KEPCO NITSA 1636R3 REVISED Transmittal Letter · 9/8/2011 · KEPCO, including the right to make any subsequent assignment in accordance with Section 7.0 of the KEPCO Service Agreement

September 8, 2011

The Honorable Kimberly D. BoseSecretary Federal Energy Regulatory Commission 888 First Street NEWashington, DC 20426

Re: Southwest Power Pool, Inc., Docket No. ER11-4148-___Submission of Amended Network Integration Transmission Service Agreement and Network Operating Agreement

Dear Secretary Bose:

Pursuant to section 205 of the Federal Power Act, 16 U.S.C. § 824d, and section 35.13 of the Federal Energy Regulatory Commission’s (“Commission”) regulations, 18 C.F.R. § 35.13, Southwest Power Pool, Inc. (“SPP”) amends its July 29, 2011 filing in this docket1 and submits: (1) an executed, amended Service Agreement for Network Integration Transmission Service (“Service Agreement”) between SPP as Transmission Provider and Kansas Electric Power Cooperative, Inc. (“KEPCO”) as Network Customer (“KEPCO Service Agreement”); and (2) a Network Operating Agreement (“NOA”) between SPP as Transmission Provider, KEPCO as Network Customer, and Westar Energy, Inc. (“Westar”) as Host Transmission Owner (“KEPCO NOA”).2 The KEPCO Agreements amend and replace the July 29 Agreements. Because the KEPCO Agreements have the same proposed effective date and are intended to replace and

1 See Submission of Network Integration Transmission Service Agreements of

Southwest Power Pool, Inc., Docket No. ER11-4148-000 (July 29, 2011) (“July 29 Filing”). The agreements in the July 29 Filing are referred to collectively as the “July 29 Agreements” and individually as the “July 29 Service Agreement” and the “July 29 NOA.”

2 The KEPCO Service Agreement and KEPCO NOA are referred to collectively as the “KEPCO Agreements,” and SPP, KEPCO, and Westar are referred to collectively as “the Parties.” The KEPCO Agreements are designated as Third Revised Service Agreement No. 1636.

The Honorable Kimberly D. BoseSeptember 8, 2011Page 2

substitute for the July 29 Agreements, the Commission need not act on the July 29 Agreements, but rather only accept for filing the KEPCO Agreements.3

I. Background

On July 29, 2011, SPP filed with the Commission the July 29 Agreements, which contained terms and conditions that do not conform to the standard forms of service agreements in the SPP Open Access Transmission Tariff (“Tariff”).4 SPP requested and effective date of June 1, 2011, for the July 29 Agreements.5 The July 29 Filing is currently pending before the Commission.

Since the July 29 Filing, the Parties have revised the July 29 Service Agreements to add the following sentence in Section 8.6 of Attachment 1: “The composite loss percentages in Section 28.5 shall exclude transmission losses.” This additional language clarifies that only distribution losses (and not transmission losses) will be replaced in accordance with Westar’s Open Access Transmission Tariff, which is on file with the Commission. Except for this revision, the KEPCO Agreements are identical to the July 29 Agreements.

II. Description of and Justification for the Non-Conforming Language in the KEPCO Agreements

In addition to the change to Section 8.6 of Attachment 1 described above, like the July 29 Agreements, the KEPCO Service Agreement contains language that does not conform to the pro forma Agreements.6 Section 8.6 of Attachment 1 of the KEPCO Service Agreement also specifies that “[t]he Network Customer shall replace all distribution losses in accordance with Westar Energy's Open Access Transmission Tariff, Section 28.5, based upon the location of each delivery point meter located on distribution 3 For the same reasons as stated above, to the extent required, SPP moves to

withdraw the July 29 Filing. Withdrawal is permitted because no Commission or delegated order has been issued on the July 29 Agreements, and the July 29 Agreements have not become effective. See 18 C.F.R. § 35.17(a)(1) (“A public utility may withdraw in its entirety a rate schedule, tariff or service agreement filing that has not become effective and upon which no Commission or delegated order has been issued by filing a withdrawal motion with the Commission.”).

4 See Tariff at Attachment F (“pro forma Service Agreement”) and Attachment G (“pro forma NOA”), collectively “the pro forma Agreements.”

5 See July 29 Filing at 4.

6 The KEPCO NOA does not contain any non-conforming language and conforms to the pro forma NOA.


facilities.”7 Section 8.6 of Attachment 1 of the pro forma Service Agreement contains a fill-in-the-blank provision for Real Power Losses – Distribution. Here, Parties added language to specify that the distribution losses would be replaced in accordance with Westar’s Open Access Transmission Tariff, which is on file with the Commission. The added language is just and reasonable and will benefit the Parties because it clarifies that distribution (and not transmission losses) will be calculated in accordance with a Commission-accepted tariff.

Section 7.0 of the KEPCO Service Agreement contains additional language to provide that either KEPCO or SPP may, without the need for consent from the other, transfer or assign the KEPCO Service Agreement to any person succeeding to all or substantially all of the assets of the assigning party, provided that all required regulatory approvals for such transfer or assignment, including approval of the Rural Utilities Service (“RUS”) as to KEPCO are obtained. Moreover, both KEPCO and SPP acknowledge and agree that KEPCO has assigned and pledged as security the KEPCO Service Agreement and all of its rights hereunder to the RUS. KEPCO and SPP further acknowledge and agree that the RUS will have the right, upon written notice to SPP, to assume all obligations of KEPCO, whereupon the RUS will succeed to all rights of KEPCO, including the right to make any subsequent assignment in accordance with Section 7.0 of the KEPCO Service Agreement.

The additional language in Section 7.0 of the KEPCO Service Agreement clarifies that certain actions by the Parties are subject to applicable regulatory oversight, but such oversight does not infringe upon the Commission’s exclusive jurisdiction. Furthermore, given that KEPCO continues to be a RUS borrower, it is reasonable to require RUS approval prior to a transfer or assignment of KEPCO’s assets. In addition, a previous iteration of the KEPCO Service Agreement, which the Commission accepted, contains identical language in Section 7.0.8

Section 8.9 of Attachment 1 of the KEPCO Service Agreement contains language specifying that the cost support and monthly charges for Wholesale Distribution Service Charges are detailed in a new, non-conforming Appendix 4 to the KEPCO Service Agreement. The inclusion of the cost support and monthly charges for Wholesale Distribution Service in Appendix 4 is consistent with Schedule 10 of the SPP Tariff, which requires cost support when Service Agreements containing Wholesale Distribution Charges are filed with the Commission.9 The Commission accepted a previous iteration

7 See KEPCO Service Agreement at Attachment 1, § 8.6.

8 See Sw. Power Pool, Inc., Letter Order, Docket No. ER11-3073-000 (May 11, 2011) (“May Letter Order”).

9 See SPP Tariff at Schedule 10 (“All rates and charges for Wholesale Distribution Service shall be on file with the appropriate agency as required by law or

(continued . . . )


of the KEPCO Service Agreement, which included similar non-conforming language in Section 8.9 and Appendix 4, in the May Letter Order.10

Appendix 3 of the Fourth Revised KEPCO Service Agreement, which identifies the pertinent delivery points located on Westar’s distribution facilities, also contains non-conforming language. Specifically, the Parties have included additional information beyond the name, ownership, and voltage of the delivery point contemplated by the chart in Appendix 3 of the pro forma Service Agreement. The additional information, which includes the SPP bus name and number and the delivery point numbers, is necessary and benefits the Parties because it provides additional detail on the distribution losses for the delivery points. The Commission previously has accepted agreements submitted by SPP with similar language.11

For the reasons stated in this transmittal letter and the July 29 Filing, the Commission should accept the KEPCO Agreements filed herein.

III. Effective Date and Waiver

Consistent with the effective date requested in the July 29 Filing, SPP requests an effective date of June 1, 2011 for the KEPCO Agreements. To permit such an effective date, SPP requests a waiver of the Commission’s 60-day notice requirement set forth at 18 C.F.R. § 35.3. Waiver is appropriate because the Parties have agreed to this effective date. In addition, new delivery points in the KEPCO Service Agreement became effective on June 1, 2011, and waiver will allow the KEPCO Service Agreement to become effective on the same day as the delivery points. The Commission granted a similar waiver with regard to previous KEPCO Agreements, which were filed on March 14, 2011, to permit them to become effective on October 1, 2010.12 The Commission likewise should grant the requested waiver here.

( . . . continued)

regulation. To the extent that a Service Agreement containing provisions for Wholesale Distribution Service is required to be filed with the Commission, the Transmission Provider, in consultation with the appropriate Transmission Owner, shall provide along with the filing, adequate cost support to justify the customer-specific rates and charges being assessed under this Schedule 10.”).

10 See supra note 8.

11 See Sw. Power Pool, Inc., Letter Order, Docket No. ER10-1698-000 (Aug. 20, 2010); Sw. Power Pool, Inc., Letter Order, Docket No. ER10-1688-000 (Aug. 20, 2010).

12 See May Letter Order.


IV. Additional Information

A. Information Required by Section 35.13 of the Commission’sRegulations, 18 C.F.R. § 35.13:(1) Documents submitted with this filing:

In addition to this transmittal letter, SPP includes the following:

(i) A clean copy of the KEPCO Agreements; and

(ii) A redlined copy of the KEPCO Agreements.

(2) Effective Date:

As discussed herein, SPP respectfully requests that the Commission accept the KEPCO Agreements with an effective date of June 1, 2011.

(3) Service:

SPP is serving a copy of this filing on all parties to the service list in ER11-4148, and to representatives for KEPCO and Westar listed in the KEPCO Agreements.


(4) Basis of Rate:

All charges will be determined in accordance with the SPP Tariff and the KEPCO Agreements.

B. Communications:

Copies of this filing have been served upon all parties to the KEPCO Agreements. Any correspondence regarding this matter should be directed to:

Heather Starnes, J.D.Manager – Regulatory PolicySouthwest Power Pool, Inc.415 North McKinley, #140 Plaza WestLittle Rock, AR 72205Telephone: (501) 614-3380Fax: (501) [email protected]

Carrie L. BumgarnerTyler R. BrownWRIGHT & TALISMAN, P.C.1200 G Street, N.W., Suite 600Washington, DC 20005-3802Telephone: (202) 393-1200Fax: (202) [email protected]@wrightlaw.com

V. Conclusion

For all the foregoing reasons, SPP respectfully requests that the Commission accept the KEPCO Agreements with an effective date of June 1, 2011.

Respectfully submitted,

/s/Tyler R. Brown_______Carrie L. BumgarnerTyler R. Brown

Attorneys for Southwest Power Pool, Inc.

K:\SPP\Service Agreement Filings\Transmission Service Agreement Filings\KEPCO NITSA 1636R3 REVISED Transmittal Letter.doc

CERTIFICATE OF SERVICE

I hereby certify that I have this day served the foregoing document upon each

person designated on the official service list compiled by the Secretary in these

proceedings.

Dated at Washington, DC, this 8th day of September, 2011.

Tyler R. BrownTyler R. Brown

Attorney for Southwest Power Pool, Inc.

1 1431666 & 74318195

Southwest Power Pool, Inc. Third Revised Service Agreement No. 1636

SERVICE AGREEMENT FOR NETWORK INTEGRATION TRANSMISSION

SERVICE BETWEEN SOUTHWEST POWER POOL, INC. AND KANSAS

ELECTRIC POWER COOPERATIVE, INC.

This Network Integration Transmission Service Agreement ("Service Agreement") is

entered into this 1st day of June 2011, by and between Kansas Electric Power Cooperative, Inc.

("Network Customer" or “KEPCO”), and Southwest Power Pool, Inc. ("Transmission Provider").

The Network Customer and Transmission Provider shall be referred to individually as “Party”

and collectively as "Parties."

WHEREAS, the Transmission Provider has determined that the Network Customer has

made a valid request for Network Integration Transmission Service in accordance with the

Transmission Provider’s Open Access Transmission Tariff ("Tariff") filed with the Federal

Energy Regulatory Commission ("Commission") as it may from time to time be amended;

WHEREAS, the Transmission Provider administers Network Integration Transmission

Service for Transmission Owners within the SPP Region and acts as agent for the Transmission

Owners in providing service under the Tariff;

WHEREAS, the Network Customer has represented that it is an Eligible Customer under

the Tariff; and

WHEREAS, the Parties intend that capitalized terms used herein shall have the same

meaning as in the Tariff.

NOW, THEREFORE, in consideration of the mutual covenants and agreements herein,

the Parties agree as follows:

1.0 The Transmission Provider agrees during the term of this Service Agreement, as it may

be amended from time to time, to provide Network Integration Transmission Service in

accordance with the Tariff to enable delivery of power and energy from the Network

2 1431666 & 74318195

Customer’s Network Resources that the Network Customer has committed to meet its

load.

2.0 The Network Customer agrees to take and pay for Network Integration Transmission

Service in accordance with the provisions of Parts I, III and V of the Tariff and this

Service Agreement with attached specifications.

3.0 The terms and conditions of such Network Integration Transmission Service shall be

governed by the Tariff, as in effect at the time this Service Agreement is executed by the

Network Customer, or as the Tariff is thereafter amended or by its successor tariff, if any.

The Tariff, as it currently exists, or as it is hereafter amended, is incorporated in this

Service Agreement by reference. In the case of any conflict between this Service

Agreement and the Tariff, the Tariff shall control. The Network Customer has been

determined by the Transmission Provider to have a Completed Application for Network

Integration Transmission Service under the Tariff. The completed specifications are

based on the information provided in the Completed Application and are incorporated

herein and made a part hereof as Attachment 1.

4.0 Service under this Service Agreement shall commence on such date as it is permitted to

become effective by the Commission. This Service Agreement shall be effective through

June 1st, 2013. Thereafter, it will continue from year to year unless terminated by the

Network Customer or the Transmission Provider by giving the other one-year advance

written notice or by the mutual written consent of the Transmission Provider and

Network Customer. Upon termination, the Network Customer remains responsible for

any outstanding charges including all costs incurred and apportioned or assigned to the

Network Customer under this Service Agreement.

5.0 The Transmission Provider and Network Customer have executed a Network Operating

Agreement as required by the Tariff.

6.0 Any notice or request made to or by either Party regarding this Service Agreement shall

be made to the representative of the other Party as indicated below. Such representative

and address for notices or requests may be changed from time to time by notice by one

Party or the other.

3 1431666 & 74318195

Southwest Power Pool, Inc. (Transmission Provider):

Carl Monroe

Executive Vice President and Chief Operating Officer

415 N. McKinley,140 Plaza West

Little Rock, AR 72205

Network Customer:

Mark Barbee

Vice President Engineering

Kansas Electric Power Cooperative Inc.

600 SW Corporate View

Topeka, KS 66615

7.0 This Service Agreement shall not be assigned by either Party without the prior written

consent of the other Party, which consent shall not be unreasonably withheld. However,

either Party may, without the need for consent from the other, transfer or assign this

Service Agreement to any person succeeding to all or substantially all of the assets of

such Party provided that all required regulatory approvals (if any), including approval of

the Rural Utilities Service (“RUS”) as to KEPCO, are obtained in connection with such

transfer or assignment. However, the assignee shall be bound by the terms and

conditions of this Service Agreement. The Parties acknowledge and agree that KEPCO

has assigned and pledged as security this Service Agreement and all of its rights

hereunder to RUS. The Parties further acknowledge and agree that RUS shall have the

right upon written notice to the Transmission Provider to assume all obligations of

KEPCO hereunder whereupon RUS shall succeed to all rights of KEPCO hereunder

(including the right to make any subsequent assignment in accordance with this section).

8.0 Nothing contained herein shall be construed as affecting in any way the Transmission

Provider’s or a Transmission Owner’s right to unilaterally make application to the

Federal Energy Regulatory Commission, or other regulatory agency having jurisdiction,

for any change in the Tariff or this Service Agreement under Section 205 of the Federal

4 1431666 & 74318195

Power Act, or other applicable statute, and any rules and regulations promulgated

thereunder; or the Network Customer's rights under the Federal Power Act and rules and

regulations promulgated thereunder.

9.0 By signing below, the Network Customer verifies that all information submitted to the

Transmission Provider to provide service under the Tariff is complete, valid and accurate,

and the Transmission Provider may rely upon such information to fulfill its

responsibilities under the Tariff.

IN WITNESS WHEREOF, the Parties have caused this Service Agreement to be

executed by their respective authorized officials.

TRANSMISSION PROVIDER NETWORK CUSTOMER

/s/ Carl Monroe /s/ Mark R. Barbee

Carl Monroe Mark BarbeeExecutive Vice President and Chief Vice President EngineeringOperating Officer Kansas Electric PowerSouthwest Power Pool, Inc. Cooperative, Inc.

7/28/2011 7/26/2011

Date Date

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)

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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


Voltage (Meter) (kV) SPP Bus Number / Name


Ownership (Meter)

(1)LYON-COFFEY COOP533301EAST ST3 115 kV

AMERICUS - T. BIRD 1111 Westar 34.5

533628CC1BURL2 69 kV BURLINGTON KCC01 Westar 12.5(Bus) 533167KEENE 3 115 kV ESKRIDGE 1105 Westar

12.5(Circuit)

533301EAST ST3 115 kV HARTFORD 1102 Westar

12.5(Circuit)

533301EAST ST3 115 kV

MELVERN / BETO JUNCTION 1108 Westar

12.5(Circuit)

533308VAUGHN 3 115 kV OLPE 1112 Westar 12.5 (Bus) OLPE DEDUCT (A) 1112M Westar 12.5 (E)533306READING3 115 kV READING 1104 Westar

12.5(Circuit)

READING DEDUCT (A) 706B Westar 12.5 (Bus)

533302EEUREKA3 115 kV TORONTO 1004 Westar 12.5(Circuit)533631CC4VERN2 69 kV VERNON KCC04 Westar 12.5(Bus)533308VAUGHN 3 115 kV VIRGIL 1003 Westar 12.5(Circuit)533301EAST ST3 115 kV WAVERLY 1005 Westar 34.5533309WEMPORI3 115 kV WEST EMPORIA 1106 Westar

12.5(Low Side)

533630CC3WEST2 69 kV WESTPHALIA KCC03 Westar 12.5(Bus)533310 WILLIAMS 1113 Westar 4.2

29 1431666 & 74318195

WMBROS 3 115 kV (Low Side)533653WOLFCRK2 69 kV WOLF CREEK KCC06 Westar

12.5(Low Side)


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)

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 June 1, 2011(Details per REC on following pages)

TRANSMISSION CUSTOMER LOAD EFFECTIVE

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

Load Location NPPC %

Substation Distribution Plant

Dollars

Customer Allocation of Substation

Substation WDS Dollars

Circuit Distribution Plant Dollars

Customer Allocation of

Circuits Circuit WDS

Dollars Total WDS Dollars (a) (b) (c) (d) (e) (f) (g) (b*c*a) (e*f*a) (Total Cols d + g) Marquette-Langley 1.510% $ - 0.00% $ - $ - 0.00% $ - $ - Medora 1.510% $ - 0.00% $ - $ - 0.00% $ - $ - Sand Hill 1.510% $ - 0.00% $ - $ - 0.00% $ - $ - Yoder 1.510% $ - 0.00% $ - $ - 0.00% $ - $ -

Totals $ - $ - $ -

35 1431666 & 74318195

APPENDIX 4 – WHOLESALE DISTRIBUTION SERVICE CHARGE – Westar Energy System – Continues TRANSMISSION CUSTOMER LOAD EFFECTIVE

KEPCo - Bluestem REC See list below Oct 1, 2010



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% $ - $ - 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

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."




Energy Regulatory Commission ("Commission");


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;


the Tariff;

WHEREAS, the Network Customer and Transmission Provider have entered into a

Network Integration Transmission Service Agreement (“Service Agreement”) under the Tariff;

and


meaning as in the Tariff, unless otherwise specified herein.



1.0 Network Service

This Operating Agreement sets out the terms and conditions under which the

Transmission Provider, Host Transmission Owner, and Network Customer will cooperate

50 1431666 & 74318195

and the Host Transmission Owner and Network Customer will operate their respective

systems and specifies the equipment that will be installed and operated. The Parties shall

operate and maintain their respective systems in a manner that will allow the Host

Transmission Owner and the Network Customer to operate their systems and Control

Area and the Transmission Provider to perform its obligations consistent with Good

Utility Practice. The Transmission Provider may, on a non-discriminatory basis, waive

the requirements of Section 4.1 and Section 8.3 to the extent that such information is

unknown at the time of application or where such requirement is not applicable.

2.0 Designated Representatives of the Parties

2.1 Each Party shall designate a representative and alternate ("Designated

Representative(s)") from their respective company to coordinate and implement,

on an ongoing basis, the terms and conditions of this Operating Agreement,

including planning, operating, scheduling, redispatching, curtailments, control

requirements, technical and operating provisions, integration of equipment,

hardware and software, and other operating considerations.

2.2 The Designated Representatives shall represent the Transmission Provider, Host

Transmission Owner, and Network Customer in all matters arising under this

Operating Agreement and which may be delegated to them by mutual agreement

of the Parties hereto.

2.3 The Designated Representatives shall meet or otherwise confer at the request of

any Party upon reasonable notice, and each Party may place items on the meeting

agenda. All deliberations of the Designated Representatives shall be conducted

by taking into account the exercise of Good Utility Practice. If the Designated

Representatives are unable to agree on any matter subject to their deliberation,

that matter shall be resolved pursuant to Section 12.0 of the Tariff, or otherwise,

as mutually agreed by the Parties.

3.0 System Operating Principles

3.1 The Network Customer must design, construct, and operate its facilities safely

and efficiently in accordance with Good Utility Practice, NERC, SPP, or any

51 1431666 & 74318195

successor requirements, industry standards, criteria, and applicable

manufacturer’s equipment specifications, and within operating physical parameter

ranges (voltage schedule, load power factor, and other parameters) required by the

Host Transmission Owner and Transmission Provider.

3.2 The Host Transmission Owner and Transmission Provider reserve the right to

inspect the facilities and operating records of the Network Customer upon

mutually agreeable terms and conditions.

3.3 Electric service, in the form of three phase, approximately sixty hertz alternating

current, shall be delivered at designated delivery points and nominal voltage(s)

listed in the Service Agreement. When multiple delivery points are provided to a

specific Network Load identified in Appendix 3 of the Service Agreement, they

shall not be operated in parallel by the Network Customer without the approval of

the Host Transmission Owner and Transmission Provider. The Designated

Representatives shall establish the procedure for obtaining such approval. The

Designated Representatives shall also establish and monitor standards and

operating rules and procedures to assure that transmission system integrity and the

safety of customers, the public and employees are maintained or enhanced when

such parallel operations is permitted either on a continuing basis or for

intermittent switching or other service needs. Each Party shall exercise due

diligence and reasonable care in maintaining and operating its facilities so as to

maintain continuity of service.

3.4 The Host Transmission Owner and Network Customer shall operate their systems

and delivery points in continuous synchronism and in accord with applicable

NERC Standards, SPP Criteria, and Good Utility Practice.

3.5 If the function of any Party’s facilities is impaired or the capacity of any delivery

point is reduced, or synchronous operation at any delivery point(s) becomes

interrupted, either manually or automatically, as a result of force majeure or

maintenance coordinated by the Parties, the Parties will cooperate to remove the

cause of such impairment, interruption or reduction, so as to restore normal

operating conditions expeditiously.

52 1431666 & 74318195

3.6 The Transmission Provider and Host Transmission Owner, if applicable, reserve

the sole right to take any action necessary during an actual or imminent

emergency to preserve the reliability and integrity of the Transmission System,

limit or prevent damage, expedite restoration of service, ensure safe and reliable

operation, avoid adverse effects on the quality of service, or preserve public

safety.

3.7 In an emergency, the reasonable judgment of the Transmission Provider and Host

Transmission Owner, if applicable, in accordance with Good Utility Practice,

shall be the sole determinant of whether the operation of the Network Customer

loads or equipment adversely affects the quality of service or interferes with the

safe and reliable operation of the transmission system. The Transmission

Provider or Host Transmission Owner, if applicable, may discontinue

transmission service to such Network Customer until the power quality or

interfering condition has been corrected. Such curtailment of load, redispatching,

or load shedding shall be done on a non-discriminatory basis by Load Ratio

Share, to the extent practicable. The Transmission Provider or Host Transmission

Owner, if applicable, will provide reasonable notice and an opportunity to

alleviate the condition by the Network Customer to the extent practicable.

4.0 System Planning & Protection

4.1 No later than October 1 of each year, the Network Customer shall provide the

Transmission Provider and Host Transmission Owner the following information:

a) A ten (10) year projection of summer and winter peak demands with the

corresponding power factors and annual energy requirements on an

aggregate basis for each delivery point. If there is more than one delivery

point, the Network Customer shall provide the summer and winter peak

demands and energy requirements at each delivery point for the normal

operating configuration;

b) A ten (10) year projection by summer and winter peak of planned

generating capabilities and committed transactions with third parties

53 1431666 & 74318195

which resources are expected to be used by the Network Customer to

supply the peak demand and energy requirements provided in (a);

c) A ten (10) year projection by summer and winter peak of the estimated

maximum demand in kilowatts that the Network Customer plans to

acquire from the generation resources owned by the Network Customer,

and generation resources purchased from others; and

d) A projection for each of the next ten (10) years of transmission facility

additions to be owned and/or constructed by the Network Customer which

facilities are expected to affect the planning and operation of the

transmission system within the Host Transmission Owner’s Control Area.

This information is to be delivered to the Transmission Provider’s and Host

Transmission Owner’s Designated Representatives pursuant to Section 2.0.

4.2 Information exchanged by the Parties under this article will be used for system

planning and protection only, and will not be disclosed to third parties absent

mutual consent or order of a court or regulatory agency.

4.3 The Host Transmission Owner, and Transmission Provider, if applicable, will

incorporate this information in its system load flow analyses performed during the

first half of each year. Following completion of these analyses, the Transmission

Provider or Host Transmission Owner will provide the following to the Network

Customer:

a) A statement regarding the ability of the Host Transmission Owner’s

transmission system to meet the forecasted deliveries at each of the

delivery points;

b) A detailed description of any constraints on the Host Transmission

Owner’s system within the five (5) year horizon that will restrict

forecasted deliveries; and

c) In the event that studies reveal a potential limitation of the Transmission

Provider’s ability to deliver power and energy to any of the delivery

points, a Designated Representative of the Transmission Provider will

coordinate with the Designated Representatives of the Host Transmission

Owner and the Network Customer to identify appropriate remedies for

54 1431666 & 74318195

such constraints including but not limited to: construction of new

transmission facilities, upgrade or other improvements to existing

transmission facilities or temporary modification to operating procedures

designed to relieve identified constraints. Any constraints within the

Transmission System will be remedied pursuant to the procedures of

Attachment O of the Tariff.

For all other constraints the Host Transmission Owner, upon

agreement with the Network Customer and consistent with Good Utility

Practice, will endeavor to construct and place into service sufficient

capacity to maintain reliable service to the Network Customer.

An appropriate sharing of the costs to relieve such constraints will

be determined by the Parties, consistent with the Tariff and with the

Commission’s rules, regulations, policies, and precedents then in effect. If

the Parties are unable to agree upon an appropriate remedy or sharing of

the costs, the Transmission Provider shall submit its proposal for the

remedy or sharing of such costs to the Commission for approval consistent

with the Tariff.

4.4 The Host Transmission Owner and the Network Customer shall coordinate with

the Transmission Provider: (1) all scheduled outages of generating resources and

transmission facilities consistent with the reliability of service to the customers of

each Party, and (2) additions or changes in facilities which could affect another

Party’s system. Where coordination cannot be achieved, the Designated

Representatives shall intervene for resolution.

4.5 The Network Customer shall coordinate with the Host Transmission Owner

regarding the technical and engineering arrangements for the delivery points,

including one line diagrams depicting the electrical facilities configuration and

parallel generation, and shall design and build the facilities to avoid interruptions

on the Host Transmission Owner’s transmission system.

4.6 The Network Customer shall provide for automatic and underfrequency load

shedding of the Network Customer Network Load in accordance with the SPP

Criteria related to emergency operations.

55 1431666 & 74318195

5.0 Maintenance of Facilities

5.1 The Network Customer shall maintain its facilities necessary to reliably receive

capacity and energy from the Host Transmission Owner’s transmission system

consistent with Good Utility Practice. The Transmission Provider or Host

Transmission Owner, as appropriate, may curtail service under this Operating

Agreement to limit or prevent damage to generating or transmission facilities

caused by the Network Customer’s failure to maintain its facilities in accordance

with Good Utility Practice, and the Transmission Provider or Host Transmission

Owner may seek as a result any appropriate relief from the Commission.

5.2 The Designated Representatives shall establish procedures to coordinate the

maintenance schedules, and return to service, of the generating resources and

transmission and substation facilities, to the greatest extent practical, to ensure

sufficient transmission resources are available to maintain system reliability and

reliability of service.

5.3 The Network Customer shall obtain: (1) concurrence from the Transmission

Provider before beginning any scheduled maintenance of facilities which could

impact the operation of the Transmission System over which transmission service

is administered by Transmission Provider; and (2) clearance from the

Transmission Provider when the Network Customer is ready to begin

maintenance on a transmission line or substation. The Transmission Provider

shall coordinate clearances with the Host Transmission Owner. The Network

Customer shall notify the Transmission Provider and the Host Transmission

Owner as soon as practical at the time when any unscheduled or forced outages

occur and again when such unscheduled or forced outages end.

6.0 Scheduling Procedures

6.1 Prior to the beginning of each week, the Network Customer shall provide to the

Transmission Provider expected hourly energy schedules for that week for all

energy flowing into the Transmission System administered by Transmission

Provider.

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,

57 1431666 & 74318195

and shall not permit unauthorized persons to have access to the space housing the

equipment. Network Customer shall provide to (or provide for, if the Network

Customer is not the meter owner) the Host Transmission Owner access to load

data and other data available from any delivery point meter. If the Network

Customer does not own the meter, the Host Transmission Owner shall make

available, upon request, all load data and other data obtained by the Host

Transmission Owner from the relevant delivery point meter, if available utilizing

existing equipment. The Network Customer will cooperate on the installation of

advanced technology metering in place of the standard metering equipment at a

delivery point at the expense of the requestor; provided, however, that meter

owner shall not be obligated to install, operate or maintain any meter or related

equipment that is not approved for use by the meter owner and/or Host

Transmission Owner, and provided that such equipment addition can be

accomplished in a manner that does not interfere with the operation of the meter

owner’s equipment or any Party’s fulfillment of any statutory or contractual

obligation.

8.2 The Network Customer shall provide for the testing of the metering equipment at

suitable intervals and its accuracy of registration shall be maintained in

accordance with standards acceptable to the Transmission Provider and consistent

with Good Utility Practice. At the request of the Transmission Provider or Host

Transmission Owner, a special test shall be made, but if less than two percent

inaccuracy is found, the requesting Party shall pay for the test. Representatives of

the Parties may be present at all routine or special tests and whenever any

readings for purposes of settlement are taken from meters not having an

automated record. If any test of metering equipment discloses an inaccuracy

exceeding two percent, the accounts of the Parties shall be adjusted. Such

adjustment shall apply to the period over which the meter error is shown to have

been in effect or, where such period is indeterminable, for one-half the period

since the prior meter test. Should any metering equipment fail to register, the

amounts of energy delivered shall be estimated from the best available data.

58 1431666 & 74318195

8.3 If the Network Customer is supplying energy to retail load that has a choice in its

supplier, the Network Customer shall be responsible for providing all information

required by the Transmission Provider for billing purposes. Metering information

shall be available to the Transmission Provider either by individual retail

customer or aggregated retail energy information for that load the Network

Customer has under contract during the billing month. For the retail load that has

interval demand metering, the actual energy used by interval must be supplied.

For the retail load using standard kWh metering, the total energy consumed by

meter cycle, along with the estimated demand profile must be supplied. All rights

and limitations between Parties granted in Sections 8.1, and 8.2 are applicable in

regards to retail metering used as the basis for billing the Network Customer.

9.0 Connected Generation Resources

9.1 The Network Customer’s connected generation resources that have automatic

generation control and automatic voltage regulation shall be operated and

maintained consistent with regional operating standards, and the Network

Customer or the operator shall operate, or cause to be operated, such resources to

avoid adverse disturbances or interference with the safe and reliable operation of

the transmission system.

9.2 For all Network Resources of the Network Customer, the following generation

telemetry readings to the Host Transmission Owner are required:

1) Analog MW;

2) Integrated MWHRS/HR;

3) Analog MVARS; and

4) Integrated MVARHRS/HR.

10.0 Redispatching, Curtailment and Load Shedding

10.1 In accordance with Section 33 of the Tariff, the Transmission Provider may

require redispatching of generation resources or curtailment of loads to relieve

existing or potential transmission system constraints. The Network Customer

shall submit verifiable incremental and decremental cost data from its Network

59 1431666 & 74318195

Resources to the Transmission Provider. These costs will be used as the basis for

least-cost redispatch. Information exchanged by the Parties under this article will

be used for system redispatch only, and will not be disclosed to third parties

absent mutual consent or order of a court or regulatory agency. The Network

Customer shall respond immediately to requests for redispatch from the

Transmission Provider. The Transmission Provider will bill or credit the Network

Customer as appropriate.

10.2 The Parties shall implement load-shedding procedures to maintain the reliability

and integrity for the Transmission System as provided in Section 33.1 of the

Tariff and in accordance with applicable NERC and SPP requirements and Good

Utility Practice. Load shedding may include (1) automatic load shedding, (2)

manual load shedding, and (3) rotating interruption of customer load. When

manual load shedding or rotating interruptions are necessary, the Host

Transmission Owner shall notify the Network Customer’s dispatcher or

schedulers of the required action and the Network Customer shall comply

immediately.

10.3 The Network Customer will coordinate with the Host Transmission Owner to

ensure sufficient load shedding equipment is in place on their respective systems

to meet SPP requirements. The Network Customer and the Host Transmission

Owner shall develop a plan for load shedding which may include manual load

shedding by the Network Customer.

11.0 Communications

11.1 The Network Customer shall, at its own expense, install and maintain

communication link(s) for scheduling. The communication link(s) shall be used

for data transfer and for voice communication.

11.2 A Network Customer self-supplying Ancillary Services or securing Ancillary

Services from a third-party shall, at its own expense, install and maintain

telemetry equipment communicating between the generating resource(s)

providing such Ancillary Services and the Host Transmission Owner's Control

Area.

60 1431666 & 74318195

12.0 Cost Responsibility

12.1 The Network Customer shall be responsible for all costs incurred by the Network

Customer, Host Transmission Owner, and Transmission Provider to implement

the provisions of this Operating Agreement including, but not limited to,

engineering, administrative and general expenses, material and labor expenses

associated with the specification, design, review, approval, purchase, installation,

maintenance, modification, repair, operation, replacement, checkouts, testing,

upgrading, calibration, removal, and relocation of equipment or software, so long

as the direct assignment of such costs is consistent with Commission policy.

12.2 The Network Customer shall be responsible for all costs incurred by Network

Customer, Host Transmission Owner, and Transmission Provider for on-going

operation and maintenance of the facilities required to implement the provisions

of this Operating Agreement so long as the direct assignment of such costs is

consistent with Commission policy. Such work shall include, but is not limited

to, normal and extraordinary engineering, administrative and general expenses,

material and labor expenses associated with the specifications, design, review,

approval, purchase, installation, maintenance, modification, repair, operation,

replacement, checkouts, testing, calibration, removal, or relocation of equipment

required to accommodate service provided under this Operating Agreement.

13.0 Billing and Payments

Billing and Payments shall be in accordance with Section 7 of the Tariff.

14.0 Dispute Resolution

Any dispute among the Parties regarding this Operating Agreement shall be resolved

pursuant to Section 12 of the Tariff, or otherwise, as mutually agreed by the Parties.

15.0 Assignment

This Operating Agreement shall inure to the benefit of and be binding upon the Parties

and their respective successors and assigns, but shall not be assigned by any Party, except

61 1431666 & 74318195

to successors to all or substantially all of the electric properties and assets of such Party,

without the written consent of the other Parties. Such written consent shall not be

unreasonably withheld.

16.0 Choice of Law

The interpretation, enforcement, and performance of this Operating Agreement shall be

governed by the laws of the State of Arkansas, except laws and precedent of such

jurisdiction concerning choice of law shall not be applied, except to the extent governed

by the laws of the United States of America.

17.0 Entire Agreement

The Tariff and Service Agreement, as they are amended from time to time, are

incorporated herein and made a part hereof. To the extent that a conflict exists between

the terms of this Operating Agreement and the terms of the Tariff, the Tariff shall control.

18.0 Unilateral Changes and Modifications

Nothing contained in this Operating Agreement or any associated Service Agreement

shall be construed as affecting in any way the right of the Transmission Provider or a

Transmission Owner unilaterally to file with the Commission, or make application to the

Commission for, changes in rates, charges, classification of service, or any rule,

regulation, or agreement related thereto, under section 205 of the Federal Power Act and

pursuant to the Commission’s rules and regulations promulgated thereunder, or under

other applicable statutes or regulations.

Nothing contained in this Operating Agreement or any associated Service

Agreement shall be construed as affecting in any way the ability of any Network

Customer receiving Network Integration Transmission Service under the Tariff to

exercise any right under the Federal Power Act and pursuant to the Commission’s rules

and regulations promulgated thereunder; provided, however, that it is expressly

recognized that this Operating Agreement is necessary for the implementation of the

Tariff and Service Agreement. Therefore, no Party shall propose a change to this

62 1431666 & 74318195

Operating Agreement that is inconsistent with the rates, terms and conditions of the Tariff

and/or Service Agreement.

19.0 Term

This Operating Agreement shall become effective on the date assigned by the

Commission (“Effective Date”), and shall continue in effect until the Tariff or the

Network Customer’s Service Agreement is terminated, whichever shall occur first.

20.0 Notice

20.1 Any notice that may be given to or made upon any Party by any other Party under

any of the provisions of this Operating Agreement shall be in writing, unless

otherwise specifically provided herein, and shall be considered delivered when

the notice is personally delivered or deposited in the United States mail, certified

or registered postage prepaid, to the following:

[Transmission Provider]Southwest Power Pool, Inc.Carl MonroeExecutive Vice President and Chief Operating Officer415 North McKinley, #140 Plaza WestLittle Rock, AR 72205-3020501-614-3218 phone 501-664-9553 [email protected]

[Host Transmission Owner]Westar Energy, Inc.Kelly HarrisonVice President, Transmission Operations and Environmental Services818 S. Kansas AvenueTopeka, KS 66612 785-575-1636 phone 785-575-8061 fax [email protected]

[Network Customer]Kansas Electric Power Cooperative, Inc.

63 1431666 & 74318195

Mark BarbeeVice President Engineering600 SW Corporate ViewTopeka, KS 66615785-273-7010 phone 785-271-4888 fax [email protected]

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

accordance with this Article 20.

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

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

transmission as may be appropriate and shall be confirmed in writing as soon as

reasonably practical thereafter, if any Party so requests in any particular instance.

64 1431666 & 74318195

21.0 Execution in Counterparts

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

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

construed together and shall constitute one instrument.

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

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

effective as of the Effective Date.

TRANSMISSION PROVIDER HOST TRANSMISSION OWNER

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

_Carl Monroe____________ _Kelly B. Harrison____________________Printed Name Printed Name

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

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

NETWORK CUSTOMER

__/s/ Mark R. Barbee______Signature

_Mark R. Barbee_________Printed Name

_VP of Engineering_______Title

_7/26/2011______________Date

1 1431666 & 74318195

Southwest Power Pool, Inc.

Third Revised Service Agreement No. 1636

SERVICE AGREEMENT FOR NETWORK INTEGRATION TRANSMISSION

SERVICE BETWEEN SOUTHWEST POWER POOL, INC. AND KANSAS

ELECTRIC POWER COOPERATIVE, INC.

This Network Integration Transmission Service Agreement ("Service Agreement") is

entered into this 1st day of June 2011, by and between Kansas Electric Power Cooperative, Inc.

("Network Customer" or “KEPCO”), and Southwest Power Pool, Inc. ("Transmission Provider").

The Network Customer and Transmission Provider shall be referred to individually as “Party”

and collectively as "Parties."




Energy Regulatory Commission ("Commission") as it may from time to time be amended;


Service for Transmission Owners within the SPP Region and acts as agent for the Transmission

Owners in providing service under the Tariff;


the Tariff; and


meaning as in the Tariff.



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.

7/28/2011 7/26/2011

Date Date

5 1431666 & 74318195

ATTACHMENT 1 TO THE NETWORK INTEGRATION TRANSMISSION SERVICE

AGREEMENT

BETWEEN SOUTHWEST POWER POOL AND

SPECIFICATIONS FOR NETWORK INTEGRATION TRANSMISSION SERVICE

1.0 Network Resources

The Network Resources are listed in Appendix 1.

2.0 Network Loads

The Network Load consists of the bundled native load or its equivalent for Network

Customer load in the Westar Energy Control Area as listed in Appendix 3.

The Network Customer’s Network Load shall be measured on an hourly integrated basis,

by suitable metering equipment located at each connection and delivery point, and each

generating facility. The meter owner shall cause to be provided to the Transmission

Provider, Network Customer and applicable Transmission Owner, on a monthly basis

such data as required by Transmission Provider for billing. The Network Customer’s

load shall be adjusted, for settlement purposes, to include applicable Transmission Owner

transmission and distribution losses, as applicable, as specified in Sections 8.5 and 8.6,

respectively. For a Network Customer providing retail electric service pursuant to a state

retail access program, profiled demand data, based upon revenue quality non-IDR meters

may be substituted for hourly integrated demand data. Measurements taken and all

metering equipment shall be in accordance with the Transmission Provider’s standards

and practices for similarly determining the Transmission Provider’s load. The actual

hourly Network Loads, by delivery point, internal generation site and point where power

may flow to and from the Network Customer, with separate readings for each direction of

flow, shall be provided.

3.0 Affected Control Areas and Intervening Systems Providing Transmission Service

6 1431666 & 74318195

The affected control area is Westar Energy. The intervening systems providing

transmission service are _____none____

4.0 Electrical Location of Initial Sources

See Appendix 1.

5.0 Electrical Location of the Ultimate Loads

The loads of Network Customer identified in Section 2.0 hereof as the Network Load are

electrically located within the Westar Energy Control Area.

6.0 Delivery Points

The delivery points are the interconnection points identified in Section 2.0 as the

Network Load.

7.0 Receipt Points

The Points of Receipt are listed in Appendix 2.

8.0 Compensation

Service under this Service Agreement may be subject to some combination of the charges

detailed below. The appropriate charges for individual transactions will be determined in

accordance with the terms and conditions of the Tariff.

8.1 Transmission Charge

Monthly Demand Charge per Section 34 and Part V of the Tariff.

8.2 System Impact and/or Facility Study Charge

7 1431666 & 74318195

Studies may be required in the future to assess the need for system

reinforcements in light of the ten-year forecast data provided. Future charges, if

required, shall be in accordance with Section 32 of the Tariff.

8.3 Direct Assignment Facilities Charge

8.4 Ancillary Service Charges

8.4.1 The following Ancillary Services are required under this Service

Agreement.

a) Scheduling, System Control and Dispatch Service per Schedule 1 of the

Tariff.

b) Tariff Administration Service per Schedule 1-A of the Tariff.

c) Reactive Supply and Voltage Control from Generation Sources Service

per Schedule 2 of the Tariff.

d) Regulation and Frequency Response Service per Schedule 3 of the

Tariff.

e) Energy Imbalance Service per Schedule 4 of the Tariff.

f) Operating Reserve - Spinning Reserve Service per Schedule 5 of the

Tariff.

g) Operating Reserve - Supplemental Reserve Service per Schedule 6 of the

Tariff.

The Ancillary Services may be self-supplied by the Network Customer or

provided by a third party in accordance with Sections 8.4.2 through 8.4.4, with

the exception of the Ancillary Services for Schedules 1, 1-A, and 2, which must

be purchased from the Transmission Provider.

8.4.2 In accordance with the Tariff, when the Network Customer elects to self-

supply or have a third party provide Ancillary Services, the Network

Customer shall indicate the source for its Ancillary Services to be in

effect for the upcoming calendar year in its annual forecasts. If the

Network Customer fails to include this information with its annual

8 1431666 & 74318195

forecasts, Ancillary Services will be purchased from the Transmission

Provider in accordance with the Tariff.

8.4.3 When the Network Customer elects to self-supply or have a third party

provide Ancillary Services and is unable to provide its Ancillary

Services, the Network Customer will pay the Transmission Provider for

such services and associated penalties in accordance with the Tariff as a

result of the failure of the Network Customer’s alternate sources for

required Ancillary Services.

8.4.4 All costs for the Network Customer to supply its own Ancillary Services

shall be the responsibility of the Network Customer.

8.5 Real Power Losses – Transmission

The Network Customer shall replace losses in accordance with Attachment M of

the Tariff.

8.6 Real Power Losses – Distribution

The Network Customer shall replace all distribution losses in accordance with

Westar Energy's Open Access Transmission Tariff, Section 28.5, based upon the

location of each delivery point meter located on distribution facilities. The

composite loss percentages in Section 28.5 shall exclude transmission

losses.

8.7 Power Factor Correction Charge

8.8 Redispatch Charge

Redispatch charges shall be in accordance with Section 33.3 of the Tariff.

8.9 Wholesale Distribution Service Charge

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)


(1)

LYON-COFFEY COOP

533301

AMERICUS - T.

BIRD 1111 Westar 34.5

EAST ST3 115

kV

533628

BURLINGTON KCC01 Westar 12.5(Bus)

CC1BURL2 69

kV

533167

ESKRIDGE 1105 Westar

12.5

(Circuit)

KEENE 3 115

kV

533301

HARTFORD 1102 Westar

12.5

(Circuit)

EAST ST3 115

kV

533301

MELVERN / BETO

JUNCTION 1108 Westar

12.5

(Circuit)

EAST ST3 115

kV

533308

OLPE 1112 Westar 12.5 (Bus)

VAUGHN 3 115

kV

OLPE DEDUCT (A) 1112M Westar 12.5 (E)

533306

READING 1104 Westar

12.5

(Circuit)

READING3 115

kV

READING

DEDUCT (A) 706B Westar 12.5 (Bus)

533302

TORONTO 1004 Westar 12.5(Circuit)(Circuit)

EEUREKA3 115

kV

533631

VERNON KCC04 Westar 12.5(Bus)

CC4VERN2 69

kV

533308

VIRGIL 1003 Westar 12.5(Circuit)

VAUGHN 3 115

kV

533301

WAVERLY 1005 Westar 34.5

EAST ST3 115

kV

533309

WEST EMPORIA 1106 Westar

12.5

(Low Side)

WEMPORI3 115

kV

533630

WESTPHALIA KCC03 Westar 12.5(Bus)

CC3WEST2 69

kV

29 1431666 & 74318195

533310

WILLIAMS 1113 Westar

4.2

(Low Side)

WMBROS 3 115

kV

533653

WOLF CREEK KCC06 Westar

12.5

(Low Side)

WOLFCRK2 69

kV


(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

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 June 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% $ - $ -

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

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."




Energy Regulatory Commission ("Commission");


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;


the Tariff;

WHEREAS, the Network Customer and Transmission Provider have entered into a

Network Integration Transmission Service Agreement (“Service Agreement”) under the Tariff;

and


meaning as in the Tariff, unless otherwise specified herein.



1.0 Network Service

This Operating Agreement sets out the terms and conditions under which the

Transmission Provider, Host Transmission Owner, and Network Customer will cooperate

50 1431666 & 74318195

and the Host Transmission Owner and Network Customer will operate their respective

systems and specifies the equipment that will be installed and operated. The Parties shall

operate and maintain their respective systems in a manner that will allow the Host

Transmission Owner and the Network Customer to operate their systems and Control

Area and the Transmission Provider to perform its obligations consistent with Good

Utility Practice. The Transmission Provider may, on a non-discriminatory basis, waive

the requirements of Section 4.1 and Section 8.3 to the extent that such information is

unknown at the time of application or where such requirement is not applicable.

2.0 Designated Representatives of the Parties

2.1 Each Party shall designate a representative and alternate ("Designated

Representative(s)") from their respective company to coordinate and implement,

on an ongoing basis, the terms and conditions of this Operating Agreement,

including planning, operating, scheduling, redispatching, curtailments, control

requirements, technical and operating provisions, integration of equipment,

hardware and software, and other operating considerations.

2.2 The Designated Representatives shall represent the Transmission Provider, Host

Transmission Owner, and Network Customer in all matters arising under this

Operating Agreement and which may be delegated to them by mutual agreement

of the Parties hereto.

2.3 The Designated Representatives shall meet or otherwise confer at the request of

any Party upon reasonable notice, and each Party may place items on the meeting

agenda. All deliberations of the Designated Representatives shall be conducted

by taking into account the exercise of Good Utility Practice. If the Designated

Representatives are unable to agree on any matter subject to their deliberation,

that matter shall be resolved pursuant to Section 12.0 of the Tariff, or otherwise,

as mutually agreed by the Parties.

3.0 System Operating Principles

3.1 The Network Customer must design, construct, and operate its facilities safely

and efficiently in accordance with Good Utility Practice, NERC, SPP, or any

51 1431666 & 74318195

successor requirements, industry standards, criteria, and applicable

manufacturer’s equipment specifications, and within operating physical parameter

ranges (voltage schedule, load power factor, and other parameters) required by the

Host Transmission Owner and Transmission Provider.

3.2 The Host Transmission Owner and Transmission Provider reserve the right to

inspect the facilities and operating records of the Network Customer upon

mutually agreeable terms and conditions.

3.3 Electric service, in the form of three phase, approximately sixty hertz alternating

current, shall be delivered at designated delivery points and nominal voltage(s)

listed in the Service Agreement. When multiple delivery points are provided to a

specific Network Load identified in Appendix 3 of the Service Agreement, they

shall not be operated in parallel by the Network Customer without the approval of

the Host Transmission Owner and Transmission Provider. The Designated

Representatives shall establish the procedure for obtaining such approval. The

Designated Representatives shall also establish and monitor standards and

operating rules and procedures to assure that transmission system integrity and the

safety of customers, the public and employees are maintained or enhanced when

such parallel operations is permitted either on a continuing basis or for

intermittent switching or other service needs. Each Party shall exercise due

diligence and reasonable care in maintaining and operating its facilities so as to

maintain continuity of service.

3.4 The Host Transmission Owner and Network Customer shall operate their systems

and delivery points in continuous synchronism and in accord with applicable

NERC Standards, SPP Criteria, and Good Utility Practice.

3.5 If the function of any Party’s facilities is impaired or the capacity of any delivery

point is reduced, or synchronous operation at any delivery point(s) becomes

interrupted, either manually or automatically, as a result of force majeure or

maintenance coordinated by the Parties, the Parties will cooperate to remove the

cause of such impairment, interruption or reduction, so as to restore normal

operating conditions expeditiously.

52 1431666 & 74318195

3.6 The Transmission Provider and Host Transmission Owner, if applicable, reserve

the sole right to take any action necessary during an actual or imminent

emergency to preserve the reliability and integrity of the Transmission System,

limit or prevent damage, expedite restoration of service, ensure safe and reliable

operation, avoid adverse effects on the quality of service, or preserve public

safety.

3.7 In an emergency, the reasonable judgment of the Transmission Provider and Host

Transmission Owner, if applicable, in accordance with Good Utility Practice,

shall be the sole determinant of whether the operation of the Network Customer

loads or equipment adversely affects the quality of service or interferes with the

safe and reliable operation of the transmission system. The Transmission

Provider or Host Transmission Owner, if applicable, may discontinue

transmission service to such Network Customer until the power quality or

interfering condition has been corrected. Such curtailment of load, redispatching,

or load shedding shall be done on a non-discriminatory basis by Load Ratio

Share, to the extent practicable. The Transmission Provider or Host Transmission

Owner, if applicable, will provide reasonable notice and an opportunity to

alleviate the condition by the Network Customer to the extent practicable.

4.0 System Planning & Protection

4.1 No later than October 1 of each year, the Network Customer shall provide the

Transmission Provider and Host Transmission Owner the following information:

a) A ten (10) year projection of summer and winter peak demands with the

corresponding power factors and annual energy requirements on an

aggregate basis for each delivery point. If there is more than one delivery

point, the Network Customer shall provide the summer and winter peak

demands and energy requirements at each delivery point for the normal

operating configuration;

b) A ten (10) year projection by summer and winter peak of planned

generating capabilities and committed transactions with third parties

53 1431666 & 74318195

which resources are expected to be used by the Network Customer to

supply the peak demand and energy requirements provided in (a);

c) A ten (10) year projection by summer and winter peak of the estimated

maximum demand in kilowatts that the Network Customer plans to

acquire from the generation resources owned by the Network Customer,

and generation resources purchased from others; and

d) A projection for each of the next ten (10) years of transmission facility

additions to be owned and/or constructed by the Network Customer which

facilities are expected to affect the planning and operation of the

transmission system within the Host Transmission Owner’s Control Area.

This information is to be delivered to the Transmission Provider’s and Host

Transmission Owner’s Designated Representatives pursuant to Section 2.0.

4.2 Information exchanged by the Parties under this article will be used for system

planning and protection only, and will not be disclosed to third parties absent

mutual consent or order of a court or regulatory agency.

4.3 The Host Transmission Owner, and Transmission Provider, if applicable, will

incorporate this information in its system load flow analyses performed during the

first half of each year. Following completion of these analyses, the Transmission

Provider or Host Transmission Owner will provide the following to the Network

Customer:

a) A statement regarding the ability of the Host Transmission Owner’s

transmission system to meet the forecasted deliveries at each of the

delivery points;

b) A detailed description of any constraints on the Host Transmission

Owner’s system within the five (5) year horizon that will restrict

forecasted deliveries; and

c) In the event that studies reveal a potential limitation of the Transmission

Provider’s ability to deliver power and energy to any of the delivery

points, a Designated Representative of the Transmission Provider will

coordinate with the Designated Representatives of the Host Transmission

Owner and the Network Customer to identify appropriate remedies for

54 1431666 & 74318195

such constraints including but not limited to: construction of new

transmission facilities, upgrade or other improvements to existing

transmission facilities or temporary modification to operating procedures

designed to relieve identified constraints. Any constraints within the

Transmission System will be remedied pursuant to the procedures of

Attachment O of the Tariff.

For all other constraints the Host Transmission Owner, upon

agreement with the Network Customer and consistent with Good Utility

Practice, will endeavor to construct and place into service sufficient

capacity to maintain reliable service to the Network Customer.

An appropriate sharing of the costs to relieve such constraints will

be determined by the Parties, consistent with the Tariff and with the

Commission’s rules, regulations, policies, and precedents then in effect. If

the Parties are unable to agree upon an appropriate remedy or sharing of

the costs, the Transmission Provider shall submit its proposal for the

remedy or sharing of such costs to the Commission for approval consistent

with the Tariff.

4.4 The Host Transmission Owner and the Network Customer shall coordinate with

the Transmission Provider: (1) all scheduled outages of generating resources and

transmission facilities consistent with the reliability of service to the customers of

each Party, and (2) additions or changes in facilities which could affect another

Party’s system. Where coordination cannot be achieved, the Designated

Representatives shall intervene for resolution.

4.5 The Network Customer shall coordinate with the Host Transmission Owner

regarding the technical and engineering arrangements for the delivery points,

including one line diagrams depicting the electrical facilities configuration and

parallel generation, and shall design and build the facilities to avoid interruptions

on the Host Transmission Owner’s transmission system.

4.6 The Network Customer shall provide for automatic and underfrequency load

shedding of the Network Customer Network Load in accordance with the SPP

Criteria related to emergency operations.

55 1431666 & 74318195

5.0 Maintenance of Facilities

5.1 The Network Customer shall maintain its facilities necessary to reliably receive

capacity and energy from the Host Transmission Owner’s transmission system

consistent with Good Utility Practice. The Transmission Provider or Host

Transmission Owner, as appropriate, may curtail service under this Operating

Agreement to limit or prevent damage to generating or transmission facilities

caused by the Network Customer’s failure to maintain its facilities in accordance

with Good Utility Practice, and the Transmission Provider or Host Transmission

Owner may seek as a result any appropriate relief from the Commission.

5.2 The Designated Representatives shall establish procedures to coordinate the

maintenance schedules, and return to service, of the generating resources and

transmission and substation facilities, to the greatest extent practical, to ensure

sufficient transmission resources are available to maintain system reliability and

reliability of service.

5.3 The Network Customer shall obtain: (1) concurrence from the Transmission

Provider before beginning any scheduled maintenance of facilities which could

impact the operation of the Transmission System over which transmission service

is administered by Transmission Provider; and (2) clearance from the

Transmission Provider when the Network Customer is ready to begin

maintenance on a transmission line or substation. The Transmission Provider

shall coordinate clearances with the Host Transmission Owner. The Network

Customer shall notify the Transmission Provider and the Host Transmission

Owner as soon as practical at the time when any unscheduled or forced outages

occur and again when such unscheduled or forced outages end.

6.0 Scheduling Procedures

6.1 Prior to the beginning of each week, the Network Customer shall provide to the

Transmission Provider expected hourly energy schedules for that week for all

energy flowing into the Transmission System administered by Transmission

Provider.

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,

57 1431666 & 74318195

and shall not permit unauthorized persons to have access to the space housing the

equipment. Network Customer shall provide to (or provide for, if the Network

Customer is not the meter owner) the Host Transmission Owner access to load

data and other data available from any delivery point meter. If the Network

Customer does not own the meter, the Host Transmission Owner shall make

available, upon request, all load data and other data obtained by the Host

Transmission Owner from the relevant delivery point meter, if available utilizing

existing equipment. The Network Customer will cooperate on the installation of

advanced technology metering in place of the standard metering equipment at a

delivery point at the expense of the requestor; provided, however, that meter

owner shall not be obligated to install, operate or maintain any meter or related

equipment that is not approved for use by the meter owner and/or Host

Transmission Owner, and provided that such equipment addition can be

accomplished in a manner that does not interfere with the operation of the meter

owner’s equipment or any Party’s fulfillment of any statutory or contractual

obligation.

8.2 The Network Customer shall provide for the testing of the metering equipment at

suitable intervals and its accuracy of registration shall be maintained in

accordance with standards acceptable to the Transmission Provider and consistent

with Good Utility Practice. At the request of the Transmission Provider or Host

Transmission Owner, a special test shall be made, but if less than two percent

inaccuracy is found, the requesting Party shall pay for the test. Representatives of

the Parties may be present at all routine or special tests and whenever any

readings for purposes of settlement are taken from meters not having an

automated record. If any test of metering equipment discloses an inaccuracy

exceeding two percent, the accounts of the Parties shall be adjusted. Such

adjustment shall apply to the period over which the meter error is shown to have

been in effect or, where such period is indeterminable, for one-half the period

since the prior meter test. Should any metering equipment fail to register, the

amounts of energy delivered shall be estimated from the best available data.

58 1431666 & 74318195

8.3 If the Network Customer is supplying energy to retail load that has a choice in its

supplier, the Network Customer shall be responsible for providing all information

required by the Transmission Provider for billing purposes. Metering information

shall be available to the Transmission Provider either by individual retail

customer or aggregated retail energy information for that load the Network

Customer has under contract during the billing month. For the retail load that has

interval demand metering, the actual energy used by interval must be supplied.

For the retail load using standard kWh metering, the total energy consumed by

meter cycle, along with the estimated demand profile must be supplied. All rights

and limitations between Parties granted in Sections 8.1, and 8.2 are applicable in

regards to retail metering used as the basis for billing the Network Customer.

9.0 Connected Generation Resources

9.1 The Network Customer’s connected generation resources that have automatic

generation control and automatic voltage regulation shall be operated and

maintained consistent with regional operating standards, and the Network

Customer or the operator shall operate, or cause to be operated, such resources to

avoid adverse disturbances or interference with the safe and reliable operation of

the transmission system.

9.2 For all Network Resources of the Network Customer, the following generation

telemetry readings to the Host Transmission Owner are required:

1) Analog MW;

2) Integrated MWHRS/HR;

3) Analog MVARS; and

4) Integrated MVARHRS/HR.

10.0 Redispatching, Curtailment and Load Shedding

10.1 In accordance with Section 33 of the Tariff, the Transmission Provider may

require redispatching of generation resources or curtailment of loads to relieve

existing or potential transmission system constraints. The Network Customer

shall submit verifiable incremental and decremental cost data from its Network

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Resources to the Transmission Provider. These costs will be used as the basis for

least-cost redispatch. Information exchanged by the Parties under this article will

be used for system redispatch only, and will not be disclosed to third parties

absent mutual consent or order of a court or regulatory agency. The Network

Customer shall respond immediately to requests for redispatch from the

Transmission Provider. The Transmission Provider will bill or credit the Network

Customer as appropriate.

10.2 The Parties shall implement load-shedding procedures to maintain the reliability

and integrity for the Transmission System as provided in Section 33.1 of the

Tariff and in accordance with applicable NERC and SPP requirements and Good

Utility Practice. Load shedding may include (1) automatic load shedding, (2)

manual load shedding, and (3) rotating interruption of customer load. When

manual load shedding or rotating interruptions are necessary, the Host

Transmission Owner shall notify the Network Customer’s dispatcher or

schedulers of the required action and the Network Customer shall comply

immediately.

10.3 The Network Customer will coordinate with the Host Transmission Owner to

ensure sufficient load shedding equipment is in place on their respective systems

to meet SPP requirements. The Network Customer and the Host Transmission

Owner shall develop a plan for load shedding which may include manual load

shedding by the Network Customer.

11.0 Communications

11.1 The Network Customer shall, at its own expense, install and maintain

communication link(s) for scheduling. The communication link(s) shall be used

for data transfer and for voice communication.

11.2 A Network Customer self-supplying Ancillary Services or securing Ancillary

Services from a third-party shall, at its own expense, install and maintain

telemetry equipment communicating between the generating resource(s)

providing such Ancillary Services and the Host Transmission Owner's Control

Area.

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12.0 Cost Responsibility

12.1 The Network Customer shall be responsible for all costs incurred by the Network

Customer, Host Transmission Owner, and Transmission Provider to implement

the provisions of this Operating Agreement including, but not limited to,

engineering, administrative and general expenses, material and labor expenses

associated with the specification, design, review, approval, purchase, installation,

maintenance, modification, repair, operation, replacement, checkouts, testing,

upgrading, calibration, removal, and relocation of equipment or software, so long

as the direct assignment of such costs is consistent with Commission policy.

12.2 The Network Customer shall be responsible for all costs incurred by Network

Customer, Host Transmission Owner, and Transmission Provider for on-going

operation and maintenance of the facilities required to implement the provisions

of this Operating Agreement so long as the direct assignment of such costs is

consistent with Commission policy. Such work shall include, but is not limited

to, normal and extraordinary engineering, administrative and general expenses,

material and labor expenses associated with the specifications, design, review,

approval, purchase, installation, maintenance, modification, repair, operation,

replacement, checkouts, testing, calibration, removal, or relocation of equipment

required to accommodate service provided under this Operating Agreement.

13.0 Billing and Payments

Billing and Payments shall be in accordance with Section 7 of the Tariff.

14.0 Dispute Resolution

Any dispute among the Parties regarding this Operating Agreement shall be resolved

pursuant to Section 12 of the Tariff, or otherwise, as mutually agreed by the Parties.

15.0 Assignment

This Operating Agreement shall inure to the benefit of and be binding upon the Parties

and their respective successors and assigns, but shall not be assigned by any Party, except

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to successors to all or substantially all of the electric properties and assets of such Party,

without the written consent of the other Parties. Such written consent shall not be

unreasonably withheld.

16.0 Choice of Law

The interpretation, enforcement, and performance of this Operating Agreement shall be

governed by the laws of the State of Arkansas, except laws and precedent of such

jurisdiction concerning choice of law shall not be applied, except to the extent governed

by the laws of the United States of America.

17.0 Entire Agreement

The Tariff and Service Agreement, as they are amended from time to time, are

incorporated herein and made a part hereof. To the extent that a conflict exists between

the terms of this Operating Agreement and the terms of the Tariff, the Tariff shall control.

18.0 Unilateral Changes and Modifications

Nothing contained in this Operating Agreement or any associated Service Agreement

shall be construed as affecting in any way the right of the Transmission Provider or a

Transmission Owner unilaterally to file with the Commission, or make application to the

Commission for, changes in rates, charges, classification of service, or any rule,

regulation, or agreement related thereto, under section 205 of the Federal Power Act and

pursuant to the Commission’s rules and regulations promulgated thereunder, or under

other applicable statutes or regulations.

Nothing contained in this Operating Agreement or any associated Service

Agreement shall be construed as affecting in any way the ability of any Network

Customer receiving Network Integration Transmission Service under the Tariff to

exercise any right under the Federal Power Act and pursuant to the Commission’s rules

and regulations promulgated thereunder; provided, however, that it is expressly

recognized that this Operating Agreement is necessary for the implementation of the

Tariff and Service Agreement. Therefore, no Party shall propose a change to this

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Operating Agreement that is inconsistent with the rates, terms and conditions of the Tariff

and/or Service Agreement.

19.0 Term

This Operating Agreement shall become effective on the date assigned by the

Commission (“Effective Date”), and shall continue in effect until the Tariff or the

Network Customer’s Service Agreement is terminated, whichever shall occur first.

20.0 Notice

20.1 Any notice that may be given to or made upon any Party by any other Party under

any of the provisions of this Operating Agreement shall be in writing, unless

otherwise specifically provided herein, and shall be considered delivered when

the notice is personally delivered or deposited in the United States mail, certified

or registered postage prepaid, to the following:

[Transmission Provider]

Southwest Power Pool, Inc.

Carl Monroe


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]


63 1431666 & 74318195

Mark Barbee



Topeka, KS 66615

785-273-7010 phone

785-271-4888 fax

[email protected]

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

accordance with this Article 20.

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

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

transmission as may be appropriate and shall be confirmed in writing as soon as

reasonably practical thereafter, if any Party so requests in any particular instance.

64 1431666 & 74318195

21.0 Execution in Counterparts

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

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

construed together and shall constitute one instrument.

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

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

effective as of the Effective Date.

TRANSMISSION PROVIDER HOST TRANSMISSION OWNER

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

Signature Signature

_Carl Monroe____________ _Kelly B. Harrison____________________

Printed Name Printed Name

_EVP & COO____________ _VP-Transmission Ops. & Environmental Svcs.___

Title Title

_07/28/2011_____________ _July 28, 2011______________________

Date Date

NETWORK CUSTOMER

__/s/ Mark R. Barbee______

Signature

_Mark R. Barbee_________

Printed Name

_VP of Engineering_______

Title

_7/26/2011______________

Date