourth Revised KEPCO Agreements.3
I. Background
On August 1, 2011, SPP filed with the Commission the August 1 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 an effective date of July 1, 2011, for the August 1 Agreements.5 The August 1 Filing currently is pending before the Commission.
Since the August 1 Filing, the Parties have revised the August 1 Service Agreements to add the following sentence to Section 8.6 of Attachment: “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 Fourth Revised KEPCO Agreements are identical to the August 1 Agreements.
II. Description of and Justification for the Non-Conforming Language in the Fourth Revised KEPCO Agreements
In addition to the change to Section 8.6 of Attachment 1 described above, like the August 1 Agreements, the Fourth Revised KEPCO Service Agreement contains other language that does not conform to the pro forma Agreements.6 Section 8.6 of Attachment 1 of the Fourth Revised 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 3 For the same reasons as stated above, to the extent required, SPP moves to
withdraw the August 1 Filing. Withdrawal is permitted because no Commission or delegated order has been issued on the August 1 Agreements, and the August 1 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 August 1 Filing at 4.
6 The Fourth Revised KEPCO NOA does not contain any non-conforming language and conforms to the pro forma NOA.
The Honorable Kimberly D. BoseSeptember 8, 2011Page 3
delivery point meter located on distribution 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 will 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-approved tariff.
Section 7.0 of the Fourth Revised 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 Fourth Revised 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 Fourth Revised KEPCO Service Agreement.
The additional language in Section 7.0 Agreement clarifies that any transfer or assignment of the Fourth Revised KEPCO Service Agreement by the Parties is subject to applicable regulatory oversight, including RUS oversight, but such oversight does not infringe upon the Commission’s exclusive jurisdiction over the Fourth Revised KEPCO Service Agreement. 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 Parties’ Service Agreement, which the Commission accepted, contains identical language in Section 7.0.8
Section 8.9 of Attachment 1 of the Fourth Revised 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 Fourth Revised 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
7 See Fourth Revised 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”).
The Honorable Kimberly D. BoseSeptember 8, 2011Page 4
containing Wholesale Distribution Charges are filed with the Commission.9 The Commission accepted a previous iteration 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 August 1 Filing, the Commission should accept the Fourth Revised KEPCO Agreements filed herein.
III. Effective Date and Waiver
Consistent with the effective date requested in the August 1 Filing, SPP requests an effective date of July 1, 2011 for the Fourth Revised 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 Fourth Revised KEPCO Agreements replace the August 1 Agreements, and the August 1 Agreements were filed within 30 days of the commencement of service.12
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 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 May Letter Order; 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 Prior Notice and Filing Requirements Under Part II of the Federal Power Act, 64 FERC ¶ 61,139, at 61,983-84, order on reh’g, 65 FERC ¶ 61,081 (1993) (the Commission will grant waiver of the 60-day prior notice requirement “if
(continued . . . )
The Honorable Kimberly D. BoseSeptember 8, 2011Page 5
IV. Additional Information
A. Information Required by Section 35.13 of the Commission’s Regulations, 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 Fourth Revised KEPCO Agreements; and
(ii) A redlined copy of the Fourth Revised KEPCO Agreements.
(2) Effective Date:
As discussed herein, SPP respectfully requests that the Commission accept the Fourth Revised KEPCO Agreements with an effective date of July 1, 2011.
(3) Service:
SPP is serving a copy of this filing on all parties to the service list in ER11-4172, and to the representatives for KEPCO and Westar listed in the Fourth Revised KEPCO Agreements.
( . . . continued)
service agreements are filed within 30 days after service commences.”); see also 18 C.F.R. § 35.3(a)(2).
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 Fourth Revised KEPCO Agreements.
B. Communications:
Copies of this filing have been served upon all parties to the Fourth Revised 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 Fourth Revised KEPCO Agreements with an effective date of July 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 1636R4 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.Fourth 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 July 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 BarbeeExecutive Vice President and Chief Vice President EngineeringOperating Officer Kansas Electric PowerSouthwest Power Pool, Inc. Cooperative, Inc.
07/28/2011 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
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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
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.
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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.
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.
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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 34.5533628CC1BURL2 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)533310WMBROS 3 115 kV WILLIAMS 1113 Westar
4.2 (Low Side)
533653WOLFCRK2 69 kV WOLF CREEK KCC06 Westar
12.5(Low Side)
APPENDIX 3 – DELIVERY POINTS – Westar Energy System – Continues
29 1431666 & 74318195
(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)
533016WWUPLNT4 138kV
BENTLEY KSG16 Westar 12.5 (Bus)
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 July 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% $ - $ - Bentley (B) 1.370% $ - 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
(B) Sedgwick REC, Bentley Delivery Point, WDS Effective July 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
50 1431666 & 74318195
cooperate 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,
51 1431666 & 74318195
SPP, or any 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.
3.6 The Transmission Provider and Host Transmission Owner, if applicable,
reserve the sole right to take any action necessary during an actual or
52 1431666 & 74318195
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 which resources are expected to be used by the Network
Customer to supply the peak demand and energy requirements
provided in (a);
53 1431666 & 74318195
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 such constraints
including but not limited to: construction of new transmission
54 1431666 & 74318195
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.
56 1431666 & 74318195
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, and shall not permit unauthorized
57 1431666 & 74318195
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.
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
58 1431666 & 74318195
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 Resources to the Transmission Provider. These
59 1431666 & 74318195
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.
12.0 Cost Responsibility
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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 to successors to all or substantially all of the electric properties
61 1431666 & 74318195
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 Operating Agreement that is inconsistent with the rates,
terms and conditions of the Tariff and/or Service Agreement.
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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.Mark BarbeeVice President Engineering600 SW Corporate ViewTopeka, KS 66615785-273-7010 phone 785-271-4888 fax
63 1431666 & 74318195
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
1 1431666 & 74318195
Southwest Power Pool, Inc.
Fourth 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 July 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.
07/28/2011 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)
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
533310
WILLIAMS 1113 Westar
4.2
(Low Side)
WMBROS 3 115
kV
533653
WOLF CREEK KCC06 Westar
12.5
(Low Side)
WOLFCRK2 69
kV
29 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)
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
533016
WWUPLNT4
138kV
BENTLEY KSG16 Westar 12.5 (Bus)
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 July 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% $ - $ -
Bentley (B) 1.370% $ - 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
(B) Sedgwick REC, Bentley Delivery Point, WDS Effective July 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
50 1431666 & 74318195
cooperate 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,
51 1431666 & 74318195
SPP, or any 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.
3.6 The Transmission Provider and Host Transmission Owner, if applicable,
reserve the sole right to take any action necessary during an actual or
52 1431666 & 74318195
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 which resources are expected to be used by the Network
Customer to supply the peak demand and energy requirements
provided in (a);
53 1431666 & 74318195
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 such constraints
including but not limited to: construction of new transmission
54 1431666 & 74318195
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.
56 1431666 & 74318195
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, and shall not permit unauthorized
57 1431666 & 74318195
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.
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
58 1431666 & 74318195
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 Resources to the Transmission Provider. These
59 1431666 & 74318195
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.
12.0 Cost Responsibility
60 1431666 & 74318195
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 to successors to all or substantially all of the electric properties
61 1431666 & 74318195
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 Operating Agreement that is inconsistent with the rates,
terms and conditions of the Tariff and/or Service Agreement.
62 1431666 & 74318195
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.
Mark Barbee
Vice President Engineering
600 SW Corporate View
Topeka, KS 66615
785-273-7010 phone
785-271-4888 fax
63 1431666 & 74318195
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