The Honorable Kimberly D. Bose the Fourth Revised KEPCO Agreements. · 2019-02-08 · The Honorable Kimberly D. Bose September 8, 2011 Page 3 delivery point meter located on distribution

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.


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”).


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 . . . )


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).


(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.

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 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

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

9 1431666 & 74318195

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.

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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.

15 1431666 & 74318195

Appendix 2

Receipt Points of


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


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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)

19 1431666 & 74318195

20 1431666 & 74318195

APPENDIX 3 – DELIVERY POINTS – Westar Energy System – Continues(a) (b) (c) (d)

Voltage (Meter)

(kV)



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


Voltage (Meter)

(kV)



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


Voltage (Meter) (kV)



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





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





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)



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


Voltage (Meter)

(kV)



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





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)


29 1431666 & 74318195

(a) (b) (c) (d)Voltage (Meter)

(kV)



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


Voltage (Meter)

(kV)



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





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



Dollars






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


KEPCo - Brown-Atchison REC See list below Oct 1, 2010



Dollars






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


KEPCo - Butler REC See list below Oct 1, 2010

Load Location NPPC

%


Dollars

Customer Allocation

of Substation



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


KEPCo - Caney Valley REC See list below Oct 1, 2010



Dollars






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


KEPCo - DS&O REC See list below Oct 1, 2010



Dollars






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


KEPCo - Flint Hills REC See list below Oct 1, 2010



Dollars

Customer Allocation

of Substation



Customer Allocation of Circuits


(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


KEPCo - Heartland REC See list below Oct 1, 2010



Dollars






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


KEPCo - Leavenworth-Jefferson REC See list below Oct 1, 2010



Dollars






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


KEPCo - Lyon-Coffey REC See list below Oct 1, 2010



Dollars






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



KEPCo - Radiant REC See list below Oct 1, 2010



Dollars






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


KEPCo - Rolling Hills REC See list below Oct 1, 2010

Load Location NPPC % Substation Distribution

Plant Dollars






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


Plant Dollars






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


KEPCo - Sedgwick REC See list below Oct 1, 2010


Plant Dollars






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


KEPCo - Sumner-Cowley REC See list below Oct 1, 2010


Plant Dollars






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


KEPCo - Twin Valley REC See list below Oct 1, 2010



Dollars






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

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


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.


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 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

[email protected]

Any Party may change its notice address by written notice to the other

Parties in accordance with this Article 20.

20.2 Any notice, request, or demand pertaining to operating matters may be

delivered in writing, in person or by first class mail, e-mail, messenger, or

facsimile transmission as may be appropriate and shall be confirmed in

writing as soon as reasonably practical thereafter, if any Party so requests

in any particular instance.

64 1431666 & 74318195

21.0 Execution in Counterparts

This Operating Agreement may be executed in any number of counterparts with

the same effect as if all Parties executed the same document. All such

counterparts shall be construed together and shall constitute one instrument.

IN WITNESS WHEREOF, the Parties have caused this Operating Agreement to

be executed by their respective authorized officials, and copies delivered to each Party, to

become effective as of the Effective Date.

TRANSMISSION PROVIDER HOST TRANSMISSION OWNER

_/s/ Carl Monroe__________ _/s/ Kelly B. Harrison__________________Signature Signature

_Carl Monroe____________ _Kelly B. Harrison____________________Printed Name Printed Name

_EVP & COO____________ _VP-Transmission Ops. & Environmental Svcs.___Title Title

_07/28/2011_____________ _July 28, 2011______________________Date Date

NETWORK CUSTOMER

__/s/ Mark R. Barbee______Signature

_Mark R. Barbee_________Printed Name

_VP of Engineering_______Title

_7/26/2011______________Date

1 1431666 & 74318195

Southwest Power Pool, Inc.

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


415 N. McKinley,140 Plaza West

Little Rock, AR 72205

Network Customer:

Mark Barbee


Kansas Electric Power Cooperative Inc.


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

9 1431666 & 74318195

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

11 1431666 & 74318195

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

12 1431666 & 74318195

APPENDIX 1

Network Resources of


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


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


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


(a) (b) (c) (d)

SPP Bus

Number / Name


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


(a) (b) (c) (d)

SPP Bus

Number / Name


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


(a) (b) (c) (d)

SPP Bus

Number / Name


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


(a) (b) (c) (d)

SPP Bus

Number / Name


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


533887

TALMAGE #1 1409 Westar

12.5


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


(a) (b) (c) (d)

SPP Bus

Number / Name


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


(a) (b) (c) (d)

SPP Bus

Number / Name


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


(a) (b) (c) (d)

SPP Bus

Number / Name


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


(a) (b) (c) (d)

SPP Bus

Number / Name


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


(a) (b) (c) (d)

SPP Bus

Number / Name


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


(a) (b) (c) (d)

SPP Bus

Number / Name


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


(a) (b) (c) (d)

SPP Bus

Number / Name


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)


KEPCo - Ark Valley REC See list below Oct 1, 2010



Dollars






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



KEPCo - Bluestem REC See list below Oct 1, 2010



Dollars







(a) (b) (c) (d) (e) (f) (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



KEPCo - Brown-Atchison REC See list below Oct 1, 2010



Dollars







(a) (b) (c) (d) (e) (f) (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



KEPCo - Butler REC See list below Oct 1, 2010

Load Location NPPC

%


Dollars

Customer Allocation

of Substation



Customer Allocation

of Circuits


(a) (b) (c) (d) (e) (f) (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



KEPCo - Caney Valley REC See list below Oct 1, 2010



Dollars







(a) (b) (c) (d) (e) (f) (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



KEPCo - DS&O REC See list below Oct 1, 2010



Dollars







(a) (b) (c) (d) (e) (f) (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



KEPCo - Flint Hills REC See list below Oct 1, 2010



Dollars

Customer Allocation

of Substation



Customer Allocation of Circuits


(a) (b) (c) (d) (e) (f) (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



KEPCo - Heartland REC See list below Oct 1, 2010



Dollars







(a) (b) (c) (d) (e) (f) (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



KEPCo - Leavenworth-Jefferson REC See list below Oct 1, 2010



Dollars







(a) (b) (c) (d) (e) (f) (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



KEPCo - Lyon-Coffey REC See list below Oct 1, 2010



Dollars







(a) (b) (c) (d) (e) (f) (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



KEPCo - Radiant REC See list below Oct 1, 2010



Dollars







(a) (b) (c) (d) (e) (f) (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



KEPCo - Rolling Hills REC See list below Oct 1, 2010


Plant Dollars







(a) (b) (c) (d) (e) (f) (g)


New Beverly 1.510% $ - 0.00% $ - $ - 0.00% $ - $ -

Totals $ - $ - $ -


KEPCo - Sharpe Gen Aux See below list Oct 1, 2010


Plant Dollars







(a) (b) (c) (d) (e) (f) (g)


Auxillary Load 1.510% $ - 0.00% $ - $ - 0.00% $ - $ -

Totals $ - $ - $ -

46 1431666 & 74318195



KEPCo - Sedgwick REC See list below Oct 1, 2010


Plant Dollars







(a) (b) (c) (d) (e) (f) (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



KEPCo - Sumner-Cowley REC See list below Oct 1, 2010


Plant Dollars







(a) (b) (c) (d) (e) (f) (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



KEPCo - Twin Valley REC See list below Oct 1, 2010



Dollars







(a) (b) (c) (d) (e) (f) (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


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


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


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.


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


415 North McKinley, #140 Plaza West

Little Rock, AR 72205-3020

501-614-3218 phone

501-664-9553 fax

[email protected]

[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

[email protected]

[Network Customer]


Mark Barbee



Topeka, KS 66615

785-273-7010 phone

785-271-4888 fax

63 1431666 & 74318195

[email protected]

Any Party may change its notice address by written notice to the other

Parties in accordance with this Article 20.

20.2 Any notice, request, or demand pertaining to operating matters may be

delivered in writing, in person or by first class mail, e-mail, messenger, or

facsimile transmission as may be appropriate and shall be confirmed in

writing as soon as reasonably practical thereafter, if any Party so requests

in any particular instance.

64 1431666 & 74318195

21.0 Execution in Counterparts

This Operating Agreement may be executed in any number of counterparts with

the same effect as if all Parties executed the same document. All such

counterparts shall be construed together and shall constitute one instrument.

IN WITNESS WHEREOF, the Parties have caused this Operating Agreement to

be executed by their respective authorized officials, and copies delivered to each Party, to

become effective as of the Effective Date.

TRANSMISSION PROVIDER HOST TRANSMISSION OWNER

_/s/ Carl Monroe__________ _/s/ Kelly B. Harrison__________________

Signature Signature

_Carl Monroe____________ _Kelly B. Harrison____________________

Printed Name Printed Name

_EVP & COO____________ _VP-Transmission Ops. & Environmental

Svcs.___

Title Title

_07/28/2011_____________ _July 28, 2011______________________

Date Date

NETWORK CUSTOMER

__/s/ Mark R. Barbee______

Signature

_Mark R. Barbee_________

Printed Name

_VP of Engineering_______

Title

_7/26/2011______________

Date