Southwest Power Pool Inc nitsa noa_er… · 2014-03-31 · Revised Service Agreement No. 2198. 2 See Submission of Network Integration Transmission Service Agreement and Network

March 31, 2014 The Honorable Kimberly D. Bose Secretary Federal Energy Regulatory Commission 888 First Street NE Washington, DC 20426 Re: Southwest Power Pool, Inc., Docket No. ER14-____

Submission of 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”) submits the following: (1) an executed Service Agreement for Network Integration Transmission Service (“Service Agreement”) between SPP as Transmission Provider and Kansas Power Pool (“KPP”) as Network Customer (“Sixteenth Revised KPP Service Agreement”); and (2) an executed Network Operating Agreement (“NOA”) between SPP as Transmission Provider, KPP as Network Customer, and Midwest Energy, Inc. (“Midwest”), Mid-Kansas Electric Company, LLC (“MKEC”), and Westar Energy, Inc. (“Westar”) as Host Transmission Owners (“Sixteenth Revised KPP NOA”).1 The Sixteenth Revised KPP Agreements modify and supersede the Service Agreement and NOA currently pending before the Commission in Docket No. ER14-1414-000.2 SPP is submitting this filing because the Sixteenth Revised KPP Agreements include terms and conditions that do not conform to

1 The Sixteenth Revised KPP Service Agreement and Sixteenth Revised KPP NOA

are referred to collectively as the “Sixteenth Revised KPP Agreements,” and SPP, KPP, Midwest, MKEC, and Westar are referred to collectively as “the Parties.” The Sixteenth Revised KPP Agreements have been designated as Sixteenth Revised Service Agreement No. 2198.

2 See Submission of Network Integration Transmission Service Agreement and Network Operating Agreement of Southwest Power Pool, Inc., Docket No. ER14-1414-000 (March 4, 2014) (“March Filing”). The Service Agreement and NOA submitted in the March Filing are referred to collectively as the “Fifteenth Revised KPP Agreements” and individually as the “Fifteenth Revised KPP Service Agreement” and the “Fifteenth Revised KPP NOA.”

The Honorable Kimberly D. Bose March 31, 2014 Page 2 the standard forms of service agreements in the Open Access Transmission Tariff (“SPP Tariff”).3

I. Background On May 2, 2011, SPP submitted an unexecuted Service Agreement and NOA to the Commission between the Parties.4 The Original KPP Service Agreement was filed unexecuted due to a dispute between KPP and MKEC over the Service and Operating Agreements for Local Delivery Service (“SOALDS”) in Attachment D of the Original KPP Service Agreement. In addition, the Original KPP NOA was filed unexecuted because Midwest declined to execute the Original KPP NOA because SPP declined to include additional language in Section 9.2 of the Original KPP NOA that Midwest had requested. At the time, SPP did not include the requested language because SPP had insufficient time to evaluate its impacts. On July 1, 2011, the Commission conditionally accepted the Original KPP Agreements subject to a compliance filing to remove language in Sections 8.5, 8.6, and 8.12 of the Original KPP Service Agreement.5 On August 1, 2011, SPP submitted its compliance filing.6 Westar also filed a request for rehearing of the July 1 Order with respect to the Commission’s decision requiring SPP to remove the language related to distribution losses in Section 8.6 of the Original KPP Service Agreement.7

On September 29, 2011, the Commission issued an Order on Rehearing and Compliance, in which it granted Westar’s Request for Rehearing and conditionally accepted SPP’s August 1 Compliance Filing, effective April 1, 2011.8 In the September 29 Order, the Commission directed SPP to modify further the Original KPP Service 3 See SPP Tariff at Attachment F (“pro forma Service Agreement”) and Attachment

G (“pro forma NOA”), collectively “the pro forma Agreements.”

4 See Submission of Network Integration Transmission Service Agreement of Southwest Power Pool, Inc., Docket No. ER11-3494-000 (May 2, 2011). These agreements are referred to collectively as the “Original KPP Agreements” and individually as the “Original KPP Service Agreement” and the “Original KPP NOA.”

5 See Sw. Power Pool, Inc., 136 FERC ¶ 61,003, PP 43, 44 (2011) (“July 1 Order”).

6 Compliance Filing of Southwest Power Pool, Inc., Docket No. ER11-3494-001 (Aug. 1, 2011) (“August 1 Compliance Filing”).

7 Request for Rehearing of Westar Energy, Inc., Docket No. ER11-3494-002 (Aug. 1, 2011) (“Request for Rehearing”).

8 See Sw. Power Pool, Inc., 136 FERC ¶ 61,223 (2011) (“September 29 Order”).

The Honorable Kimberly D. Bose March 31, 2014 Page 3 Agreement to specify in Section 8.6 of Attachment 1 that composite loss percentages shall exclude transmission losses.9 Consequently, SPP submitted its compliance filing to further revise Section 8.6 of Attachment 1 of the Original KPP Service Agreement on October 12, 2011.10 The Commission accepted the October 12 Compliance Filing on December 7, 2011.11 Following the July 1 Order, the Original KPP Agreements have been updated numerous times.12

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

Sixteenth Revised KPP Agreements

Since the March Filing, the Parties revised the Fifteenth Revised KPP Service Agreement to remove a reference in Section 8.4.1 of Attachment 1 to an obsolete Service Agreement for Ancillary Services and Distribution Facilities (SPP Service Agreement No. 1136) between Westar and KPP;13 update wholesale distribution service charges in Section 8.9 of Attachment 1, and to add a new non-conforming Appendix 4. In addition, the Parties updated the Fifteenth Revised KPP Agreements to include the changes to the pro forma Agreements approved by the Commission for SPP’s Integrated Marketplace.14 9 September 29 Order at PP 13, 14.

10 Compliance Filing of Southwest Power Pool, Inc., Docket No. ER11-3494-003 (Oct. 12, 2011) (“October 12 Compliance Filing”).

11 See Sw. Power Pool, Inc., Letter Order, Docket No. ER11-3494-003 (Dec. 7, 2011) (“December 7 Letter Order”).

12 See March Filing; Sw. Power Pool, Inc., Letter Order, Docket No. ER14-1171-000 (Mar. 10, 2014); Sw. Power Pool, Inc., Letter Order, Docket No. ER14-438-000 (Jan. 14, 2014); Sw. Power Pool, Inc., Letter Order, Docket No. ER14-173-000 (Dec. 16, 2013); Sw. Power Pool, Inc., Letter Order, Docket No. ER13-2439-000 (Nov. 18, 2013); Sw. Power Pool, Inc., Letter Order, Docket No. ER13-2190-000 (Oct. 16, 2013); Sw. Power Pool, Inc., Letter Order, Docket No. ER13-2056-000 (Sept. 20, 2013); Sw. Power Pool, Inc., Letter Order, Docket No. ER13-1832-000 (Aug. 20, 2013); Sw. Power Pool, Inc., Letter Order, ER13-1809-000 (Aug. 20, 2013); Sw. Power Pool, Inc., Letter Order, Docket No. ER13-1350-000 (June 19, 2013); Sw. Power Pool, Inc., Letter Order, Docket No. ER13-1012-000 (Apr. 23, 2013); Sw. Power Pool, Inc., Letter Order, Docket No. ER13-498-000 (Jan. 28, 2013); Sw. Power Pool, Inc., Letter Order, Docket No. ER12-2702-000, -001 (Jan. 9, 2013).; Sw. Power Pool, Inc., Letter Order, Docket No. ER12-2157-000 (Aug. 23, 2012); Sw. Power Pool, Inc., Letter Order, Docket No. ER12-1677-000 (June 21, 2012).

13 SPP will separately file a termination of SPP Service Agreement No. 1136.

14 See Sw. Power Pool, Inc., 141 FERC ¶ 61,048 (2012).

The Honorable Kimberly D. Bose March 31, 2014 Page 4 To facilitate these changes, the Parties executed the Sixteenth Revised KPP Service Agreement and Sixteenth Revised KPP NOA which are submitted herein as the Sixteenth Revised KPP Agreements. The Sixteenth Revised KPP Agreements includes terms and conditions that do not conform to the pro forma Agreements, including non-conforming language retained from the Fifteenth Revised KPP Service Agreement and previous iterations of the agreements.15

First, Section 8.4 of Attachment 1 of the Sixteenth Revised KPP Service

Agreement states that for KPP’s load in the MKEC Zone, KPP has entered into a Service Agreement for Ancillary Services with MKEC that is included as Appendix 5. The Commission has accepted Service Agreements submitted by SPP that contained similar language.16

Second, Section 8.6 of Attachment 1 of the pro forma Service Agreement contains a fill-in-the-blank provision for Real Power Losses – Distribution. In Section 8.6 of Attachment 1 of the Sixteenth Revised KPP Service Agreement, the Parties insert language specifying 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 facilities” and that the “composite loss percentages in Section 28.5 shall exclude transmission losses.”17 The inserted language is just and reasonable because it provides the Parties with detail on how distribution losses will be calculated in accordance with a Commission-approved tariff

15 The Sixteenth Revised KPP NOA does not contain any non-conforming language

and conforms to the pro forma NOA.

16 See Sw. Power Pool, Inc., Letter Order, Docket No. ER14-1171-000 (Mar. 10, 2014); Sw. Power Pool, Inc., Letter Order, Docket No. ER14-438-000 (Jan. 14, 2014); Sw. Power Pool, Inc., Letter Order, Docket No. ER14-173-000 (Dec. 16, 2013); Sw. Power Pool, Inc., Letter Order, Docket No. ER13-2439-000 (Nov. 18, 2013); Sw. Power Pool, Inc., Letter Order, Docket No. ER13-2190-000 (Oct. 16, 2013); Sw. Power Pool, Inc., Letter Order, Docket No. ER13-2056-000 (Sept. 20, 2013); Sw. Power Pool, Inc., Letter Order, Docket No. ER13-1832-000 (Aug. 20, 2013); Sw. Power Pool, Inc., Letter Order, ER13-1809-000 (Aug. 20, 2013); Sw. Power Pool, Inc., Letter Order, Docket No. ER13-1350-000 (June 19, 2013); Sw. Power Pool, Inc., Letter Order, Docket No. ER13-1012-000 (Apr. 23, 2013); Sw. Power Pool, Inc., Letter Order, Docket No. ER13-498-000 (Jan. 28, 2013); Sw. Power Pool, Inc., Letter Order, Docket No. ER12-2702-000, -001 (Jan. 9, 2013); Sw. Power Pool, Inc., Letter Order, Docket No. ER12-2157-000 (Aug. 23, 2012); Sw. Power Pool, Inc., Letter Order, Docket No. ER12-1677-000 (June 21, 2012); July 1 Order; Sw. Power Pool, Inc., 131 FERC ¶ 61,070 (2010); Sw. Power Pool, Inc., Letter Order, Docket Nos. ER08-766-000 and -001 (June 23, 2008).

17 See Sixteenth Revised KPP Service Agreement at Attachment 1, § 8.6.

The Honorable Kimberly D. Bose March 31, 2014 Page 5 (i.e. Westar’s Open Access Transmission Tariff). This language is identical to the language that was included in the Original KPP Service Agreement as revised by the October 12 Compliance Filing ordered by the Commission in the September 29 Order18 and accepted by the Commission in the December 7 Letter Order,19 and has been included in each subsequent revision to the Original KPP Service Agreement.20

Third, Section 8.8 of Attachment 1 of the Sixteenth Revised KPP Service

Agreement contains the following non-conforming language:

[M]aximum firm import capability limitations will be enforced for Network Customer load both before and after completion of required network upgrades as detailed in Attachment B and Attachment C respectively subject to later re-studies, facility improvements, and/or modifications to Network Customer's network loads and/or resources. These limitations are applicable during peak loading conditions as identified by Midwest Energy and Westar Energy.21

Attachments B and C are non-conforming attachments of the Sixteenth Revised KPP Service Agreement. The language in Section 8.8 of Attachment 1 and Attachments B and C is necessary to provide for the maximum firm import capability limitations associated with KPP’s network service. Identical language was accepted by the Commission in the Original KPP Service Agreement, and has been included in each subsequent revision.22

Fourth, Section 8.9 of Attachment 1 of the Sixteenth Revised KPP Service Agreement contains language specifying that the cost support and monthly charges for Wholesale Distribution Service Charges are detailed in an additional, non-conforming Appendix 4 to the Sixteenth Revised KPP 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 Service Charges are filed with the Commission.23 The Commission has previously accepted agreements submitted by SPP with similar language.24 18 See September 29 Order at P 13.

19 See December 7 Letter Order. 20 See supra n. 12.


22 See supra n. 12.

23 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

The Honorable Kimberly D. Bose March 31, 2014 Page 6

Fifth, Section 8.9 of Attachment 1 of the Sixteenth Revised KPP Service Agreement further provides that Wholesale Distribution Service Charges for all of KPP’s load on MKEC’s transmission system, if any, are “specified in agreements approved by the Kansas Corporation Commission (“KCC”) in KCC Docket No. 11-GIME-597-GIE and on file with the KCC, as they may be amended by order of the KCC from time to time.”25 Section 8.9 also provides that the monthly rate for Wholesale Distribution Service Charges shall be “as specified in the [MKEC] Open Access Transmission Tariff approved by the KCC in KCC Docket No. 12-MKEE-650-TAR and on file with the KCC, as it may be amended by order of the KCC from time to time.”26 This language is consistent with Schedule 10 of the SPP Tariff, which provides that “[a]ll rates and charges for Wholesale Distribution Service shall be on file with the appropriate agency as required by law or regulation.”27 The Commission previously has accepted agreements submitted by SPP with identical language.28

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.”).

24 See Sw. Power Pool, Inc., Letter Order, Docket No. ER13-2276-000 (Oct. 22, 2013); Sw. Power Pool, Inc., Letter Order, Docket No. ER13-2274-000 (Oct. 22, 2013); Sw. Power Pool, Inc., Letter Order, Docket No. ER13-1011-000 (Apr. 23, 2013); Sw. Power Pool, Inc., Letter Order, Docket Nos. ER12-1713-000, -001 (July 3, 2012); Sw. Power Pool, Inc., Letter Order, Docket No. ER12-1426-000 (May 24, 2012); Sw. Power Pool, Inc., Letter Order, Docket No. ER12-828-000 (Mar. 15, 2012); Sw. Power Pool, Inc., Letter Order, Docket No. ER12-827-000 (Mar. 15, 2012); Sw. Power Pool, Inc., Letter Order, Docket No. ER12-813-000 (Mar. 12, 2012); Sw. Power Pool, Inc., Letter Order, Docket Nos. ER11-4180-001, et al. (Nov. 2, 2011).

25 See Sixteenth Revised KPP Service Agreement at Attachment 1, § 8.9. In previous iterations of the Sixteenth Revised KPP Service Agreement, Section 8.9 of Attachment 1 referenced an Attachment D that contained the SOALDS which were the subject of the unexecuted filing of the Original KPP Agreements. The Parties subsequently revised the Service Agreement to remove the SOALDS in Attachment D and replace the language with the language referencing the KCC docket described herein. The Commission first accepted this language in Sw. Power Pool, Inc., Letter Order, Docket No. ER12-2702-000, -001 (Jan. 9, 2013).


27 See supra n. 25.

28 See Sw. Power Pool, Inc., Letter Order, Docket No. ER14-1175-000 (Mar. 10, 2014); Sw. Power Pool, Inc., Letter Order, Docket No. ER14-1171-000 (Mar. 10,


Finally, Appendix 3 of the Sixteenth Revised KPP Service Agreement contains

non-conforming language. Specifically, the Parties include 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 number/name, delivery point name, and a footnote indicating that the voltage of the delivery point is the voltage where the meter is physically located, is necessary and benefits the Parties because it provides additional detail regarding the delivery points. The Commission previously has accepted agreements submitted by SPP with similar language.29

2014); Sw. Power Pool, Inc., Letter Order, Docket No. ER14-438-000 (Jan. 14, 2014).

29 See Sw. Power Pool, Inc., Letter Order, Docket No. ER14-1171-000 (Mar. 10, 2014); Sw. Power Pool, Inc., Letter Order, Docket No. ER14-438-000 (Jan. 14, 2014); Sw. Power Pool, Inc., Letter Order, Docket No. ER14-173-000 (Dec. 16, 2013); Sw. Power Pool, Inc., Letter Order, Docket No. ER13-2439-000 (Nov. 18, 2013); Sw. Power Pool, Inc., Letter Order, Docket No. ER13-2190-000 (Oct. 16, 2013); Sw. Power Pool, Inc., Letter Order, Docket No. ER13-2056-000 (Sept. 20, 2013); Sw. Power Pool, Inc., Letter Order, Docket No. ER13-2041-000 (Sept. 5, 2013); Sw. Power Pool, Inc., Sw. Power Pool, Inc., Letter Order, Docket No. ER13-1832-000 (Aug. 20, 2013); Sw. Power Pool, Inc., Letter Order, ER13-1809-000 (Aug. 20, 2013); Letter Order, Docket No. ER13-1571-000 (Aug. 14, 2013); Sw. Power Pool, Inc., Letter Order, Docket No. ER13-1350-000 (June 19, 2013); Sw. Power Pool, Inc., Letter Order, Docket No. ER13-1012-000 (Apr. 23, 2013); Sw. Power Pool, Inc., Letter Order, Docket No. ER13-498-000 (Jan. 28, 2013); Sw. Power Pool, Inc., Letter Order, Docket No. ER12-2702-000, -001 (Jan. 9, 2013); Sw. Power Pool, Inc., Letter Order, Docket No. ER12-2157-000 (Aug. 23, 2012); Sw. Power Pool, Inc., Letter Order, Docket No. ER12-1677-000 (June 21, 2012); Sw. Power Pool, Inc., Letter Order, Docket Nos. ER11-4180-001, et al. (Nov. 2, 2011).

The Honorable Kimberly D. Bose March 31, 2014 Page 8 III. Effective Date and Waiver SPP requests an effective date of March 1, 2014, for the Sixteenth Revised KPP 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 Sixteenth Revised KPP Agreements are being filed within 30 days of the commencement of service.30 IV. Additional Information

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

In addition to this transmittal letter, SPP is submitting the following:

(a) A clean copy of the Sixteenth Revised KPP Agreements; and

(b) A redline copy of the Sixteenth Revised KPP Agreements.

2. Effective Date:

As discussed herein, SPP respectfully requests that the Commission accept the Sixteenth Revised KPP Agreements with an effective date of March 1, 2014.

3. Service:

SPP is serving a copy of this filing on the representatives of the Parties listed in the Sixteenth Revised KPP Agreements.

4. Basis of Rate:

All charges will be determined in accordance with the SPP Tariff and the Sixteenth Revised KPP Agreements.

30 See Prior Notice and Filing Requirements Under Part II of the Federal Power

Act, 64 FERC ¶ 61,139, at 61,983-84, order on reh'g, 65 FERC ¶ 61,081 (1993) (the Commission will grant waiver of the 60-day prior notice requirement “if service agreements are filed within 30 days after service commences.”); see also 18 C.F.R. § 35.3(a)(2).


B. Communications:

Any correspondence regarding this matter should be directed to:

Tessie Kentner Attorney Southwest Power Pool, Inc. 201 Worthen Drive Little Rock, AR 72223 Telephone: (501) 688-1782 [email protected]

Nicole Wagner Manager - Regulatory Policy Southwest Power Pool, Inc. 201 Worthen Drive Little Rock, AR 72223 Telephone: (501) 688-1642 [email protected]

V. Conclusion For all the foregoing reasons, SPP respectfully requests that the Commission accept the Sixteenth Revised KPP Agreements with an effective date of March 1, 2014. Respectfully submitted, /s/ Tessie Kentner

Tessie Kentner

Attorney for Southwest Power Pool, Inc.

mailto:[email protected]

mailto:[email protected]

1 75401876, 75402065, 75402069

Southwest Power Pool, Inc. Sixteenth Revised Service No. 2198

SERVICE AGREEMENT FOR NETWORK INTEGRATION TRANSMISSION SERVICE BETWEEN SOUTHWEST POWER POOL, INC. AND KANSAS POWER

POOL

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

entered into this 1st day of March, 2014, by and between Kansas Power Pool ("Network

Customer" or “KPP”), and Southwest Power Pool, Inc. ("Transmission Provider" or “SPP”). 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:

2 75401876, 75402065, 75402069

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 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 1, 2026. 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.

3 75401876, 75402065, 75402069

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.

Southwest Power Pool, Inc. (Transmission Provider):

Tessie Kentner

Attorney

201 Worthen Drive

Little Rock, AR 72223-4936

Email Address: [email protected]

Phone Number: 501-688-1782

Network Customer:

CEO/General Manager

Kansas Power Pool

250 W. Douglas, Suite 110

Wichita, KS 67202


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. However, the assignee shall be bound by the terms and conditions of this

Service Agreement.

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,

4 75401876, 75402065, 75402069

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

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/ Lanny Nickell /s/ Larry W. Holloway Signature

Signature

Lanny Nickell Larry W. Holloway Printed Name

Printed Name

VP, Engineering KPP Operations Manager Title

Title

3/31/14 3/7/2014 Date Date

5 75401876, 75402065, 75402069

ATTACHMENT 1 TO THE NETWORK INTEGRATION TRANSMISSION SERVICE AGREEMENT

BETWEEN SOUTHWEST POWER POOL AND KANSAS POWER POOL 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 the Network

Customer load connected to Mid-Kansas Electric Company, LLC’s (“Mid-Kansas”)

Zone, Midwest Energy, Inc.’s (“Midwest Energy”) Zone, and Westar Energy, Inc.’s

(“Westar Energy”) Zone(s), 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 Zone(s) and Intervening Systems Providing Transmission Service

The Zone(s) area are Sunflower Electric Power Corporation and Westar Energy. The

intervening systems providing transmission service are none.

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4.0 Electrical Location of Initial Sources

See Appendix 1.

5.0 Electrical Location of the Ultimate Loads

The loads of Kansas Power Pool, identified in Section 2.0 hereof as the Network Load

are electrically located within the Mid-Kansas, Midwest Energy , and the Westar Energy

Zone(s).

6.0 Delivery Points

The delivery points are the interconnection points of Kansas Power Pool, 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.

Network loads connected to the Westar Energy Zone are based on the charges for the

Westar Energy pricing zone, network loads connected to the Midwest Energy Zone are

based on the charges for the Midwest Energy pricing zone, and network loads connected

to the Mid-Kansas Electric Company Zone are based on the charges for the Mid-Kansas

Electric Company pricing zone.

8.2 System Impact and/or Facility Study Charge

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

of the ten-year forecast data provided. Future charges, if required, shall be in accordance

with Section 32 of the Tariff.

8.3 Direct Assignment Facilities Charge

System reinforcements are required to address the City of Kingman’s 6 MW path limit as

part of Attachment D to allow for SPP Network Integration Transmission Service to

Kingman’s forecasted load. Future charges, if required shall be in accordance with Mid-

Kansas Open Access Transmission Tariff and/or the Mid-Kansas Tariff. The following

System reinforcements have been identified in SPP-2009-AGP2 to address the City of

Kingman's 6 MW path limit. Alternatives to these system reinforcements would be

subject to mutual agreement between the Network Customer and Mid-Kansas and SPP.

Upgrade Name Upgrade Description Transmission Owner

Date Required in Service

Estimated Engineering and

Construction Pratt 115/34.5kV Transformer

Install new 115/34.5 kV TXF rated at 25/30/37.5 MVA at Pratt 115 kV Substation to address 34.5kV distribution limitations to address 34.5kV distribution limitations

SUNC

8/1/2010

$2,000,000

Cunningham - Pratt 34.5kV CKT 1

Rebuild and reconductor 15 miles of 34.5-kV Line with T2 Raven (T2 4/0 ACSR) from Pratt to the Cunningham metering station to address 34.5kV distribution limitations

SUNC

8/1/2010

$4,164,600

Cunningham Voltage Regulator

Replace existing voltage regulator with a 18 MVA rated voltage regulator

SUNC 8/1/2010

$250,000

8 75401876, 75402065, 75402069

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.

For Network Customer’s load in Mid-Kansas’ Zone:

The Network Customer has entered into a Service Agreement for Ancillary

Services with Mid-Kansas that was executed contemporaneously with this

Agreement, which is included as Appendix 5.

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 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.

9 75401876, 75402065, 75402069

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 be responsible for losses in accordance with Attachment M

of the Tariff.

8.6 Real Power Losses - Distribution

For Delivery Points on Westar Energy Network System: 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.

For transmission requests and network resources (denoted in the table below), provide

generation redispatch power in the specified amounts necessary to alleviate loading on

the facilities listed in Attachment A prior to completion of Service Upgrades, Reliability

and Construction Pending upgrades. The Network Customer agrees to provide redispatch

pairs listed in Table 6 of the final posting of the respective Aggregate Study (denoted in

the table below), and the Transmission Provider agrees that such redispatch will satisfy

the redispatch obligation.

10 75401876, 75402065, 75402069

Transmission Request Subject of Request Aggregate Study

1222644 and 1222955 replaced

by 1610003 and 1610004

combined into 75401876 and

75402065

Initial pooling of KPP Pool load

and resources in Midwest Energy

and Westar Energy Zones

2007-AG1

1223078 replaced by 1610083

replaced by 74243470 combined

into 75402069


and resources in Mid-Kansas

Electric Company Zone

2007-AG1

1222932 Replaced by 1610008

and 1610042 combined into

75349545,75349552,75406648,

and 75406653

Addition of 45 MW Westar

Energy Coal Purchase - Jeffrey

Energy Center 1, 2, 3 to network

load in Midwest Energy and

Westar Energy Zones

2007-AG1

1223078 Replaced by 73235882


75406660

Addition of 5 MW Westar Energy

Coal Purchase - Jeffrey Energy

Center 1, 2, 3 to network load in

Mid-Kansas Electric Company

Zone

2007-AG1

1285893 replaced by 73315260

combined into 75401876

Addition of City of Scranton and

St. Mary’s to KPP pool

2007-AG2

11 75401876, 75402065, 75402069


1607046 combined into

75401876

Addition of City of Marion to

KPP Pool in Westar Energy Zone

2009-AGP2

73447072, 73450023, and

73450028 replaced by

75402446,75402448, and

75402460

Addition of Greensburg Wind

Network Resource

2009-AGP2

74236802,74236811, and


75402762,75402778, and

75402810

Addition of Kansas City Power

and Light Purchase Network

Resource

2009-AGP2

74234218 Addition of Dogwood Resource 2010-AGP1

In the absence of implementation of interim redispatch as requested by the Transmission

Provider for Network Customer transactions resulting in overloads on limiting facilities,

the Transmission Provider shall curtail the customers schedule.

Such redispatch obligations shall be arranged in accordance with Attachment K and shall

occur in advance of curtailment of other firm reservations impacting these constraints.

Network Customer shall bear the cost of such redispatch.

This interim redispatch shall remain in place until the Network Upgrades are completed

and the ATC required for this service is available.

Additionally, maximum firm import capability limitations will be enforced for Network

Customer load both before and after completion of required network upgrades as detailed

in Attachment B and Attachment C respectively subject to later re-studies, facility

improvements, and/or modifications to Network Customer's network loads and/or

resources. These limitations are applicable during peak loading conditions as identified

by Midwest Energy and Westar Energy.

12 75401876, 75402065, 75402069

8.9 Wholesale Distribution Service Charge

For Network Customer’s load in Westar’s Zone: Wholesale Distribution Service Charge

cost support and monthly charge is detailed in Appendix 4.

For Network Customer’s Load in Mid-Kansas’ Zone: Wholesale Distribution Service

Charges, if any, are specified in agreements approved by the Kansas Corporation

Commission (“KCC”) in KCC Docket No. 11-GIME-597-GIE and on file with the KCC,

as they may be amended by order of the KCC from time to time. The monthly rate shall

be as specified in the Mid-Kansas Open Access Transmission Tariff approved by the

KCC in KCC Docket No. 12-MKEE-650-TAR and on file with the KCC, as it may be

amended by order of the KCC from time to time.

8.10 Network Upgrade Charges

A. The Network Customer has confirmed the following Network Resources requiring

Network Upgrades:

1. Initial pooling of KPP Pool load and resources in Midwest Energy and

Westar Energy Zones as more specifically identified in the study of

transmission service request 1222644 and 1222955 replaced by 1610003

and 1610004 combined into 75401876 and 75402065. Contingent upon

the completion of required upgrades as specified below, designation of

these resources shall be effective on June 1, 2009 and shall remain

effective through June 1, 2026.

The requested service depends on and is contingent on completion of the

following aggregate study SPP-2007-AG1 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.

13 75401876, 75402065, 75402069

Service Upgrades


Date Required in

Service ALLEN - LEHIGH TAP

69KV CKT 1 Tear down / Rebuild 5.69-mile line;

954-KCM ACSR WERE 6/1/2009

ALLEN 69KV Capacitor Allen 69 kV 15 MVAR Capacitor Addition

WERE 6/1/2009

ALTOONA EAST 69KV Capacitor

ALTOONA EAST 69KV 6 MVAR Capacitor Addition

WERE 6/1/2009

ATHENS 69KV Capacitor Athens 69 kV 15 MVAR Capacitor Addition

WERE 6/1/2009

Athens to Owl Creek 69 kV

Rebuild 2.93 miles with 954 kcmil ACSR (138kV/69kV Operation)

WERE 6/1/2009

BARTLESVILLE SOUTHEAST - NORTH BARTLESVILLE 138KV

CKT 1

Rebuild 8.37 miles of 795 ACSR with 1590 ACSR & reset relays @

BSE

AEPW 6/1/2009

BURLINGTON JUNCTION - COFFEY

COUNTY NO. 3 WESTPHALIA 69KV

CKT 1


WERE 6/1/2009

BURLINGTON JUNCTION - WOLF CREEK 69KV CKT 1


WERE 6/1/2009

CHANUTE TAP – TIOGA 69KV CKT 1

Replace Jumpers WERE 6/1/2010

COFFEY COUNTY NO. 3 WESTPHALIA - GREEN

69KV CKT 1


WERE 6/1/2009

Green to Vernon 69 kV Rebuild 7.19 miles with 954 kcmil ACSR (138kV/69kV Operation)

WERE 6/1/2009

COFFEYVILLE TAP – DEARING 138 KV CKT 1

WERE #2

Replace Disconnect Switches, Wavetrap, Breaker, Jumpers

WERE 6/1/2010

COFEYVILLE TAP NORTH BARTLESVILLE

138KV CKT 1

Rebuild 13.11 miles of 795 ACSR with 1590 ACSR

AEPW 6/1/2009

LEHIGH TAP - OWL CREEK 69KV CKT 1

Tear down / Rebuild 8.47-mile 69 kV line with 954-KCM ACSR

(138kV/69kV Operation)

WERE 6/1/2009

LEHIGH TAP - UNITED NO. 9 CONGER 69KV

CKT 1

Tear down / Rebuild 0.91-mile 69 kV line; 954-KCM ACSR (138kV/69kV Operation)

WERE 6/1/2009

14 75401876, 75402065, 75402069


Date Required in

Service NEOSHO - NORTHEAST PARSONS 138KV CKT 1

Replace bus and Jumpers at NE Parsons 138 KV substation

WERE 6/1/2011

NORTH ELLINWOOD 69KV SUBSTATION

Tap the College – South Ellinwood 69kV line and install a new North

Ellinwood substation

MIDW 6/1/2009

NORTH ELLINWOOD- CITY OF NORTH

ELLINWOOD 34.5 CKT 1

Build approximately 4.5 miles of new 34.5 kV line with 477 ACSR

from North Ellinwood to interconnect near the City of

Ellinwood

MIDW 6/1/2009

TIMBER JCT CAP BANK Install 30 MVAR Cap bank at new Timber Junction 138kV

WERE 6/1/2009

TIOGA 69KV Capacitor Tioga 69 kV 15 MVAR Capacitor Addition

WERE 6/1/2009

Vernon to Athens 69 kV Rebuild 5.17 miles with 954 KCM-ACSR (138kV/69kV Operation)

WERE 6/1/2009


following aggregate study SPP-2007-AG1 Reliability and Construction Pending

Upgrades resulting from the SPP Expansion Plan. These upgrades costs are not

assignable to the Network Customer.


Date Required in

Service Sub - Franklin 161 kV Tap Litchfield - Marmaton 161 kV

line at new Franklin substation WERE 6/1/2013

XFR - Franklin 161/69 kV Transformer Ckt 1

New 161/69 kV transformer at Franklin

WERE 6/1/2013

Line - Franklin - Mulberry 69 kV Ckt 1

Build 6 miles of double circuit 69 kV line from new Franklin

substation to Mulberry - Sheffield 69 kV line, tapping line and connecting

to Mulberry.

WERE 6/1/2013

Line - Franklin - Sheffield 69 kV Ckt 1



to Sheffield.

WERE 6/1/2013

15 75401876, 75402065, 75402069

In addition to all other applicable charges, Network Customer shall pay remaining

monthly revenue requirements of $347.15 from June 1, 2009 – May 1, 2026 for a total of

$70,471.45 for remaining revenue requirements for upgrades by Empire District Electric

Company for the Oronogo Junction- Riverton 161kV upgrade to be completed on or

before June 1, 2011.

This upgrade was required to provide firm Point-To-Point Service to the City of Erie,

Kansas under transmission service request 974637 (later converted to Network Integrated

Transmission Service under transmission service request 1173206).


monthly revenue requirements of $1330.47 from June 1, 2009 – May 1, 2010 for a total

of $14,635.17 for remaining revenue requirements. The revenue requirement for the

American Electric Power transmission facility upgrade is $656.33/month for the Explorer

Glenpool-Riverside Station 138kV upgrade. The revenue requirements for Oklahoma Gas

and Electric’s transmission facility upgrades are $222.44/month for the Beeline-Explorer

Glenpool 138kV upgrade, and $451.70/month for the Explorer Glenpool-Riverside

Station 138kV upgrade.

These upgrades were required to provide firm Point-To-Point Service to the City of

Ellinwood, Kansas under transmission service request 610383. This service is now

reflected as network service request 1610074 for the Ellinwood portion of the original

service.

2. Additional Westar Energy Purchase, 45MW, as more specifically

identified in transmission service request 1222932 replaced by 1610008

and 1610042 combined into 75349545, 75349552, 75406648, and

75406653. Contingent upon the completion of required upgrades as

specified below, designation of this resource shall be effective on June 1,

2009 and shall remain effective through April 1, 2022.





16 75401876, 75402065, 75402069

Service Upgrades



ALLEN - LEHIGH TAP 69KV CKT 1

Tear down / Rebuild 5.69-mile line; 954-KCM ACSR WERE 6/1/2009

ALLEN 69KV Capacitor Allen 69 kV 15 MVAR Capacitor Addition WERE 6/1/2009


ALTOONA EAST 69KV 6 MVAR Capacitor Addition WERE 6/1/2009

ATHENS 69KV Capacitor Athens 69 kV 15 MVAR Capacitor Addition WERE 6/1/2009


Rebuild 2.93 miles with 954 kcmil ACSR (138kV/69kV Operation) WERE 6/1/2009

BARTLESVILLE SOUTHEAST – NORTH BARTLESVILLE 138 KV

CKT 1

Rebuild 8.37 miles of 795 ACSR with 1590 ACSR & reset relays @BSE AEPW 6/1/2009



CKT 1




CHANUTE TAP – TIOGA 69KV CKT 1 Replace Jumpers WERE 6/1/2010

COFFEY COUNTY NO. 3 WESTPHALIA -

GREEN 69KV CKT 1


COFFEYVILLE TAP – DEARING 138 KV CKT

1 WERE #2

Replace Disconnect Switches, Wavetrap, Breaker, Jumpers WERE 6/1/2010

COFFEYVILLE TAP – NORTH

BARTLESVILLE 138 KV CKT 1

Rebuild 13.11 miles of 795 ACSR with 1590 ACSR AEPW 6/1/2009

Green to Vernon 69 kV Rebuild 7.19 miles with 954 kcmil ACSR (138kV/69kV Operation) WERE 6/1/2009


Tear down / Rebuild 8.47-mile 69 kV line with 954-KCM ACSR (138kV/69kV Operation)

WERE 6/1/2009

17 75401876, 75402065, 75402069




CKT 1

Tear down / Rebuild 0.91-mile 69 kV line; 954-KCM ACSR (138kV/69kV

Operation) WERE 6/1/2009

NEOSHO NORTHEAST PARSONS 138 KV CKT

1

Replace bus and Jumpers at NE Parsons 138 kV substation WERE 6/1/2011


Tap the College – South Ellinwood 69 kV line and install a new North

Ellinwood Substation MIDW 6/1/2009

NORTH ELLINWOOD 69/34.5KV

TRANSFORMER CKT 1

Install a new 69/34.5kV transformer at North Ellinwood MIDW 6/1/2009

NORTH ELLINWOOD – CITY OF NORTH

ELLINWOOD 34.5 KV CKT 1

Build approximately 4.5 miles of new 34.5 kV line with 477 ACSR from

North Ellinwood to interconnect near the City of Ellinwood

MIDW 6/1/2009

TIMBER JCT CAP BANK

Install 30 MVAR Cap bank at new Timber Junction 138kV WERE 6/1/2009

TIOGA 69KV Capacitor Tioga 69 kV 15 MVAR Capacitor Addition WERE 6/1/2009

Vernon to Athens 69 kV Rebuild 5.17 miles with 954 KCM ACSR (138kV/69kV Operation) WERE 6/1/2009







Sub - Franklin 161 kV Tap Litchfield - Marmaton 161 kV line at new Franklin substation WERE 6/1/2013


New 161/69 kV transformer at Franklin WERE 6/1/2013



substation to Mulberry - Sheffield 69 kV line, tapping line and

connecting to Mulberry.

WERE 6/1/2013

18 75401876, 75402065, 75402069






connecting to Sheffield.

WERE 6/1/2013

BONANZA - NORTH HUNTINGTON 69KV

Convert from 69KV to 161KV AEPW 6/1/2019

3. Additional GRDA resource, 4MW, as more specifically identified in

transmission request 1457536 replaced by 74107443 combined into

75402384, 75402413, and 75402421. Contingent upon the completion of

required upgrades as specified below, designation of these Network

Resources shall be effective on June 1, 2010 and remain effective through

June 1, 2026.


following aggregate study SPP-2008-AGP1 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.

Service Upgrades



ARCADIA - REDBUD 345KV CKT 3

Add eight mile 3rd 345 kV line from Redbud to Arcadia

OKGE 6/1/2019

ARCADIA (ARCADIA2) 345/138/13.8KV

TRANSFORMER CKT 1 Accelerate

Add 3rd 345/138KV Auto and convert the 345kV and 138kV to a breaker and a half configuration.

OKGE 6/1/2010

BRYANT - MEMORIAL 138KV CKT 1 Change out wavetrap to 2000A OKGE 6/1/2019

4. Additional Westar Energy Purchase, 5MW, as more specifically identified

in transmission service request 1223078 Replaced by 73235882 combined

into 75349562 and 75406660. Contingent upon the completion of

19 75401876, 75402065, 75402069

required upgrades as specified below, designation of these resources shall

be effective on January 1, 2010 and shall remain effective through April 1,

2022.


following aggregate study SPP-2007-AG1 allocated Network Upgrades.



the Tariff.

Service Upgrades



Craig 161kV 20MVar Cap Bank Upgrade

Additional 20 MVAR to make a total of 70 MVAR at Craig 542978 KACP 6/1/2011

EVANS ENERGY CENTER SOUTH -

LAKERIDGE 138KV CKT 1 Displacement



following aggregate study SPP-2007-AG1 Reliability and Construction

Pending Upgrades resulting from the SPP Expansion Plan. These

upgrades costs are not assignable to the Network Customer.



KELLY - SOUTH SENECA 115KV CKT 1

Rebuild 10.28 mile line with 1192.5 kcmil ACSR and replace CTs. WERE 6/1/2009

5. Initial pooling of KPP Pool load and resources in Mid-Kansas Electric

Company Zone as more specifically identified in the study of transmission

service request 1223078 replaced by 1610083 replaced by 74243470

combined into 75402069. Contingent upon the completion of required

upgrades as specified below, designation of these resources shall be

20 75401876, 75402065, 75402069

effective on March 1, 2008 and shall remain effective through June 1,

2026.









6. Addition of City of Greensburg-3MW, as more specifically identified in

the study of transmission service request 1457802 replaced by 74116547



effective on June 1, 2010 and shall remain effective through June 1, 2026.


following aggregate study SPP-2008-AGP1 Transmission Owner

Reliability and Construction Pending Upgrades resulting from the SPP

Expansion Plan. These upgrades costs are not assignable to the Network

Customer.



KNOLL - AXTELL 345KV CKT 1 MIDW

Build a new 345kV line from Knoll - Axtell MIDW 6/1/2010

KNOLL 345/230 KV TRANSFORMER

Add new 345/230 KV TRANSFORMER MIDW 6/1/2010

KNOLL - AXTELL 345KV CKT 1 NPPD

Build a new 345kV line from Knoll - Axtell

NPPD 6/1/2010

SPEARVILLE - KNOLL 345KV CKT 1 MIDW

Build a new 345kV line from Spearville - Knoll MIDW 6/1/2010

SPEARVILLE - KNOLL 345KV CKT 1 SUNC

Build a new 345kV line from Spearville - Knoll SUNC 6/1/2010

21 75401876, 75402065, 75402069

7. Addition of City of Marion, 6MW, as more specifically identified in

transmission request 1607046 combined into 75401876. Contingent upon


these resources shall be effective on April 1, 2011 and shall remain



following aggregate study SPP-2009-AGP2 Reliability and Construction



Priority Project Upgrades


Date Required in

Service Line - Comanche County - Medicine Lodge 345 kV

dbl ckt

Build a new 55 mile double circuit 345 kV line

MKEC 4/1/2011

Line - Hitchland - Woodward 345 kV dbl ckt

OKGE

Build a new 60.5 mile double circuit 345 kV line

OKGE 4/1/2011


SPS


SPS 4/1/2011

Line - Medicine Lodge - Wichita 345 kV dbl ckt

MKEC

Build a new 35 mile double circuit 345 kV line with at least 3000 A capacity from the new Medicine

Lodge 345 kV substation to the WR interception from the Wichita

substation.

MKEC 4/1/2011


WERE


MKEC 4/1/2011

Line - Spearville - Comanche County 345 kV

dbl ckt MKEC


MKEC 4/1/2011


dbl ckt SUNC

Build a new 27.5 mile double circuit 345 kV line with at least 3000 A

capacity from the Spearville substation to the MKEC interception

point from the new Comanche County substation.

SUNC 4/1/2011

22 75401876, 75402065, 75402069

8. Addition of Greensburg Wind resource, 12.5MW, as more specifically

identified in transmission request 73447072, 73450023, and 73450028

replaced by 75402446, 75402448, and 75402460. Contingent upon the

completion of required upgrades as specified below, designation of these

resources shall be effective on April 1, 2011 and shall remain effective

through April 1, 2021.


following aggregate study SPP-2009-AGP2 allocated Network Upgrades.



the Tariff.

Service Upgrades



CRESWELL - OAK 69KV CKT 1

Replace jumpers and bus, and reset CTs and relaying. Rebuild

substations. WERE 6/1/2011

Line - Medicine Lodge - Woodward 345 kV dbl Ckt

MKEC

Build a new 28.6 mile dbl ckt 345 kV line with at least 3000 A capacity

from the Medicine Lodge sub to the KS/OK state border towards the

Woodward District EHV sub. Install the necessary breakers and terminal

equipment at the Medicine Lodge sub.

MKEC 4/1/2011


OKGE

Build a new 79 mile dbl ckt 345 kV line with at least 3000 A capacity

from the Woodward District EHV sub to the KS/OK state border towards the

Medicine Lodge sub. Upgrade the Woodward District EHV sub with the

necessary breakers and terminal equipment.

OKGE 4/1/2011

XFR - Medicine Lodge 345/138 kV

Install a 400 MVA 345/138 kV transformer at the new 345 kV

Medicine Lodge substation.

WERE 4/1/2011

23 75401876, 75402065, 75402069


following aggregate study SPP-2009-AGP2 Reliability . These upgrades

costs are not assignable to the Network Customer.

Planned Projects Upgrade


Date Required in

Service BELL - PECK 69KV CKT 1

Tear down / Rebuild 8.23 mile Bell-Peck 69 kV line with 1192 ACSR and replace

CT

WERE 6/1/2011

TIMBER JUNCTION -

UDALL 69KV CKT 1

Tear down / Rebuild Udall-Timber Jct 69 kV using 954 kcmil ACSR

WERE 6/1/2011

CLAY CENTER SWITCHING

STATION - TC RILEY 115KV

CKT 1

Build 6.7 mile 115 kV line with Single 1192.5 kcmil ACSR (Bunting) WERE 10/1/2012

TC RILEY 115KV Install a 2000 Amp bus system, GOAB switches, metering and communication

systems. WERE 10/1/2012

9. Addition of Municipal Energy Agency of Nebraska resource, 1MW, as

more specifically identified in transmission request 73447046, 73450014,

and 73450018 combined into 75402711, 75402731, and 75402737,

Contingent upon the completion of required upgrades as specified below,

designation of these resources shall be effective on April 1, 2011 and shall

remain effective through April 1, 2021.





the Tariff.

Service Upgrades

24 75401876, 75402065, 75402069







following aggregate study SPP-2009-AGP2 Reliability and Upgrades.

These upgrades costs are not assignable to the Network Customer.

Reliability Project Upgrade



OGALLALA 230/115KV

TRANSFORMER CKT 1

Replace 187MVA Ogallala transformer with 336MVA

Ogallala transformer

NPPD

6/1/2017

Priority Projects Upgrades



Line - Comanche County - Medicine

Lodge 345 kV dbl ckt


MKEC 4/1/2011

Line - Hitchland - Woodward 345 kV dbl

ckt OKGE


OKGE 4/1/2011


ckt SPS


SPS 4/1/2011

Line - Medicine Lodge - Wichita 345 kV dbl

ckt MKEC

Build a new 35 mile double circuit 345 kV line with at least 3000 A capacity from the new Medicine Lodge 345 kV substation to the

WR interception from the Wichita substation.

MKEC 4/1/2011


ckt WERE


MKEC 4/1/2011

25 75401876, 75402065, 75402069



Line - Spearville - Comanche County 345

kV dbl ckt MKEC


MKEC 4/1/2011


kV dbl ckt SUNC

Build a new 27.5 mile double circuit 345 kV line with at least

3000 A capacity from the Spearville substation to the

MKEC interception point from the new Comanche County

substation.

SUNC 4/1/2011

Line - Medicine Lodge - Woodward 345 kV

dbl Ckt MKEC

Build a new 28.6 mile dbl ckt 345 kV line with at least 3000 A

capacity from the Medicine Lodge sub to the KS/OK state border

towards the Woodward District EHV sub. Install the necessary

breakers and terminal equipment at the Medicine Lodge sub.

MKEC 4/1/2011


dbl Ckt OKGE

Build a new 79 mile dbl ckt 345 kV line with at least 3000 A capacity from the Woodward

District EHV sub to the KS/OK state border towards the Medicine

Lodge sub. Upgrade the Woodward District EHV sub with

the necessary breakers and terminal equipment.

OKGE 4/1/2011




WERE 4/1/2011

Planned Projects Upgrades



BELL - PECK 69KV CKT 1

Tear down / Rebuild 8.23 mile Bell-Peck 69 kV line with 1192

ACSR and replace CT

WERE 6/1/2011

26 75401876, 75402065, 75402069



TIMBER JUNCTION - UDALL 69KV CKT

1

Tear down / Rebuild Udall-Timber Jct 69 kV using 954 kcmil

ACSR

WERE 6/1/2011

TC RILEY 115KV Install a 2000 Amp bus system, GOAB switches, metering and

communication systems. WERE 10/1/2012

10. Pooling of KPP Pool load and resources in Midwest Energy, Mid-Kansas

Electric Company, and Westar Energy Zones as more specifically

identified in the study of transmission service request 73446841 replaced

by 75401876,75402065, and 75402069. Contingent upon the completion

of required upgrades as specified below, designation of these resources

shall be effective on April 1, 2011 and shall remain effective through June

1, 2026.





the Tariff.

Service Upgrades








27 75401876, 75402065, 75402069





Date Required in

Service



ACSR and replace CT

WERE 6/1/2011


1


ACSR WERE 6/1/2011



11. Additional Kansas City Power and Light Purchase, 45MW, as more

specifically identified in transmission requests 74236802, 74236811, and

74236821 replaced by 75402762, 75402778, and 75402810. Contingent

upon the completion of required upgrades as specified below, designation

of these resources shall be effective on April 1, 2011 and shall remain

effective through April 1, 2016.





the Tariff.

Service Upgrades






28 75401876, 75402065, 75402069


following aggregate study SPP-2009-AGP2 Expansion Plan Upgrade and

Priority Projects. These upgrades costs are not assignable to the Network

Customer.

Expansion Plan Upgrades


Date Required in

Service

Line - Iatan - Nashua 345 kV

Tap Nashua 345kV bus in Hawthorn-St. Joseph 345kV line, add Iatan-Nashua

345kV line and Nashua 345/161kv transformer

KCPL

6/1/2012



Date Required in

Service Line - Comanche

County - Medicine Lodge 345 kV dbl ckt


MKEC 4/1/2011


ckt OKGE


OKGE 4/1/2011


ckt SPS


SPS 4/1/2011


ckt MKEC

Build a new 35 mile double circuit 345 kV line with at least 3000 A capacity

from the new Medicine Lodge 345 kV substation to the WR interception from

the Wichita substation.

MKEC 4/1/2011


ckt WERE


MKEC 4/1/2011


kV dbl ckt MKEC


MKEC 4/1/2011

29 75401876, 75402065, 75402069


Date Required in

Service


kV dbl ckt SUNC

Build a new 27.5 mile double circuit 345 kV line with at least 3000 A capacity from the Spearville substation to the

MKEC interception point from the new Comanche County substation.

SUNC 4/1/2011


dbl Ckt MKEC

Build a new 28.6 mile dbl ckt 345 kV line with at least 3000 A capacity from the Medicine Lodge sub to the KS/OK

state border towards the Woodward District EHV sub. Install the necessary breakers and terminal equipment at the

Medicine Lodge sub.

MKEC 4/1/2011


dbl Ckt OKGE

Build a new 79 mile dbl ckt 345 kV line with at least 3000 A capacity from the

Woodward District EHV sub to the KS/OK state border towards the



OKGE 4/1/2011


Install a 400 MVA 345/138 kV transformer at the new 345 kV Medicine

Lodge substation.

WERE 4/1/2011



Date Required in

Service BELL - PECK 69KV

CKT 1


CT

WERE 6/1/2011


1


WERE 6/1/2011

30 75401876, 75402065, 75402069


Date Required in

Service



12. Dogwood Purchase, 40MW, as more specifically identified in

transmission request 74234218 Contingent upon the completion of

required upgrades as specified below, designation of this resource shall be






the Tariff.

Service Upgrades



EL PASO - FARBER 138KV CKT 1

Tear down / Rebuild 3.1 miles with dual 477 ACSR WERE 6/1/2014


following aggregate study SPP-2010-AGP1 Construction Pending and

Planned Project Upgrade. These upgrades costs are not assignable to the

Network Customer.

Construction Pending



31 75401876, 75402065, 75402069




Planned Projects





ACSR and replace CT

WERE 6/1/2014

BELL - SUMNER COUNTY NO. 3

MILLER 69KV CKT 1

Tear down / Rebuild 7.3-miles with 954 ACSR

WERE 6/1/2014

CITY OF WELLINGTON -

SUMNER COUNTY NO. 3 MILLER 69KV CKT 1


WERE 6/1/2014


SUMNER COUNTY NO. 4 ROME 69KV

CKT 1


WERE 6/1/2014

CRESWELL - SUMNER COUNTY NO. 4 ROME 69KV

CKT 1


WERE 6/1/2014

TIMBER JUNCTION -

UDALL 69KV CKT 1


WERE 6/1/2014

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.

32 75401876, 75402065, 75402069

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

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

33 75401876, 75402065, 75402069

Appendix 1

Network Resources of

Kansas Power Pool

34 75401876, 75402065, 75402069

APPENDIX 1: Kansas Power Pool NETWORK RESOURCES

Maximum Net

Dependable

Capacity Network

Resource Summer Winter Location Comments

Attica Gen ATI2 0.6 0.6 Harper County, KS


Attica Gen ATI4 0.7 0.7 Harper County, KS Kingman Gen

KING6 3.5 3.5 Kingman County,

KS Kingman Gen


KS Kingman Gen


KS AugN1 3.8 3.8 Butler Co., KS AugN2 3.8 3.8 Butler Co., KS AugN3 5.7 5.7 Butler Co., KS AugN4 6.7 6.7 Butler Co., KS Bur1A 2.3 2.3 Coffey Co, KS Bur4A 3 3 Coffey Co, KS Bur6 4.8 4.8 Coffey Co, KS

ClayD1 2.8 2.8 Clay Co., KS Effective 1/1/2012

ClayD2 3.5 3.5 Clay Co., KS ClayD3 4.5 4.5 Clay Co., KS ClayD4 1.9 1.9 Clay Co., KS ClayD6 6.7 6.7 Clay Co., KS ClayST1 5 5 Clay Co., KS Dogwood 40 40 Cass, MO Effective

6/1/2014 Elw1 1.7 1.7 Barton Co., KS Elw5 2.9 2.9 Barton Co., KS Effective

1/1/2014 MinD6 3 3 Ottawa Co., KS Ox1 1.5 1.5 Sumner Co., KS Ox2 1.5 1.5 Sumner Co., KS

WellGT 21.5 21.5 Nemaha Co., KS WellST 20 20 Sumner Co., KS WellD1 2 2 Sumner Co., KS WellD2 2 2 Sumner Co., KS WinfGT 10.3 10.3 Cowley Co., KS Effective

1/1/2013 WinfST 26.7 26.7 Cowley Co., KS WinfD1 2.4 2.4 Cowley Co., KS WinfD2 2.4 2.4 Cowley Co., KS

35 75401876, 75402065, 75402069

Grand River Dam Authority Purchase

15.3 15.3 Mayes Co., OK

Nearman Power Sales Contract

12.5 12.5 Wyanodotte Co., KS

Greensburg Wind 0 0 Kiowa Co., KS Firm Transmission for

12.5MW Displacement

Agreement between

Municipal Energy Agency of

Nebraska and Western Area

Power Administration comprising of

generation from Ansley for 1.5MW,

Benkelman 0.8MW, Broken

Bow 7.3MW, Burwell 3.3MW, Callaway 1MW, Crete 6.1MW, Curtis 3.1MW, Oxford 3.7MW, Pender 4.4MW,

Red Cloud 4.4MW, Sargent 2.3MW, Stuart 1.8MW, West

Point 4MW, and Fairbury 16MW

2.8 2.8 Term of

Service:4/1/2011 to 4/1/2021

Power Sales Contract between

Southwestern Power

Administration and Kansas

Municipal Energy Agency

5.1 5.1

Westar Energy Coal Purchase - Jeffrey Energy Center 1, 2, 3

50MW beginning 4/1/2011 and increasing to

59MW beginning 1/1/2012

59 Potowatomie Co., KS.

36 75401876, 75402065, 75402069

Appendix 2

Receipt Points of

Kansas Power Pool

37 75401876, 75402065, 75402069

APPENDIX 2: Kansas Power Pool RECEIPT POINTS

Tieline / Plant Name Ownership Voltage (kV)

SWPA-WERE SWPA and WERE various SWPA-MWE SWPA, WERE, and MWE various SWPA-WPEK SWPA, WERE and WPEK various GRDA-WERE GRDA and WERE various GRDA-MWE GRDA, WERE, and MWE various GRDA-WPEK GRDA, WERE, and WPEK various Jeffrey-WERE WERE various Jeffrey-MWE WERE and MWE various Jeffrey-WPEK WERE and WPEK various Nearman-WERE KCBPU and WERE various Nearman-MWE KCBPU, WERE and MWE various Nearman-WPEK KCBPU, WERE and WPEK various NPPD-WERE NPPD and WERE various NPPD-MWE NPPD, MWE and WERE various NPPD-WPEK NPPD, WPEK and WERE various WERE Coal-WERE WERE various WERE Coal-MWE WERE and MWE various WERE Coal-WPEK WERE and WPEK various KPP WERE Muni-WERE WERE various KPP WERE Muni-MWE WERE and MWE various KPP WERE Muni-WPEK WERE and WPEK various KPP-MWE Muni - MWE MWE various KPP MWE Muni-WERE MWE and WERE various KPP MWE Muni-WPEK MWE, WERE and WPEK various KPP WPEK Muni-WPEK WPEK various KPP WPEK Muni-WERE WPEK and WERE various KPP WPEK Muni-MWE WPEK, WERE and MWE various Greensburg Wind KPP 34.5 City of Attica Generation KPP 34.5 City of Kingman Generation KPP 34.5

38 75401876, 75402065, 75402069

Appendix 3

Delivery Points of

Kansas Power Pool

39 75401876, 75402065, 75402069

APPENDIX 3 Kansas Power Pool

Delivery Points

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

SPP Bus Number / Name

Delivery Point Name

Point of Delivery Voltage [kV]

(2) Meter

Ownership

Meter Voltage [kV] Measured (Location)

(1) 533582 AUGUSTA2 69.0 kV City of Augusta 69 Westar

69 (Transmission)/(a)

533624 BURLING2 69.0 kV City of Burlington 69 Westar

12.5 (Low Side)/(b)


12.5 (Low Side)/(b)

533625 BURLIND2 69.0 kV City of Burlington 69 Westar

12.5 (Low Side)/(b)

533323 CLAYCTR3 115.0 kV City of Clay Center 34.5 Westar

12.5 (Low Side)/(b)

533323 CLAYCTR3 115.0 kV

City of Clay Center 115 kV (ii) 115 Westar


533760 ERIE 2 69.0 kV

City of Erie Gen Aux 69 Westar

0.48 (Bus)/(h)

533760 ERIE 2 69.0 kV City of Erie North 69 Westar


533760 ERIE 2 69.0 kV City of Erie South 2.4 Westar

2.4 (Low Side)/(b)

533732 BURRTON2 69.0 kV

City of Haven Industrial Park 12.5 Westar

12.5 (Circuit)/(d)

533732 BURRTON2 69.0 kV

City of Haven Residential 2.4 Westar

2.4 (Bus)/(e)

533369 HILSBOR3 115.0 kV City of Hillsboro 12.5 Westar

12.5 (Low Side)/(b)

533366 FLORENC3 115.0 kV City of Marion 12.5 Westar

12.5 (Low Side)/(b)

533376 SALINA 3 115.0 kV City of Minneapolis 34.5 Westar

34.5 (Transmission)/(a)

533732 BURRTON2 69.0 kV

City of Mount Hope 12.5 Westar

12.5 (Circuit)/(d)

532982 OXFORD 4 138.0 kV City of Oxford 12.5 Westar

12.5 (Circuit)/(d)

532852 JEC 6 230.0 kV City of St Marys 12.5 Westar

12.5 (Low Side)/(b)

533559 UDALL 2 69.0 kV City of Udall 12.5 Westar

12.5 (Circuit)/(d)

40 75401876, 75402065, 75402069

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


Delivery Point Name


(2) Meter

Ownership


(1) 533332 KNOB HL3 115 kV City of Waterville 4.2 Westar

4.2 (Bus)/(b)

533560 WELLING2 69.0 kV

City of Wellington #2 69 Westar

12.5 (Low Side)/(b)

533556 STROTHR2 69.0 kV

City of Winfield Oak to Strother 69 Westar


533561 WINFLD2 69.0 kV

City of Winfield Weaver to Oak 69 Westar


533323 CLAYCTR3 115.0 kV Riley 115 kV (i) 115 Westar


532852 JEC 6 230.0 kV

St Marys Deduct (iii) 12.5 Westar

0.48 (Circuit)/(h)

533557 TIMBER 2 69.0 kV Winfield Lakes 12.5 Westar

12.5 (Circuit)/(d)

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. After September 1, 2012, the applicable Loss Factor, from the Loss Factor tables included in Section 28.5 of Westar Energy’s OATT, are identified as (a) through (h) in the Notes column of those tables. Any special configuration not represented in (a) through (h) will be outlined as a special footnote within this appendix.

(2) The Points of Delivery under this NITSA are located at, or immediately adjacent to, the connection between Westar Energy’s facilities and the Network Customer’s facilities.

(i) Riley 115 kV planned in-service is 10/1/2012. This in-service date is contingent upon completion of the Chapman Junction 115KV, Chapman Junction 115V Capacitor, Clay Center Junction 115KV, Clay Center Junction - Clay Center Switching Station 115KV CKT 1, Clay Center Switching Station - TC Riley 115KV CKT 1, and TC Riley 115KV planned upgrades, identified in Section 8.10 of Attachment 1 of this Agreement.

(ii) City of Clay Center 115 kV planned in-service is 10/1/2012. This in-service date is contingent upon completion of the Chapman Junction 115KV, Clay Center Junction 115KV, Clay Center Junction - Clay Center Switching Station - 115KV CKT 1, and Clay Center Switching Station 115 KV planned upgrades, identified in Section 8.10 of Attachment 1 of this Agreement.

(iii) St Marys Deduct is a reduction to the City of St Marys delivery point.

41 75401876, 75402065, 75402069

Continue APPENDIX 3 - Midwest Energy System

Kansas Power Pool

Delivery Points on Midwest Energy Transmission and Distribution System

SPP Bus Number Delivery Point Name Ownership Voltage (kV) (Meter) (Location)

Midwest Energy Delivery Points:

530575 North Ellinwood -Ellinwood Midwest Energy 4.2 kV

(Low Side)

42 75401876, 75402065, 75402069

Continue APPENDIX 3 – Mid Kansas Electric Company Kansas Power Pool Delivery Points on Mid Kansas Electric Company Transmission and Distribution System for

Kansas Power Pool (KPP):

SPP Bus Number Delivery Point Name Ownership Voltage (kV) Mid Kansas Electric Company

Delivery Points:

539726 serves Kingman Pratt 34.5 KV

Mid Kansas Electric Company

34.5

539668 serves Attica and Kingman

Harper 138 KV


138.0

539734 serves Lucas and Luray Waldo 34.5kV Mid Kansas Electric Company

34.5

539708 serves Holyrood Ellsworth 34.5kV Mid Kansas Electric Company

34.5

539710 Greensburg 34.5kV Mid Kansas Electric Company

34.5

Note: Transmission service to Lucas and Luray begins 1/1/2010. Service to Holyrood begins 5/1/2010. Greensburg service to begin 6/1/2010.

43 75401876, 75402065, 75402069

Attachment A

Interim Redispatch Required for Transmission Service

44 75401876, 75402065, 75402069

Attachment A


Posted Study

Request

Limiting Facility Direction of Flow

Upgrade(s) Relief Amount (MW)

Outage(s) Season of Relief

1222644 ALLEN - LEHIGH TAP 69KV CKT 1

FROM->TO Upgrade Set #1: ALLEN - LEHIGH TAP 69KV CKT 1 Athens to Owl Creek 69 kV BURLINGTON JUNCTION - COFFEY COUNTY NO. 3 WESTPHALIA 69KV CKT 1 BURLINGTON JUNCTION - WOLF CREEK 69KV CKT 1 COFFEY COUNTY NO. 3 WESTPHALIA - GREEN 69KV CKT 1 Green to Vernon 69 kV LEHIGH TAP - OWL CREEK 69KV CKT 1 Vernon to Athens 69 kV

0.03 TIOGA - UNITED NO. 7 ROSE 69KV CKT 1

Starting 2010 6/1 - 10/1 Until EOC of Upgrade


FROM->TO Upgrade Set #1 0.83 TIOGA (TIOGA 1X) 138/69/13.2KV TRANSFORMER CKT 1






FROM->TO Upgrade Set #1 0.83 ALTOONA - TIOGA 138KV CKT 1



FROM->TO Upgrade Set #1 0.2 ORCHARD - UNITED NO. 7 ROSE 69KV CKT 1


45 75401876, 75402065, 75402069

Posted Study

Request





FROM->TO Upgrade Set #1 0.136 ATHENS SWITCHING STATION - OWL CREEK 69KV CKT 1





1222644 LEHIGH TAP - OWL CREEK 69KV CKT 1

TO->FROM Upgrade Set #2: Athens to Owl Creek 69 kV BURLINGTON JUNCTION - COFFEY COUNTY NO. 3 WESTPHALIA 69KV CKT 1 BURLINGTON JUNCTION - WOLF CREEK 69KV CKT 1 COFFEY COUNTY NO. 3 WESTPHALIA - GREEN 69KV CKT 1 Green to Vernon 69 kV LEHIGH TAP - OWL CREEK 69KV CKT 1 Vernon to Athens 69 kV

0.51 ALLEN - LEHIGH TAP 69KV CKT 1


1222644 MARMATON - UNITED NO. 1 ELSMORE 69KV CKT 1




FROM->TO Upgrade Set #2 2 ALTOONA - TIOGA 138KV CKT 1



FROM->TO Upgrade Set #2 2 TIOGA (TIOGA 1X) 138/69/13.2KV TRANSFORMER CKT 1





46 75401876, 75402065, 75402069

Posted Study

Request




1222644 ENA - TIOGA 69KV CKT 1






1222644 MARMTNE5 (MARMTN1X) 161/69/13.2KV TRANSFORMER CKT 1




FROM->TO Upgrade Set #2 .54 ALTOONA - TIOGA 138KV CKT 1


1222644 TIOGA (TIOGA 1X) 138/69/13.2KV TRANSFORMER CKT 1

FROM->TO Upgrade Set #2 1.91

UNITED NO. 1 ELSMORE - ZILA JUNCTION 69KV CKT 1



TO->FROM Upgrade Set #2 0.46 UNITED NO. 1 ELSMORE - ZILA JUNCTION 69KV CKT 1



FROM->TO Upgrade Set #2 0.51 LITCHFIELD - PITNAC 69KV CKT 1





47 75401876, 75402065, 75402069

Posted Study

Request











FROM->TO Upgrade Set #2 0.21 MARMATON - UNITED NO. 1 ELSMORE 69KV CKT 1




MARMATON - UNITED NO. 1 ELSMORE 69KV CKT 1



FROM->TO Upgrade Set #2 0.18 UNITED NO. 1 ELSMORE - ZILA JUNCTION 69KV CKT 1



FROM->TO Upgrade Set #2 0.1 ALLEN - ZILA JUNCTION 69KV CKT 1


1222644 UNITED NO. 1 ELSMORE - ZILA JUNCTION 69KV CKT 1









48 75401876, 75402065, 75402069

Posted Study

Request










1222644 ALLEN - ZILA JUNCTION 69KV CKT 1

TO->FROM Upgrade Set #2 2.18 TIOGA (TIOGA 1X) 138/69/13.2KV TRANSFORMER CKT 1


1222644 ARCO TAP - ENA 69KV CKT 1




TO->FROM Upgrade Set #2 0.23 MARMATON - UNITED NO. 1 ELSMORE 69KV CKT 1





1222644 ALTOONA - TIOGA 138KV CKT 1






1222644 ALTOONA - NORTHEAST PARSONS 138KV CKT 1






49 75401876, 75402065, 75402069

Posted Study

Request




1222644 ARCO TAP - MONARCH 69KV CKT 1

TO->FROM Upgrade Set #2 0.26 ALTOONA - TIOGA 138KV CKT 1



TO->FROM Upgrade Set #2 0.13 COFFEYVILLE TAP - DEARING 138KV CKT 1









TO->FROM Upgrade Set #2 1.86

TIOGA (TIOGA 1X) 138/69/13.2KV TRANSFORMER CKT 1





1222644 ALLEN - MONARCH 69KV CKT 1












50 75401876, 75402065, 75402069

Posted Study

Request










1222644 ATHENS SWITCHING STATION - OWL CREEK 69KV CKT 1

FROM->TO Upgrade Set #2 0.27 ALLEN - LEHIGH TAP 69KV CKT 1











51 75401876, 75402065, 75402069

Additional Interim Redispatch Required for Transmission Service

Posted Study

Request


Upgrade(s) Relief Amount

(MW)



FROM->TO

Upgrade Set #1: ALLEN - LEHIGH TAP 69KV CKT 1 Athens to Owl Creek 69 kV BURLINGTON JUNCTION - COFFEY COUNTY NO. 3 WESTPHALIA 69KV CKT 1 BURLINGTON JUNCTION - WOLF CREEK 69KV CKT 1 COFFEY COUNTY NO. 3 WESTPHALIA - GREEN 69KV CKT 1 Green to Vernon 69 kV LEHIGH TAP - OWL CREEK 69KV CKT 1 Vernon to Athens 69 kV




FROM->TO

Upgrade Set #1 5.3 TIOGA (TIOGA 1X) 138/69/13.2KV TRANSFORMER CKT 1



FROM->TO




FROM->TO

Upgrade Set #1 5.4 ALTOONA - TIOGA 138KV CKT 1



FROM->TO

Upgrade Set #1 1.2 ORCHARD - UNITED NO. 7 ROSE 69KV CKT 1



FROM->TO

Upgrade Set #1 0.9 ATHENS SWITCHING STATION - OWL CREEK 69KV CKT 1



FROM->TO



52 75401876, 75402065, 75402069

Posted Study

Request



(MW)


1222932 ARKANSAS CITY - PARIS 69KV CKT 1

TO->FROM

ARKANSAS CITY - PARIS 69KV CKT 1 #1 Displacement

0.7 CRESWELL - OAK 69KV CKT 1



FROM->TO

Upgrade Set #2: Athens to Owl Creek 69 kV BURLINGTON JUNCTION - COFFEY COUNTY NO. 3 WESTPHALIA 69KV CKT 1 BURLINGTON JUNCTION - WOLF CREEK 69KV CKT 1 COFFEY COUNTY NO. 3 WESTPHALIA - GREEN 69KV CKT 1 Green to Vernon 69 kV LEHIGH TAP - OWL CREEK 69KV CKT 1 Vernon to Athens 69 kV

10.9 TIOGA (TIOGA 1X) 138/69/13.2KV TRANSFORMER CKT 1



TO->FROM

Upgrade Set #2 2.6 MARMATON - UNITED NO. 1 ELSMORE 69KV CKT 1



FROM->TO




TO->FROM

Upgrade Set #2 2.6 UNITED NO. 1 ELSMORE - ZILA JUNCTION 69KV CKT 1



FROM->TO




FROM->TO




FROM->TO



53 75401876, 75402065, 75402069

Posted Study

Request



(MW)



TO->FROM

Upgrade Set #2 2.9 ALLEN - LEHIGH TAP 69KV CKT 1



FROM->TO




FROM->TO




FROM->TO




FROM->TO




FROM->TO

Upgrade Set #2 7.8 ALLEN - ZILA JUNCTION 69KV CKT 1



FROM->TO




FROM->TO




FROM->TO



54 75401876, 75402065, 75402069

Posted Study

Request



(MW)



FROM->TO




FROM->TO




FROM->TO




FROM->TO




FROM->TO




TO->FROM




FROM->TO




TO->FROM




FROM->TO



55 75401876, 75402065, 75402069

Posted Study

Request



(MW)



FROM->TO




FROM->TO




FROM->TO




FROM->TO




FROM->TO




TO->FROM




TO->FROM




TO->FROM




TO->FROM




FROM->TO




FROM->TO



56 75401876, 75402065, 75402069

Posted Study

Request



(MW)



FROM->TO

Upgrade Set #2 3.2 LITCHFIELD - PITNAC 69KV CKT 1



FROM->TO




FROM->TO




FROM->TO




TO->FROM




FROM->TO




TO->FROM




FROM->TO




TO->FROM




TO->FROM



57 75401876, 75402065, 75402069

Posted Study

Request



(MW)



TO->FROM




TO->FROM

Upgrade Set #2 1.1 COFFEYVILLE TAP - DEARING 138KV CKT 1


1607046 CENTENNIAL - COWSKIN 138KV

CKT 1

TO->FROM

Upgrade Set #3 Line - Comanche County - Medicine Lodge 345 kV dbl ckt Line - Hitchland - Woodward 345 kV dbl ckt OKGE Line - Hitchland - Woodward 345 kV dbl ckt SPS Line - Medicine Lodge - Wichita 345 kV dbl ckt MKEC Line - Medicine Lodge - Wichita 345 kV dbl ckt WERE Line - Spearville - Comanche County 345 kV dbl ckt MKEC Line - Spearville - Comanche County 345 kV dbl ckt SUNC Line - Woodward - Comanche County 345 kV dbl ckt MKEC Line - Woodward - Comanche County 345 kV dbl ckt OKGE

1.1 EVANS ENERGY CENTER SOUTH -

LAKERIDGE 138KV

Starting 2012 6/1 - 10/1 Until EOC of

Upgrade

73450023 CRESWELL - OAK 69KV CKT 1

FROM->TO

CRESWELL - OAK 69KV CKT 1 1.7 CRESWELL - PARIS 69KV CKT 1


Upgrade 73450023

CITY OF WINFIELD - TIMBER JUNCTION

69KV CKT 1

TO->FROM

RICHLAND - UDALL 69KV CKT 1 1.2 CRESWELL - OAK 69KV CKT 1


Upgrade 74236802 CRESWELL - OAK

69KV CKT 1 FROM-

>TO CRESWELL - OAK 69KV CKT 1 6.1 CRESWELL - PARIS

69KV CKT 1 Starting 2012 6/1 - 10/1 Until EOC of

Upgrade

58 75401876, 75402065, 75402069

Posted Study

Request



(MW)



CKT 1

TO->FROM

Upgrade Set #3 3.3 EVANS ENERGY CENTER SOUTH -

LAKERIDGE 138KV


Upgrade 74236802 MUND - PENTAGON

115KV CKT 1 TO-

>FROM Line - Iatan - Nashua 345 kV 1.8 87TH 7 345.00 -

CRAIG 345KV CKT 1 Starting 2012 12/1 -

4/1 Until EOC of Upgrade

74236802 CITY OF WINFIELD - TIMBER JUNCTION

69KV CKT 1

TO->FROM



Upgrade

59 75401876, 75402065, 75402069

Attachment B

60 75401876, 75402065, 75402069

Attachment B

Maximum Firm Import Capability before completion of the following upgrades Upgrade: TIMBER JUNCTION 138 kV Capacitor Sumner County to Timber Junction 138/69 kV RICHLAND - ROSE HILL JUNCTION 69KV CKT 1 ROSE HILL JUNCTION - WEAVER 69KV CKT 1 Season Identified: 2010 Summer Peak

KPP SINK Maximum Firm Import Capability (MW)1 Applicable Period Most Limiting Criteria Violation

WELLINGTON 17 June - September Creswell - Sumner County No. 4 Rome 69kV

Ckt 1 overload for Gill-Peck 69kV outage

WINFIELD 47 June - September 138kV low voltages for Transmission Operating

Directive for El Paso-Farber 138kV outage

WINFIELD 52 June - September Creswell-Oak 69kV overload for Creswell -

Paris 69kV outage

WINFIELD 53 June - September Rose Hill Junction - Weaver 69 kV Ckt 1

overload for El Paso-Farber 138kV outage OXFORD, WELLINGTON, and WINFIELD Simultaneous

472 June - September

138kV low voltages for Transmission Operating Directive for El Paso-Farber 138kV outage

OXFORD, WELLINGTON, and WINFIELD Simultaneous 652 June - September

Rose Hill Junction - Weaver 69 kV Ckt 1 overload for El Paso-Farber 138kV outage

1 Maximum Firm Import Capability based on 98% Lagging Power Factor at all Point of Interconnections 2 Oxford, Wellington, and Winfield restriction is based upon common constraints limiting simultaneous Maximum Firm Import Capability for these cities.

61 75401876, 75402065, 75402069

Attachment C

62 75401876, 75402065, 75402069

Attachment C

Maximum Firm Import Capability Upgrade: N/A

KPP SINK Maximum Firm Import

Capability (MW) Applicable Period Most Limiting Criteria Violation CLAY CENTER 13.1 kV 15 June - September

Clay Center Junction 115/34.5kV transformer overload for System Intact

Maximum Firm Import Capability after completion of the following upgrades Upgrade: TIMBER JUNCTION 138 kV Capacitor Sumner County to Timber Junction 138/69 kV RICHLAND - ROSE HILL JUNCTION 69KV CKT 1 ROSE HILL JUNCTION - WEAVER 69KV CKT 1 Season Identified: 2019 Summer Peak

KPP SINK Maximum Firm Import Capability

(MW)1 Applicable Period Most Limiting Criteria Violation

WELLINGTON 17 June - September Creswell - Sumner County No. 4 Rome 69kV Ckt 1

overload for Gill-Peck 69kV outage

WINFIELD 68 June - September Creswell-Oak 69kV overload for Creswell - Paris 69kV

outage OXFORD, WELLINGTON, and WINFIELD Simultaneous 732 June - September

Creswell - Newkirk 138kV overload for Transmission Operating Directive for El Paso-Farber 138kV outage


Richland - Udall 69kV overload for El Paso-Farber 138kV outage


63 75401876, 75402065, 75402069

Maximum Firm Import Capability after completion of upgrades Upgrade: Green to Vernon 69 kV Vernon to Athens 69 kV Athens to Owl Creek 69 kV TIOGA 69KV Capacitor LEHIGH TAP - OWL CREEK 69KV CKT 1 ALLEN 69KV Capacitor BURLINGTON JUNCTION - WOLF CREEK 69KV CKT 1 ATHENS 69KV Capacitor

BURLINGTON JUNCTION - COFFEY COUNTY NO. 3 WESTPHALIA 69KV CKT 1

COFFEY COUNTY NO. 3 WESTPHALIA - GREEN 69KV CKT 1 Season Identified: 2019 Summer Peak

KPP SINK Maximum Firm Import Capability (MW)1 Applicable Period Most Limiting Criteria Violation CHANUTE,ERIE, and IOLA Simultaneous 1012 June - September

Allen - Monarch 69kV overload for Altoona-Tioga 138kV outage

1 Maximum Firm Import Capability based on 98% Lagging Power Factor at all Point of Interconnections 2 Chanute, Erie, and Iola restriction is based upon common constraints limiting simultaneous Maximum Firm Import Capability for these cities Note: Long-Term Firm Import Capacity for Chanute, Erie, and Iola will be reviewed upon actual in-service date of

64 75401876, 75402065, 75402069

Appendix 4

Wholesale Distribution Charges

65 75401876, 75402065, 75402069

APPENDIX 4

Kansas Power Pool

Total Monthly Wholesale Distribution Service Charge

Municipal Monthly Wholesale

Distribution Service Charge Haven $2,651.22 Hillsboro $873.10 Marion $22.74 Mount Hope $1,525.73 Oxford $1,694.32 St Marys $2,203.21 Udall $830.62 Waterville $383.31 Winfield $40.05

Total Monthly Wholesale Distribution Service Charge $10,224.30

66 75401876, 75402065, 75402069

Appendix 5

Service Agreement for Ancillary Services

67 75401876, 75402065, 75402069

Appendix 5

Service Agreement for Ancillary Services 1.0 This Service Agreement for Ancillary Services, dated as of March 1, 2008 (“ Service

Agreement”), is entered into, by and between Southwest Power Pool, Inc. (“SPP” or “Transmission Provider”), Mid-Kansas Electric Corporation, LLC (“MKEC” or “Transmission Owner”) and Kansas Power Pool (“Transmission Customer”). Transmission Provider and, Transmission Owner and Transmission Customer each may be referred to as a “Party” or collectively as the “Parties”.

2.0 The Transmission Customer is a Network Transmission Service customer under the SPP

Tariff for the cities of Attica and Kingman, Kansas. 3.0 Service under this Service Agreement shall commence on March 1, 2008, and shall be

effective through March 1, 2018. Thereafter, it will continue from year to year unless terminated by the Transmission Customer, the Transmission Provider or the Transmission Owner by giving the other Parties one-year advance written notice or by the mutual written consent of the Parties. In recognition of Transmission Customer’s continued efforts to develop an operational pool and to include additional participants therein, this Service Agreement will apply to such additional participants if and when Transmission Customer adds such additional participants to such operational pool; provided such additional participants are located within the Mid Kansas Electric Corporation Zone. Additionally, upon the date when the Transmission Provider can directly supply one or more of the Ancillary Services provided for in this Service Agreement, such service shall be taken from the Transmission Provider rather than from Transmission Owner unless otherwise self-supplied. Each Ancillary Service supplied under this Service Agreement can be individually transferred to the Transmission Provider to supply that service prior to the termination date of this Service Agreement.

4. 0 The Transmission Customer may self-supply all or a portion of its Ancillary Services as provided in the Tariff and this Service Agreement. The ability of the Transmission Customer to self-supply an Ancillary Service will begin upon the satisfactory demonstration to the Transmission Provider that the Transmission Customer has the ability to self-supply that specific Ancillary Service. To self-supply an Ancillary Service, the Transmission Customer must meet the appropriate North American Electric Reliablity Corporation (“NERC”), Tariff and SPP criteria including the criteria attached hereto as Attachment 1, for the requested self-supplied Ancillary Service. In the event that the Transmission Customer fails to self-supply all or a portion of those Ancillary Services it has been approved to self-supply in sufficient quantities to satisfy the requirements of the Tariff, the Transmission Customer shall be assessed the appropriate penalty charge as provided in the Tariff. Transmission Customer resources that the Transmission Provider has determined meet these criteria and are eligible for credits are listed in Attachment 2 attached hereto.

5. 0 The Transmission Customer agrees to take and pay for Transmission Service and

Ancillary Service in accordance with the provisions of the Tariff and this Service Agreement, including the Billing Principles attached hereto as Attachment 3.

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6.0 In the event that transmission service to the Transmission Customer is unavailable to one or more of the Transmission Customer’s delivery points, and the Transmission Customer has been directed to generate or reduce load by either the Transmission Provider or the Transmission Owner, the Transmission Provider will pro-rate down the capacity portion of the relevant monthly billing based upon the amount of load that could not receive the contracted for Ancillary Service and the duration of the interruption, consistent with the Tariff and this Service Agreement including the Billing Principles attached hereto as Attachment 3.

7.0 Transmission Provider shall have the right to make a unilateral filing with the Federal Energy Regulatory Commission (“FERC”) to modify this Service Agreement under Section 205 or any other applicable provision of the Federal Power Act and FERC's rules and regulations thereunder, and the Transmission Customer and Transmission Owner shall have the right to make a unilateral filing with FERC to modify this Service Agreement under Section 206 or any other applicable provision of the Federal Power Act and FERC's rules and regulations thereunder; provided that each Party shall have the right to protest any such filing by any other Party and to participate fully in any proceeding before FERC in which such modifications may be considered. Nothing in this Service Agreement shall limit the rights of the Parties or of FERC under Sections 205 or 206 of the Federal Power Act and FERC's rules and regulations thereunder, except to the extent that the Parties otherwise mutually agree as provided herein. The standard of review the Commission shall apply when acting on any such proposed modifications to the Service Agreement shall be the "just and reasonable" standard of review rather than the "public interest" standard of review.

8.0 Any notice or request made to or by any Party regarding this Service Agreement shall be

made to the representatives of the other Parties as indicated below.

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KPP: Transmission Customer MKEC: Transmission Owner Colin Whitley General Manager 200 West Douglas, Suite 601 Wichita, KS 67202 316-264-3166 [email protected]

L. Earl Watkins, Jr. President and CEO 301 West 13th Street Hays, Kansas 67601 785-628-2845

SPP: Transmission Provider Carl Monroe Executive Vice President, Operations and Chief Operating Officer 415 North McKinley, #140 Plaza West Little Rock, AR 72205-3020 501-614-3218 [email protected]

9.0 All the attachments to this Service Agreement are incorporated into and made a part of

this Service Agreement. The Tariff is incorporated herein and made a part hereof. 10.0 This Service Agreement may be executed in any number of counterparts, each of which

shall be an original, but all of which together shall constitute one instrument.

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IN WITNESS WHEREOF, the Parties have caused this Service Agreement to be executed by their respective authorized officials. KPP: Transmission Customer

By: ________________________________

Title: ______________________________

Date: _______________________________

MKEC: Transmission Owner

By: _______________________________

Title: ______________________________

Date: _______________________________

SPP: Transmission Provider

By: ________________________________

Title: ______________________________

Date: _______________________________

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Specifications for Providing Ancillary Services for Transmission Service 1.0 Transmission Customer’s Loads:

(a) Transmission Customer's Loads shall include any load served at points of delivery to which transmission service has been taken under the Tariff, located within the Mid Kansas Electric Corporation Zone.

2.0 Description of the Transmission Customer's transmission facilities integrated

with and supporting the Transmission Owner’s Transmission System: (a) None designated at this time. KPP preserves the right to apply for

recognition of customer-owned transmission. 3.0 Service under this Service Agreement shall be subject to the charges, terms

and conditions as stated in the Tariff, and the Billing Principles attached hereto as Attachment 3. 3.1 Scheduling and Tariff Administration Service (Schedules 1 & 1A); and

Reactive Supply and Voltage Control from Generation Sources Service (Schedule 2) shall be purchased from the Transmission Provider. Transmission Customer may receive any compensation or credits for Ancillary Service 2 for which Transmission Customer is eligible that Transmission Provider provides pursuant to the Tariff.

3.2 Regulation and Frequency Response Service (Schedule 3) shall be purchased from the Transmission Owner through Schedule 3 of the Tariff. The Transmission Customer will be able to self-supply this Ancillary Service when it has demonstrated to the Transmission Provider and the Transmission Provider has confirmed that the Transmission Customer has the proper control and metering equipment and has met all other requirements necessary to allow it perform this ancillary function on a continuous basis, pursuant to the appropriate NERC, Tariff, and SPP criteria, including the criteria in Attachment 1 attached hereto, and any other future regulations governing the Transmission Owner.

3.3 Energy Imbalance Service (Schedule 4) shall be purchased from the

Transmission Provider through the Transmission Provider’s real-time energy imbalance service market.

3.4 Operating Reserve-Spinning Reserve Service (Schedule 5) shall be

purchased or provided pursuant to Schedule 5 of the Tariff. The Transmission Customer will be able to self-supply this Ancillary Service

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when it has demonstrated to the Transmission Provider and the Transmission Provider has confirmed that the Transmission Customer has the proper control and metering equipment and has met all other requirements necessary to allow it to perform this ancillary function on a continuous basis, pursuant to the appropriate NERC, Tariff, and SPP criteria, including criteria in Attachment 1 attached hereto, and any other future regulations governing the Transmission Owner.

3.5 Operating Reserve-Supplemental Reserve Service (Schedule 6) shall be

purchased or provided pursuant to Schedule 6 of the Tariff. The Transmission Customer will be able to self-supply this Ancillary Service when it has demonstrated to the Transmission Provider and the Transmission Provider has confirmed that the Transmission Customer has the proper control and metering equipment and has met all other requirements necessary to allow it to perform this ancillary function on a continuous basis, pursuant to the appropriate NERC, Tariff, and SPP criteria, including criteria in Attachment 1 attached hereto, and any other future regulations governing the Transmission Owner.

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Attachment 1 of Appendix 5

Requirements for Credits Against Ancillary Services and

Requirements for Demonstration of Self-Supply of Ancillary Services

A. Requirements for Credits Against Ancillary Service 2 Billing

1. Reactive Supply and Voltage Control from Generation Sources Service

("Ancillary Service 2") may not be self-supplied by a Transmission Customer.

Ancillary Service 2 must be purchased from the Transmission Provider

pursuant to the provisions of Schedule 2 to the Transmission Provider's Tariff.

2. The Transmission Provider will bill the Transmission Customer for

Ancillary Service 2 in all circumstances.

3. A Transmission Customer that is able to provide a Reactive Power

Resource(s) delivered to the Transmission Provider’s Transmission System

that contributes to the Transmission Provider's or Host Transmission Owner's

supply of Reactive Power Resources necessary for their provision of Ancillary

Service 2 may receive credits for those Reactive Power Resources that it is

willing to commit pursuant to the provisions of the Tariff.

4. The Reactive Resource must be subject to the contractual control or

functional control of the Transmission Customer.

5. Where the Transmission Customer is relying on a contractual

arrangement to make available a Reactive Power Resource, the supplier or

functionary providing or operating the Transmission Customer's generation

resource must demonstrate with sufficient clarity that the Reactive Power

Resource is functioning on behalf of the Transmission Customer to meet a

portion of the Reactive Power supply obligation of the Transmission Provider

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and Transmission Owner for which the Reactive Power Resource credit is

sought.

6. The Transmission Customer is fully responsible for the compliance and

functional performance of the Reactive Power Resource (s) and/or service

provider(s) for which it has a contractual arrangement.

7. The Transmission Provider or the Host Transmission Owner will

provide credits to the Transmission Customer pursuant to a bilateral

agreement between the Transmission Provider or Host Transmission Owner

and the Transmission Customer provided that:

a. The Reactive Power Resource is be operated within, or

electronically encompassed by, the host control system contributing

reactive power on a real-time basis for the provision of Ancillary

Service 2. Reactive Power Resources located outside the

Transmission Provider’s Transmission System are not eligible for

credits.

b. The voltage regulator on the Reactive Power Resource is in

service in the automatic mode and the Reactive Power

Resource is available and able to follow a voltage or power factor

schedule on the transmission interface for the point of

receipt/delivery at the direction of the Transmission Provider or

Control Area Operators.

c. The Reactive Power Resource meets the directed voltage or power

factor schedule within +/-1%, but not to exceed the design

capability of the equipment.

d. The Transmission Customer provides, or causes to be provided,

telemetry of the real and reactive power output of the Reactive

Power Resource(s) and the voltage(s) at the point(s) on the

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transmission system where voltage or power factor schedule(s) are

to be followed. Telemetry will be provided at a 4 to 10 second

sampling rates to the host control area operator on a continuous

basis and shall otherwise be consistent with the requirements of the

Metering Agreement attached hereto as Attachment 3 of this

Service Agreement.

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B. Requirements for Demonstration of Self Supply of Ancillary Services 3, 5 and 6

1. The generation resource(s), owned by the Transmission Customer or utilized by

contract, providing the Ancillary Service(s) must fully comply with SPP and NERC

Criteria with no finding of material non-compliance during the operation of the Resource.

2. Where the Transmission Customer is relying on a contractual arrangement to

meet a portion or all of its obligations, the supplier or functionary providing or operating

the Transmission Customer's generation resource must demonstrate with sufficient

clarity that the generation resource is functioning on behalf of the Transmission

Customer to meet that portion of the Ancillary Service(s) obligation of the Transmission

Customer for which the generation resource is claimed.

3. Firm power service (purchases including regulation, spinning and non-spinning

reserves) will reduce the AS 3, AS 5 and AS 6 responsibilities of the Transmission

Customer.

4. The Transmission Customer must sufficiently notify the Transmission Provider

and the affected Control Area Operator(s) of its arrangements and coordinate the self-

provision of Ancillary Service(s) to allow the Transmission Provider and the Control

Area(s) to reduce their obligations to provide the Ancillary Service(s) on behalf of the

Transmission Customer. The Transmission Customer’s resources may be made

available to the Control Area Operator(s) to deploy to meet the responsibilities of the

Control Area(s) or, where operational control is retained by the Transmission Customer

or the resources are outside the host Control Area for the Transmission Customer’s

load, coordinated with the Control Area Operator to allow the Control Area Operator to

reduce its obligations under SPP and NERC criteria and adjust its operations

accordingly.

5. The Transmission Customer is fully responsible for the compliance and functional

performance of the generation resource(s) and/or service provider(s) for which it has a

contractual arrangement.

6. Any violation of the conditions stated above will be deemed to be non-

performance of the Transmission Customer’s obligation to arrange for Ancillary

Service(s), and the Transmission Provider will provide Ancillary Services to the

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Transmission Customer according the Transmission Provider's Tariff. The

Transmission Customer will be billed for all applicable charges for the services provided

and, unless the Transmission Customer has made appropriate prior arrangements with

SPP before the non-performance, for penalties applicable to the Transmission

Provider’s provision of the unarranged Ancillary Service(s) to the extent provided by the

Tariff.

7. A generation resource owned by the Transmission Customer or utilized by

contract for the provision of Ancillary Service(s) that is located outside the Transmission

Provider's Transmission System is not eligible for use in the self-supply of Ancillary

Services unless firm transmission service has been arranged for the delivery of power

and energy in sufficient quantities to cover the required Ancillary Service being self-

provided. Such transmission service will reflect such Generation Resource as the

source and the load supplied as the sink.

8. For any Generation Resource owned by the Transmission Customer or utilized

by contract for the provision of Ancillary Service(s), the Transmission Customer must

supply the Transmission Provider a copy of the interconnection agreement in effect

between such supplier and the relevant transmission provider, provided such

transmission provider is an entity other than the Transmission Provider.

9. Specific Resource requirements for each Service:

a. Regulation and Frequency Response Service (AS 3) On-line capacity under

AGC and a subject to the contractual control or the operational authority of

the Transmission Customer.

b. Operating Reserve - Spinning Reserve Service (AS 5) For a unit specific resource or

entitlement (including purchases): Idle on-line capacity subject to the contractual

control or operational authority of the Transmission Customer. No charges for AS 5

shall be assessed on that portion of the Transmission Customer's load that is supplied

by purchases from third parties of firm power resources, provided that Transmission

Customer has demonstrated to SPP, and SPP is able to determine, that such third

parties are to provide AS 5 under the agreement(s) for such purchases and to the

extent the third party does supply AS5.

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c. Operating Reserve - Supplemental Reserve Service (AS 6) For a unit specific

resource or entitlement (including purchases): 1. Idle on-line capacity in excess of the

capacity counted for spinning reserve (AS 5) and subject to the operational authority

of the Transmission Customer and 2. Uncommitted quick start capacity capable of

meeting SPP and NERC criteria for non-spinning reserve subject to the operational

authority of the Transmission Customer. No charges for AS 6 shall be assessed on

that portion of Transmission Customer's load that is supplied by purchases from third

parties of firm power resources, provided that Transmission Customer has

demonstrated to SPP, and SPP is able to determine, that such third parties are to

provide AS 6 under the agreement(s) for such purchases and to the extent the third

party does supply AS6.

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Attachment 2 of Appendix 5 KPP Initial Resources on MKEC System Recognized for Self Provision of AS 3, AS 5 and AS 6 City City Generation1 Capacity (MW) Attica 2.15 Kingman 8.8 Total 10.95

AS#3 Yes when metered and placed under AGC


AS#6 Yes Notes: 1 AS rights available when running, metered and meeting operational requirements.

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Billing Principles

I. General

The Kansas Power Pool (“KPP”) is comprised of a number of cities that purchase either Point-to-Point (“PTP”) transmission service or Network Integration Transmission Service (“NITS”). The type of transmission service reserved for each city is the basis for how its ancillary service charges are calculated. SPP provides Ancillary Services 3 through 5 under the SPP Open Access Transmission Tariff (“OATT”). Because SPP does not have generation, MKEC, as the local Balancing Authority, supplies some of these ancillary services pursuant to its OATT. Thus references herein to the SPP OATT also refer to the MKEC OATT. II. Transmission Service Transmission service is a separate service from Ancillary Service. PTP transmission service and NITS are governed by the Tariff. To the extent the KPP cities take scheduled transmission service for which they have a reservation and/or unscheduled transmission service for which they do not have a reservation, the KPP cities will be subject to all charges, including penalties, for such transmission service in accordance with the Tariff. MKEC shall notify the SPP to the extent that any KPP city exceeds its firm reserved capacity at any Point of Receipt or Point of Delivery. III. MKEC's Development of the Monthly Bill for Ancillary Services A. Aggregation

KPP will be allowed to purchase Ancillary Services on the aggregate load of the KPP cities on a NITS basis beginning March 1, 2008 and continuing thereafter; provided that such aggregation continues to comply with the requirements of NERC and SPP scheduling criteria.

B. Effects of Transmission Line Loading Relief ("TLR")

When a transaction is affected by TLR, the energy scheduled under that reservation may be fully

or partially curtailed. If SPP called the TLR, SPP may adjust any transmission charges related to those affected reservations in accordance with its business practices. SPP shall calculate the amount of credits that KPP is entitled to receive against its charges for transmission service for reductions due to TLRs. SPP shall refund all such credits with interest. If the transmission reservation is reduced due to TLR (i.e., SPP called the TLR), MKEC shall reduce the ancillary service charges to correspond to the amount of the reduced MW reservation. If the transaction MW reservation is not affected (i.e., the schedule is reduced due to TLR called by an entity other than SPP) and the transmission reservation is Firm, the unused reservation shall be applied to deliveries of imbalance energy during those hours.

C. Self-Supply of Ancillary Services

KPP can totally or partially self-supply Ancillary Services 3, 5, and 6 as provided in this Service Agreement for Ancillary Services(“ Service Agreement”). SPP will notify MKEC as to any ancillary services that KPP is totally self-supplying and any qualified schedules or resources that KPP is using to

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partially self-supply ancillary services. Attachment 2 of this Service Agreement, as such Attachment 2 may be modified from time to time, contains a complete list of KPP resources that SPP has determined qualify for self-supply. Attachment 2 of this Service Agreement, as attached hereto as of the execution of this Service Agreement, reflects the KPP resources that SPP has determined qualify for self-supply effective as of March 1, 2008.

1. Ancillary Service 3 (Voltage and Regulation Control): Calculate the Hourly Ancillary Service 3 Charge for Each Hour of the Month: Hourly Ancillary Service 3 Charge = [ATTR] * [OATT Ancillary Service 3 hourly rate] Calculate the Total Ancillary Service 3 Charge for the Month: Total Ancillary Service 3 Charge per Month = Σ [Hourly Ancillary Service 3 Charges]

2. Ancillary Service 5 (Spinning Reserves):

Calculate the Hourly Ancillary Service 5 Demand Charge for Each Hour of the Month Hourly Ancillary Service 5 Demand Charge = [ATTR] * [OATT Ancillary Service 5 hourly demand rate]

Calculate the Monthly Ancillary Service 5 Energy Charge Monthly Ancillary Service 5 Energy Charge = (Total Energy Delivered for the Month – Total Energy

Delivered from Credited Sources for the Month) * (Ancillary Service 5 Energy Charge) Calculate the Total Ancillary Service 5 Charge for the Month: Total Ancillary Service 5 Charge per Month = Σ [Hourly Ancillary Service 5 Demand Charges] + [Monthly

Ancillary Service 5 Energy Charge]

3. Ancillary Service 6 (Supplemental Reserves):


Calculate the Total Ancillary Service 6 Charge for the Month: Total Ancillary Service 6 Charge per Month = Σ [Hourly Ancillary Service 6 Demand Charges]

D. Network Integrated Transmission Service (NITS): For those cities that are taking NITS service, the ancillary charges are based upon the rolling twelve-month average Network Load. The hourly demand used in these ancillary service calculations is based upon the total load of the city behind the meter, which is calculated by summing the load measured by the tie meters between MKEC and the city plus the internal generation of the city plus any transmission and distribution losses. The credits are based upon the amount of energy delivered to the city from credited sources.

1. Ancillary Service 3 (Voltage and Regulation Control):

Calculate the Monthly Ancillary Service 3 Charge: Monthly Ancillary Service 3 Charge = [Monthly Ancillary Service 3 rate] * [Rolling 12 month average

Network Load]

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Calculate the Monthly Credit for Self-Supply: Monthly Credit for Self-Supply = [Total Energy Delivered from Credited Sources during the month] *

[Hourly Ancillary Service 3 rate]

Calculate the Total Monthly Amount Billed for Ancillary Service 3: Amount billed for Ancillary Service 3 = [Monthly Ancillary Service 3 Charge] – [Monthly Credit for Self Supply]

2. Ancillary Service 5 (Spinning Reserves): Calculate the Monthly Ancillary Service 5 Demand Charge: Monthly Ancillary Service 5 Demand Charge = [Monthly Ancillary Service 5 demand rate] * [Rolling 12

month average Network Load]

Calculate the Monthly Credit for Self-Supply Monthly Credit for Self-Supply = [Total Energy Delivered from Credited Sources during the month] *

[Hourly Ancillary Service 5 demand rate]

Calculate the Monthly Ancillary Service 5 Charge: Monthly Ancillary Service 5 Charge = [Monthly Ancillary Service 5 Demand Charge] – [Monthly Credit for

Self Supply] Calculate the Monthly Ancillary Service 5 Energy Charge: Monthly Ancillary Service 5 Energy Charge = (Total Energy Delivered for the month – Total Energy

Delivered from Credited Sources for the month) * (Ancillary Service 5 Energy Charge) Calculate the Total Ancillary Service 5 Charge per Month: Total Ancillary Service 5 Charge per Month = [Monthly Ancillary Service 5 Charge] + [Monthly Ancillary

Service 5 Energy Charge]


Calculate the Monthly Ancillary Service 6 Demand Charge: Monthly Ancillary Service 6 Demand Charge = [Monthly Ancillary Service 6 demand rate] * [Rolling

12 month average Network Load]



Calculate the Monthly Ancillary Service 6 Charge: Monthly Ancillary Service 6 Charge = [Monthly Ancillary Service 6 Demand Charge] – [Monthly

Credit for Self Supply]

IV. The SPP Bill SPP shall bill KPP monthly, and on a timely and consistent basis, including applicable charges for ancillary services from MKEC, and KPP shall pay to SPP, subject to the dispute resolution procedures of the SPP Tariff, (1) the monthly bill for ancillary services developed by MKEC under Part II

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of these Billing Principles and (2) any additional charges that KPP is subject to under SPP's OATT or any applicable agreements.

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NETWORK OPERATING AGREEMENT BETWEEN SOUTHWEST POWER POOL, INC., KANSAS POWER POOL, MIDWEST ENERGY, INC., MID-KANSAS ELECTRIC

COMPANY, LLC AND WESTAR ENERGY, INC.

This Network Operating Agreement ("Operating Agreement") is entered into this 1st day

of March, 2014, by and between Kansas Power Pool ("Network Customer"), Southwest Power

Pool, Inc. ("Transmission Provider") and Midwest Energy, Inc., Mid-Kansas Electric Company,

LLC and Westar Energy, Inc. ("Host Transmission Owners"). The Network Customer,

Transmission Provider and Host Transmission Owners 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(s) owns the transmission facilities to which

the Network Customer’s Network Load is physically connected;


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.



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1.0 Network Service

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

Transmission Provider, Host Transmission Owners, and Network Customer will

cooperate and the Host Transmission Owners 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 Owners and the Network Customer to operate their systems 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.

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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 Owners, 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.

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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

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 Owners and Transmission Provider.

3.2 The Host Transmission Owners 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 Owners 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 Owners 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

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

operating conditions expeditiously.

3.6 The Transmission Provider and Host Transmission Owners, 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 Owners, 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 Owners, 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

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

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

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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 Owners the following information:

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

corresponding power factors and annual energy requirements on an

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

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

demands and energy requirements at each delivery point for the normal

operating configuration;

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

generating capabilities and committed transactions with third parties

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

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

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 Owners’ Zones.

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

Transmission Owners’ 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 Owners, 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 Owners will provide the following to the Network

Customer:

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a) A statement regarding the ability of the Host Transmission Owners’

transmission systems to meet the forecasted deliveries at each of the

delivery points;

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

Owners’ systems 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

Owners and the Network Customer to identify appropriate remedies for

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 Owners, 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 Owners 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

91 75401876, 75402065, 75402069

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 Owners

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 Owners’ transmission systems.

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.

92 75401876, 75402065, 75402069

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 Owners’ transmission systems

consistent with Good Utility Practice. The Transmission Provider or Host

Transmission Owners, 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

Owners 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 Owners. The Network

Customer shall notify the Transmission Provider and the Host Transmission

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

occur and again when such unscheduled or forced outages end.

93 75401876, 75402065, 75402069

6.0 Scheduling Procedures

6.1 The Network Customer is responsible for providing its Resource and load

information to the Transmission Provider in accordance with Attachment AE.

6.2 For Interchange Transactions the Network Customer shall submit, or arrange to

have submitted, the schedule of Energy to or from the Transmission Provider and

a transaction identification E-Tag for each such schedule where required by

NERC Standard INT-001.

94 75401876, 75402065, 75402069

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, 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.

95 75401876, 75402065, 75402069

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 Owners’ representatives to have

access to the equipment at all reasonable hours and for any reasonable purpose,

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 Owners 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 Owners shall make

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

Transmission Owners 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 Owners, 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 Owners, 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

96 75401876, 75402065, 75402069

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

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

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

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

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

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

supplier, the Network Customer shall be responsible for 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.

97 75401876, 75402065, 75402069

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 as instructed by the Transmission Provider.

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

telemetry readings shall be submitted to the Transmission Provider and Host

Transmission Owners:

1) Analog MW;

2) Integrated MWHRS/HR;

3) Analog MVARS; and

4) Integrated MVARHRS/HR.

98 75401876, 75402065, 75402069

10.0 Redispatching, Curtailment and Load Shedding

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

require redispatching of Resources to relieve existing or potential transmission

system constraints. The Transmission Provider shall redispatch Resources in

accordance with the Energy and Operating Reserve Markets operations specified

in Attachment AE. 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 using the settlement

procedures specified in Attachment AE.

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 Owners 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 Owners to

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

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

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

shedding by the Network Customer.

99 75401876, 75402065, 75402069

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 Owners’ Zones.

100 75401876, 75402065, 75402069

12.0 Cost Responsibility

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

Customer, Host Transmission Owners, 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 Owners, 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.

101 75401876, 75402065, 75402069

13.0 Billing and Payments

Billing and Payments shall be in accordance with Attachment AE and Section 7 of the

Tariff.

102 75401876, 75402065, 75402069

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.

103 75401876, 75402065, 75402069

15.0 Assignment

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

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

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

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

unreasonably withheld.

104 75401876, 75402065, 75402069

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.

105 75401876, 75402065, 75402069

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.

106 75401876, 75402065, 75402069

18.0 Unilateral Changes and Modifications

Nothing contained in this Operating Agreement or any associated Service Agreement

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

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

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

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

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

other applicable statutes or regulations.

Nothing contained in this Operating Agreement or any associated Service

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

Customer receiving Network Integration Transmission Service under the Tariff to

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

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

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

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

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

and/or Service Agreement.

107 75401876, 75402065, 75402069

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.

108 75401876, 75402065, 75402069

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. Tessie Kentner Attorney 201 Worthen Drive Little Rock, AR 72223-4936 501-688-1782 Phone [email protected] Host Transmission Owner: Midwest Energy, Inc. William N. Dowling Vice President of Energy Management & Supply 1330 Canterbury Road, P.O. Box 898 Hays, KS 67601 Phone: (785) 625-1432 Fax (785) 625-1494 Email: [email protected] Host Transmission Owner: Mid-Kansas Electric Company, LLC Stuart Lowry 301 West 13th Street P.O. Box 980 Hays, KS 67601 Phone: (785) 623-3335 Fax (785) 623-3395 Email: [email protected] Host Transmission Owner: Westar Energy, Inc. Thomas Stuchlik Executive Director, System Operations 818 S. Kansas Avenue

109 75401876, 75402065, 75402069

Topeka, KS 66612 Phone: (785) 575-6046 Fax (785) 575-1798 Email: [email protected] Network Customer: Kansas Power Pool CEO/General Manager 250 W. Douglas, Suite 110 Wichita, KS 67202 Phone: (316) 264-3166 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.

110 75401876, 75402065, 75402069

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/ Lanny Nickell_________ _/s/ Aaron Rome__________ Signature Signature _Lanny Nickell___________ _Aaron Rome____________ Printed Name Printed Name __VP, Engineering________ _Mgr. Transmission and Market Operations Title Title _3-31-14________________ _3-28-2014______________ Date Date HOST TRANSMISSION OWNER HOST TRANSMISSION OWNER _/s/ Thomas R. Stuchlik____ _/s/ Stuart S. Lowry______ Signature Signature _Thomas R. Stuchlik_______ _Stuart S. Lowry_________ Printed Name Printed Name _Executive Director System Ops _President and CEO______ Title Title _3/11/2014________________ _March 11, 2014_________ Date Date NETWORK CUSTOMER

111 75401876, 75402065, 75402069

_/s/ Larry W. Holloway____ Signature _Larry W. Holloway______ Printed Name _Kansas Power Pool Operations Manager Title _March 7, 2014_________ Date

1 75401876, 75402065, 75402069

Southwest Power Pool, Inc. Sixteenth Revised Service No. 2198

SERVICE AGREEMENT FOR NETWORK INTEGRATION TRANSMISSION SERVICE BETWEEN SOUTHWEST POWER POOL, INC. AND KANSAS POWER

POOL

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

entered into this 1st day of March, 2014, by and between Kansas Power Pool ("Network

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



2 75401876, 75402065, 75402069

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 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 1, 2026. 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.

3 75401876, 75402065, 75402069

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.

Southwest Power Pool, Inc. (Transmission Provider):

Tessie Kentner

Attorney

201 Worthen Drive

Little Rock, AR 72223-4936

Email Address: [email protected]


Network Customer:

CEO/General Manager

Kansas Power Pool

250 W. Douglas, Suite 110

Wichita, KS 67202


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. However, the assignee shall be bound by the terms and conditions of this

Service Agreement.

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,

4 75401876, 75402065, 75402069

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

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/ Lanny Nickell /s/ Larry W. Holloway Signature

Signature

Lanny Nickell Larry W. Holloway Printed Name

Printed Name

VP, Engineering KPP Operations Manager Title

Title

3/31/14 3/7/2014 Date Date

5 75401876, 75402065, 75402069

ATTACHMENT 1 TO THE NETWORK INTEGRATION TRANSMISSION SERVICE AGREEMENT

BETWEEN SOUTHWEST POWER POOL AND KANSAS POWER POOL 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 the Network

Customer load connected to Mid-Kansas Electric Company, LLC’s (“Mid-Kansas”)

Zone, Midwest Energy, Inc.’s (“Midwest Energy”) Zone, and Westar Energy, Inc.’s

(“Westar Energy”) Zone(s), 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 Zone(s) and Intervening Systems Providing Transmission Service

The Zone(s) area are Sunflower Electric Power Corporation and Westar Energy. The

intervening systems providing transmission service are none.

6 75401876, 75402065, 75402069

4.0 Electrical Location of Initial Sources

See Appendix 1.

5.0 Electrical Location of the Ultimate Loads

The loads of Kansas Power Pool, identified in Section 2.0 hereof as the Network Load

are electrically located within the Mid-Kansas, Midwest Energy , and the Westar Energy

Zone(s).

6.0 Delivery Points

The delivery points are the interconnection points of Kansas Power Pool, 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.

Network loads connected to the Westar Energy Zone are based on the charges for the

Westar Energy pricing zone, network loads connected to the Midwest Energy Zone are

based on the charges for the Midwest Energy pricing zone, and network loads connected

to the Mid-Kansas Electric Company Zone are based on the charges for the Mid-Kansas

Electric Company pricing zone.

8.2 System Impact and/or Facility Study Charge

7 75401876, 75402065, 75402069

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

System reinforcements are required to address the City of Kingman’s 6 MW path limit as

part of Attachment D to allow for SPP Network Integration Transmission Service to

Kingman’s forecasted load. Future charges, if required shall be in accordance with Mid-

Kansas Open Access Transmission Tariff and/or the Mid-Kansas Tariff. The following

System reinforcements have been identified in SPP-2009-AGP2 to address the City of

Kingman's 6 MW path limit. Alternatives to these system reinforcements would be

subject to mutual agreement between the Network Customer and Mid-Kansas and SPP.



Estimated Engineering and

Construction Pratt 115/34.5kV Transformer

Install new 115/34.5 kV TXF rated at 25/30/37.5 MVA at Pratt 115 kV Substation to address 34.5kV distribution limitations to address 34.5kV distribution limitations

SUNC

8/1/2010

$2,000,000

Cunningham - Pratt 34.5kV CKT 1

Rebuild and reconductor 15 miles of 34.5-kV Line with T2 Raven (T2 4/0 ACSR) from Pratt to the Cunningham metering station to address 34.5kV distribution limitations

SUNC

8/1/2010

$4,164,600

Cunningham Voltage Regulator

Replace existing voltage regulator with a 18 MVA rated voltage regulator

SUNC 8/1/2010

$250,000

8 75401876, 75402065, 75402069

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.

For Network Customer’s load in Mid-Kansas’ Zone:

The Network Customer has entered into a Service Agreement for Ancillary

Services with Mid-Kansas that was executed contemporaneously with this

Agreement, which is included as Appendix 5.

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 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.

9 75401876, 75402065, 75402069

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 be responsible for losses in accordance with Attachment M

of the Tariff.

8.6 Real Power Losses - Distribution

For Delivery Points on Westar Energy Network System: 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.

For transmission requests and network resources (denoted in the table below), provide

generation redispatch power in the specified amounts necessary to alleviate loading on

the facilities listed in Attachment A prior to completion of Service Upgrades, Reliability

and Construction Pending upgrades. The Network Customer agrees to provide redispatch

pairs listed in Table 6 of the final posting of the respective Aggregate Study (denoted in

the table below), and the Transmission Provider agrees that such redispatch will satisfy

the redispatch obligation.

10 75401876, 75402065, 75402069


1222644 and 1222955 replaced

by 1610003 and 1610004


75402065


and resources in Midwest Energy

and Westar Energy Zones

2007-AG1

1223078 replaced by 1610083

replaced by 74243470 combined

into 75402069


and resources in Mid-Kansas

Electric Company Zone

2007-AG1

1222932 Replaced by 1610008

and 1610042 combined into

75349545,75349552,75406648,

and 75406653

Addition of 45 MW Westar

Energy Coal Purchase - Jeffrey

Energy Center 1, 2, 3 to network

load in Midwest Energy and

Westar Energy Zones

2007-AG1

1223078 Replaced by 73235882


75406660

Addition of 5 MW Westar Energy

Coal Purchase - Jeffrey Energy

Center 1, 2, 3 to network load in

Mid-Kansas Electric Company

Zone

2007-AG1

1285893 replaced by 73315260

combined into 75401876

Addition of City of Scranton and

St. Mary’s to KPP pool

2007-AG2

11 75401876, 75402065, 75402069


1607046 combined into

75401876

Addition of City of Marion to

KPP Pool in Westar Energy Zone

2009-AGP2

73447072, 73450023, and


75402446,75402448, and

75402460

Addition of Greensburg Wind

Network Resource

2009-AGP2

74236802,74236811, and


75402762,75402778, and

75402810

Addition of Kansas City Power

and Light Purchase Network

Resource

2009-AGP2

74234218 Addition of Dogwood Resource 2010-AGP1

In the absence of implementation of interim redispatch as requested by the Transmission

Provider for Network Customer transactions resulting in overloads on limiting facilities,

the Transmission Provider shall curtail the customers schedule.

Such redispatch obligations shall be arranged in accordance with Attachment K and shall

occur in advance of curtailment of other firm reservations impacting these constraints.

Network Customer shall bear the cost of such redispatch.

This interim redispatch shall remain in place until the Network Upgrades are completed

and the ATC required for this service is available.

Additionally, maximum firm import capability limitations will be enforced for Network

Customer load both before and after completion of required network upgrades as detailed

in Attachment B and Attachment C respectively subject to later re-studies, facility

improvements, and/or modifications to Network Customer's network loads and/or

resources. These limitations are applicable during peak loading conditions as identified

by Midwest Energy and Westar Energy.

12 75401876, 75402065, 75402069

8.9 Wholesale Distribution Service Charge

For Network Customer’s load in Westar’s Zone: Wholesale Distribution Service Charge

cost support and monthly charge is detailed in Appendix 4.

For Network Customer’s Load in Mid-Kansas’ Zone: Wholesale Distribution Service

Charges, if any, are specified in agreements approved by the Kansas Corporation

Commission (“KCC”) in KCC Docket No. 11-GIME-597-GIE and on file with the KCC,

as they may be amended by order of the KCC from time to time. The monthly rate shall

be as specified in the Mid-Kansas Open Access Transmission Tariff approved by the

KCC in KCC Docket No. 12-MKEE-650-TAR and on file with the KCC, as it may be

amended by order of the KCC from time to time.

8.10 Network Upgrade Charges

A. The Network Customer has confirmed the following Network Resources requiring

Network Upgrades:

1. Initial pooling of KPP Pool load and resources in Midwest Energy and

Westar Energy Zones as more specifically identified in the study of

transmission service request 1222644 and 1222955 replaced by 1610003

and 1610004 combined into 75401876 and 75402065. Contingent upon


these resources shall be effective on June 1, 2009 and shall remain






13 75401876, 75402065, 75402069

Service Upgrades


Date Required in

Service ALLEN - LEHIGH TAP

69KV CKT 1 Tear down / Rebuild 5.69-mile line;

954-KCM ACSR WERE 6/1/2009

ALLEN 69KV Capacitor Allen 69 kV 15 MVAR Capacitor Addition

WERE 6/1/2009


ALTOONA EAST 69KV 6 MVAR Capacitor Addition

WERE 6/1/2009

ATHENS 69KV Capacitor Athens 69 kV 15 MVAR Capacitor Addition

WERE 6/1/2009



WERE 6/1/2009

BARTLESVILLE SOUTHEAST - NORTH BARTLESVILLE 138KV

CKT 1

Rebuild 8.37 miles of 795 ACSR with 1590 ACSR & reset relays @

BSE

AEPW 6/1/2009



CKT 1


WERE 6/1/2009



WERE 6/1/2009

CHANUTE TAP – TIOGA 69KV CKT 1

Replace Jumpers WERE 6/1/2010

COFFEY COUNTY NO. 3 WESTPHALIA - GREEN

69KV CKT 1


WERE 6/1/2009

Green to Vernon 69 kV Rebuild 7.19 miles with 954 kcmil ACSR (138kV/69kV Operation)

WERE 6/1/2009

COFFEYVILLE TAP – DEARING 138 KV CKT 1

WERE #2

Replace Disconnect Switches, Wavetrap, Breaker, Jumpers

WERE 6/1/2010

COFEYVILLE TAP NORTH BARTLESVILLE

138KV CKT 1

Rebuild 13.11 miles of 795 ACSR with 1590 ACSR

AEPW 6/1/2009


Tear down / Rebuild 8.47-mile 69 kV line with 954-KCM ACSR

(138kV/69kV Operation)

WERE 6/1/2009


CKT 1

Tear down / Rebuild 0.91-mile 69 kV line; 954-KCM ACSR (138kV/69kV Operation)

WERE 6/1/2009

14 75401876, 75402065, 75402069


Date Required in

Service NEOSHO - NORTHEAST PARSONS 138KV CKT 1

Replace bus and Jumpers at NE Parsons 138 KV substation

WERE 6/1/2011


Tap the College – South Ellinwood 69kV line and install a new North

Ellinwood substation

MIDW 6/1/2009

NORTH ELLINWOOD- CITY OF NORTH

ELLINWOOD 34.5 CKT 1

Build approximately 4.5 miles of new 34.5 kV line with 477 ACSR

from North Ellinwood to interconnect near the City of

Ellinwood

MIDW 6/1/2009

TIMBER JCT CAP BANK Install 30 MVAR Cap bank at new Timber Junction 138kV

WERE 6/1/2009

TIOGA 69KV Capacitor Tioga 69 kV 15 MVAR Capacitor Addition

WERE 6/1/2009

Vernon to Athens 69 kV Rebuild 5.17 miles with 954 KCM-ACSR (138kV/69kV Operation)

WERE 6/1/2009






Date Required in

Service Sub - Franklin 161 kV Tap Litchfield - Marmaton 161 kV

line at new Franklin substation WERE 6/1/2013


New 161/69 kV transformer at Franklin

WERE 6/1/2013




to Mulberry.

WERE 6/1/2013




to Sheffield.

WERE 6/1/2013

15 75401876, 75402065, 75402069


monthly revenue requirements of $347.15 from June 1, 2009 – May 1, 2026 for a total of

$70,471.45 for remaining revenue requirements for upgrades by Empire District Electric

Company for the Oronogo Junction- Riverton 161kV upgrade to be completed on or

before June 1, 2011.

This upgrade was required to provide firm Point-To-Point Service to the City of Erie,

Kansas under transmission service request 974637 (later converted to Network Integrated

Transmission Service under transmission service request 1173206).


monthly revenue requirements of $1330.47 from June 1, 2009 – May 1, 2010 for a total

of $14,635.17 for remaining revenue requirements. The revenue requirement for the

American Electric Power transmission facility upgrade is $656.33/month for the Explorer

Glenpool-Riverside Station 138kV upgrade. The revenue requirements for Oklahoma Gas

and Electric’s transmission facility upgrades are $222.44/month for the Beeline-Explorer

Glenpool 138kV upgrade, and $451.70/month for the Explorer Glenpool-Riverside

Station 138kV upgrade.

These upgrades were required to provide firm Point-To-Point Service to the City of

Ellinwood, Kansas under transmission service request 610383. This service is now

reflected as network service request 1610074 for the Ellinwood portion of the original

service.

2. Additional Westar Energy Purchase, 45MW, as more specifically

identified in transmission service request 1222932 replaced by 1610008

and 1610042 combined into 75349545, 75349552, 75406648, and

75406653. Contingent upon the completion of required upgrades as

specified below, designation of this resource shall be effective on June 1,

2009 and shall remain effective through April 1, 2022.





16 75401876, 75402065, 75402069

Service Upgrades



ALLEN - LEHIGH TAP 69KV CKT 1

Tear down / Rebuild 5.69-mile line; 954-KCM ACSR WERE 6/1/2009

ALLEN 69KV Capacitor Allen 69 kV 15 MVAR Capacitor Addition WERE 6/1/2009


ALTOONA EAST 69KV 6 MVAR Capacitor Addition WERE 6/1/2009

ATHENS 69KV Capacitor Athens 69 kV 15 MVAR Capacitor Addition WERE 6/1/2009



BARTLESVILLE SOUTHEAST – NORTH BARTLESVILLE 138 KV

CKT 1

Rebuild 8.37 miles of 795 ACSR with 1590 ACSR & reset relays @BSE AEPW 6/1/2009



CKT 1




CHANUTE TAP – TIOGA 69KV CKT 1 Replace Jumpers WERE 6/1/2010

COFFEY COUNTY NO. 3 WESTPHALIA -

GREEN 69KV CKT 1


COFFEYVILLE TAP – DEARING 138 KV CKT

1 WERE #2


COFFEYVILLE TAP – NORTH

BARTLESVILLE 138 KV CKT 1

Rebuild 13.11 miles of 795 ACSR with 1590 ACSR AEPW 6/1/2009

Green to Vernon 69 kV Rebuild 7.19 miles with 954 kcmil ACSR (138kV/69kV Operation) WERE 6/1/2009


Tear down / Rebuild 8.47-mile 69 kV line with 954-KCM ACSR (138kV/69kV Operation)

WERE 6/1/2009

17 75401876, 75402065, 75402069




CKT 1

Tear down / Rebuild 0.91-mile 69 kV line; 954-KCM ACSR (138kV/69kV

Operation) WERE 6/1/2009

NEOSHO NORTHEAST PARSONS 138 KV CKT

1

Replace bus and Jumpers at NE Parsons 138 kV substation WERE 6/1/2011


Tap the College – South Ellinwood 69 kV line and install a new North

Ellinwood Substation MIDW 6/1/2009

NORTH ELLINWOOD 69/34.5KV

TRANSFORMER CKT 1

Install a new 69/34.5kV transformer at North Ellinwood MIDW 6/1/2009

NORTH ELLINWOOD – CITY OF NORTH

ELLINWOOD 34.5 KV CKT 1

Build approximately 4.5 miles of new 34.5 kV line with 477 ACSR from

North Ellinwood to interconnect near the City of Ellinwood

MIDW 6/1/2009

TIMBER JCT CAP BANK

Install 30 MVAR Cap bank at new Timber Junction 138kV WERE 6/1/2009

TIOGA 69KV Capacitor Tioga 69 kV 15 MVAR Capacitor Addition WERE 6/1/2009

Vernon to Athens 69 kV Rebuild 5.17 miles with 954 KCM ACSR (138kV/69kV Operation) WERE 6/1/2009







Sub - Franklin 161 kV Tap Litchfield - Marmaton 161 kV line at new Franklin substation WERE 6/1/2013


New 161/69 kV transformer at Franklin WERE 6/1/2013




connecting to Mulberry.

WERE 6/1/2013

18 75401876, 75402065, 75402069






connecting to Sheffield.

WERE 6/1/2013

BONANZA - NORTH HUNTINGTON 69KV

Convert from 69KV to 161KV AEPW 6/1/2019

3. Additional GRDA resource, 4MW, as more specifically identified in

transmission request 1457536 replaced by 74107443 combined into

75402384, 75402413, and 75402421. Contingent upon the completion of

required upgrades as specified below, designation of these Network

Resources shall be effective on June 1, 2010 and remain effective through

June 1, 2026.


following aggregate study SPP-2008-AGP1 allocated network upgrades.



the Tariff.

Service Upgrades



ARCADIA - REDBUD 345KV CKT 3

Add eight mile 3rd 345 kV line from Redbud to Arcadia

OKGE 6/1/2019

ARCADIA (ARCADIA2) 345/138/13.8KV

TRANSFORMER CKT 1 Accelerate

Add 3rd 345/138KV Auto and convert the 345kV and 138kV to a breaker and a half configuration.

OKGE 6/1/2010

BRYANT - MEMORIAL 138KV CKT 1 Change out wavetrap to 2000A OKGE 6/1/2019

4. Additional Westar Energy Purchase, 5MW, as more specifically identified

in transmission service request 1223078 Replaced by 73235882 combined

into 75349562 and 75406660. Contingent upon the completion of

19 75401876, 75402065, 75402069

required upgrades as specified below, designation of these resources shall

be effective on January 1, 2010 and shall remain effective through April 1,

2022.


following aggregate study SPP-2007-AG1 allocated Network Upgrades.



the Tariff.

Service Upgrades



Craig 161kV 20MVar Cap Bank Upgrade

Additional 20 MVAR to make a total of 70 MVAR at Craig 542978 KACP 6/1/2011

EVANS ENERGY CENTER SOUTH -

LAKERIDGE 138KV CKT 1 Displacement










5. Initial pooling of KPP Pool load and resources in Mid-Kansas Electric

Company Zone as more specifically identified in the study of transmission

service request 1223078 replaced by 1610083 replaced by 74243470



20 75401876, 75402065, 75402069

effective on March 1, 2008 and shall remain effective through June 1,

2026.









6. Addition of City of Greensburg-3MW, as more specifically identified in

the study of transmission service request 1457802 replaced by 74116547





following aggregate study SPP-2008-AGP1 Transmission Owner

Reliability and Construction Pending Upgrades resulting from the SPP

Expansion Plan. These upgrades costs are not assignable to the Network

Customer.



KNOLL - AXTELL 345KV CKT 1 MIDW

Build a new 345kV line from Knoll - Axtell MIDW 6/1/2010

KNOLL 345/230 KV TRANSFORMER

Add new 345/230 KV TRANSFORMER MIDW 6/1/2010

KNOLL - AXTELL 345KV CKT 1 NPPD

Build a new 345kV line from Knoll - Axtell

NPPD 6/1/2010

SPEARVILLE - KNOLL 345KV CKT 1 MIDW

Build a new 345kV line from Spearville - Knoll MIDW 6/1/2010

SPEARVILLE - KNOLL 345KV CKT 1 SUNC

Build a new 345kV line from Spearville - Knoll SUNC 6/1/2010

21 75401876, 75402065, 75402069

7. Addition of City of Marion, 6MW, as more specifically identified in

transmission request 1607046 combined into 75401876. Contingent upon


these resources shall be effective on April 1, 2011 and shall remain






Priority Project Upgrades


Date Required in

Service Line - Comanche County - Medicine Lodge 345 kV

dbl ckt


MKEC 4/1/2011


OKGE


OKGE 4/1/2011


SPS


SPS 4/1/2011


MKEC

Build a new 35 mile double circuit 345 kV line with at least 3000 A capacity from the new Medicine

Lodge 345 kV substation to the WR interception from the Wichita

substation.

MKEC 4/1/2011


WERE


MKEC 4/1/2011


dbl ckt MKEC


MKEC 4/1/2011


dbl ckt SUNC

Build a new 27.5 mile double circuit 345 kV line with at least 3000 A

capacity from the Spearville substation to the MKEC interception

point from the new Comanche County substation.

SUNC 4/1/2011

22 75401876, 75402065, 75402069

8. Addition of Greensburg Wind resource, 12.5MW, as more specifically

identified in transmission request 73447072, 73450023, and 73450028

replaced by 75402446, 75402448, and 75402460. Contingent upon the

completion of required upgrades as specified below, designation of these

resources shall be effective on April 1, 2011 and shall remain effective

through April 1, 2021.





the Tariff.

Service Upgrades







MKEC

Build a new 28.6 mile dbl ckt 345 kV line with at least 3000 A capacity

from the Medicine Lodge sub to the KS/OK state border towards the

Woodward District EHV sub. Install the necessary breakers and terminal

equipment at the Medicine Lodge sub.

MKEC 4/1/2011


OKGE

Build a new 79 mile dbl ckt 345 kV line with at least 3000 A capacity

from the Woodward District EHV sub to the KS/OK state border towards the



OKGE 4/1/2011




WERE 4/1/2011

23 75401876, 75402065, 75402069


following aggregate study SPP-2009-AGP2 Reliability . These upgrades

costs are not assignable to the Network Customer.

Planned Projects Upgrade


Date Required in

Service BELL - PECK 69KV CKT 1


CT

WERE 6/1/2011

TIMBER JUNCTION -

UDALL 69KV CKT 1


WERE 6/1/2011

CLAY CENTER SWITCHING

STATION - TC RILEY 115KV

CKT 1

Build 6.7 mile 115 kV line with Single 1192.5 kcmil ACSR (Bunting) WERE 10/1/2012



9. Addition of Municipal Energy Agency of Nebraska resource, 1MW, as

more specifically identified in transmission request 73447046, 73450014,

and 73450018 combined into 75402711, 75402731, and 75402737,

Contingent upon the completion of required upgrades as specified below,

designation of these resources shall be effective on April 1, 2011 and shall

remain effective through April 1, 2021.





the Tariff.

Service Upgrades

24 75401876, 75402065, 75402069







following aggregate study SPP-2009-AGP2 Reliability and Upgrades.

These upgrades costs are not assignable to the Network Customer.

Reliability Project Upgrade



OGALLALA 230/115KV

TRANSFORMER CKT 1

Replace 187MVA Ogallala transformer with 336MVA

Ogallala transformer

NPPD

6/1/2017




Line - Comanche County - Medicine

Lodge 345 kV dbl ckt


MKEC 4/1/2011


ckt OKGE


OKGE 4/1/2011


ckt SPS


SPS 4/1/2011


ckt MKEC

Build a new 35 mile double circuit 345 kV line with at least 3000 A capacity from the new Medicine Lodge 345 kV substation to the

WR interception from the Wichita substation.

MKEC 4/1/2011


ckt WERE


MKEC 4/1/2011

25 75401876, 75402065, 75402069




kV dbl ckt MKEC


MKEC 4/1/2011


kV dbl ckt SUNC

Build a new 27.5 mile double circuit 345 kV line with at least

3000 A capacity from the Spearville substation to the

MKEC interception point from the new Comanche County

substation.

SUNC 4/1/2011


dbl Ckt MKEC

Build a new 28.6 mile dbl ckt 345 kV line with at least 3000 A

capacity from the Medicine Lodge sub to the KS/OK state border

towards the Woodward District EHV sub. Install the necessary

breakers and terminal equipment at the Medicine Lodge sub.

MKEC 4/1/2011


dbl Ckt OKGE

Build a new 79 mile dbl ckt 345 kV line with at least 3000 A capacity from the Woodward

District EHV sub to the KS/OK state border towards the Medicine

Lodge sub. Upgrade the Woodward District EHV sub with

the necessary breakers and terminal equipment.

OKGE 4/1/2011




WERE 4/1/2011






ACSR and replace CT

WERE 6/1/2011

26 75401876, 75402065, 75402069




1


ACSR

WERE 6/1/2011



10. Pooling of KPP Pool load and resources in Midwest Energy, Mid-Kansas

Electric Company, and Westar Energy Zones as more specifically

identified in the study of transmission service request 73446841 replaced

by 75401876,75402065, and 75402069. Contingent upon the completion

of required upgrades as specified below, designation of these resources

shall be effective on April 1, 2011 and shall remain effective through June

1, 2026.





the Tariff.

Service Upgrades








27 75401876, 75402065, 75402069





Date Required in

Service



ACSR and replace CT

WERE 6/1/2011


1


ACSR WERE 6/1/2011



11. Additional Kansas City Power and Light Purchase, 45MW, as more

specifically identified in transmission requests 74236802, 74236811, and

74236821 replaced by 75402762, 75402778, and 75402810. Contingent

upon the completion of required upgrades as specified below, designation

of these resources shall be effective on April 1, 2011 and shall remain

effective through April 1, 2016.





the Tariff.

Service Upgrades






28 75401876, 75402065, 75402069


following aggregate study SPP-2009-AGP2 Expansion Plan Upgrade and

Priority Projects. These upgrades costs are not assignable to the Network

Customer.

Expansion Plan Upgrades


Date Required in

Service

Line - Iatan - Nashua 345 kV

Tap Nashua 345kV bus in Hawthorn-St. Joseph 345kV line, add Iatan-Nashua

345kV line and Nashua 345/161kv transformer

KCPL

6/1/2012



Date Required in

Service Line - Comanche

County - Medicine Lodge 345 kV dbl ckt


MKEC 4/1/2011


ckt OKGE


OKGE 4/1/2011


ckt SPS


SPS 4/1/2011


ckt MKEC

Build a new 35 mile double circuit 345 kV line with at least 3000 A capacity

from the new Medicine Lodge 345 kV substation to the WR interception from

the Wichita substation.

MKEC 4/1/2011


ckt WERE


MKEC 4/1/2011


kV dbl ckt MKEC


MKEC 4/1/2011

29 75401876, 75402065, 75402069


Date Required in

Service


kV dbl ckt SUNC

Build a new 27.5 mile double circuit 345 kV line with at least 3000 A capacity from the Spearville substation to the

MKEC interception point from the new Comanche County substation.

SUNC 4/1/2011


dbl Ckt MKEC

Build a new 28.6 mile dbl ckt 345 kV line with at least 3000 A capacity from the Medicine Lodge sub to the KS/OK

state border towards the Woodward District EHV sub. Install the necessary breakers and terminal equipment at the

Medicine Lodge sub.

MKEC 4/1/2011


dbl Ckt OKGE

Build a new 79 mile dbl ckt 345 kV line with at least 3000 A capacity from the

Woodward District EHV sub to the KS/OK state border towards the



OKGE 4/1/2011


Install a 400 MVA 345/138 kV transformer at the new 345 kV Medicine

Lodge substation.

WERE 4/1/2011



Date Required in

Service BELL - PECK 69KV

CKT 1


CT

WERE 6/1/2011


1


WERE 6/1/2011

30 75401876, 75402065, 75402069


Date Required in

Service



12. Dogwood Purchase, 40MW, as more specifically identified in

transmission request 74234218 Contingent upon the completion of

required upgrades as specified below, designation of this resource shall be






the Tariff.

Service Upgrades



EL PASO - FARBER 138KV CKT 1

Tear down / Rebuild 3.1 miles with dual 477 ACSR WERE 6/1/2014


following aggregate study SPP-2010-AGP1 Construction Pending and

Planned Project Upgrade. These upgrades costs are not assignable to the

Network Customer.

Construction Pending



31 75401876, 75402065, 75402069




Planned Projects





ACSR and replace CT

WERE 6/1/2014

BELL - SUMNER COUNTY NO. 3

MILLER 69KV CKT 1


WERE 6/1/2014


SUMNER COUNTY NO. 3 MILLER 69KV CKT 1


WERE 6/1/2014


SUMNER COUNTY NO. 4 ROME 69KV

CKT 1


WERE 6/1/2014

CRESWELL - SUMNER COUNTY NO. 4 ROME 69KV

CKT 1


WERE 6/1/2014

TIMBER JUNCTION -

UDALL 69KV CKT 1


WERE 6/1/2014

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.

32 75401876, 75402065, 75402069

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

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

33 75401876, 75402065, 75402069

Appendix 1

Network Resources of

Kansas Power Pool

34 75401876, 75402065, 75402069

APPENDIX 1: Kansas Power Pool NETWORK RESOURCES

Maximum Net

Dependable

Capacity Network

Resource Summer Winter Location Comments



Attica Gen ATI4 0.7 0.7 Harper County, KS Kingman Gen


KS Kingman Gen


KS Kingman Gen


KS AugN1 3.8 3.8 Butler Co., KS AugN2 3.8 3.8 Butler Co., KS AugN3 5.7 5.7 Butler Co., KS AugN4 6.7 6.7 Butler Co., KS Bur1A 2.3 2.3 Coffey Co, KS Bur4A 3 3 Coffey Co, KS Bur6 4.8 4.8 Coffey Co, KS

ClayD1 2.8 2.8 Clay Co., KS Effective 1/1/2012

ClayD2 3.5 3.5 Clay Co., KS ClayD3 4.5 4.5 Clay Co., KS ClayD4 1.9 1.9 Clay Co., KS ClayD6 6.7 6.7 Clay Co., KS ClayST1 5 5 Clay Co., KS Dogwood 40 40 Cass, MO Effective

6/1/2014 Elw1 1.7 1.7 Barton Co., KS Elw5 2.9 2.9 Barton Co., KS Effective

1/1/2014 MinD6 3 3 Ottawa Co., KS Ox1 1.5 1.5 Sumner Co., KS Ox2 1.5 1.5 Sumner Co., KS

WellGT 21.5 21.5 Nemaha Co., KS WellST 20 20 Sumner Co., KS WellD1 2 2 Sumner Co., KS WellD2 2 2 Sumner Co., KS WinfGT 10.3 10.3 Cowley Co., KS Effective

1/1/2013 WinfST 26.7 26.7 Cowley Co., KS WinfD1 2.4 2.4 Cowley Co., KS WinfD2 2.4 2.4 Cowley Co., KS

35 75401876, 75402065, 75402069

Grand River Dam Authority Purchase

15.3 15.3 Mayes Co., OK

Nearman Power Sales Contract

12.5 12.5 Wyanodotte Co., KS

Greensburg Wind 0 0 Kiowa Co., KS Firm Transmission for

12.5MW Displacement

Agreement between

Municipal Energy Agency of

Nebraska and Western Area

Power Administration comprising of

generation from Ansley for 1.5MW,

Benkelman 0.8MW, Broken

Bow 7.3MW, Burwell 3.3MW, Callaway 1MW, Crete 6.1MW, Curtis 3.1MW, Oxford 3.7MW, Pender 4.4MW,

Red Cloud 4.4MW, Sargent 2.3MW, Stuart 1.8MW, West

Point 4MW, and Fairbury 16MW

2.8 2.8 Term of

Service:4/1/2011 to 4/1/2021

Power Sales Contract between

Southwestern Power

Administration and Kansas

Municipal Energy Agency

5.1 5.1

Westar Energy Coal Purchase - Jeffrey Energy Center 1, 2, 3

50MW beginning 4/1/2011 and increasing to

59MW beginning 1/1/2012

59 Potowatomie Co., KS.

36 75401876, 75402065, 75402069

Appendix 2

Receipt Points of

Kansas Power Pool

37 75401876, 75402065, 75402069

APPENDIX 2: Kansas Power Pool RECEIPT POINTS

Tieline / Plant Name Ownership Voltage (kV)

SWPA-WERE SWPA and WERE various SWPA-MWE SWPA, WERE, and MWE various SWPA-WPEK SWPA, WERE and WPEK various GRDA-WERE GRDA and WERE various GRDA-MWE GRDA, WERE, and MWE various GRDA-WPEK GRDA, WERE, and WPEK various Jeffrey-WERE WERE various Jeffrey-MWE WERE and MWE various Jeffrey-WPEK WERE and WPEK various Nearman-WERE KCBPU and WERE various Nearman-MWE KCBPU, WERE and MWE various Nearman-WPEK KCBPU, WERE and WPEK various NPPD-WERE NPPD and WERE various NPPD-MWE NPPD, MWE and WERE various NPPD-WPEK NPPD, WPEK and WERE various WERE Coal-WERE WERE various WERE Coal-MWE WERE and MWE various WERE Coal-WPEK WERE and WPEK various KPP WERE Muni-WERE WERE various KPP WERE Muni-MWE WERE and MWE various KPP WERE Muni-WPEK WERE and WPEK various KPP-MWE Muni - MWE MWE various KPP MWE Muni-WERE MWE and WERE various KPP MWE Muni-WPEK MWE, WERE and WPEK various KPP WPEK Muni-WPEK WPEK various KPP WPEK Muni-WERE WPEK and WERE various KPP WPEK Muni-MWE WPEK, WERE and MWE various Greensburg Wind KPP 34.5 City of Attica Generation KPP 34.5 City of Kingman Generation KPP 34.5

38 75401876, 75402065, 75402069

Appendix 3

Delivery Points of

Kansas Power Pool

39 75401876, 75402065, 75402069

APPENDIX 3 Kansas Power Pool

Delivery Points

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


Delivery Point Name


(2) Meter

Ownership


(1) 533582 AUGUSTA2 69.0 kV City of Augusta 69 Westar



12.5 (Low Side)/(b)


12.5 (Low Side)/(b)

533625 BURLIND2 69.0 kV City of Burlington 69 Westar

12.5 (Low Side)/(b)

533323 CLAYCTR3 115.0 kV City of Clay Center 34.5 Westar

12.5 (Low Side)/(b)

533323 CLAYCTR3 115.0 kV

City of Clay Center 115 kV (ii) 115 Westar


533760 ERIE 2 69.0 kV

City of Erie Gen Aux 69 Westar

0.48 (Bus)/(h)

533760 ERIE 2 69.0 kV City of Erie North 69 Westar


533760 ERIE 2 69.0 kV City of Erie South 2.4 Westar

2.4 (Low Side)/(b)

533732 BURRTON2 69.0 kV

City of Haven Industrial Park 12.5 Westar

12.5 (Circuit)/(d)

533732 BURRTON2 69.0 kV

City of Haven Residential 2.4 Westar

2.4 (Bus)/(e)

533369 HILSBOR3 115.0 kV City of Hillsboro 12.5 Westar

12.5 (Low Side)/(b)

533366 FLORENC3 115.0 kV City of Marion 12.5 Westar

12.5 (Low Side)/(b)

533376 SALINA 3 115.0 kV City of Minneapolis 34.5 Westar

34.5 (Transmission)/(a)

533732 BURRTON2 69.0 kV

City of Mount Hope 12.5 Westar

12.5 (Circuit)/(d)

532982 OXFORD 4 138.0 kV City of Oxford 12.5 Westar

12.5 (Circuit)/(d)

532852 JEC 6 230.0 kV City of St Marys 12.5 Westar

12.5 (Low Side)/(b)

533559 UDALL 2 69.0 kV City of Udall 12.5 Westar

12.5 (Circuit)/(d)

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


Delivery Point Name


(2) Meter

Ownership


(1) 533332 KNOB HL3 115 kV City of Waterville 4.2 Westar

4.2 (Bus)/(b)

533560 WELLING2 69.0 kV

City of Wellington #2 69 Westar

12.5 (Low Side)/(b)

533556 STROTHR2 69.0 kV

City of Winfield Oak to Strother 69 Westar


533561 WINFLD2 69.0 kV

City of Winfield Weaver to Oak 69 Westar


533323 CLAYCTR3 115.0 kV Riley 115 kV (i) 115 Westar


532852 JEC 6 230.0 kV

St Marys Deduct (iii) 12.5 Westar

0.48 (Circuit)/(h)

533557 TIMBER 2 69.0 kV Winfield Lakes 12.5 Westar

12.5 (Circuit)/(d)

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. After September 1, 2012, the applicable Loss Factor, from the Loss Factor tables included in Section 28.5 of Westar Energy’s OATT, are identified as (a) through (h) in the Notes column of those tables. Any special configuration not represented in (a) through (h) will be outlined as a special footnote within this appendix.

(2) The Points of Delivery under this NITSA are located at, or immediately adjacent to, the connection between Westar Energy’s facilities and the Network Customer’s facilities.

(i) Riley 115 kV planned in-service is 10/1/2012. This in-service date is contingent upon completion of the Chapman Junction 115KV, Chapman Junction 115V Capacitor, Clay Center Junction 115KV, Clay Center Junction - Clay Center Switching Station 115KV CKT 1, Clay Center Switching Station - TC Riley 115KV CKT 1, and TC Riley 115KV planned upgrades, identified in Section 8.10 of Attachment 1 of this Agreement.

(ii) City of Clay Center 115 kV planned in-service is 10/1/2012. This in-service date is contingent upon completion of the Chapman Junction 115KV, Clay Center Junction 115KV, Clay Center Junction - Clay Center Switching Station - 115KV CKT 1, and Clay Center Switching Station 115 KV planned upgrades, identified in Section 8.10 of Attachment 1 of this Agreement.

(iii) St Marys Deduct is a reduction to the City of St Marys delivery point.

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Continue APPENDIX 3 - Midwest Energy System

Kansas Power Pool

Delivery Points on Midwest Energy Transmission and Distribution System

SPP Bus Number Delivery Point Name Ownership Voltage (kV) (Meter) (Location)

Midwest Energy Delivery Points:

530575 North Ellinwood -Ellinwood Midwest Energy 4.2 kV

(Low Side)

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Continue APPENDIX 3 – Mid Kansas Electric Company Kansas Power Pool Delivery Points on Mid Kansas Electric Company Transmission and Distribution System for

Kansas Power Pool (KPP):

SPP Bus Number Delivery Point Name Ownership Voltage (kV) Mid Kansas Electric Company

Delivery Points:

539726 serves Kingman Pratt 34.5 KV


34.5

539668 serves Attica and Kingman

Harper 138 KV


138.0

539734 serves Lucas and Luray Waldo 34.5kV Mid Kansas Electric Company

34.5

539708 serves Holyrood Ellsworth 34.5kV Mid Kansas Electric Company

34.5

539710 Greensburg 34.5kV Mid Kansas Electric Company

34.5

Note: Transmission service to Lucas and Luray begins 1/1/2010. Service to Holyrood begins 5/1/2010. Greensburg service to begin 6/1/2010.

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Attachment A


44 75401876, 75402065, 75402069

Attachment A


Posted Study

Request





FROM->TO Upgrade Set #1: ALLEN - LEHIGH TAP 69KV CKT 1 Athens to Owl Creek 69 kV BURLINGTON JUNCTION - COFFEY COUNTY NO. 3 WESTPHALIA 69KV CKT 1 BURLINGTON JUNCTION - WOLF CREEK 69KV CKT 1 COFFEY COUNTY NO. 3 WESTPHALIA - GREEN 69KV CKT 1 Green to Vernon 69 kV LEHIGH TAP - OWL CREEK 69KV CKT 1 Vernon to Athens 69 kV













FROM->TO Upgrade Set #1 0.2 ORCHARD - UNITED NO. 7 ROSE 69KV CKT 1


45 75401876, 75402065, 75402069

Posted Study

Request





FROM->TO Upgrade Set #1 0.136 ATHENS SWITCHING STATION - OWL CREEK 69KV CKT 1






TO->FROM Upgrade Set #2: Athens to Owl Creek 69 kV BURLINGTON JUNCTION - COFFEY COUNTY NO. 3 WESTPHALIA 69KV CKT 1 BURLINGTON JUNCTION - WOLF CREEK 69KV CKT 1 COFFEY COUNTY NO. 3 WESTPHALIA - GREEN 69KV CKT 1 Green to Vernon 69 kV LEHIGH TAP - OWL CREEK 69KV CKT 1 Vernon to Athens 69 kV

0.51 ALLEN - LEHIGH TAP 69KV CKT 1






FROM->TO Upgrade Set #2 2 ALTOONA - TIOGA 138KV CKT 1



FROM->TO Upgrade Set #2 2 TIOGA (TIOGA 1X) 138/69/13.2KV TRANSFORMER CKT 1





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Posted Study

Request














FROM->TO Upgrade Set #2 .54 ALTOONA - TIOGA 138KV CKT 1




UNITED NO. 1 ELSMORE - ZILA JUNCTION 69KV CKT 1






FROM->TO Upgrade Set #2 0.51 LITCHFIELD - PITNAC 69KV CKT 1





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Posted Study

Request















MARMATON - UNITED NO. 1 ELSMORE 69KV CKT 1

















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Posted Study

Request


































49 75401876, 75402065, 75402069

Posted Study

Request








TO->FROM Upgrade Set #2 0.13 COFFEYVILLE TAP - DEARING 138KV CKT 1









TO->FROM Upgrade Set #2 1.86

TIOGA (TIOGA 1X) 138/69/13.2KV TRANSFORMER CKT 1

















50 75401876, 75402065, 75402069

Posted Study

Request











FROM->TO Upgrade Set #2 0.27 ALLEN - LEHIGH TAP 69KV CKT 1











51 75401876, 75402065, 75402069

Additional Interim Redispatch Required for Transmission Service

Posted Study

Request



(MW)



FROM->TO

Upgrade Set #1: ALLEN - LEHIGH TAP 69KV CKT 1 Athens to Owl Creek 69 kV BURLINGTON JUNCTION - COFFEY COUNTY NO. 3 WESTPHALIA 69KV CKT 1 BURLINGTON JUNCTION - WOLF CREEK 69KV CKT 1 COFFEY COUNTY NO. 3 WESTPHALIA - GREEN 69KV CKT 1 Green to Vernon 69 kV LEHIGH TAP - OWL CREEK 69KV CKT 1 Vernon to Athens 69 kV




FROM->TO




FROM->TO




FROM->TO




FROM->TO

Upgrade Set #1 1.2 ORCHARD - UNITED NO. 7 ROSE 69KV CKT 1



FROM->TO

Upgrade Set #1 0.9 ATHENS SWITCHING STATION - OWL CREEK 69KV CKT 1



FROM->TO



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Posted Study

Request



(MW)


1222932 ARKANSAS CITY - PARIS 69KV CKT 1

TO->FROM

ARKANSAS CITY - PARIS 69KV CKT 1 #1 Displacement

0.7 CRESWELL - OAK 69KV CKT 1



FROM->TO

Upgrade Set #2: Athens to Owl Creek 69 kV BURLINGTON JUNCTION - COFFEY COUNTY NO. 3 WESTPHALIA 69KV CKT 1 BURLINGTON JUNCTION - WOLF CREEK 69KV CKT 1 COFFEY COUNTY NO. 3 WESTPHALIA - GREEN 69KV CKT 1 Green to Vernon 69 kV LEHIGH TAP - OWL CREEK 69KV CKT 1 Vernon to Athens 69 kV

10.9 TIOGA (TIOGA 1X) 138/69/13.2KV TRANSFORMER CKT 1



TO->FROM




FROM->TO




TO->FROM




FROM->TO




FROM->TO




FROM->TO



53 75401876, 75402065, 75402069

Posted Study

Request



(MW)



TO->FROM




FROM->TO




FROM->TO




FROM->TO




FROM->TO




FROM->TO




FROM->TO




FROM->TO




FROM->TO



54 75401876, 75402065, 75402069

Posted Study

Request



(MW)



FROM->TO




FROM->TO




FROM->TO




FROM->TO




FROM->TO




TO->FROM




FROM->TO




TO->FROM




FROM->TO



55 75401876, 75402065, 75402069

Posted Study

Request



(MW)



FROM->TO




FROM->TO




FROM->TO




FROM->TO




FROM->TO




TO->FROM




TO->FROM




TO->FROM




TO->FROM




FROM->TO




FROM->TO



56 75401876, 75402065, 75402069

Posted Study

Request



(MW)



FROM->TO

Upgrade Set #2 3.2 LITCHFIELD - PITNAC 69KV CKT 1



FROM->TO




FROM->TO




FROM->TO




TO->FROM




FROM->TO




TO->FROM




FROM->TO




TO->FROM




TO->FROM



57 75401876, 75402065, 75402069

Posted Study

Request



(MW)



TO->FROM




TO->FROM

Upgrade Set #2 1.1 COFFEYVILLE TAP - DEARING 138KV CKT 1



CKT 1

TO->FROM

Upgrade Set #3 Line - Comanche County - Medicine Lodge 345 kV dbl ckt Line - Hitchland - Woodward 345 kV dbl ckt OKGE Line - Hitchland - Woodward 345 kV dbl ckt SPS Line - Medicine Lodge - Wichita 345 kV dbl ckt MKEC Line - Medicine Lodge - Wichita 345 kV dbl ckt WERE Line - Spearville - Comanche County 345 kV dbl ckt MKEC Line - Spearville - Comanche County 345 kV dbl ckt SUNC Line - Woodward - Comanche County 345 kV dbl ckt MKEC Line - Woodward - Comanche County 345 kV dbl ckt OKGE

1.1 EVANS ENERGY CENTER SOUTH -

LAKERIDGE 138KV


Upgrade

73450023 CRESWELL - OAK 69KV CKT 1

FROM->TO

CRESWELL - OAK 69KV CKT 1 1.7 CRESWELL - PARIS 69KV CKT 1


Upgrade 73450023

CITY OF WINFIELD - TIMBER JUNCTION

69KV CKT 1

TO->FROM



Upgrade 74236802 CRESWELL - OAK

69KV CKT 1 FROM-

>TO CRESWELL - OAK 69KV CKT 1 6.1 CRESWELL - PARIS

69KV CKT 1 Starting 2012 6/1 - 10/1 Until EOC of

Upgrade

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Posted Study

Request



(MW)



CKT 1

TO->FROM

Upgrade Set #3 3.3 EVANS ENERGY CENTER SOUTH -

LAKERIDGE 138KV


Upgrade 74236802 MUND - PENTAGON

115KV CKT 1 TO-

>FROM Line - Iatan - Nashua 345 kV 1.8 87TH 7 345.00 -

CRAIG 345KV CKT 1 Starting 2012 12/1 -

4/1 Until EOC of Upgrade

74236802 CITY OF WINFIELD - TIMBER JUNCTION

69KV CKT 1

TO->FROM



Upgrade

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Attachment B

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Attachment B

Maximum Firm Import Capability before completion of the following upgrades Upgrade: TIMBER JUNCTION 138 kV Capacitor Sumner County to Timber Junction 138/69 kV RICHLAND - ROSE HILL JUNCTION 69KV CKT 1 ROSE HILL JUNCTION - WEAVER 69KV CKT 1 Season Identified: 2010 Summer Peak

KPP SINK Maximum Firm Import Capability (MW)1 Applicable Period Most Limiting Criteria Violation

WELLINGTON 17 June - September Creswell - Sumner County No. 4 Rome 69kV

Ckt 1 overload for Gill-Peck 69kV outage

WINFIELD 47 June - September 138kV low voltages for Transmission Operating

Directive for El Paso-Farber 138kV outage

WINFIELD 52 June - September Creswell-Oak 69kV overload for Creswell -

Paris 69kV outage

WINFIELD 53 June - September Rose Hill Junction - Weaver 69 kV Ckt 1

overload for El Paso-Farber 138kV outage OXFORD, WELLINGTON, and WINFIELD Simultaneous

472 June - September

138kV low voltages for Transmission Operating Directive for El Paso-Farber 138kV outage


Rose Hill Junction - Weaver 69 kV Ckt 1 overload for El Paso-Farber 138kV outage


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Attachment C

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Attachment C

Maximum Firm Import Capability Upgrade: N/A

KPP SINK Maximum Firm Import

Capability (MW) Applicable Period Most Limiting Criteria Violation CLAY CENTER 13.1 kV 15 June - September

Clay Center Junction 115/34.5kV transformer overload for System Intact

Maximum Firm Import Capability after completion of the following upgrades Upgrade: TIMBER JUNCTION 138 kV Capacitor Sumner County to Timber Junction 138/69 kV RICHLAND - ROSE HILL JUNCTION 69KV CKT 1 ROSE HILL JUNCTION - WEAVER 69KV CKT 1 Season Identified: 2019 Summer Peak

KPP SINK Maximum Firm Import Capability

(MW)1 Applicable Period Most Limiting Criteria Violation

WELLINGTON 17 June - September Creswell - Sumner County No. 4 Rome 69kV Ckt 1

overload for Gill-Peck 69kV outage

WINFIELD 68 June - September Creswell-Oak 69kV overload for Creswell - Paris 69kV

outage OXFORD, WELLINGTON, and WINFIELD Simultaneous 732 June - September

Creswell - Newkirk 138kV overload for Transmission Operating Directive for El Paso-Farber 138kV outage


Richland - Udall 69kV overload for El Paso-Farber 138kV outage


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Maximum Firm Import Capability after completion of upgrades Upgrade: Green to Vernon 69 kV Vernon to Athens 69 kV Athens to Owl Creek 69 kV TIOGA 69KV Capacitor LEHIGH TAP - OWL CREEK 69KV CKT 1 ALLEN 69KV Capacitor BURLINGTON JUNCTION - WOLF CREEK 69KV CKT 1 ATHENS 69KV Capacitor

BURLINGTON JUNCTION - COFFEY COUNTY NO. 3 WESTPHALIA 69KV CKT 1

COFFEY COUNTY NO. 3 WESTPHALIA - GREEN 69KV CKT 1 Season Identified: 2019 Summer Peak

KPP SINK Maximum Firm Import Capability (MW)1 Applicable Period Most Limiting Criteria Violation CHANUTE,ERIE, and IOLA Simultaneous 1012 June - September

Allen - Monarch 69kV overload for Altoona-Tioga 138kV outage

1 Maximum Firm Import Capability based on 98% Lagging Power Factor at all Point of Interconnections 2 Chanute, Erie, and Iola restriction is based upon common constraints limiting simultaneous Maximum Firm Import Capability for these cities Note: Long-Term Firm Import Capacity for Chanute, Erie, and Iola will be reviewed upon actual in-service date of

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Appendix 4

Wholesale Distribution Charges

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APPENDIX 4

Kansas Power Pool

Total Monthly Wholesale Distribution Service Charge

Municipal Monthly Wholesale

Distribution Service Charge Haven $2,651.22 Hillsboro $873.10 Marion $22.74 Mount Hope $1,525.73 Oxford $1,694.32 St Marys $2,203.21 Udall $830.62 Waterville $383.31 Winfield $40.05

Total Monthly Wholesale Distribution Service Charge $10,224.30

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Appendix 5

Service Agreement for Ancillary Services

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Appendix 5

Service Agreement for Ancillary Services 1.0 This Service Agreement for Ancillary Services, dated as of March 1, 2008 (“ Service

Agreement”), is entered into, by and between Southwest Power Pool, Inc. (“SPP” or “Transmission Provider”), Mid-Kansas Electric Corporation, LLC (“MKEC” or “Transmission Owner”) and Kansas Power Pool (“Transmission Customer”). Transmission Provider and, Transmission Owner and Transmission Customer each may be referred to as a “Party” or collectively as the “Parties”.

2.0 The Transmission Customer is a Network Transmission Service customer under the SPP

Tariff for the cities of Attica and Kingman, Kansas. 3.0 Service under this Service Agreement shall commence on March 1, 2008, and shall be

effective through March 1, 2018. Thereafter, it will continue from year to year unless terminated by the Transmission Customer, the Transmission Provider or the Transmission Owner by giving the other Parties one-year advance written notice or by the mutual written consent of the Parties. In recognition of Transmission Customer’s continued efforts to develop an operational pool and to include additional participants therein, this Service Agreement will apply to such additional participants if and when Transmission Customer adds such additional participants to such operational pool; provided such additional participants are located within the Mid Kansas Electric Corporation Zone. Additionally, upon the date when the Transmission Provider can directly supply one or more of the Ancillary Services provided for in this Service Agreement, such service shall be taken from the Transmission Provider rather than from Transmission Owner unless otherwise self-supplied. Each Ancillary Service supplied under this Service Agreement can be individually transferred to the Transmission Provider to supply that service prior to the termination date of this Service Agreement.

4. 0 The Transmission Customer may self-supply all or a portion of its Ancillary Services as provided in the Tariff and this Service Agreement. The ability of the Transmission Customer to self-supply an Ancillary Service will begin upon the satisfactory demonstration to the Transmission Provider that the Transmission Customer has the ability to self-supply that specific Ancillary Service. To self-supply an Ancillary Service, the Transmission Customer must meet the appropriate North American Electric Reliablity Corporation (“NERC”), Tariff and SPP criteria including the criteria attached hereto as Attachment 1, for the requested self-supplied Ancillary Service. In the event that the Transmission Customer fails to self-supply all or a portion of those Ancillary Services it has been approved to self-supply in sufficient quantities to satisfy the requirements of the Tariff, the Transmission Customer shall be assessed the appropriate penalty charge as provided in the Tariff. Transmission Customer resources that the Transmission Provider has determined meet these criteria and are eligible for credits are listed in Attachment 2 attached hereto.

5. 0 The Transmission Customer agrees to take and pay for Transmission Service and

Ancillary Service in accordance with the provisions of the Tariff and this Service Agreement, including the Billing Principles attached hereto as Attachment 3.

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6.0 In the event that transmission service to the Transmission Customer is unavailable to one or more of the Transmission Customer’s delivery points, and the Transmission Customer has been directed to generate or reduce load by either the Transmission Provider or the Transmission Owner, the Transmission Provider will pro-rate down the capacity portion of the relevant monthly billing based upon the amount of load that could not receive the contracted for Ancillary Service and the duration of the interruption, consistent with the Tariff and this Service Agreement including the Billing Principles attached hereto as Attachment 3.

7.0 Transmission Provider shall have the right to make a unilateral filing with the Federal Energy Regulatory Commission (“FERC”) to modify this Service Agreement under Section 205 or any other applicable provision of the Federal Power Act and FERC's rules and regulations thereunder, and the Transmission Customer and Transmission Owner shall have the right to make a unilateral filing with FERC to modify this Service Agreement under Section 206 or any other applicable provision of the Federal Power Act and FERC's rules and regulations thereunder; provided that each Party shall have the right to protest any such filing by any other Party and to participate fully in any proceeding before FERC in which such modifications may be considered. Nothing in this Service Agreement shall limit the rights of the Parties or of FERC under Sections 205 or 206 of the Federal Power Act and FERC's rules and regulations thereunder, except to the extent that the Parties otherwise mutually agree as provided herein. The standard of review the Commission shall apply when acting on any such proposed modifications to the Service Agreement shall be the "just and reasonable" standard of review rather than the "public interest" standard of review.

8.0 Any notice or request made to or by any Party regarding this Service Agreement shall be

made to the representatives of the other Parties as indicated below.

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KPP: Transmission Customer MKEC: Transmission Owner Colin Whitley General Manager 200 West Douglas, Suite 601 Wichita, KS 67202 316-264-3166 [email protected]

L. Earl Watkins, Jr. President and CEO 301 West 13th Street Hays, Kansas 67601 785-628-2845

SPP: Transmission Provider Carl Monroe Executive Vice President, Operations and Chief Operating Officer 415 North McKinley, #140 Plaza West Little Rock, AR 72205-3020 501-614-3218 [email protected]

9.0 All the attachments to this Service Agreement are incorporated into and made a part of

this Service Agreement. The Tariff is incorporated herein and made a part hereof. 10.0 This Service Agreement may be executed in any number of counterparts, each of which

shall be an original, but all of which together shall constitute one instrument.

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IN WITNESS WHEREOF, the Parties have caused this Service Agreement to be executed by their respective authorized officials. KPP: Transmission Customer

By: ________________________________

Title: ______________________________

Date: _______________________________

MKEC: Transmission Owner

By: _______________________________

Title: ______________________________

Date: _______________________________

SPP: Transmission Provider

By: ________________________________

Title: ______________________________

Date: _______________________________

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Specifications for Providing Ancillary Services for Transmission Service 1.0 Transmission Customer’s Loads:

(a) Transmission Customer's Loads shall include any load served at points of delivery to which transmission service has been taken under the Tariff, located within the Mid Kansas Electric Corporation Zone.

2.0 Description of the Transmission Customer's transmission facilities integrated

with and supporting the Transmission Owner’s Transmission System: (a) None designated at this time. KPP preserves the right to apply for

recognition of customer-owned transmission. 3.0 Service under this Service Agreement shall be subject to the charges, terms

and conditions as stated in the Tariff, and the Billing Principles attached hereto as Attachment 3. 3.1 Scheduling and Tariff Administration Service (Schedules 1 & 1A); and

Reactive Supply and Voltage Control from Generation Sources Service (Schedule 2) shall be purchased from the Transmission Provider. Transmission Customer may receive any compensation or credits for Ancillary Service 2 for which Transmission Customer is eligible that Transmission Provider provides pursuant to the Tariff.

3.2 Regulation and Frequency Response Service (Schedule 3) shall be purchased from the Transmission Owner through Schedule 3 of the Tariff. The Transmission Customer will be able to self-supply this Ancillary Service when it has demonstrated to the Transmission Provider and the Transmission Provider has confirmed that the Transmission Customer has the proper control and metering equipment and has met all other requirements necessary to allow it perform this ancillary function on a continuous basis, pursuant to the appropriate NERC, Tariff, and SPP criteria, including the criteria in Attachment 1 attached hereto, and any other future regulations governing the Transmission Owner.

3.3 Energy Imbalance Service (Schedule 4) shall be purchased from the

Transmission Provider through the Transmission Provider’s real-time energy imbalance service market.

3.4 Operating Reserve-Spinning Reserve Service (Schedule 5) shall be

purchased or provided pursuant to Schedule 5 of the Tariff. The Transmission Customer will be able to self-supply this Ancillary Service

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when it has demonstrated to the Transmission Provider and the Transmission Provider has confirmed that the Transmission Customer has the proper control and metering equipment and has met all other requirements necessary to allow it to perform this ancillary function on a continuous basis, pursuant to the appropriate NERC, Tariff, and SPP criteria, including criteria in Attachment 1 attached hereto, and any other future regulations governing the Transmission Owner.

3.5 Operating Reserve-Supplemental Reserve Service (Schedule 6) shall be

purchased or provided pursuant to Schedule 6 of the Tariff. The Transmission Customer will be able to self-supply this Ancillary Service when it has demonstrated to the Transmission Provider and the Transmission Provider has confirmed that the Transmission Customer has the proper control and metering equipment and has met all other requirements necessary to allow it to perform this ancillary function on a continuous basis, pursuant to the appropriate NERC, Tariff, and SPP criteria, including criteria in Attachment 1 attached hereto, and any other future regulations governing the Transmission Owner.

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Requirements for Credits Against Ancillary Services and

Requirements for Demonstration of Self-Supply of Ancillary Services

A. Requirements for Credits Against Ancillary Service 2 Billing

1. Reactive Supply and Voltage Control from Generation Sources Service

("Ancillary Service 2") may not be self-supplied by a Transmission Customer.

Ancillary Service 2 must be purchased from the Transmission Provider

pursuant to the provisions of Schedule 2 to the Transmission Provider's Tariff.

2. The Transmission Provider will bill the Transmission Customer for

Ancillary Service 2 in all circumstances.

3. A Transmission Customer that is able to provide a Reactive Power

Resource(s) delivered to the Transmission Provider’s Transmission System

that contributes to the Transmission Provider's or Host Transmission Owner's

supply of Reactive Power Resources necessary for their provision of Ancillary

Service 2 may receive credits for those Reactive Power Resources that it is

willing to commit pursuant to the provisions of the Tariff.

4. The Reactive Resource must be subject to the contractual control or

functional control of the Transmission Customer.

5. Where the Transmission Customer is relying on a contractual

arrangement to make available a Reactive Power Resource, the supplier or

functionary providing or operating the Transmission Customer's generation

resource must demonstrate with sufficient clarity that the Reactive Power

Resource is functioning on behalf of the Transmission Customer to meet a

portion of the Reactive Power supply obligation of the Transmission Provider

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and Transmission Owner for which the Reactive Power Resource credit is

sought.

6. The Transmission Customer is fully responsible for the compliance and

functional performance of the Reactive Power Resource (s) and/or service

provider(s) for which it has a contractual arrangement.

7. The Transmission Provider or the Host Transmission Owner will

provide credits to the Transmission Customer pursuant to a bilateral

agreement between the Transmission Provider or Host Transmission Owner

and the Transmission Customer provided that:

a. The Reactive Power Resource is be operated within, or

electronically encompassed by, the host control system contributing

reactive power on a real-time basis for the provision of Ancillary

Service 2. Reactive Power Resources located outside the

Transmission Provider’s Transmission System are not eligible for

credits.

b. The voltage regulator on the Reactive Power Resource is in

service in the automatic mode and the Reactive Power

Resource is available and able to follow a voltage or power factor

schedule on the transmission interface for the point of

receipt/delivery at the direction of the Transmission Provider or

Control Area Operators.

c. The Reactive Power Resource meets the directed voltage or power

factor schedule within +/-1%, but not to exceed the design

capability of the equipment.

d. The Transmission Customer provides, or causes to be provided,

telemetry of the real and reactive power output of the Reactive

Power Resource(s) and the voltage(s) at the point(s) on the

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transmission system where voltage or power factor schedule(s) are

to be followed. Telemetry will be provided at a 4 to 10 second

sampling rates to the host control area operator on a continuous

basis and shall otherwise be consistent with the requirements of the

Metering Agreement attached hereto as Attachment 3 of this

Service Agreement.

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B. Requirements for Demonstration of Self Supply of Ancillary Services 3, 5 and 6

1. The generation resource(s), owned by the Transmission Customer or utilized by

contract, providing the Ancillary Service(s) must fully comply with SPP and NERC

Criteria with no finding of material non-compliance during the operation of the Resource.

2. Where the Transmission Customer is relying on a contractual arrangement to

meet a portion or all of its obligations, the supplier or functionary providing or operating

the Transmission Customer's generation resource must demonstrate with sufficient

clarity that the generation resource is functioning on behalf of the Transmission

Customer to meet that portion of the Ancillary Service(s) obligation of the Transmission

Customer for which the generation resource is claimed.

3. Firm power service (purchases including regulation, spinning and non-spinning

reserves) will reduce the AS 3, AS 5 and AS 6 responsibilities of the Transmission

Customer.

4. The Transmission Customer must sufficiently notify the Transmission Provider

and the affected Control Area Operator(s) of its arrangements and coordinate the self-

provision of Ancillary Service(s) to allow the Transmission Provider and the Control

Area(s) to reduce their obligations to provide the Ancillary Service(s) on behalf of the

Transmission Customer. The Transmission Customer’s resources may be made

available to the Control Area Operator(s) to deploy to meet the responsibilities of the

Control Area(s) or, where operational control is retained by the Transmission Customer

or the resources are outside the host Control Area for the Transmission Customer’s

load, coordinated with the Control Area Operator to allow the Control Area Operator to

reduce its obligations under SPP and NERC criteria and adjust its operations

accordingly.

5. The Transmission Customer is fully responsible for the compliance and functional

performance of the generation resource(s) and/or service provider(s) for which it has a

contractual arrangement.

6. Any violation of the conditions stated above will be deemed to be non-

performance of the Transmission Customer’s obligation to arrange for Ancillary

Service(s), and the Transmission Provider will provide Ancillary Services to the

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Transmission Customer according the Transmission Provider's Tariff. The

Transmission Customer will be billed for all applicable charges for the services provided

and, unless the Transmission Customer has made appropriate prior arrangements with

SPP before the non-performance, for penalties applicable to the Transmission

Provider’s provision of the unarranged Ancillary Service(s) to the extent provided by the

Tariff.

7. A generation resource owned by the Transmission Customer or utilized by

contract for the provision of Ancillary Service(s) that is located outside the Transmission

Provider's Transmission System is not eligible for use in the self-supply of Ancillary

Services unless firm transmission service has been arranged for the delivery of power

and energy in sufficient quantities to cover the required Ancillary Service being self-

provided. Such transmission service will reflect such Generation Resource as the

source and the load supplied as the sink.

8. For any Generation Resource owned by the Transmission Customer or utilized

by contract for the provision of Ancillary Service(s), the Transmission Customer must

supply the Transmission Provider a copy of the interconnection agreement in effect

between such supplier and the relevant transmission provider, provided such

transmission provider is an entity other than the Transmission Provider.

9. Specific Resource requirements for each Service:

a. Regulation and Frequency Response Service (AS 3) On-line capacity under

AGC and a subject to the contractual control or the operational authority of

the Transmission Customer.

b. Operating Reserve - Spinning Reserve Service (AS 5) For a unit specific resource or

entitlement (including purchases): Idle on-line capacity subject to the contractual

control or operational authority of the Transmission Customer. No charges for AS 5

shall be assessed on that portion of the Transmission Customer's load that is supplied

by purchases from third parties of firm power resources, provided that Transmission

Customer has demonstrated to SPP, and SPP is able to determine, that such third

parties are to provide AS 5 under the agreement(s) for such purchases and to the

extent the third party does supply AS5.

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c. Operating Reserve - Supplemental Reserve Service (AS 6) For a unit specific

resource or entitlement (including purchases): 1. Idle on-line capacity in excess of the

capacity counted for spinning reserve (AS 5) and subject to the operational authority

of the Transmission Customer and 2. Uncommitted quick start capacity capable of

meeting SPP and NERC criteria for non-spinning reserve subject to the operational

authority of the Transmission Customer. No charges for AS 6 shall be assessed on

that portion of Transmission Customer's load that is supplied by purchases from third

parties of firm power resources, provided that Transmission Customer has

demonstrated to SPP, and SPP is able to determine, that such third parties are to

provide AS 6 under the agreement(s) for such purchases and to the extent the third

party does supply AS6.

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Attachment 2 of Appendix 5 KPP Initial Resources on MKEC System Recognized for Self Provision of AS 3, AS 5 and AS 6 City City Generation1 Capacity (MW) Attica 2.15 Kingman 8.8 Total 10.95



AS#6 Yes Notes: 1 AS rights available when running, metered and meeting operational requirements.

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Billing Principles

I. General

The Kansas Power Pool (“KPP”) is comprised of a number of cities that purchase either Point-to-Point (“PTP”) transmission service or Network Integration Transmission Service (“NITS”). The type of transmission service reserved for each city is the basis for how its ancillary service charges are calculated. SPP provides Ancillary Services 3 through 5 under the SPP Open Access Transmission Tariff (“OATT”). Because SPP does not have generation, MKEC, as the local Balancing Authority, supplies some of these ancillary services pursuant to its OATT. Thus references herein to the SPP OATT also refer to the MKEC OATT. II. Transmission Service Transmission service is a separate service from Ancillary Service. PTP transmission service and NITS are governed by the Tariff. To the extent the KPP cities take scheduled transmission service for which they have a reservation and/or unscheduled transmission service for which they do not have a reservation, the KPP cities will be subject to all charges, including penalties, for such transmission service in accordance with the Tariff. MKEC shall notify the SPP to the extent that any KPP city exceeds its firm reserved capacity at any Point of Receipt or Point of Delivery. III. MKEC's Development of the Monthly Bill for Ancillary Services A. Aggregation

KPP will be allowed to purchase Ancillary Services on the aggregate load of the KPP cities on a NITS basis beginning March 1, 2008 and continuing thereafter; provided that such aggregation continues to comply with the requirements of NERC and SPP scheduling criteria.

B. Effects of Transmission Line Loading Relief ("TLR")

When a transaction is affected by TLR, the energy scheduled under that reservation may be fully

or partially curtailed. If SPP called the TLR, SPP may adjust any transmission charges related to those affected reservations in accordance with its business practices. SPP shall calculate the amount of credits that KPP is entitled to receive against its charges for transmission service for reductions due to TLRs. SPP shall refund all such credits with interest. If the transmission reservation is reduced due to TLR (i.e., SPP called the TLR), MKEC shall reduce the ancillary service charges to correspond to the amount of the reduced MW reservation. If the transaction MW reservation is not affected (i.e., the schedule is reduced due to TLR called by an entity other than SPP) and the transmission reservation is Firm, the unused reservation shall be applied to deliveries of imbalance energy during those hours.

C. Self-Supply of Ancillary Services

KPP can totally or partially self-supply Ancillary Services 3, 5, and 6 as provided in this Service Agreement for Ancillary Services(“ Service Agreement”). SPP will notify MKEC as to any ancillary services that KPP is totally self-supplying and any qualified schedules or resources that KPP is using to

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partially self-supply ancillary services. Attachment 2 of this Service Agreement, as such Attachment 2 may be modified from time to time, contains a complete list of KPP resources that SPP has determined qualify for self-supply. Attachment 2 of this Service Agreement, as attached hereto as of the execution of this Service Agreement, reflects the KPP resources that SPP has determined qualify for self-supply effective as of March 1, 2008.

1. Ancillary Service 3 (Voltage and Regulation Control): Calculate the Hourly Ancillary Service 3 Charge for Each Hour of the Month: Hourly Ancillary Service 3 Charge = [ATTR] * [OATT Ancillary Service 3 hourly rate] Calculate the Total Ancillary Service 3 Charge for the Month: Total Ancillary Service 3 Charge per Month = Σ [Hourly Ancillary Service 3 Charges]

2. Ancillary Service 5 (Spinning Reserves):


Calculate the Monthly Ancillary Service 5 Energy Charge Monthly Ancillary Service 5 Energy Charge = (Total Energy Delivered for the Month – Total Energy

Delivered from Credited Sources for the Month) * (Ancillary Service 5 Energy Charge) Calculate the Total Ancillary Service 5 Charge for the Month: Total Ancillary Service 5 Charge per Month = Σ [Hourly Ancillary Service 5 Demand Charges] + [Monthly

Ancillary Service 5 Energy Charge]



Calculate the Total Ancillary Service 6 Charge for the Month: Total Ancillary Service 6 Charge per Month = Σ [Hourly Ancillary Service 6 Demand Charges]

D. Network Integrated Transmission Service (NITS): For those cities that are taking NITS service, the ancillary charges are based upon the rolling twelve-month average Network Load. The hourly demand used in these ancillary service calculations is based upon the total load of the city behind the meter, which is calculated by summing the load measured by the tie meters between MKEC and the city plus the internal generation of the city plus any transmission and distribution losses. The credits are based upon the amount of energy delivered to the city from credited sources.

1. Ancillary Service 3 (Voltage and Regulation Control):

Calculate the Monthly Ancillary Service 3 Charge: Monthly Ancillary Service 3 Charge = [Monthly Ancillary Service 3 rate] * [Rolling 12 month average

Network Load]

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Calculate the Monthly Credit for Self-Supply: Monthly Credit for Self-Supply = [Total Energy Delivered from Credited Sources during the month] *

[Hourly Ancillary Service 3 rate]

Calculate the Total Monthly Amount Billed for Ancillary Service 3: Amount billed for Ancillary Service 3 = [Monthly Ancillary Service 3 Charge] – [Monthly Credit for Self Supply]

2. Ancillary Service 5 (Spinning Reserves): Calculate the Monthly Ancillary Service 5 Demand Charge: Monthly Ancillary Service 5 Demand Charge = [Monthly Ancillary Service 5 demand rate] * [Rolling 12

month average Network Load]



Calculate the Monthly Ancillary Service 5 Charge: Monthly Ancillary Service 5 Charge = [Monthly Ancillary Service 5 Demand Charge] – [Monthly Credit for

Self Supply] Calculate the Monthly Ancillary Service 5 Energy Charge: Monthly Ancillary Service 5 Energy Charge = (Total Energy Delivered for the month – Total Energy

Delivered from Credited Sources for the month) * (Ancillary Service 5 Energy Charge) Calculate the Total Ancillary Service 5 Charge per Month: Total Ancillary Service 5 Charge per Month = [Monthly Ancillary Service 5 Charge] + [Monthly Ancillary

Service 5 Energy Charge]


Calculate the Monthly Ancillary Service 6 Demand Charge: Monthly Ancillary Service 6 Demand Charge = [Monthly Ancillary Service 6 demand rate] * [Rolling

12 month average Network Load]



Calculate the Monthly Ancillary Service 6 Charge: Monthly Ancillary Service 6 Charge = [Monthly Ancillary Service 6 Demand Charge] – [Monthly

Credit for Self Supply]

IV. The SPP Bill SPP shall bill KPP monthly, and on a timely and consistent basis, including applicable charges for ancillary services from MKEC, and KPP shall pay to SPP, subject to the dispute resolution procedures of the SPP Tariff, (1) the monthly bill for ancillary services developed by MKEC under Part II

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of these Billing Principles and (2) any additional charges that KPP is subject to under SPP's OATT or any applicable agreements.

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NETWORK OPERATING AGREEMENT BETWEEN SOUTHWEST POWER POOL, INC., KANSAS POWER POOL, MIDWEST ENERGY, INC., MID-KANSAS ELECTRIC

COMPANY, LLC AND WESTAR ENERGY, INC.

This Network Operating Agreement ("Operating Agreement") is entered into this 1st day

of March, 2014, by and between Kansas Power Pool ("Network Customer"), Southwest Power

Pool, Inc. ("Transmission Provider") and Midwest Energy, Inc., Mid-Kansas Electric Company,

LLC and Westar Energy, Inc. ("Host Transmission Owners"). The Network Customer,

Transmission Provider and Host Transmission Owners 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(s) owns the transmission facilities to which

the Network Customer’s Network Load is physically connected;


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.



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1.0 Network Service

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

Transmission Provider, Host Transmission Owners, and Network Customer will

cooperate and the Host Transmission Owners 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 Owners and the Network Customer to operate their systems 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.

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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 Owners, 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.

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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

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 Owners and Transmission Provider.

3.2 The Host Transmission Owners 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 Owners 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 Owners 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

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

operating conditions expeditiously.

3.6 The Transmission Provider and Host Transmission Owners, 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 Owners, 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 Owners, 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

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

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

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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 Owners the following information:

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

corresponding power factors and annual energy requirements on an

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

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

demands and energy requirements at each delivery point for the normal

operating configuration;

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

generating capabilities and committed transactions with third parties

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

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

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 Owners’ Zones.

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

Transmission Owners’ 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 Owners, 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 Owners will provide the following to the Network

Customer:

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a) A statement regarding the ability of the Host Transmission Owners’

transmission systems to meet the forecasted deliveries at each of the

delivery points;

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

Owners’ systems 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

Owners and the Network Customer to identify appropriate remedies for

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 Owners, 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 Owners 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

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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 Owners

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 Owners’ transmission systems.

4.6 The Network Customer shall provide for automatic and underfrequency load

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

Criteria related to emergency operations.

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5.0 Maintenance of Facilities

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

capacity and energy from the Host Transmission Owners’ transmission systems

consistent with Good Utility Practice. The Transmission Provider or Host

Transmission Owners, 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

Owners 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 Owners. The Network

Customer shall notify the Transmission Provider and the Host Transmission

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

occur and again when such unscheduled or forced outages end.

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6.0 Scheduling Procedures

6.1 The Network Customer is responsible for providing its Resource and load

information to the Transmission Provider in accordance with Attachment AE.

6.2 For Interchange Transactions the Network Customer shall submit, or arrange to

have submitted, the schedule of Energy to or from the Transmission Provider and

a transaction identification E-Tag for each such schedule where required by

NERC Standard INT-001.

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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, 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.

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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 Owners’ representatives to have

access to the equipment at all reasonable hours and for any reasonable purpose,

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 Owners 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 Owners shall make

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

Transmission Owners 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 Owners, 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 Owners, 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

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

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

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

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

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

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

supplier, the Network Customer shall be responsible for 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.

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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 as instructed by the Transmission Provider.

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

telemetry readings shall be submitted to the Transmission Provider and Host

Transmission Owners:

1) Analog MW;

2) Integrated MWHRS/HR;

3) Analog MVARS; and

4) Integrated MVARHRS/HR.

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10.0 Redispatching, Curtailment and Load Shedding

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

require redispatching of Resources to relieve existing or potential transmission

system constraints. The Transmission Provider shall redispatch Resources in

accordance with the Energy and Operating Reserve Markets operations specified

in Attachment AE. 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 using the settlement

procedures specified in Attachment AE.

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 Owners 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 Owners to

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

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

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

shedding by the Network Customer.

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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 Owners’ Zones.

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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 Owners, 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 Owners, 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.

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13.0 Billing and Payments

Billing and Payments shall be in accordance with Attachment AE and Section 7 of the

Tariff.

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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.

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15.0 Assignment

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

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

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

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

unreasonably withheld.

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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.

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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.

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18.0 Unilateral Changes and Modifications

Nothing contained in this Operating Agreement or any associated Service Agreement

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

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

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

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

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

other applicable statutes or regulations.

Nothing contained in this Operating Agreement or any associated Service

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

Customer receiving Network Integration Transmission Service under the Tariff to

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

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

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

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

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

and/or Service Agreement.

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19.0 Term

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

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

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

108 75401876, 75402065, 75402069

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. Tessie Kentner Attorney 201 Worthen Drive Little Rock, AR 72223-4936 501-688-1782 Phone [email protected] Host Transmission Owner: Midwest Energy, Inc. William N. Dowling Vice President of Energy Management & Supply 1330 Canterbury Road, P.O. Box 898 Hays, KS 67601 Phone: (785) 625-1432 Fax (785) 625-1494 Email: [email protected] Host Transmission Owner: Mid-Kansas Electric Company, LLC Stuart Lowry 301 West 13th Street P.O. Box 980 Hays, KS 67601 Phone: (785) 623-3335 Fax (785) 623-3395 Email: [email protected] Host Transmission Owner: Westar Energy, Inc. Thomas Stuchlik Executive Director, System Operations 818 S. Kansas Avenue

109 75401876, 75402065, 75402069

Topeka, KS 66612 Phone: (785) 575-6046 Fax (785) 575-1798 Email: [email protected] Network Customer: Kansas Power Pool CEO/General Manager 250 W. Douglas, Suite 110 Wichita, KS 67202 Phone: (316) 264-3166 Any Party may change its notice address by written notice to the other Parties in

accordance with this Article 20.

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

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

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

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

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21.0 Execution in Counterparts

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

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

construed together and shall constitute one instrument.

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

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

effective as of the Effective Date.

TRANSMISSION PROVIDER HOST TRANSMISSION OWNER _/s/ Lanny Nickell_________ _/s/ Aaron Rome__________ Signature Signature _Lanny Nickell___________ _Aaron Rome____________ Printed Name Printed Name __VP, Engineering________ _Mgr. Transmission and Market Operations Title Title _3-31-14________________ _3-28-2014______________ Date Date HOST TRANSMISSION OWNER HOST TRANSMISSION OWNER _/s/ Thomas R. Stuchlik____ _/s/ Stuart S. Lowry______ Signature Signature _Thomas R. Stuchlik_______ _Stuart S. Lowry_________ Printed Name Printed Name _Executive Director System Ops _President and CEO______ Title Title _3/11/2014________________ _March 11, 2014_________ Date Date NETWORK CUSTOMER

111 75401876, 75402065, 75402069

_/s/ Larry W. Holloway____ Signature _Larry W. Holloway______ Printed Name _Kansas Power Pool Operations Manager Title _March 7, 2014_________ Date