Southwest Power Pool

Southwest Power Pool BOARD OF DIRECTORS/MEMBERS COMMITTEE MEETING Southwest Power Pool Corporate Campus, Little Rock, AR

October 30, 2012

- Summary of Action Items -

1. Approved Consent Agenda items: a. Approved July 31, 2012 minutes b. Markets and Operations Policy Committee

i. MWG: MPRR 74, 76, 86, 88 ii. RTWG: TRR 071, 072, 076 iii. SSC: Compliance Filing Extension

2. Approved the Corporate Governance Committee’s recommendation that the Board of Directors

approve the appointment of Coleen Wells (KEPCo) and Mike Wise (GSEC) to serve on the Finance Committee.

3. Approved the Corporate Governance Committee’s recommendation that the Board of Directors approve the SPCTF recommended revisions to the SPP Membership Agreement to comply with the Order 1000 requirement to remove from all FERC-jurisdictional tariffs and agreements any provisions that establish a federal ROFR for an incumbent transmission provider with respect to transmission facilities selected in a regional transmission plan for purposes of cost allocation.

4. Approved the Corporate Governance Committee’s recommendation that the Board of Directors approve the removal of Appendix A from the SPP Membership Agreement.

5. Approved the Finance Committee’s recommendation that the SPP Board of Directors approve the 2013 operating and capital budgets and to establish an assessment rate and tariff administrative charge rate (schedule 1A) of 31.5¢/MWh effective January 1, 2013.

6. Approved the Markets and Operations Policy Committee’s recommendation that the Board of Directors approve its recommendation for Market Hubs Establishment MPRR 90.

7. Approved the Markets and Operations Policy Committee’s recommendation that the Board of Directors approve TRR 077 for filing at FERC.

8. Approved the Markets and Operations Policy Committee’s recommendation that the Board of

Directors approve MPRR 89 for filing at FERC.

9. Approved the Markets and Operations Policy Committee’s recommendation that the Board of Directors approve the use of all metrics listed in the Regional Cost Allocation Review (RCAR).

10. Approved the Markets and Operations Policy Committee’s recommendation that the Board of Directors approve the NPPD requested waiver for Base-Plan Funding of the Neligh 345/115 kV transformer.


Directors un-suspend the Notice to Construct (NTC) for the Altoona West Cap bank.

12. Approved the Markets and Operations Policy Committee’s recommendation that the Board of Directors approve suspending the Afton Transformer NTC for re-evaluation.

MINUTES NO. 148

Southwest Power Pool BOARD OF DIRECTORS/MEMBERS COMMITTEE MEETING Southwest Power Pool Corporate Campus, Little Rock, AR

October 30, 2012 Agenda Item 1 - Administrative Items

SPP Chair Mr. Jim Eckelberger called the meeting to order at 8:30 a.m. The following Board of Directors/Members Committee members were in attendance or represented by proxy:

Mr. Larry Altenbaumer, director Ms. Phyllis Bernard, director Mr. Julian Brix, director Mr. Nick Brown, director Mr. Scott Heidtbrink, proxy for Mr. Mike Deggendorf, Kansas City Power and Light Mr. Jim Foley, proxy for Mr. Mo Doghman, Omaha Public Power District Mr. Jim Eckelberger, director Mr. Kelly Harrison, Westar Energy Mr. Dennis Reed, proxy for Mr. Kelly Harrison, Westar Energy (part of the meeting) Mr. Dave Osburn, proxy for Ms. Cindy Holman, Oklahoma Municipal Power Authority Mr. Rob Janssen, Dogwood Energy Mr. Tom Kent, Nebraska Public Power District Mr. Jeff Knottek, City Utilities of Springfield Mr. Brett Kruse, Calpine Energy Services Mr. Les Evans, proxy for Mr. Steve Parr, Kansas Electric Power Cooperative Mr. Josh Martin, director Mr. Mel Perkins, OG+E Electric Services Mr. Gary Roulet, Western Farmers Electric Cooperative Mr. Harry Skilton, director Mr. Kevin Smith, Tenaska Mr. Stuart Solomon, American Electric Power Mr. Noman Williams, Sunflower Electric Power Corporation Mr. Mike Wise, Golden Spread Electric

Mr. Eckelberger asked for a round of introductions. There were 114 persons in attendance either in person or via phone representing 32 members (Attendance List - Attachment 1). Mr. Nick Brown reported proxies and a quorum was declared (Proxies - Attachment 2). Agenda Item 2 – Board Reports Regional State Committee Report

Mr. Olan Reeves (Arkansas Public Service Commission) presented the Regional State Committee (RSC) report. Mr. Reeves stated that the RSC met on October 29. The following items were discussed:

The RSC elected the following officers for 2013: Tom Wright, President; Dana Murphy, Vice President; and Donna Nelson, Secretary/Treasurer.

Voted to approve the 2013 RSC Budget.

Voted to approve new Business Practices, BPR 25 and BPR 32, related to waiver requests and how they are processed.

Voted to adopt a 100% regional allocation of costs related to inter-regional planning processes but agreed to revisit when more information is available.

Endorsed the Nebraska Public Power District Neligh Transformer waiver request.

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SPP Board of Directors/Members Committee Minutes October 30, 2012

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The RSC heard updates on: the Balanced Portfolio transfers; Mississippian oil play; and the Integrated Marketplace.

Federal Energy Regulatory Commission Report

Mr. Patrick Clarey provided an update on recent FERC activities:

August FERC held five regional technical conferences on better coordination between natural gas and electricity markets. The conferences explored gas-electric interdependence as well as ways to improve coordination and communication between the two industries. The regions included the Northeast, Mid-Atlantic, Southeast, Central and West regions. FERC appreciates SPP’s participation in this effort. September FERC granted SPP’s Petition for Declaratory Order and conditionally accepted the proposed Western-SPP JOA, subject to a compliance filing.

Commission Chairman Jon Wellinghoff announced the creation of a new FERC office that will help the Commission focus on potential cyber and physical security risks to energy facilities under its jurisdiction. The new Office of Energy Infrastructure Security (OEIS) will provide leadership, expertise and assistance to the Commission to identify, communicate and seek comprehensive solutions to potential risks to FERC-jurisdictional facilities from cyber attacks and such physical threats as electromagnetic pulses. OEIS will be led by Joseph McClelland, who has been Director of the Office of Electric Reliability since its formation in 2006.

October Mr. Clarey congratulated SPP and its Members and noted that at the October Open Meeting, FERC conditionally accepted SPP’s Integrated Marketplace tariff filing including day-ahead and real-time energy and operating reserve markets. The Chairman announced that current FERC General Counsel Michael Bardee will be the new head of the Office of Electric Reliability. David Morneoff will step-in as acting General Counsel.

Regional Entity Trustee Report

Mr. John Meyer presented the Regional Entity Trustee report (RE Report – Attachment 3). The report included updates on:

• BES Definition/Exception Process • Vegetation Management • Regional Standards Under Development • Misoperations • SPP Region Successful Operations • Violated Standards • SPP RE Outreach Activities YTD

Human Resources Committee Report Ms. Phyllis Bernard provided the Human Resources Committee report (HRC Report – Attachment 4). The Committee met with SPP staff prior to the Board of Directors meeting with a focus of the discussion being diversity in the workforce. There is continued outreach to colleges and universities, high schools, and junior high on the value of STEM (Science, Technology, Engineering and Math) career paths. Ms. Bernard reported that the HRC Scope statement has been updated to separate duties of the benefit plan design and benefit plan investment review between the HRC and the Finance Committee. The HRC will still


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maintain oversight of the 401(k) as required by law. The group continues to review the SPP Benefit Program, corporate culture and organizational development, training, compensation adjustments, career development programs and provide oversight of the performance compensation program. Oversight Committee Report

Mr. Josh Martin provided the Oversight Committee report. Mr. Martin reported that the Committee last met in September. The Committee heard reports from Internal Audit, Compliance, and Market Monitoring staff.

• Internal Audit continues its regular audits, as well as its oversight roles in the construction and Integrated Marketplace initiatives. An audit schedule for 2013 - 2014 was presented. Plans are to continue the focus on higher-risk areas, and particularly those that intersect with the Integrated Marketplace initiative.

• Compliance provided a report on its Member Outreach initiative. Several Evidence Reviews have been completed and more are scheduled for this year. A Compliance Forum was held August 16; the next one will be held November 14 in Little Rock. The group was asked to develop a plan for elevating attention to compliance within member organizations. In addition, the group reported on efforts to date and new ones proposed specifically focused on CIP compliance.

• The Market Monitoring Unit staff remains engaged in the Integrated Marketplace initiative, developing the various new metrics that will be necessary to monitor the new markets. This has also included support in design that has avoided the need to engage outside consultants. The MMU also continues its support of SPP’s compliance with FERC Order 760 requiring certain market data be provided on a regular basis to the new Division of Analytics and Surveillance.

The Committee also received an update on processes under development for Order 1000 compliance, specifically the proposed role for the Oversight Committee. The Oversight Committee’s next scheduled meeting is December 10. Agenda Item 3 – Consent Agenda Mr. Eckelberger presented the following Consent Agenda items for approval (Consent Agenda – Attachment 5):

a. Approve July 31, 2012 minutes b. Markets and Operations Policy Committee

i. MWG: MPRR 74, 76, 86, 88, 89 ii. RTWG: TRR 071, 072, 076 iii. SSC: Compliance Filing Extension

Mr. Eckelberger asked for requests to remove any items from the Consent Agenda or a motion to approve. Mr. Dennis Reed asked that MPRR 89 be removed from the Consent Agenda due to Markets and Operations Policy Committee’s (MOPC) approving it pending any Regional Tariff Working Group (RTWG) revisions, which occurred following the MOPC meeting. Mr. Harry Skilton moved to approve the Consent Agenda items absent MPRR 89; Mr. Josh Martin seconded the motion. The Members Committee voted in unanimous approval. The Board voted; the motion passed.

Agenda Item 4 – Corporate Governance Committee Report

Mr. Nick Brown provided the Corporate Governance Committee Report (CGC Report – Attachment 6). Mr. Brown stated that in accordance with SPP’s Bylaws, the Corporate Governance Committee recommends two candidates to fill current Transmission User member sector vacancies on the Finance Committee: Ms. Coleen Wells (KEPCo) and Mr. Mike Wise (GSEC). Mr. Brown moved that the Board of Directors approve these appointments; Mr. Julian Brix seconded the motion. The Members Committee voted in unanimous approval. The Board voted; the motion passed.


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Mr. Brown reviewed the Strategic Planning Committee Task Force (SPCTF) recommended Membership Agreement revisions regarding FERC Order 1000 compliance. Mr. Brown moved to approve:

Approve SPCTF recommended revisions to the SPP Membership Agreement to comply with the Order 1000 requirement to remove from all FERC-jurisdictional tariffs and agreements any provisions that establish a federal ROFR for an incumbent transmission provider with respect to transmission facilities selected in a regional transmission plan for purposes of cost allocation.

Mr. Harry Skilton seconded the motion. The Members Committee voted in unanimous approval. The Board voted; the motion passed. Mr. Brown reported that with the advent of the Integrated Marketplace and the development of a Consolidated Balancing Authority Agreement, the CGC felt Appendix A of the SPP Membership Agreement will no longer be necessary. Mr. Brown moved to approve the removal of Appendix A from the SPP Membership Agreement; Ms. Phyllis Bernard seconded the motion. The Members Committee voted in unanimous approval. The Board voted; the motion passed. Agenda Item 5 – Finance Committee Report

Mr. Harry Skilton presented the Finance non-members, Traci Bender (NPPD) and Carol Shoemake (OG&E), for their input and regular attendance at the meetings (FC Report – Attachment 7). Mr. Skilton reviewed the 2013 SPP budget including budget assumptions, metrics, net revenue requirements, operating expenditures, incremental positions and the proposed administrative fee. Mr. Skilton moved to approve the 2013 SPP operating and capital budgets as submitted and to establish an assessment rate and tariff administrative charge rate (schedule 1A) of 31.5¢/MWh effective January 1, 2013. Mr. Larry Altenbaumer seconded the motion. Mr. Eckelberger called for a vote regarding approval of the 2013 SPP operating and capital budgets. The Members Committee voted in unanimous approval. The Board voted; the motion passed. Mr. Eckelberger then called for a vote regarding the approval of an SPP administrative fee of 31.5¢/MWh. The Members Committee voted in unanimous approval. The Board voted; the motion passed. Agenda Item 6 – Markets and Operations Policy Committee Report

Mr. Todd Fridley provided the Markets and Operations Policy Committee report (MOPC Report – Attachment 8). He presented the following action items for approval:

MPRR 90: Mr. Fridley stated that the Marketplace Hubs Task Force (MHTF) was charged with establishing hubs to be implemented at the start of the Integrated Marketplace, including Market Trials. It is the recommendation of the MHTF to establish Market Hubs that consist of Resource Hubs and Trading Hubs. He offered the following MOPC recommendation:

The MOPC recommends that Board of Directors approve the Market Hubs Establishment MPRR 90 and the tariff language changes. Mr. Julian Brix moved for approval of MPRR 90; Mr. Larry Altenbaumer seconded the motion. The Members Committee voted in unanimous approval. The Board voted; the motion passed.

TRR 77: Mr. Fridley presented background for TRR 077, which addresses compliance with the Public Policy Requirement of FERC Order 1000 for the Transmission Planning Process and Transmission Owner Designation Process to be filed in early November 2012. He offered the following MOPC recommendation:

The MOPC recommends that the Board of Directors approve its request regarding Tariff Revision Requests 077 for filing at FERC. Mr. Harry Skilton moved for approval of MPRR 77; Ms. Phyllis Bernard seconded the motion. The Members Committee voted in unanimous approval. The Board voted; the motion passed.


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MPRR 89: The MOPC approved MPRR 89 pending approval of the Regional Tariff Working Group (RTWG). The RTWG did modify MPRR 89 but it was determined that these modifications did not change the substance of the MPRR. Mr. Fridley, therefore, recommended:

The MOPC recommends that the Board of Directors approve its request regarding Marketplace Protocol Revision Request 89. Mr. Larry Altenbaumer moved for approval of MPRR 89; Mr. Julian Brix seconded the motion. The Members Committee voted in unanimous approval. The Board voted; the motion passed.

CBA Agreement Approval: Mr. Fridley presented the Consolidated Balancing Authority Agreement. He stated that the MOPC recommends that the Board of Directors approve the Consolidated Balancing Authority Agreement. Following discussion, Mr. Eckelberger requested that the CBA Agreement be sent to the Corporate Governance Committee to determine an appropriate approach to the indemnification issues corporate-wide. No vote was taken at this time. RCAR Metrics: Mr. Fridley reviewed recommended metrics for the Regional Cost Allocation Review, which will be drafted in January 2013 and be completed in July 2013. He offered the following MOPC recommendation:

The MOPC recommends that the Board of Directors approve the use of all the metrics listed in the Regional Cost Allocation Review (RCAR). Mr. Nick Brown moved for approval of RCAR metrics; Mr. Julian Brix seconded the motion. The Members Committee voted in unanimous approval. The Board voted; the motion passed.

Following discussion, it was determined to rely on stakeholder feedback regarding benefits and value of the individual metrics or a need to revisit them. Waivers: Mr. Fridley provided background for Nebraska Public Power District’s (NPPD) waiver request for the Neligh transformer. He offered the following MOPC recommendation:

The MOPC recommends that the Board of Directors approve the requested waiver for Base-Plan Funding of the Neligh 345/115 kV transformer. Mr. Josh Martin moved to approve; Mr. Larry Altenbaumer seconded the motion. The Members Committee voted in unanimous approval. The Board voted; the motion passed.

Altoona Cap Bank: Mr. Fridley stated that according to the 3rd Quarter Project Tracking Review, Altoona East Cap bank is still needed. He offered the following MOPC recommendation:

The MOPC recommends that the Board of Directors un-suspend the Notice to Construct (NTC) for the Altoona West Cap bank. Mr. Julian Brix moved to approve; Mr. Nick Brown seconded the motion. The Members Committee voted in unanimous approval. The Board voted; the motion passed.

Afton Transformer: Mr. Fridley reported that the 4th Quarter Project Tracking Review indicated a need to suspend the NTC for Afton Transformer in order to complete a re-evaluation in January 2013 ITPNT.

The MOPC recommends that the Board of Directors suspend the Afton Transformer NTC for re-evaluation. Mr. Nick Brown moved to approve; Mr. Julian Brix seconded the motion. The Members Committee voted in unanimous approval. The Board voted; the motion passed.

Mr. Fridley then presented the following informational items:

• Integrated Marketplace Software Change • Balanced Portfolio • Probabilistic Planning


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Agenda Item 7 – Integrated Marketplace Report

Mr. Bruce Rew provided an update on the Integrated Marketplace project (Integrated Marketplace – Attachment 9).

Agenda Item 8 – Future Meetings

Mr. Eckelberger reminded the group that the next SPP Board of Directors meeting will be December 11 in Dallas (Future Meetings – Attachment 10). This meeting is focused on organizational effectiveness. Adjournment

With no further business, Mr. Eckelberger thanked everyone for participating and adjourned the meeting to Executive Session at 1:20 p.m. Stacy Duckett, Corporate Secretary Executive Session During the Executive Session, the Board discussed and provided direction to Staff on two pending legal matters.

Relationship-Based • Member-Driven • Independence Through Diversity

Evolutionary vs. Revolutionary • Reliability & Economics Inseparable

Southwest Power Pool

BOARD OF DIRECTORS/MEMBERS COMMITTEE MEETING AND ANNUAL MEETING OF MEMBERS

October 30, 2012 SPP Offices, Little Rock, AR

• A G E N D A •

8:00 a.m. – 3:00 p.m. CDT

Annual Meeting of Members

1. Call to Order and Administrative Items ..................................................................... Mr. Jim Eckelberger

2. Elections of Directors, Members Committee Representatives, and RE Trustee ............. Mr. Nick Brown

3. President’s Report ............................................................................................................ Mr. Nick Brown

Adjourn for Board of Directors/Members Committee Meeting

Board of Directors/Members Committee Meeting 1. Call to Order and Administrative Items .................................................................... Mr. Jim Eckelberger

2. Board Reports

a. Regional State Committee Report .................................................. Commissioner Olan Reeves b. Federal Energy Regulatory Commission Report ............................................ Mr. Patrick Clarey c. Regional Entity Trustees Report......................................................................... Mr. John Meyer d. Human Resources Committee Report ......................................................... Ms. Phyllis Bernard e. Oversight Committee Report .............................................................................. Mr. Josh Martin

3. Consent Agenda ....................................................................................................... Mr. Jim Eckelberger

a. Approve July 31, 2012 minutes b. Markets and Operations Policy Committee Recommendations

i. MWG: MPRR 74, 76, 86, 88, 89 ii. RTWG: TRR 071, 072, 076 iii. SSC: Compliance Filing Extension

4. Corporate Governance Committee Report ....................................................................... Mr. Nick Brown

5. Finance Committee Report ............................................................................................ Mr. Harry Skilton

6. Markets and Operations Policy Committee Report ........................................................ Mr. Todd Fridley

a. MWG: MPRR 90 – Market Hubs Establishment b. RTWG: TRR 077 – Compliance w/Order 1000 c. CBASC: CBA Agreement Approval d. ESWG: Metrics for RCAR e. Staff:

i. Waivers ii. Altoona Cap Bank – Unsuspend iii. Afton Transformer – Suspend

Relationship-Based • Member-Driven • Independence Through Diversity

Evolutionary vs. Revolutionary • Reliability & Economics Inseparable

7. Integrated Marketplace Update ........................................................................................ Mr. Bruce Rew

8. Future Meetings ........................................................................................................ Mr. Jim Eckelberger

BOD – December 11 ............................................................ Dallas

2013 RET/RSC/BOD - January 28-29 ............................... New Orleans

RET/RSC/BOD - April 29-30 ....................................... Kansas City

BOD - June 10-11 ....................................................... Little Rock

RET/RSC/BOD - July 29-30 ............................................... Denver

RET/RSC/BOD - October 28-29 ................................... Little Rock

BOD - December 10 ............................................................. Dallas

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Subject: FW: SPP/Notice of Elections - October 30, 2012

From: Deggendorf Michael [mailto:[email protected]] Sent: Thursday, October 25, 2012 5:41 PM To: Stacy Duckett Subject: Re: SPP/Notice of Elections ‐ October 30, 2012 I am giving my proxy for the upcoming meeting to Scott Heidtbrink. Thanks Stacy Thanks, Mike

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Subject: Delegation

‐‐‐‐‐Original Message‐‐‐‐‐ From: [email protected] [mailto:[email protected]] Sent: Tuesday, October 30, 2012 1:06 PM To: Stacy Duckett; Carl Monroe Subject: Delegation I will leave around 1:30. In my absence, I delegate Dennis my proxy to attend the Executive session. Kelly

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Subject: SPP October 29 & 30

From: LABS, CHRISTI A [mailto:[email protected]] Sent: Tuesday, October 16, 2012 10:57 AM To: Cheryl Robertson Cc: Doghman, Mohammad Subject: SPP October 29 & 30 Cheryl – Jennifer St. Clair asked that Mo send you an email confirming that Jim Foley will be attending the SPP meeting on October 29th & 30th for Mo. Mo is traveling out of the country at this time so I hope an email from me will be sufficient I have also copied Mo so he is aware that I have sent the email. Mo is unable to attend the SPP meeting on October 29th & 30th, Jim Foley will be attending in Mo’s place. If you need anything further please let me know. Thanks,

Christi Labs Executive Administrative Assistant Omaha Public Power District 444 South 16th Street Mall, Omaha, NE 68102 402-636-3212 [email protected]

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Subject: FW: SPP Board Meeting

From: Steve Parr [mailto:[email protected]] Sent: Friday, October 26, 2012 11:23 AM To: Stacy Duckett Cc: Evans, Les Subject: SPP Board Meeting Hi, Stacy; I thought I was going to be in Little Rock next week, but had to change my plans. I also will have a schedule issue with the actual Board meeting on Tuesday. Therefore, I would like to give Les Evans my proxy for the Members Committee and as KEPCo’s rep for the Members meeting. I still plan to participate in the Corporate Governance Committee by phone. Problem is, when the CCG meeting will start. I am assuming sometime between 1:00 and 3:00 pm. Could you email/call me on Tuesday when the Board meeting ends so I can call in for CCG? Thanks for your help. Stephen E. Parr Executive Vice President and CEO Kansas Electric Power Cooperative, Inc. 600 SW Corporate View Topeka, Kansas 66615 (785) 271-4831 Fax: (785) 271-4884

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Subject: FW: Members Meeting October 30

From: Cindy Holman [mailto:[email protected]] Sent: Tuesday, September 18, 2012 11:30 AM To: Stacy Duckett Cc: Osburn, David; Cheryl Robertson Subject: RE: Members Meeting October 30 Yes, he does have my proxy for the Annual Meeting of Members and Members Committee. Thanks. Cindy

From: Stacy Duckett [mailto:[email protected]] Sent: Tuesday, September 18, 2012 11:26 AM To: Cindy Holman Cc: Dave Osburn; Cheryl Robertson Subject: RE: Members Meeting October 30 Cindy – This is sufficient with one clarification – does he have your proxy for the Annual Meeting of Members (thus, elections) and the Members Committee? Thanks and have a great trip – Stacy From: Cindy Holman [mailto:[email protected]] Sent: Tuesday, September 18, 2012 8:56 AM To: Stacy Duckett Cc: Osburn, David Subject: Members Meeting October 30 Stacy, as I mentioned earlier, I will be out of the country for this meeting and Dave Osburn will be attending the Members meeting on my behalf. Will you need anything else from me in order for Dave to have my proxy? Thanks. Cindy Holman General Manager, OMPA P O Box 1960 Edmond, OK 73083-1960 2701 W I-35 Frontage Road Edmond, OK 73013 405-359-2533 Direct Dial 405-471-2734 Cell Phone

SPP RE Report to Board of Directors

October 30, 2012

John Meyer

Chairman, SPP RE Trustees

BES Definition/Exception Process

• FERC indicated intent to approve definition and Rules of Procedure change generally as presented

• Initial survey of SPP RE entities indicated < 100 elements identified as possible exclusions beyond definition

• Guidance Document out for comment at NERC through 11/5/12

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http://www.nerc.com/filez/standards/Project2010-17_BES.html

Vegetation Management Update

• NERC published 2Q 2012 Vegetation Management Report 9‐12‐12

• SPP RE footprint – 8 quarters with no ‘reportable’ vegetation contacts (4Q 2010 ‐ 3Q 2012)

– 3 categories of ‘reportable’ contacts

– NERC footprint – 7 quarters with no ‘actionable’ vegetation contacts

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http://www.nerc.com/files/2Q2012_Vegetation Report_FINAL DRAFT.pdf

Regional Standards Under Development

• RSR‐002‐ Request to Review Regional Standard Process

– Request submitted to MOPC 3/05/12

– Standard Drafting Team populated and meetings in progress

– Expected completion date 6/18/13

• RSR‐001‐ PRC‐006‐SPP‐01 (UFLS Standard)

– Trustees approved regional standard 7/30/12

– NERC posted standard for comment 08/15/12 ‐ 09/28/12

– Standard Drafting Team will submit responses to NERC 10/30/12

– NERC Board of Trustees will discuss 11/7/124

http://www.spp.org/section.asp?pageID=164

http://www.spp.org/committee_detail.asp?commID=122


Misoperation Counts

2010 2011 2012

1Q 61 66 302Q 138 115 463Q 115 68 ?4Q 67 61 ?

• 2010 SPP definition/regional voluntary reporting

• 2011 National definition/mandatory reporting

• 2012 Success Rate‐ 1Q 2012 92%, 2Q 2012 93%

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SPP Region Successful Operations Percentages

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76%

78%

80%

82%

84%

86%

88%

90%

92%

94%

Q1‐11 Q2‐11 Q3‐11 Q4‐11 Q1‐12 Q2‐12

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Most Violated StandardsBased on rolling 12 months through 9/30/12 [Represents ~ 80% of total violations]

*Not in Rolling 12 month Top Ten – Ranking is for all‐time violations

SPPRE

Rank

NERC 12 MonthRank

Standard DescriptionNumberViolations

Risk Factor

1 1 CIP‐007 Systems Security Management 43 Med./Lower

2 2 CIP‐005 Electronic Security Perimeters 28 Med./Lower

3 3 CIP‐006 Physical Security‐Critical Assets 26 Med./Lower

4 5 CIP‐004 Personnel & Training 21 Lower

5 4 PRC‐005 Protection System Maintenance 15 High

6 15* PRC‐008 UFLS Relay Maintenance 8 Med.

7 7 CIP‐003 Security Management Controls 8 Lower/Med.

8 6 CIP‐002 Critical Cyber Asset Identification 7 Med.

9 10 CIP‐001 Sabotage Reporting 5 Med.

SPP RE Outreach Activities YTD• 10 webinars with 485 registrants

• Two workshops with 323 stakeholder attendees

• 10 videos posted to video training webpage

• Nine E‐Newsletters

• Eight Event Analysis Lessons Learned

• Upcoming Events:

– Fall Compliance Workshop, 11/13‐14/12 ‐ Little Rock

– 2013 Implementation Plan and Audit Scope webinar, 12/3/12

– CIP‐003‐3 R5 Controlling Access to CCA Info webinar, 12/12/12

– Misoperations Reporting in webCDMS, webinar 1/8/13

– Spring Compliance Workshop, March 5‐6, 2013 ‐ Dallas8


http://www.spp.org/section.asp?group=1981&pageID=27


http://vimeopro.com/sppre/basics


http://vimeopro.com/sppre/basics

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John MeyerChairman, SPP RE Trustees

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Human Resources Committee Report

October 30, 2012

Human Resources Committee MeetingHighlights

October 10, 2012Dallas Ft. Worth Airport Hyatt, Dallas, Texasp y , ,

• The SPP Human Resources Committee members include:

– Ms. Phyllis Bernard, Chair

– Mr. Julian Brix, Director

– Mr Duane Highley Arkansas Electric Cooperative CorporationMr. Duane Highley, Arkansas Electric Cooperative Corporation

– Mr. Mike Palmer, Empire District Electric Company

– Mr. Noman Williams, Sunflower Electric Power Corporation

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Meeting Highlights

• Performance Compensation Plan Metric Change

– Committee reviewed and approved a staff proposal to replace the stakeholder survey metric from the performance compensation funding formula with a survey of the members committee on staff performance

– Succinct survey of members committee on staff performance

– Will more accurately reflect staff performance during– Will more accurately reflect staff performance during the year

– Stakeholder survey will continued to be conducted, but will no longer be used as performance compensation plan funding metric

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Meeting Highlights• SPP Fraud Prevention Report

– Committee reviewed staff report on fraud prevention d d t tiand detection measures

External and internal audits annually

HR benefit plan processes reviewed

– Training Programs

Ethics and Code of Conduct

Harassment and Discrimination Awareness

Security

Management Skills training

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Meeting Highlights• SPP Fraud Prevention Report

– SPP Internal Audit 2012 review of Compliance Hotline

Hotline implemented ‐ October 2005

Answered 24 hours a day, 7 days a week

Internal Audit review in August 2012

– No exceptions or findings related to process

– Recommendations to increase employee awareness

» Training targeted to hotline awareness» Training targeted to hotline awareness

» Increased visibility on employee web site

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Meeting Highlights

• SPP HR Staff Report

– StaffinggProjected 17 vacant positions by November 1, 2012Vacancy rate of approximately 3%

– SPP philosophy of hiring staff that value and support the SPP culture

Report on recruitment and diversity outreach programs– Report on recruitment and diversity outreach programs

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Meeting Highlights

• SPP HR Staff Report

– Fall 2012 College and University campus visits by HR and g y p ySPP staff:

Georgia Tech

Howard University

Morgan State

University of Arkansas, Little Rock

University of Arkansas, Fayetteville

Arkansas Tech University

Louisiana Tech University

Oklahoma State University

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Meeting Highlights• SPP HR Third Quarter Accomplishments

– Annual Leadership training

8 week class 26 participants In house instructors8 week class, 26 participants, In‐house instructors

– Employee Training

Employment law for managers

Effective presentations class for engineers

– Outreach

Outreach to high schools on value of STEM (Science, Technology, Engineering and Math) career paths

Outreach to girls in junior high and high school on STEM career paths via “Girls of Promise” program in Arkansas

Established relationship with University of Central Arkansas Computer Science Department 8

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Meeting Highlights• Committee reviewed their major accomplishments

during 2011 – 2012:

d d d d h– Reviewed and updated the HRC Scope statement to separate duties of benefit plan design and benefit plan investment review between the HRC and the Finance Committee.

– Reviewed Investment Policy Statements for the defined benefit, defined contribution, and retiree healthcare funds. Upheld responsibilities to assure adequacy and appropriateness.

– Assessed and approved a recommendation for 2013 compensation adjustments in the SPP budget.

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Meeting Highlights• Committee reviewed their major accomplishments

during 2011 – 2012:

d d h f l d l– Provided oversight of corporate culture and organizational development to promote employee engagement throughout the organization.

– Provided oversight of training and development of SPP’s most important asset: its people. Training programs reviewed included on‐line training, leadership training, management training, and soft skill training.

– Recognized, supported and suggested ways to assure laws, policies and ethics surrounding employment at SPP undergo continuous quality improvement.

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Meeting Highlights• Committee reviewed issues pending before the group:

– Overall benefit program design that establishes a long t l ti hi b t SPP d l tterm relationship between SPP and employees, promotes engagement and provides a cost benefit to the organization.

– Organization and career development programs at SPP to promote high levels of employee engagement.

– Overview of comprehensive compensation survey andOverview of comprehensive compensation survey and evaluation of SPP job roles by independent consultant in 2013.

– Oversight of performance compensation program.

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Meeting Highlights• Committee reviewed issues pending before the group:

– Impact of healthcare reform on SPP’s self‐insured medical lplan.

– Recruiting, hiring and retaining career employees to support the organization’s corporate goals.

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Southwest Power Pool BOARD OF DIRECTORS/MEMBERS COMMITTEE MEETING Kansas City Marriott Country Club Plaza, Kansas City, MO

July 31, 2012

- Summary of Action Items -

1. Approved Consent Agenda items: a. Approve April 24, 2012 minutes b. Markets and Operations Policy Committee

i. MWG - MPRR 51 & 71 ii. RTWG – TRR 059 & 067


Directors approve its request regarding Tariff Revision Request (TRR) 068.

3. Approved the Markets and Operations Policy Committee’s recommendation that the Board of Directors approve its request regarding Tariff Revision Request (TRR) 069.


Directors suspend the NTC for the Lynn County Substation to allow re-evaluation.

5. Approved the Markets and Operations Policy Committee’s recommendation that the Board of Directors suspend the NTC for the Halstead South Transformer 138/69 kV and Altoona East 69 kV Capacitor.

6. Approved the Markets and Operations Policy Committee’s recommendation that the Board of Directors approve OMPA’s waiver request 75196276.


Directors approve AECC’s waiver requests 76585985 and 76586012.

8. Approved the Strategic Planning Committee’s recommendation for approval of the policy decisions contained in the SPC Task Force on Order 1000 2nd Report dated July 20, 2012. The following recommendations are contained in the Report:

1. Recommendation as to what Transmission Owner Selection Criteria SPP should use

(including the adoption of the Finance Committee Task Force on Order 1000’s recommended Financial Scoring Criteria);

2. Recommendation as to What Owner Qualifications Criteria SPP should establish for Applicant Transmission Owners (including the adoption of the Finance Committee Task Force on Order 1000’s recommended Financial QTO Bid Submission Requirements and QTO Post-Selection Criteria (Firm Capital Commitment and 2% Deposit);

3. Recommendation on the Mobile-Sierra doctrine; 4. Recommendation on the Retention of ROFR for Short-Term Reliability Projects: and, 5. Recommendation on establishment of a “Need-by” date, Notice of such date and

requirement to meet deadlines.

2

MINUTES NO. 147


BOARD OF DIRECTORS/MEMBERS COMMITTEE MEETING Kansas City Marriott Country Club Plaza, Kansas City, MO

July 31, 2012 Agenda Item 1 - Administrative Items

SPP Chair Mr. Jim Eckelberger called the meeting to order at 8:00 a.m. The following Board of Directors/Members Committee members were in attendance or represented by proxy:

Mr. Larry Altenbaumer, director Ms. Phyllis Bernard, director Mr. Julian Brix, director Mr. Nick Brown, director Mr. Mike Deggendorf, Kansas City Power and Light Mr. Mo Doghman, Omaha Public Power District Mr. Jim Eckelberger, director Mr. Kelly Harrison, Westar Energy Ms. Cindy Holman, Oklahoma Municipal Power Authority Mr. Rob Janssen, Dogwood Energy Mr. Paul Malone, proxy for Mr. Tom Kent, Nebraska Public Power District Mr. Jeff Knottek, City Utilities of Springfield Mr. Brett Kruse, Calpine Energy Services Mr. Steve Parr, Kansas Electric Power Cooperative Mr. Josh Martin, director Mr. Phil Crissup, proxy for Mr. Mel Perkins, OG+E Electric Services Mr. Gary Roulet, Western Farmers Electric Cooperative Mr. Harry Skilton, director Mr. Stuart Solomon, American Electric Power Mr. Noman Williams, Sunflower Electric Power Corporation Mr. Mike Wise, Golden Spread Electric

Mr. Eckelberger asked for a round of introductions. There were 109 persons in attendance either in person or via phone representing 30 members (Attendance List - Attachment 1). Mr. Nick Brown reported proxies and a quorum was declared (Proxies - Attachment 2). Mr. Eckelberger welcomed Mr. Michael Ming (Oklahoma Secretary of Energy) and Mr. Kirk Thompson (President of Kansas Electric Power Cooperative). Agenda Item 2 – Board Reports President’s Report

Mr. Nick Brown presented the President’s Report (President’s Report – Attachment 3). Mr. Brown announced that SPP held a ribbon-cutting for the new facility on July 9, moving onto the campus on July 16. Discussion regarding a new facility began in 2008, the SPP campus was approved in 2009 and ground-breaking took place in 2010. After 67 years in leased space, it is great to have a facility designed to meet SPP’s specific needs. Mr. Brown stated that the Integrated Marketplace has been divided into three components with the systems status moving from yellow to green. Internal and external audits continue to be performed to assess project status. More information will be provided later in the meeting. SPP revenue is currently up approximately 1.8% above forecast, in part due to receipt of $1 million as part of

SPP Board of Directors/Members Committee Minutes July 31, 2012

3

a FERC penalty settlement. SPP is 3.2% below budget due to a lag in staffing and and lower utilization of consultants and contractors. Moving forward SPP plans to address:

• Transmission cost and tracking cost on a real-time basis • Gas and electric interaction and the impact on bulk electricity • NERC Standards development; specifically quickening the pace of rewriting NERC’s standards.

Any ideas would be welcome. Mr. Brown called attention to the 2012 Second Quarter Metrics provided in the background material. He stated that questions could be directed to Mr. Carl Monroe. He then called upon Mr. Monroe to provide a report on the impact of transmission expansion and congestion in the SPP footprint (Transmission Expansion & Congestion – Attachment 4). Regional Entity Trustee Report

Mr. John Meyer presented the Regional Entity Trustee report (RE Report – Attachment 5). The report included updates on:

• BES Definition/Exception Process • Vegetation Management • Misoperations • Southwest Blackout • Regional Standards Under Development • 2013 Budget Summary • SPP RE YTD Outreach Activities

In regards to CIP violations as reported by Mr. Meyer, Mr. Eckelberger stressed that we could do much better and save not only time but money. He urged the members to be more intentional in helping clear these violations. Regional State Committee Report

Mr. Olan Reeves (Arkansas Public Service Commission) presented the Regional State Committee (RSC) report. Mr. Reeves stated that the RSC met on July 30. The following items were discussed:

• Voted to support SPP’s filing on Order 1000 and 1000A seeking to maintain a Right of First Refusal (ROFR) in three areas. RSC plans to provide a letter/resolution with the SPP filing to demonstrate support.

• Voted to support the General Benefit Principles and the Interregional Cost Allocation Principles regarding seams issues.

• Voted to approve OMPA and AECC waiver requests as recommended by the Cost Allocation Working Group (CAWG).

Federal Energy Regulatory Commission Report

Mr. Patrick Clarey provided an update on recent FERC activities:

May FERC upheld its Order No. 1000 reforms to transmission planning and cost allocation. FERC denied rehearing of the July 2011 final rule establishing minimum criteria that a transmission planning process must satisfy, including general principles for cost allocation methods.


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The order also affirms the Commission’s actions in Order No. 1000 to promote competition in regional transmission planning by removing from Commission-approved tariffs and agreements any federal right of first refusal for transmission facilities selected in a regional transmission plan for purposes of cost allocation, subject to certain limitations. FERC recently approved SPP’s requested 32-day extension for a compliance filing for Order No. 1000. FERC approved a policy statement outlining how it will advise the Environmental Protection Agency (EPA) on requests for extra time for electric generators to comply with the new mercury and air toxics standards rule. The Commission will vote on its comments before providing them to EPA, but this will not constitute a final determination that a reliability standard has or will be violated, nor will it be considered a final agency action that would trigger civil penalties or other enforcement actions. June Commissioners Tony Clark and John Norris were sworn in for their new terms. FERC issued a proposal that would approve the North American Electric Reliability Corporation’s (NERC) revisions to the definition of the bulk electric system to provide greater clarity and ensure consistency in identifying system elements across the nation’s reliability regions. July FERC announced the dates and locations for five regional technical conferences on better coordination between natural gas and electricity markets. The conferences will explore gas-electric interdependence as well as ways to improve coordination and communication between the two industries. Discussion at each conference will focus on: (1) communications, coordination and information sharing; (2) scheduling; (3) market structures and rules; and (4) reliability concerns. The conferences will be open to the public, and Commission members will attend. SPP’s region will be included in an August 6th conference in St. Louis along with MISO and ERCOT.

At the July Open Meeting FERC proposed to clarify and refine its policies governing capacity allocation for new merchant transmission projects and new nonincumbent, cost-based, participant-funded transmission projects. FERC upheld NERC’s assessment of a $19,500 penalty against the Southwestern Power Administration for violations of certain reliability standards. Over objections from DOE, FERC found that under the FPA, it has the authority to impose a monetary penalty against a federal agency for violation of a mandatory reliability standard.

Oversight Committee Report

Mr. Josh Martin provided the Oversight Committee report. The Committee met in Little Rock in June. Larry Altenbaumer attended with Julian Brix to start their transition between the Oversight and Human Resources Committees.

The Committee heard quarterly reports from Internal Audit, Compliance, and Market Monitoring staff.

• Internal Audit continues its regular audits, as well as its oversight roles in the construction and Integrated Marketplace initiatives. A preliminary audit schedule for 2013 - 2014 was presented and will be finalized at the September meeting. Plans are to continue the focus on higher-risk areas, and particularly those that intersect with the Integrated Marketplace initiative.

• Compliance provided a report on its Member Outreach initiative (Outreach Efforts – Attachment 6). Several Evidence Reviews have been completed and more are scheduled for this year. A Compliance Forum was held May 24; another is scheduled for August 16 in Tulsa.


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• The Market Monitoring Unit staff remains engaged in the Integrated Marketplace initiative, developing the various new metrics that will be necessary to monitor the new markets. FERC issued Order 760 earlier this year requiring certain market data be provided on a regular basis to the new Division of Analytics and Surveillance. The MMU staff is coordinating SPP’s response to this new requirement.

The committee also heard preliminary plans for each department’s 2013 budget, and a summary of each department’s updated strategic plans. The Oversight Committee’s next scheduled meeting is September 27.

Human Resources Committee Report Ms. Phyllis Bernard provided the Human Resources Committee report (HRC Report – Attachment 6). The committee expressed appreciation for Mr. Larry Altenbaumer’s service and welcomed Mr. Julian Brix. Mr. Altenbaumer will be taking Mr. Brix’s place on the Oversight Committee. Ms. Bernard then provided an update on SPP’s fall recruitment at colleges and universities, a new campus report, and the SPP Performance Compensation Plan. Ms. Bernard thanked Mr. Mike Palmer and Mr. Noman Williams for a suggestion to have systems to contact staff in case of natural disasters such as the tornado in Joplin. Finance Committee Report

Mr. Harry Skilton presented the Finance Committee Report (FC Report – Attachment 7). Mr. Skilton stated that the Finance Committee Task Force on Order 1000 recommended key financial requirements for participants in SPP’s Competitive Solicitation Process. This is further explained in the Strategic Planning Committee’s report later in the meeting. The Credit Practices Working Group developed processes to comply with FERC Order 741 requirements for netting and offset. SPP will become the central counter party to all transactions in the Integrated Marketplace, a method consistent with most Regional Transmission Organizations. Other issues addressed in the Finance Committee meeting were:

• Reviewed performance of managers of SPP’s Pension funds

• Discussed the Business Process Improvement program

• Discussed the corporate liability insurance program and annual review

Corporate Governance Committee Report

Mr. Nick Brown provided the Corporate Governance Committee Report. Mr. Brown noted that there are vacancies for a Transmission User (TU) representative on the Human Resources Committee and two openings for TU representatives on the Finance Committee. A notice of Members Committee expiring terms has been distributed. Please send nominations to Ms. Stacy Duckett. The Committee is still reviewing changes associated with the withdrawal obligation for regional transmission costs. Mr. Brown encouraged all to review previously distributed drafts and provide any comments/questions. The Committee plans to finalize some Bylaws revisions associated with Board committee responsibilities for presentation at the October meeting. SPP will host a Chairs/Secretaries Workshop on November 27-28 in Little Rock to address organizational group administration and assessment of meetings. The CGC will meet again on August 30 at a location to be determined. Agenda Item 3 – Consent Agenda Mr. Eckelberger presented the following Consent Agenda items for approval (Consent Agenda – Attachment 8):

a. Approve April 24, 2012 minutes b. Markets and Operations Policy Committee


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i. MWG - MPRR 51 & 71 ii. RTWG – TRR 059 &067

Mr. Eckelberger asked for requests to remove any items from the Consent Agenda or a motion to approve. Ms. Bernard stated that she had requested some minor changes, which would not impact the substance of the minutes. Mr. Josh Martin moved to approve the Consent Agenda items with the April minutes as amended; Mr. Harry Skilton seconded the motion. The Members Committee voted in unanimous approval. The Board voted; the motion passed.

Agenda Item 4 – Integrated Marketplace Report

Mr. Bruce Rew provided an update on the Integrated Marketplace (Integrated Marketplace – Attachment 9). Mr. Rew addressed successes, a recovery plan, areas of concern, risks going forward and Market Participant readiness and Staff readiness. In the area of Market Participant readiness, he encouraged all participants to monitor the engagement report posted monthly on the SPP website. Mr. Eckelberger also stressed the importance of participant readiness so there would not be a repeat of the EIS Market delay. Every member should communicate issues as soon as possible in order to remain on track. Agenda Item 5 – Markets and Operations Policy Committee Report

Mr. Bill Dowling provided the Markets and Operations Policy Committee report (MOPC Report – Attachment 10). He presented the following action items for approval:

TRR 068: Mr. Dowling presented the recommendation for TRR 068 Balanced Portfolio Transfers Tariff Revisions. Following much discussion, Mr. Nick Brown moved and Mr. Julian Brix seconded to approve:

BOD approves TRR068, with the understanding that further analysis by the MOPC of the unintended consequences of the cost changes and allocation in the balanced portfolio and the required FERC filing will state that this analysis is being performed with initial report expected in October 2012.

The Members Committee voted with Mr. Mike Wise and Mr. Gary Roulet against and Mr. Noman Williams in abstention. The Board voted; the motion passed. The Project Cost Working Group has agreed to take on this review and report for October. TRR 069: Mr. Dowling presented the recommendation for TRR 069 Rates for Through and Out Transmission Service. Mr. Larry Altenbaumer moved to approve TRR 069; Mr. Harry Skilton seconded. The Members Committee voted with Mr. Kelly Harrison in abstention. The Board voted; the motion passed. NTC Suspension for Lynn County Substation: Mr. Dowling stated that the MOPC recommends suspension of the NTC for the Lynn County Substation to allow re-evaluation. Mr. Harry Skilton moved to approve; Mr. Larry Altenbaumer seconded the motion. The Members Committee voted with Mr. Mike Wise in abstention. The Board voted; the motion passed. NTC Suspensions for Halstead and Altoona: Mr. Dowling stated that the MOPC recommends suspension of the NTC for the Halstead South Transformer 138/69 kV and Altoona East 69 kV Capacitor. Mr. Josh Martin moved for approval; Mr. Harry Skilton seconded the motion. The Members Committee voted in unanimous approval. The Board voted; the motion passed. OMPA Waiver Request: Mr. Dowling asked that the Board approve MOPC’s recommendation that the cost of OASIS Request 75196276 upgrade not be allocated to OMPA. During discussion, it was suggested that the Business Practices Working Group (BPWG) reassess the waiver process to avoid waivers of such small amounts. Mr. Larry Altenbaumer moved for approval; Ms. Phyllis Bernard seconded the motion. The Members Committee voted in unanimous approval. The Board voted; the motion passed.


7

AECC Waiver Request: Mr. Dowling asked that the Board approve MOPC’s recommendation that the cost of OASIS Request 76585985 and 76586012 upgrades not be allocated to AECC. Ms. Phyllis Bernard moved for approval; Mr. Nick Brown seconded the motion. The Members Committee voted in unanimous approval. The Board voted; the motion passed. Mr. Dowling then presented the following informational items:

• CBASC – Balancing Authority Registration • ESWG – ITP20 Update • BPWG – GI and Aggregate Study Improvements • SPCWG – UFLS • Balanced Portfolio • TWG – Tres Amigas • EIS Market Benefits

Agenda Item 6 – Strategic Planning Committee Report

Mr. Ricky Bittle provided the Strategic Planning Committee report (SPC Report – Attachment 11). Mr. Bittle stated that FERC had extended SPP’s filing date to November 17, 2012. Mr. Eckelberger applauded Mr. Mel Perkins for his leadership in this effort. He also commended the RSC for their support including a trip to FERC to explain and endorse SPP’s work. Mr. Bittle then requested approval of SPC’s recommendation:

The Strategic Planning Committee recommends approval of the policy decisions contained in the SPC Task Force on Order 1000 2nd Report dated July 20, 2012. The following recommendations are contained in the Report:

1. Recommendation as to what Transmission Owner Selection Criteria SPP should use (including the adoption of the Finance Committee Task Force on Order 1000’s recommended Financial Scoring Criteria);

2. Recommendation as to What Owner Qualifications Criteria SPP should establish for Applicant Transmission Owners (including the adoption of the Finance Committee Task Force on Order 1000’s recommended Financial QTO Bid Submission Requirements and QTO Post-Selection Criteria (Firm Capital Commitment and 2% Deposit);

3. Recommendation on the Mobile-Sierra doctrine;

4. Recommendation on the Retention of ROFR for Short-Term Reliability Projects: and,

5. Recommendation on establishment of a “Need-by” date, Notice of such date and requirement to meet deadlines.

Ms. Phyllis Bernard moved for approval; Mr. Julian Brix seconded the motion. The Members Committee voted in unanimous approval. The Board voted; the motion passed. Mr. Nick Brown requested that Mr. Michael Desselle provide a brief update on the EPA effort. Mr. Desselle stated that there is monthly dialog taking place with FERC and the Department of Energy. An outage information study will be complete in late August or September as well as a list of retired units, which may be published.

Mr. Eckelberger stated that in January 2012 the Board of Directors/Members Committee held a dinner to discuss how best to address strategic planning for the organization. He suggested another dinner be scheduled with the October 2012 meetings. He also asked that members who are involved with more than one RTO share ideas that they have observed and that seem to work well.


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Agenda Item 7 – Future Meetings

Mr. Eckelberger reminded the group that the next SPP Board of Directors meeting will be October 30 in Little Rock at SPP’s new facility (Future Meetings – Attachment 12). Adjournment

With no further business, Mr. Eckelberger thanked everyone for participating and adjourned the meeting at 2:15 p.m. Stacy Duckett, Corporate Secretary Executive Session During the Executive Session, the Board approved a staff recommendation regarding settlement of a compliance matter.

Southwest Power Pool, Inc.

MARKETS AND OPERATIONS POLICY COMMITTEE Recommendation to the Board of Directors

MPPRs 74, 76, 86, 88 and 89 October 29-30, 2012

Organizational Roster

The following members represent the Market Working Group:

Richard Ross, AEP, Chairman Gene Anderson, OMPA, Vice Chairman Will Amos, OGE Lee Anderson, Lincoln Electric System Holly Black, City Utilities, Springfield, MO Jessica Collins, Xcel Energy Neal Daney, KMEA Jim Flucke, KCPL Clifford Franklin, Westar Energy, Inc. Chris Lyons, Constellation Energy Commodities Group Rick McCord, EDE Matt Moore, Golden Spread Electric Cooperative Aaron Rome, Midwest Energy, Inc. Ann Scott, Tenaska Power Services Co. Bruce Walkup, AECC Rick Yanovich, OPPD Debbie James, SPP, Secretary

Background

Please see the MPRR Recommendation Report for MPPRs 74, 76, 86, 88 and 89 that were included in the MOPC October 16-17, 2012 background materials.

Analysis

Please see the MPRR Recommendation Report for MPPRs 74, 76, 86, 88 and 89 that were included in the MOPC October 16-17, 2012 background materials.

Recommendation

The MWG recommends that the MOPC approve its request regarding Marketplace Protocol Revision Requests74, 76, 86, 88 and 89 Action Requested: Approval of MWG’s request on MPRRs 74, 76, 86, 88 and 89 APPROVED: MOPC October 16-17, 2012 MPRR’s 74, 76 and 88 Approved unanimously MPRR 86 Approved with two abstentions – EDP Renewables, Midwest Energy MPRR 89 Approved with one abstention – Tenaska Power Services

#5i. MWG PRR & MPRR Recommendations to MOPC--10 16-17 2012 Page 1 of 2

.

MPRR Number

Description

MWG Meeting Vote

RTWG Meeting Vote

ORWG Meeting Vote

74 DVER Clarification 6/20/2012 Unanimously approved

7/25/2012 Approved with modifications

7/26/2012 Approved

76 Clarification on How to Handle Not Participating Resources in

RTBM

6/20/2012 Unanimously approved


9/26/2012

Approved with modifications

7/26/2012 Approved

86 XML Instructions Clarification 7/24/2012

Approved with one abstention (OPPD)

9/26/2012 Approved with no Tariff implications


88 Non-Conforming Load and Demand Response Load

Aggregate Exception

8/15/2012 Unanimously approved

with modifications

9/26/2012 Approved

9/12/2012 Approved

89 Net Benefits Test 8/14/2012

Unanimously approved with modifications

9/12/2012

Approved with no Reliability Impact

#5i. MWG PRR & MPRR Recommendations to MOPC--10 16-17 2012 Page 2 of 2

#5k. MPRR 74 Recommendation Report 8/17/2012 Page 1 of 7

PRR Recommendation Report

PRR No. Marketplace-PRR74 PRR

Title DVER Clarification

Timeline Normal Expedited Urgent Action

Provide explanation if Expedited and/or Urgent Action is selected:

Recommendation Action

Approve Reject

Require additional information

Defer Refer

Impact Analysis Required Yes – If yes, estimated cost: No

SPP Staff will complete this section.

Protocol Section(s) Requiring Revision

Section No.: 4.2.2.5.5, 4.2.2.5.6, 4.4.3.1, 6.1.8 Title: : Dispatchable Variable Energy Resources, Non-Dispatchable Variable Energy Resources, Dispatchable Variable Energy Resource Deployment, Dispatchable Variable Energy Resource Protocol Version: 10.0

Type of Revision Correction/Clean-Up Clarification

Design Enhancement Design Change

Revision Description

This MPRR clarifies rules to state that DVERs are only eligible for Regulation-Down and not eligible to qualify to provide Regulation-Up, Spinning Reserve and Supplemental Reserve. It also clarifies how “follow” and “ignore” dispatch flags are set. The default setting for the dispatch flag will be “ignore.” The flag will be set to “follow” if the DVER is dispatched below its max operating limit or if it is cleared for Regulation-Down. The MPRR removes “Nameplate Maximum” and replaces it with “Emergency Maximum Capacity Operating Limit.”

Tariff Implications or Changes

Yes – Section No.: (Include a summary of impact and/or specific changes)

Attachment AE: 2.10 – Operating Reserve Certification, 4.1.2.4 – Dispatchable Variable Energy Resource, 4.1.2.5 – Non-Dispatchable Variable Energy Resource

No

MWG Review PRR Recommendation

Date of Vote: 6/20/2012—Unanimously approved All Segments present for the vote: Yes No Segment of Parties that voted No or Abstained: N/A

RTWG Review 7/25/2012—Approved with modifications

ORWG Review 7/26/2012—Approved

MOPC Recommendation

Board Review

EIS Market

Integrated Marketplace


Date 6/1/2012

Sponsor Name Gerardo Ugalde E-mail Address [email protected] Company Southwest Power Pool Phone Number 501.614.3212

Comments ReceivedComment Author RTWG Date 7/25/2012

Comment Description In Attachment AE in section 2.10, the word “Dispatchable” was added to distinguish Dispatchable Variable Energy Resources from Variable Energy Resources.

Comment Status The MPRR was approved as modified. The approved language is reflected in this recommendation report.

Comments Received

Comment Author ORWG Date 7/26/2012

Comment Description

ORWG approves of this MPRR, with the caveat that language should be reviewed to ensure that not ALL wind powered, hydro, etc. be forced into either DVER or NDVER status. Some of these resources may possess capability to perform as a “regular” resource and thus should be allowed to register that way. If these resources cannot be registered as a “regular” resource and are forced into DVER or NDVER status, then ORWG rejects this MPRR.

Comment Status

MWG cannot conceive of a situation where an entity would want to hold back energy/capability from such resources in order to make it capable to support such deployments (Reg-Up, Spin and Supp). Though technically it may be possible, it seems highly improbable. Relying on such resources to provide such reliability critical services seems unwise.

Proposed Protocol Language Revision

4.2.2.5.5 Dispatchable Variable Energy Resources

The following rules apply to Resources registered as Dispatchable Variable Energy Resources (“DVER”):

(1) The Minimum Emergency Capacity Operating Limit and Minimum Economic Operating Capacity Limit submitted as part of the Day-Ahead Market and/or RTBM Resource Offer must be submitted as zero MW. Otherwise, the Resource Offer will be rejected;

(2) For DVERs with an Emergency Maximum Capacity Operating Limit Nameplate Maximum of less than 200MW, the maximum ramp rate between MW specified in the Ramp-Rate-Up Curve and Ramp-Rate Down Curve in the RTBM Resource Offer multiplied by 5 cannot exceed 40MW. For DVERs with an Emergency Maximum Capacity Operating LimitNameplate Maximum greater than or equal to 200MW, the maximum ramp rate between MW levels specified in the Ramp-Rate-Up Curve and Ramp-Rate-Down Curve in the RTBM Resource

mailto:[email protected]�


Offer multiplied by 5 cannot exceed 20% of the DVER’s Emergency Maximum Capacity Operating Limit.nameplate capacity, where the DVER's nameplate capacity is specified during market registration in accordance with Section 6.1.8;

(3) For the RUC processes, the maximum operating limit shall be as submitted in the Resource Offer, except that, for wind powered DVERs, the lesser of the Emergency Maximum Capacity Operating Limit as specified in the Resource DVER Offer and SPP’s wind output forecast for that ResourceDVER. If SPP does not have an output forecast for that DVER, the maximum operating limit shall be the Emergency Maximum Capacity Operating Limit as specified in the DVER Offer; shall be used to set the maximum operating limit;

(4) For the Real-Time Balancing Market, DVER Dispatch Instructions are calculated assuming the DVER is dispatchable regardless of its Control Status. DVERs eligible to clear Regulation-Down must submit a Control Status of “Regulating” if capable of providing Regulation-Down. SPP will provide a dispatch flag to the DVER indicating whether or not the DVER should “follow” or “ignore” its Setpoint Instruction. Use of these dispatch flags in calculating Setpoint Instruction is described under Section 4.4.3.1. These flags are set as part of the RTBM solution as follows:

(a) The default value of the dispatch flag will be “ignore”. When the dispatch flag is “ignore”, the DVER’s maximum operating limit is set equal to the DVER’s actual output at the time of the current RTBM run;

(b) The dispatch flag will be set to “follow” if (i) the DVER is dispatched below its maximum operating limit or (ii) the DVER is cleared for Regulation-Down;if the current RTBM dispatch flag is “Follow”, where such flag is described under Section 4.4.3.1, the Dispatch Instruction is calculated assuming the DVER is dispatchable regardless of its Control Status;

(5) For the Real-Time Balancing Market for the current RTBM run, if the previous RTBM dispatch flag wasis “Ffollow” as set by the previous RTBM run and the current RTBM dispatch flag is “Ignore”, where such flags are described under Section 4.4.3.1, then the DVER’s maximum operating limit is set equal to either (i) the lesser of SPP’s output forecast for that DVER or the DVER’s Emergency Maximum Capacity Operating Limit; or the Emergency Maximum Capacity Operating Limit as specified in the DVER Offer if no SPP output forecast is available. the RTBM maximum operating limit is the lesser of SPP’s wind output forecast for that Resource and the previous dispatch plus ramp rate up and the DVER Dispatch Instruction is calculated based upon the DVERs Control Status. For all other DVERs dispatched at their effective max in the previous RTBM, the RTBM maximum operating limit is the actual Resource output at the time of the dispatch run and the DVERs Dispatch Instruction is calculated based upon the DVERs Control Status.


4.2.2.5.6 Non-Dispatchable Variable Energy Resources

The following rules apply to Resources registered as Non-Dispatchable Variable Energy Resources (“NDVER”):

(1) For the RUC processes, the maximum operating limit shall be as submitted in the Resource Offer, except that, for wind powered NDVERs, the lesser of the Resource Offer or SPP’s wind output forecast for that Resource shall be used to set the maximum operating limit;

(1) For the RUC processes, the maximum operating limit shall be as submitted in the Resource Offer;

(2) For the Real-Time Balancing Market, the Resource’s Energy Offer Curve shall not apply, and offer prices shall be assumed equal to zero for the purposes of calculating production costs relating to RUC make-whole payments and cost allocation thereof under Sections Error! Reference source not found. and Error! Reference source not found.. The Resource must operate in “Manual” Control Status and the Setpoint Instruction will be an echo of actual SCADA output as updated every ten seconds.

4.4.3.1 Dispatchable Variable Energy Resource Deployment

SPP shall provide a binary signal flag via ICCP and XML which notifies the Dispatchable Variable Energy Resource (DVERs) to either “Follow” or “Ignore” the RTBM Dispatch Instruction. When the “Follow” Dispatch Instruction signal is received, the Dispatchable Variable Energy Resource shall follow the Setpoint Instruction and the Setpoint Instruction shall be equal to either (i) the sum of the RTBM Dispatch Instruction and Regulation Deployment Instruction if cleared to provide Regulation-Down if Control Status is “Regulating”; or (ii) the RTBM Dispatch Instruction if Control Status is “Non-Regulating” or “Manual”. In any Dispatch Interval in which the DVER dispatch flag is set to “Ignore”, the Setpoint Instruction is calculated as the echo of actual SCADA outputnormally based upon the DVERs Control Status.

6.1.8 Dispatchable Variable Energy Resource

All Variable Energy Resources must register as a Dispatchable Variable Energy Resource except for: Variable Energy Resources with an interconnection agreement executed prior to May 21, 2011;. Non-wind (e.g. solar, run-of-the-river hydro, biomass) Variable Energy Resources shall not be required to register as a Dispatchable Variable Energy Resources unless they choose to register as such.

(1) A Dispatchable Variable Energy Resource is eligible to submit Offers for Regulation-Down if that Resource qualifies to provide Regulation-Down by passing the test described under Section 6.1.11.3.

(2) A Dispatchable Variable Energy Resource is not eligible to submit Offers for Regulation-Up, Spinning Reserve or Supplemental Reserve;

(3) TheseDispatchable Variable Energy Resources are committed and dispatched the same as any other Resource in the Day-Ahead Market.


(4) For the RUC and RTBM, special commitment and dispatch rules apply as defined under Section 4.2.2.5.5 Dispatchable Variable Energy Resources.

(1)(5) Dispatchable Variable Energy Resource data submittal requirements are defined in the SPP Criteria.

Proposed Tariff Language Revision

2.10 Operating Reserve Certification

In order to be eligible to submit Operating Reserve Offers, a Market Participant’s

Resource must meet the certification requirements in the Subsections below. Dispatchable

Variable Energy Resources may only qualify to provide Regulation-Down. Dispatchable

Variable Energy Resources are not eligible to provide Regulation-Up or Contingency Reserve.

4.1.2.4 Dispatchable Variable Energy Resource

Each Market Participant may submit Resource Offers for Dispatchable Variable

Energy Resources using the same Offer parameters available to any other Resource,

except that:

(1) The minimum operating limits specified in the Resource Offer must be equal to

zero;

(2) The maximum operating limits submitted in the Resource Offer for use in the

Day-Ahead Market, the Day-Ahead RUC and the Intra-Day RUC for a wind

powered Dispatchable Variable Energy Resource shall be calculated by the

Transmission Provider as equal to the lesser of the submitted maximum operating

limits submitted in the Resource Offer or the Transmission Provider’s output

forecast for that Resource to the extent that such output forecast is available,

otherwise the maximum operating limits shall be equal to those submitted in the

Resource Offer;

(3) For Dispatchable Variable Energy Resources with a maximum capability of less

than two-hundred (200) MWs, submitted ramp rates multiplied by five (5) cannot

exceed forty (40) MWs;

(4) For Dispatchable Variable Energy Resources with a maximum capability of

greater than two-hundred (200) MWs, submitted ramp rates multiplied by five (5)

cannot exceed twenty percent (20%) of the maximum capability;


(5) For the RTBM, during times when the Transmission Provider issues a Dispatch

Instruction to a Dispatchable Variable Energy Resource to reduce output, the

Resource’s Setpoint Instruction shall be equal to the sum of the Resource’s

Dispatch Instruction and any Regulation-Down deployment, even if the Market

Participant has indicated that the Resource is not dispatchable; and

(6) For the RTBM, during times when the Transmission Provider issues a Dispatch

Instruction to a Dispatchable Variable Energy Resource to increase output and has

issued a Dispatch Instruction in the previous Dispatch Interval to reduce output,

the Transmission Provider shall calculate the Resource maximum operating limit

to be equal to the lesser of:

(a) The Transmission Provider’s Dispatchable Variable Energy Resource

output forecast for that Resource; or

(b) The maximum operating limits submitted in the Resource Offer or the

Transmission Provider’s Dispatchable Variable Energy Resource output

forecast for that Resource to the extent the such forecast is available; or

(b) The maximum operating limits submitted in the Resource Offer if the

Transmission Provider’s Dispatchable Variable Energy Resource output

forecast for that Resource is not available. The sum of the Dispatch

Instruction issued in the previous Dispatch Interval and five (5) times the

Resource’s ramp rate.

Otherwise, the Resource’s maximum operating limit for use in the current

Dispatch Interval shall be equal to the Resource’s actual output at the start of the

Dispatch Interval.

4.1.2.5 Non-Dispatchable Variable Energy Resource

Each Market Participant may submit Resource Offers for Non-Dispatchable

Variable Energy Resources using the same Offer parameters available to any other

Resource, except that

(1) For the RTBM, the Resource’s Energy Offer Curve shall not apply;

(2) For the RTBM, the Resource’s Dispatch Instruction shall be equal to the

Resource’s actual output at the start of the Dispatch Interval and the Resources

must operate as non-dispatchable; and


(3) Resource Energy Offer Curve prices shall be assumed equal to zero (0) for the

purposes of calculating production costs relating to RUC make whole payments

and cost allocation thereof under Sections 8.6.5 and 8.6.7 of this Attachment AE;

and.

(4) The maximum operating limits for use in the Day-Ahead RUC and the Intra-Day

RUC shall be calculated by the Transmission Provider as equal to the lesser of the

maximum operating limits submitted in the Resource Offer or the Transmission

Provider’s output forecast for that Resource to the extent that such output forecast

is available, otherwise the maximum operating limits shall be equal to those

submitted in the Resource Offer;

Proposed Criteria Language Revision N/A

#5l. MPRR 76 Recommendation Report 10/2/2012 Page 1 of 7



Title Clarification on How to Handle Not Participating Resources in RTBM




Approve Reject


Defer Refer




Section No.: 4.2.2 Title: Offer Submittal Protocol Version: 10.0



Revision Description This MPRR clarifies that Resources with an Commitment Status of “Not Participating” in the Day-Ahead Market who apply that offer to the Real-Time Balancing Market will have their offer rejected and be forced to input a new offer.


Yes – Section No.: (Include a summary of impact and/or specific changes) Attachment AE: 4.1—Offer Submittal

No


Date of Vote: 6/20/2012—Unanimously approved All Segments present for the vote: Yes No Segment of Parties that voted No or Abstained: N/A

RTWG Review 7/25/2012—Approved with modifications 9/26/2012—Approved with modifications


MOPC Recommendation

Board Review

Date 6/1/2012

Sponsor Name Marisa Choate E-mail Address [email protected] Company Southwest Power Pool Phone Number 501.688.1707

EIS Market




Comments Received

Comment Author RTWG Date 7/25/2012 Comment Description Section 4.1(2)(a) was altered for readability.

Comment Status MWG changed Sections 4.1(10)(d) and (e) of Attachment AE to distinguish between an outage and not participating status.

Comments Received

Comment Author RTWG Date 10/2/2012

Comment Description Tariff language was changed. Section 4.1(2)(a) was corrected to point to the correct section 4.1(10)(e) instead of 4.1(10)(d). Section 4.1(10)(e) was reworded for clarification.

Comment Status


4.2.2 Offer Submittal

Beginning seven days prior to the Operating Day, Market Participants may begin to submit Offers for use in the DA Market and Offers for use in the RTBM. DA Market Offers may be updated up to 1100 hours Day-Ahead and RTBM Offers may be updated 30 minutes prior to each Operating Hour. The following business rules apply to Offer submittal:

(1) Offers submitted for use in the DA Market are submitted independent from the Offers submitted for use in the RTBM;

(2) Market Participants have the option of specifying that the Offers submitted for use in the DA Market also apply in the RTBM;

(a) If this option is selected and a Resource has a Commitment Status of “Not Participating” the submission will be rejected.

(2)(3) Submitted Resource Offers roll forward hour to hour until changed within each respective market (DA Market and RTBM);

(3)(4) Offers may be submitted that vary for each hour of the Operating Day except Offer parameters relating to unit commitment, as identified under Section 4.2.2.1, for which a single value is submitted that rolls forward in each hour until updated;

(4)(5) Offers submitted for use in the RTBM are also used in the RUC processes;

(5)(6) Resource Offers may only be submitted at Resource Settlement Locations, Import Interchange Transaction Offers may only be submitted at External Interface Settlement Locations; Virtual Energy Offers may be submitted at any Settlement Location, including a Hub;

(6)(7) Resource Offers for Regulation-Up may only be submitted for Regulation Qualified Resources and Regulation-Up Qualified Resources. Resource Offers for Regulation-Down may only be submitted for Regulation Qualified Resources and Regulation-Down Qualified


Resources. Resource Offers for Spinning Reserve may only be submitted for Spin Qualified Resources. Resource Offers for Supplemental Reserve may be submitted for either a Spin Qualified Resource or a Supplemental Qualified Resource. Resource qualifications are verified by SPP as part of the registration process as follows;

(a) A Regulation Qualified Resource, Regulation-Up Qualified Resource or Regulation-Down Qualified Resource must pass a specific regulation test as described under Section 6.1.11.3 that verifies:

(i) The Resource has the necessary equipment installed to be able to respond to Automatic Generation Control on a 4-second basis, including telemetering that can be scanned and updated on a 2-second basis; and

(ii) The Resource is capable of deploying 100% of cleared Regulation-Up or cleared Regulation-Down within the Regulation Response Time for a continuous duration of 60 minutes.

(b) A Spin Qualified Resource must:

(i) Self-Certify as described under Section 6.1.11.1 that the Resource is capable of deploying 100% of cleared Spinning Reserve or cleared Supplemental Reserve within the Contingency Reserve Deployment Period for a continuous duration of 60 minutes; and

(ii) Provide telemetered output data that can be scanned every 10 seconds.

(c) A Supplemental Qualified Resource must:

(i) Self-certify as described under Section 6.1.11.2 that the Resource is capable of deploying 100% of cleared Supplemental Reserve from an off-line state within the Contingency Reserve Deployment Period for a continuous duration of 60 minutes.

(ii) Provide telemetered output data that can be scanned every 10 seconds.

(7)(8) Resource Offers consisting of Energy Offer Curve, Regulation-Up Offer, Regulation-Down Offer, Spinning Reserve Offer and Supplemental Reserve Offer are limited by the offer caps and floors specified under Section 8.2.5.


4.1 Offer Submittal

Beginning seven (7) days prior to the Operating Day, Market Participants may begin to

submit Offers for use in the Day-Ahead Market and Offers for use in the RTBM. Day-Ahead

Market Offers may be updated up to 1100 hours Day-Ahead and RTBM Offers may be updated


thirty (30) minutes prior to each Operating Hour. Offer submittals shall conform to the

following:

(1) Offers submitted in the Day-Ahead Market are independent from Offers submitted in the

RTBM;

(2) Market Participants may specify that the Offers submitted in the Day-Ahead Market also

apply in the RTBM;

(a) Such an Offer shall be rejected in the RTBM ifIf this option is selected and a the Market Participant has submitted a Resource commitment status of as “unavailablenot participating” as described in under Section 4.1(10)(de) of this Attachment AE and the Resource is not participating in the Day-Ahead Market. and the Resource is otherwise available, the submission will be rejected.[MBC1]

(3) Submitted Resource Offers will automatically roll forward hour to hour until changed

within each respective market;

(4) Offers may be submitted that vary for each hour of the Operating Day, except the Offer

parameters related to unit commitment as defined in the Market Protocols for which a

single value is submitted. These unit commitment Offer parameters will automatically

roll forward in each hour until updated;

(5) Offers submitted for use in the RTBM are also used in the RUC;

(6) Resource Offers may only be submitted at Resource Settlement Locations, Import

Interchange Transaction Offers may only be submitted at External Interface Settlement

Locations and Virtual Energy Offers may be submitted at any Settlement Location,

including a Market Hub;

(7) For Regulation Qualified Resources and Regulation-Up Qualified Resources, Market

Participants may submit Resource Offers for Regulation-Up, Spinning Reserve and

Supplemental Reserve. For Regulation-Down Qualified Resources and Regulation

Qualified Resources, Market Participants may submit Resource Offers for Regulation-

Down. For Spin Qualified Resources, Market Participants may submit Resource Offers

for Spinning Reserve and Supplemental Reserve. For Supplemental Qualified Resources,

Market Participants may submit Resource Offers for Supplemental Reserve. Resource

qualifications are verified by the Transmission Provider as part of the registration process

as follows:

(a) A Regulation Qualified Resource, Regulation-Up Qualified Resource or

Regulation-Down Qualified Resource must pass a specific regulation test as


defined in Section 2.10.3 of this Attachment AE and must be capable of

deploying one hundred percent (100%) of cleared Regulation-Up and/or

Regulation-Down within the Regulation Response Time for a continuous duration

of sixty (60) minutes and provide telemetered output data that meets the technical

requirements specified in the Market Protocols.

(b) A Spin Qualified Resource must self-certify that the Resource is capable of

deploying one hundred percent (100%) of cleared Spinning Reserve or cleared

Supplemental Reserve within the Contingency Reserve Deployment Period for a

continuous duration of sixty (60) minutes and provide telemetered output data that

meets the technical requirements specified in the Market Protocols.

(c) A Supplemental Qualified Resource must self-certify that the Resource is capable

of deploying one hundred percent (100%) of cleared Supplemental Reserve from

an off-line state within the Contingency Reserve Deployment Period for a

continuous duration of sixty (60) minutes and provide telemetered output data that

meets the technical requirements specified in the Market Protocols.

(8) Resource Offers are limited by the Offer caps and floors specified in Section 4.1.1 of this

Attachment AE;

(9) The Resource Offer parameters that constitute a valid Offer for use in either the Day-

Ahead Market or RTBM are submitted using the data formats, procedures, and

information defined in the Market Protocols and will include the following (as further

defined in the Market Protocols):

• Resource Name

• Resource Type

• Start-up Offer

• No-Load Offer

• Energy Offer Curve

• Regulation–Up and Regulation-Down Offers

• Spinning and Supplemental Reserve Offers

• Sync-To-Min and Min-To-Off Times

• Start-Up Time

• Hot to Intermediate and Hot to Cold Times

• Maximum Daily and Weekly Starts


• Maximum Daily Energy

• Maximum and Minimum Run Times

• Minimum Down Time

• Minimum Emergency Capacity Operating Limit and Run Time

• Minimum Normal, Economic, and Regulation Capacity Operating Limits

• Maximum Normal, Economic, and Regulation Capacity Operating Limits

• Maximum Emergency Capacity Operating Limits and Run Time

• Maximum Quick-Start Response Limit

• Ramp-Rate-Up and Ramp-Rate-Down

• Turn-Around Ramp Rate Factor

• Regulation Ramp Rate

• Contingency Reserve Ramp Rate

• Resource Status

• JOU Ownership Share

(10) Market Participants must specify a Resource commitment status as part of the Resource

Offer using the data formats, procedures, and information defined in the Market

Protocols. Market Participants use the commitment status to indicate;

(a) Whether they are self-committing a Resource;

(b) Whether the Resource may be committed by the Transmission Provider;

(c) Whether the Resource may be committed by the Transmission Provider only to

alleviate an anticipated Emergency Condition or local reliability issue; or

(d) Whether the Resource is unavailable on an outage.

(e) Whether the Resource is has elected not to participateing in the DA Market.

(11) Market Participants must specify a Resource dispatch status as part of the Resource Offer

using the data formats, procedures and information defined in the Market Protocols.

Market Participants use the dispatch status to notify the Transmission Provider whether

the Resource is:

(a) Eligible for Energy Dispatch;

(b) Eligible for Operating Reserve clearing; or

(c) Self-scheduled for Operating Reserve.

(12) Resource limits submitted as part of the Resource Offer must pass the validation rules

defined in the Market Protocols, otherwise, the Resource Offer will be rejected; and


(13) The Market Participant must comply with the must-offer requirements as defined in Section 2.11

of this Attachment AE.


#5q. MPRR 86 Recommendation Report 10/1/2012 Page 1 of 6



Title XML Instructions Clarification




Approve Reject


Defer Refer




Section No.: 4.4.2.4, 4.4.2.5, 4.4.3, 4.4.3.1, 4.4.3.2, 4.4.3.4 Title: RTBM Results, Out-of-Merit Energy (OOME) Dispatch, Energy and Operating Reserve Deployment, Dispatchable Variable Energy Resource Deployment, Non-Dispatchable Variable Energy Resource Deployment, Contingency Reserve Deployment Protocol Version: 10.0




The Protocols were not clear as to how MPs were to use operational instructions via XML. This MPRR clarifies that the receipt of XML instructions for Resources other than Block Demand Response Resources are to be used by Market Participants as a back-up in case of ICCP communications failure.


Yes – Section No.: (Include a summary of impact and/or specific changes)

No


Date of Vote: 7/24/2012—Approved All Segments present for the vote: Yes No Segment of Parties that voted No or Abstained: Abstained—OPPD

RTWG Review 9/26/2012—Approved with no Tariff Implications

ORWG Review 8/23/2012—Approved with modifications

MOPC Recommendation

Board Review

EIS Market



Date 7/11/2012

Sponsor Name Casey Cathey E-mail Address [email protected] Company Southwest Power Pool Phone Number 501.614.3267

Reasons for AbstainingAbstainer OPPD Date 7/25/2012 Reason No comments received

Comments ReceivedComment Author Carrie Simpson Date 7/18/2012

Comment Description

After further SPP internal review, some phrases were deleted as they were deemed unnecessary since Contingency Reserve Deployment Instructions will not be sent as XML. In the event of ICCP failure, energy deployments will be sent via XML every five minutes and any CR events will be communicated manually through OOM instructions.

Comment Status Comments were taken into consideration. The approved language is reflected in this recommendation report.

Comments Received

Comment Author ORWG Date 8/23/2012

Comment Description

ORWG added the following sentence to Section 4.4.3 to clarify that XML integration is not required: “This requirement does not necessitate automatic integration of the XML instructions within the Market Participants control systems.” This statement does not change the intent of the MPRR; it only clarifies what was already intended.

Comment Status


4.4.2.4 RTBM Results

Following execution of the RTBM SCED, the following results are communicated to Market Participants prior to the start of the applicable Dispatch Interval for information purposes. However, allAll Market Participants must have the capability to receive and follow Resource Dispatch Instructions via XML in the event of an ICCP communications failure following an ICCP data communication failure. The following results are communicated to each Market Participant that relates only to that Market Participant:

(1) Resource Dispatch Instructions. The Dispatch Instruction is a MW output target for the end of the applicable Dispatch Interval;

(2) Cleared Regulation-Up, Regulation-Down, Spinning Reserve and Supplemental Reserve MW by Resource.



These values are used by the Energy Management System (EMS) for Energy and Regulation Deployment and by the Reserve Sharing System (RSS) for Contingency Reserve Deployment. and will also be used by Market Participants as back-up Resource Dispatch Instructions in the event that SPP can no longer send ICCP Setpoint Instructions.

The following results are communicated to all Market Participants and are used for settlement purposes (i.e. prices used for settlement are “ex-ante”);

(1) Locational Marginal Prices (LMPs) for each Settlement Location, the Marginal Congestion Component (MCC) of LMP for each Settlement Location and the Marginal Losses Component (MLC) of LMP for each Settlement Location; and

(2) Market Clearing Prices for Regulation-Up, Regulation-Down, Spinning Reserve and Supplemental Reserve for each Reserve Zone.

4.4.2.5 Out-of-Merit Energy (OOME) Dispatch

SPP or a local Transmission Operator may issue reliability directives via a Manual Dispatch Instruction to any on-line Resource to resolve a reliability issue (referred to in the system as OOME, or out-of-merit energy). In such an event, a Resource will receive Setpoint Instructions via ICCP (and XML as backup) from SPP that include a Manual Dispatch Instruction for the duration of the reliability directive or may receive a Manual Dispatch Instruction directly from a local Transmission Operator. The Manual Dispatch Instructions will specify the MW level the Resource is expected to produce until such time as the constraint can be resolved by SCED through the RTBM. Such MW levels may include (i) dispatch below a Resource’s Minimum Economic Capacity Operating Limit down to Minimum Normal Capacity Operating Limit or Minimum Emergency Capacity Operating Limit as system conditions warrant or (ii) dispatch above a Resource’s Maximum Economic Capacity Operating Limit up to Maximum Normal Capacity Operating Limit or Maximum Emergency Capacity Operating Limit as system conditions warrant. While the OOME instruction is active, the resource minimum and maximum limits will be treated as though they are equal to the OOME instruction. The resource will not be eligible to clear reserve products during an OOME event. SPP will make every effort to define and activate the appropriate constraint.

When an OOME event occurs, the Transmission Operator may, when necessary, issue Manual Dispatch instructions directly to the affected Resource(s) and will notify SPP that it has done so, and SPP will ensure that the following occurs:

(1) Notifications are immediately issued that an OOME has been initiated and the MW level the resource is supposed to produce;

(2) Setpoint Instructions and Economic/Emergency Minimum and Economic/Emergency Maximum Limits for the current dispatch interval are immediately adjusted to the OOME MW level that has been issued;


(3) Setpoint Instructions for future intervals and Economic/Emergency Minimum and Economic/Emergency Maximum limits not yet dispatched will be set to the OOME MW level that has been issued;

(4) SPP notifies the Market Participant when the OOME event had ended;

(5) Asset Owners are compensated for OOME events in accordance with Section 4.5.9.9.

4.4.3 Energy and Operating Reserve Deployment

SPP deploys Energy, Regulation-Up, Regulation-Down, Spinning Reserve and on-line Supplemental Reserve simultaneously through the issuance of Setpoint Instructions via ICCP to each Resource on a 4-second basis. Deployment of Supplemental Reserve from off-line Quick-Start Resources is accomplished through SPP issuance of a start-up order following a Contingency Reserve event. The Setpoint Instruction is the sum of:

(1) The Resource MW Dispatch Instruction for the current Dispatch Interval either as developed by SCED under Section 4.4.2.3 or by Manual Dispatch Instruction as described under Section 4.4.2.4;

(2) Regulation-Up Deployment Instruction;

(3) Regulation-Down Deployment Instruction;

(4) Spinning Reserve Deployment Instruction; and

(5) On-line Supplemental Reserve Deployment Instruction.

Resource Setpoint Instructions represent the total amount of desired deployment (i.e. the Setpoint Instruction does not include a ramped signal, but a stepped signal). However, for information purposes, SPP will also provide a ramped Setpoint Instruction.

In the event of an ICCP communications failure, SPP will communicate Energy Dispatch Instructions and Contingency Reserve Deployment Instructions to Market Participants via XML and Market Participants must have the capability to receive and follow such XML instructions following an ICCP data communications failure. This requirement does not necessitate automatic integration of the XML instructions within the Market Participants control systems.

4.4.3.1 Dispatchable Variable Energy Resource Deployment

SPP shall provide a binary signal flag via ICCP (and XML as backup) which notifies the Dispatchable Variable Energy Resource (DVERs) to either “Follow” or “Ignore” the RTBM Dispatch Instruction. When the “Follow” Dispatch Instruction signal is received, the Dispatchable Variable Energy Resource shall follow the Setpoint Instruction and the Setpoint Instruction shall be equal to either (i) the sum of the RTBM Dispatch Instruction and Regulation Deployment Instruction if cleared to provide Regulation-Down if Control Status is “Regulating”; or (ii) the RTBM Dispatch Instruction if Control


Status is “Non-Regulating” or “Manual”. In any Dispatch Interval in which the DVER dispatch flag is set to “Ignore”, the Setpoint Instruction is calculated normally based upon the DVERs Control Status.

4.4.3.2 Non-Dispatchable Variable Energy Resource Deployment

Non-Dispatchable Variable Energy Resources (NDVERs) will be deployed the echo of actual SCADA output via ICCP (and XML as backup).

4.4.3.4 Contingency Reserve Deployment

Contingency Reserve procured in the RTBM will be deployed through a Contingency Reserve Deployment Instruction, via both Inter-Control Center Communications Protocol (ICCP) (and Extensible Markup Language (XML) instruction as backup) except in the case of a Block Demand Response Resource which only receives an XML instruction, following a system event, normally following the sudden loss of a Resource. The following rules apply to the deployment of Contingency Reserve for both internal SPP BA contingencies and for providing assistance to a Reserve Sharing Group member. Scheduling procedures for provision of assistance to/from Reserve Sharing Group members are described under Section 4.4.3.5:

(1) Contingency Reserve is deployed on Resources with cleared Contingency Reserve and Export Interchange Transactions providing Supplemental Reserve in the Dispatch Interval immediately following the system event;

(2) Spinning Reserve and on-line Supplemental Reserve is deployed ahead of off-line Supplemental Reserve;

(3) A Resource with deployed Spinning Reserve and/or on-line Supplemental Reserve that moves into “Manual” Control Status will continue to be issued a Setpoint Instruction that includes the amount of Spinning Reserve and/or Supplemental Reserve deployed on that Resource as described under Exhibit 4-10;

(4) If the amount of Spinning Reserve and on-line Supplemental Reserve cleared is greater than or equal to the Contingency Reserve amount required in response to a contingency, no off-line Supplemental Reserve is deployed;

(5) Spinning Reserve and on-line Supplemental Reserve is deployed in proportion to the amount of Spinning Reserve and on-line Supplemental Reserve cleared on each Resource, adjusted as needed to ensure deliverability;

(6) Supplemental Reserve from off-line Quick-Start Resources is deployed on Resources in merit order based on economics of Start-Up Offer, No-Load Offer, Energy Offer Curves and Minimum Run Time, adjusted as needed to ensure deliverability. For the purposes of deploying Supplemental Reserve supplied from Export Interchange Transactions, as described under Section 4.2.3.3, the merit order cost will be equal to zero;


(7) If a Resource fails all four of the tests described under Section 4.4.4.3 and the Resource’s individual smallest positive Shortfall Quantity is greater than 25% of the Contingency Reserve Deployment Instruction, the amount of Contingency Reserve available to be cleared on Resource will be reduced by that percentage based on the current Contingency Reserve Ramp Rate, for online deployment, or Maximum Quick-Start Response Limit for offline deployments, for the remainder of the Operating Day.


N/A


#5r. MPRR 88 Recommendation Report 9/27/2012 Page 1 of 9



Title Non-Conforming Load and Demand Response Load Aggregate Exception




Approve Reject


Defer Refer




Section No.: 4.2.2.5.1, 4.2.2.5.2, 6.2.2, 6.2.3 Title: Dispatchable Demand Response Resource, Block Demand Response Resource, Non-Conforming Load, Demand Response Load Asset Protocol Version: 10.0




Demand Response locations and Non-Conforming Loads may be served from more than one location in the field. The current design requires participants to register separate Non-Conforming Loads for each Non-Conforming PNode, as well as separate Demand Response Loads for each DR PNode. There is a need to represent these as an Aggregate PNode rather than registering them as multiple loads and submitting multiple forecasts because operators might not be able to forecast the individual loads, but only the process that those loads are serving. Also, representing Demand Response Loads and Non-Conforming Loads as Aggregate PNodes for loads in the same ultimate location significantly reduces operator workload without compromising system accuracy. This MPRR allows Non-Conforming Loads and Demand Response Loads to be registered as Aggregate PNodes, provided it is one load being served from multiple buses.


Yes – Section No: (Include a summary of impact and/or specific changes) Attachment AE: 2.2 Application and Asset Registration

No


Date of Vote: 8/15/2012—Unanimously approved with modifications All Segments present for the vote: Yes No Segment of Parties that voted No or Abstained: N/A

EIS Market



RTWG Review 9/26/2012—Approved


MOPC Recommendation

Board Review

Date 7/27/2012

Sponsor Name Chris Davis E-mail Address [email protected] Company Southwest Power Pool Phone Number 501.688.2546

Comments ReceivedComment Author MWG Date 8/15/2012

Comment Description The word “ultimate” was removed from the suggested language in 6.2.2 and 6.2.3 of the Protocols as it was confusing.



4.2.2.5.1 Dispatchable Demand Response Resource

The following special modeling rules apply to a DDR Resource.

(1) A DDR Resource is a special type of Resource created to model demand reduction associated with controllable load and/or a behind-the-meter generator that is dispatchable on a 5-minute basis;

(2) A DDR Resource is modeled in the Commercial Model the same as any other Resource with a defined Settlement Location and associated PNode or APNode that corresponds to the associated Demand Response Load PNode or APNode definition;

(3) A DDR Resource is also included in the SPP Network Model as a generator;

(4) A DDR Resource must have a corresponding Demand Response Load (DRL);

(5) The Demand Response Load for a DDR Resource must have telemetering installed;

(6) The Market Participant must submit the real-time value of the Demand Response Load to SPP via SCADA on a 10-second basis;

(7) A DDR Resource may select one of two options for reporting of the actual DDR Resource output: Submitted Resource Production Option or the Calculated Resource Production Option.



(a) Submitted Resource Production Option - For DDR Resources that are utilizing strictly behind-the-meter Generation to provide the response or DDR Resources where the retail provider is offering the Resource under an agreed upon Retail Tariff provision that includes near real-time measurement and verification terms, the amount of the response provided may be sent directly to SPP via ICCP and will represent the real-time resource production.

(i) The Market Participant must determine the real-time resource production and submit the value to SPP via SCADA on a 10-second basis.

(ii) After-the-fact integrated meter values will be submitted directly by the Meter Agent for the DDR Resource.

(b) Calculated Resource Production Option - SPP will calculate the real-time resource output for operational dispatch and actual Resource output for settlements.

(i) A baseline hourly load profile must be submitted for the DRL prior to the hour for which the DDR Resource has been committed that represents the forecast consumption for the hour assuming no load reduction.

(ii) At the start of the Operating Hour for which a DDR Resource is committed, SPP will take a snapshot of the demand MW consumption of the Demand Response Load.

(iii) The Real-Time Resource output for operational dispatch in the Dispatch Interval will be calculated as the difference between 1) the Minimum of (Hourly Load Profile of the DRL, Snapshot of the DRL SCADA interval prior to Deployment) and 2) the Real-Time SCADA value for the DRL.

(iv) The actual Resource output for use in settlements in the Dispatch Interval will be calculated as the difference between 1) the Minimum of (Hourly Load Profile of the DRL, Snapshot of the DRL SCADA interval prior to Deployment) and 2) the actual metered value for the DRL. The actual metered value for the DRL in the Dispatch Interval is either directly submitted by the Meter Agent if 5-minute metering is available or, is calculated by SPP based upon the hourly metered value submitted and the profiling method described under Section 4.5.9.

Exhibit 4-7 shows how a DDR Resource’s Real-Time output for operational dispatch would be calculated within an Operating Hour using the Calculated Resource Production Option.


Exhibit 4-1: Calculated DDR Output

Interval Net Tele-

metered Value of

DRL (1)

Hourly Load Profile

(2)

Telemetered Value prior to Deployment

(3)

DDR Resource Production

(4) = Min(2,3) – (1)

1 38 70 68 30 2 40 70 68 28 3 42 70 68 26 4 33 70 68 35 5 32 70 68 36 6 30 70 68 38 7 22 70 68 46 8 24 70 68 44 9 16 70 68 52

10 25 70 68 43 11 23 70 68 45 12 30 70 68 38

4.2.2.5.2 Block Demand Response Resource

The following special modeling rules apply to a BDR Resource.

(1) A BDR Resource is a special type of Resource created to model demand reduction that is not dispatchable on a 5-minute basis but can be committed and dispatched in hourly blocks;

(2) A BDR Resource is modeled in the Commercial Model the same as any other Resource with a defined Settlement Location and associated PNode or APNode that corresponds to the associated Demand Response Load PNode or APNode definition;

(3) A BDR Resource is not included in the SPP Network Model as a Resource;

(4) A BDR Resource must also have a corresponding Demand Response Load (DRL);

(5) The DRL must have telemetering installed and have the real-time Load consumption at the DRL sent to SPP SCADA via ICCP on a 10-second scan rate;

(6) All BDR Resources will use the Calculated Resource Production Option to determine the amount of Real-Time Resource Production and Actual Resource Production. Therefore, the following information requirements apply:

(a) An hourly load profile must be submitted for the DRL prior to the hour for which the BDR Resource has been committed that represents the forecast DRL consumption for the hour assuming no load reduction;

(b) The interval prior to the first interval for which a BDR Resource is committed and deployed, SPP will take a snapshot of the demand MW consumption of the DRL;

(c) The Real-Time Resource output for operational dispatch in the Dispatch Interval will be calculated as the difference between 1) the Minimum of (Hourly Load Profile of the


DRL, Snapshot of the DRL SCADA interval prior to Deployment) and 2) the Real-Time SCADA value for the DRL.

(d) The actual Resource output for use in settlements in the Dispatch Interval will be calculated as the difference between 1) the Minimum of (Hourly Load Profile of the DRL, Snapshot of the DRL SCADA interval prior to Deployment) and 2) the actual metered value for the DRL. The actual metered value for the DRL in the Dispatch Interval is either directly submitted by the Meter Agent if 5-minute metering is available or, is calculated by SPP based upon the hourly metered value submitted and the profiling method described under Section 4.5.9.

(7) There are also operational differences that apply to BDR Resources as follows:

(a) A BDR Resource will only use two operating limits: Minimum Economic Capacity Operating Limit and Maximum Economic Capacity Operating Limit. The Minimum Economic Capacity Operating Limit represents the MW amount of demand reduction associated with the first price block identified in the Energy Offer Curve. The Maximum Economic Capacity Limit will represent the maximum amount of demand reduction that can be achieved.

(b) In the RTBM, if the BDR Resource is committed and dispatched in the DA Market or RUC, the BDR Resource Minimum Economic Capacity Operating Limit will be increased to match the dispatched amount and either Spinning Reserve or Supplemental Reserve will be allowed to clear above minimum output if the BDR Resource is a Spin Qualified Resource. Spinning Reserve clearing will be based upon submitted Ramp-Rate Up curve for the BDR Resource, the submitted Spinning Reserve Offer, the Supplemental Reserve Offer and the BDR Resource’s Maximum Economic Capacity Operating Limit.

Other than the restriction on submittal of operating limits as stated in (a) above, a BDR Resource may submit Offers that include any of the Offer parameters listed under Sections 4.2.2.1 and 4.2.2.2.

6.2.2 Non-Conforming Load

Each Asset Owner must identify any Non-Conforming Load asset that the Asset Owner specifically

forecasts and the PNode or Aggregate PNode (APNode) at which it resides. A Non-Conforming Load

may only be represented by an APNode if the load is in the same ultimate location (e.g. a single

industrial process served by more than one bus). For the purposes of this registration requirement, any

Non-Conforming Load of 50 MW or greater must be identified.

6.2.3 Demand Response Load Asset

As part of the registration of a Dispatchable Demand Response Resource or a Block Demand Response

Resource, the Asset Owner must also identify a corresponding Demand Response Load Asset and its


associated PNode or APNode at which the load will be reduced. A Demand Response Load Asset may

only be represented by an APNode if the load is in the same ultimate location (e.g. a single industrial

process served by more than one bus). The PNode or APNode of the Demand Response Load Asset

must be contained within the associated Dispatchable Controllable Load or Block Demand Response

Settlement Location definition and have a single Meter Data Submission Location. The Demand

Response Load Asset is only used by SPP to identify the actual load reduction to verify DDR and BDR

compliance with Dispatch Instructions and Operating Reserve deployment instructions.


2.2 Application and Asset Registration

(1) Applications for a Market Participant to provide services in the Integrated Marketplace

must be submitted to the Transmission Provider prior to the expected date of participation

consistent with Section 6.4 of the Market Protocols. Applications must conform to the

procedures specified in the Market Protocols and may be rejected if not complete. New

Market Participants will follow the timeframe as specified in Section 6.4 of the Market

Protocols in addition to the detailed model update timing requirements in Appendix E of

the Market Protocols.

(2) As part of the application process, Market Participants must register all Resources and

load, including applicable load associated with Grandfathered Agreements (“GFAs”),

Non-Conforming Load and Demand Response Load with the Transmission Provider in

accordance with the registration process specified in the Market Protocols. Both Non-

Conforming Load and Demand Response Load may only be associated with a single

Price Node except that Non-Conforming Load and Demand Response Load may be

associated with an aggregated Price Node that contains multiple electrically equivalent

Price Nodes.

(3) Market Participants may elect to define a single Settlement Location that aggregates

multiple Meter Data Submittal Locations associated with their load assets.

(4) In addition to the responsibilities described in Section 4.1.2 of this Attachment AE and

under the Market Protocols, Market Participants wishing to model each participant’s

share of a Jointly Owned Unit as a separate Resource must choose one of the two options

described below and provide the specified additional information. A Resource registered

as a combined cycle Resource may not register as a Jointly Owned Unit.

(a) Individual Resource Option


Under the individual Resource option, each participant’s share is modeled

as a separate Resource for the purposes of commitment and dispatch and each

Resource may be committed independent of the other Resource shares. In order

to qualify for this option, each Market Participant must register its share and

certify that it is greater than or equal to the minimum physical capacity operating

limit of the physical Jointly Owned Unit.

The operating owner’s Meter Agent will be the Meter Agent for that

Jointly Owned Unit unless each individual Jointly Owned Unit participant

registers a Meter Agent for its share of the Resource.

Unless otherwise agreed to by the Jointly Owned Unit participants, the

operating owner will be responsible for submitting the following data:

• Jointly Owned Unit maximum physical capacity operating limit;

• Jointly Owned Unit minimum physical capacity operating limit; and

• Maximum physical ten (10) minute response from an off-line state. (b) Combined Resource Option

Under the combined Resource option each participant’s share is modeled

and must be registered as a separate Resource. Under this option, the

commitment decision is made assuming that all Resource shares must be

committed or none at all. Once committed, each share is dispatched

independently. This option must be selected if the eligibility criteria stated under

the individual Resource option cannot be met.

The operating owner’s Meter Agent will be the Meter Agent for that

Jointly Owned Unit unless each individual Jointly Owned Unit participant

registers a Meter Agent for its share of the Resource.

Unless otherwise agreed to by the Jointly Owned Unit participants, the

operating owner will be responsible for submitting the following data:

• Jointly Owned Unit maximum physical capacity operating limit;

• Jointly Owned Unit minimum physical capacity operating limit;

• Maximum physical ten (10) minute response from an off-line state;

and

• Participant share percentage by Market Participant.

(5) Market Participants may modify their registered assets in accordance with the asset

registration procedures specified in the Market Protocols.


(6) All loads and all Resources, excluding Behind-The-Meter Generation less than 10

Megawatts (“MWs”), must register. Failure or refusal to register a Resource will result in

the Transmission Provider filing an unexecuted version of the service agreement as

specified in Attachment AH of this Tariff for that Resource with the Commission under

the name of the generation interconnection customer under an interconnection agreement

with the Transmission Provider or the applicable Transmission Owner. In the case of a

Qualifying Facility exercising its rights under PURPA to deliver all of its net output to its

host utility, such registration will not require the Qualifying Facility to participate in the

Energy and Operating Reserve Markets or subject the Qualifying Facility to any charges

or payments related to the Energy and Operating Reserve Markets.

(7) A Market Participant wishing to Offer an External Resource in the Energy and Operating

Reserve Markets will utilize an External Resource Pseudo-Tie in accordance with

Attachment AO. In addition to the responsibilities outlined in Attachment AO, the

Market Participant registering the External Resource will be responsible for registering

and performing all responsibilities that are required of Resources in the Energy and

Operating Reserve Markets.

(8) A Market Participant wishing to offer controllable load as a Demand Response Resource

in the Energy and Operating Reserve Markets must include in its application and

registration a certification that participation in the Energy and Operating Reserve Markets

by its Demand Response Resource is not precluded under the laws or regulations of the

relevant electric retail regulatory authority. Consistent with Section 2.8 of this

Attachment, an aggregator of retail customers wishing to offer Demand Response Load

in the form of a Demand Response Resource on behalf of one or more retail customers

must also include in its application and registration a certification that participation of

each retail customer is either: (1) not precluded by the laws or regulations of the relevant

electric retail regulatory authority if the customer is served by a utility that distributed

more than 4 million MWh in the previous fiscal year; or (2) affirmatively permitted by the

laws or regulations of the relevant electric retail regulatory authority if the customer is

served by a utility that distributed 4 million MWh or less in the previous fiscal year.

Demand Response Resources must meet all application, registration and technical

requirements applicable to the Energy and Operating Reserve Markets. The

Transmission Provider is not responsible for interpreting the laws or regulations of a

relevant electric retail regulatory authority and shall be required only to verify that the


Market Participant has included such a certification in its application materials. The

Transmission Provider is not liable or responsible for Market Participants participating in

the Energy and Operating Reserve Markets in violation of any law or regulation of a

relevant electric retail regulatory authority including state-approved retail tariff(s).

(9) An aggregator of retail customers offering Demand Response Load of one or more end-

use retail customers as a Demand Response Resource in the Energy and Operating

Reserve Markets must be a Market Participant, satisfying all registration and certification

requirements applicable to Market Participants as well as certification consistent with

Section 2.8 of this Attachment.

(10) A wind-powered Variable Energy Resource with an interconnection agreement executed

after May 21, 2011 must register as a Dispatchable Variable Energy Resource. Variable

Energy Resources with fuel sources other than wind may optionally register as a

Dispatchable Variable Energy Resource. Otherwise, Variable Energy Resources must

register as Non-Dispatchable Variable Energy Resources.


#5s. MPRR 89 Recommendation Report 9/14/2012 Page 1 of 4



Title Net Benefits Test (Order No. 745 Compliance)




Approve Reject


Defer Refer




Section No.: 4.1.9 (new) Title: Calculation of Net Benefits Test for Compensation of Controllable Load Protocol Version: 11.0



Revision Description This MPRR adds language consistent with language proposed in the Tariff for the EIS Market. The language outlines the steps undertaken by SPP in calculating the net benefits test for compensating controllable load consistent with FERC Order No. 745.


Yes – Section No: (Include a summary of impact and/or specific changes) Attachment AE, section 3.8 (new)

No


Date of Vote: 8/14/2012—Unanimously approved with modifications All Segments present for the vote: Yes No Segment of Parties that voted No or Abstained: N/A

RTWG Review

ORWG Review 9/12/2012—Approved with no Reliability Impact

MOPC Recommendation

Board Review

EIS Market



Date 8/10/2012

Sponsor Name Patti Kelly E-mail Address [email protected] Company Southwest Power Pool Phone Number 501.614.3381

Comments ReceivedComment Author MWG Date 8/14/2012

Comment Description The steps in the Tariff were removed since they were already in the Protocols. Other Typos were corrected.



4.1.9 Calculation of Net Benefits Test for Compensation of Controllable Load

The Transmission Provider shall identify each month the price on a supply curve, representative of economic conditions expected for that month, at which the benefits of dispatching Controllable Load exceed the costs of the load reductions to other loads. In formulaic terms, the net benefit is deemed to be realized at the price point on the supply curve where (Delta LMP x MWh consumed) > (LMP NEW x CL) where LMP NEW is the market clearing price after the Controllable Load is dispatched and Delta LMP is the price before Controllable Load is dispatched minus the LMP NEW.

The Transmission Provider shall update and post the Net Benefits Test results and analysis for a calendar month no later than the 15th day of the preceding calendar month. The price level from the Net Benefits Test shall be calculated using the following steps:

Step 1: Retrieve the Energy Offer Curves for the on-peak hours of the same calendar month (of the prior calendar year) for which the calculation is being performed. In the case that an Energy Offer Curve is not available for a Resource, the Mitigated Energy Offer Curve will be used.

Step 2: Adjust a portion of each prior-year offer representing the typical share of fuel costs in energy offers in the SPP Region for changes in fuel prices based on the ratio of the reference month spot price to the study month forward price.

Step 3: Combine the offers to create an hourly supply curve for each on-peak hour in the period and compute an average supply curve for the period.

Step 4: Smooth the average supply curve by fitting the following function to the raw data using a non-linear, least-squares regression:

P(MW) = A + B * MW + C * MW2 + D * MW3 + e(E*MW+F)



where P(MW) is the EIS Market offer price in $/MWh, and MW is cumulative capacity. A through F are the parameters to be estimated.

Step 5: Compute the price elasticity of the smoothed average supply curve at each MW point

Step 6: Find the threshold price for the smoothed average supply curve at which elasticity falls below one for the duration of the curve. This is the Net Benefits Test threshold price for the month.

Proposed Tariff Language Revision In Section 3 of Attachment AE: (new section – all language is new) 3.8 Calculation of Net Benefits Test for Compensation of Controllable Load The Transmission Provider shall identify each month the price on a supply curve, representative of economic conditions expected for that month, at which the benefits of dispatching Controllable Load exceed the costs of the load reductions to other loads. In formulaic terms, the net benefit is deemed to be realized at the price point on the supply curve where (Delta LMP x MWh consumed) > (LMP NEW x CL) where LMP NEW is the market clearing price after the Controllable Load is dispatched and Delta LMP is the price before Controllable Load is dispatched minus the LMP NEW.

The Transmission Provider shall update and post the Net Benefits Test results and analysis for a calendar month no later than the 15th day of the preceding calendar month. The price level from the Net Benefits Test shall be calculated using the following steps: Step 1: Retrieve the Energy Offer Curves for the on-peak hours of the same calendar month (of the prior

calendar year) for which the calculation is being performed. In the case that an Energy Offer Curve is not available for a Resource, the Mitigated Energy Offer Curve will be used.

Step 2: Adjust a portion of each prior-year offer representing the typical share of fuel costs in energy

offers in the SPP Region for changes in fuel prices based on the ratio of the reference month spot price to the study month forward price.

Step 3: Combine the offers to create an hourly supply curve for each on-peak hour in the period and

compute an average supply curve for the period. Step 4: Smooth the average supply curve by fitting the following function to the raw data using a non-

linear, least-squares regression: P(MW) = A + B * MW + C * MW2 + D * MW3 + e(E*MW+F)

where P(MW) is the EIS Market offer price in $/MWh, and MW is cumulative capacity. A through F are the parameters to be estimated.

Step 5: Compute the price elasticity of the smoothed average supply curve at each MW point Step 6: Find the threshold price for smoothed average supply curve at which elasticity falls below one

for the duration of the curve. This is the Net Benefits Test threshold price for the month.



#5d. RTWG TRR 071, 072 Recommendations to MOPC 10-16-12 - consent agenda Page 1 of 2

Southwest Power Pool, Inc. MARKETS AND OPERATIONS POLICY COMMITTEE

Recommendation to the Board of Directors TRRs 071 and 072 (Consent Agenda)

October 29-30, 2012

Organizational Roster The following persons are members of the Regional Tariff Working Group:

Dennis Reed, WR (Chair) Charles Locke, KCPL (Vice-Chair) Richard Andrysik, LES Bill Dowling, Midwest Energy Luke Haner, OPPD Tom Hestermann, Sunflower Rob Janssen, Dogwood David Kays, OGE Lloyd Kolb, Golden Spread Brett Leopold, ITC Great Plains Tom Littleton, OMPA Bernie Liu, Xcel

Paul Malone, NPPD Adam McKinnie, MoPSC Robert Pennybaker, AEP Neil Rowland, KMEA Robert Shields, AECC Keith Tynes, ETEC John Varnell, Tenaska Bary Warren, EDE Mitch Williams, WFEC Brenda Fricano, SPP (Acting Secretary)

Background Please see the TRR Recommendation Reports for TRRs 071 and 072 that were included in the MOPC October 16-17, 2012 background materials.

Analysis Please see the TRR Recommendation Reports for TRRs 071 and 072 that were included in the MOPC October 16-17, 2012 background materials.

Recommendation The MOPC recommends that the BOD approve its request regarding Tariff Revision Requests 071and 072.

Action Requested: Approval of RTWG’s request on TRRs 071 and 072.

APPROVED MOPC October 16-17, 2012

TRR 071 Approved unanimously

TRR 072 Approved unanimously

TRR Number Description RTWG Meeting Vote

071

Removal of language to allow for non-Eastern Interconnection generators to participate in the SPP EIS Market as an external resource.

SPP EIS Market Participant has a resource that will begin participating in the EIS Market and it is in the Western Interconnection. In anticipation of this becoming more common, language in the pro form agreement in Attachment AO will have this reference removed.

September 26, 2012

Approved with one abstention (Golden Spread)

072

Each year, the offer cap calculation inputs are revised per ER06-451 (March 20, 2006 Order). The calculations are performed by SPP Operations and filed with FERC for approval with an effective date of January 1 of the upcoming year for use in daily offer cap calculation. The numbers that are updates are the total annual fixed cost and the variable O&M cost. Required for the EIS Market by FERC.

September 26, 2012

Approved unanimously

#5d. RTWG TRR 071, 072 Recommendations to MOPC 10-16-12 - consent agenda Page 2 of 2

Tariff Revision Request (TRR) Recommendation Report

Page 1 of 12

TRR Number 071 TRR

Title Revision to Attachment AO - External Generation

Cross Reference # PRR BRR Other (Specify) _ _____________

Sponsor Name Patti Kelly E-mail Address [email protected] Company SPP Regulatory Phone Number 501-614-3381 Date 08/10/12

Tariff Section(s) Requiring Revision

Section No. Attachment AO Titles Agreement Establishing External Generation Non-Physical Electrical Interconnection Point Tariff Version (effective date)

Requested Resolution Normal Urgent (provided justification below for urgent

request)

Revision Description Removal of language to allow for non-Eastern Interconnection generators to participate in the SPP EIS Market as an external resource.

Reason for Revision

SPP EIS Market Participant has a resource that will begin participating in the EIS Market and it is in the Western Interconnection. In anticipation of this becoming more common, language in the pro form agreement in Attachment AO will have this reference removed.

Stakeholder Approval Required (specify date and record outcome of vote; n/a for those stakeholders not required)

MWG 9/18/2012 – Approved unanimously BPWG (n/a) TWG (n/a) ORWG (n/a) Other (specify) (n/a) RTWG – 9/26/2012 – Approved with one abstention (Golden Spread) MOPC Board of Directors

Legal Review Completed

Yes (Include any comments resulting from the review)

No



Page 2 of 12

Market Protocol Implications or Changes

Yes (Include a summary of impact and/or specific changes & PRR #)

No

Business Practice Implications or Changes

Yes (Include a summary of impact and/or specific changes & BPR #)

No

Criteria Implications or Changes

Yes (Include a summary of impact and/or specific changes)

No Other Corporate Documents Implications (i.e., SPP By-Laws, Membership Agreement, etc.)

Yes (Include which corporate documents)

No

Credit Implications


No

Impact Analysis Required

Yes

No


Page 3 of 12

Proposed Tariff Language Revisions (Redlined)

ATTACHMENT AO

AGREEMENT ESTABLISHING EXTERNAL GENERATION NON-PHYSICAL ELECTRICAL INTERCONNECTION POINT

This Agreement Establishing External Generation Non-Physical Electrical Interconnection Point (including its exhibits, this “Agreement”) is entered into this ____ day of ____________ 200__ by and among [Name] (Source Balancing Authority)], an [State and type of entity] (“ ”), [Name] (Sink Balancing Authority)], an [State and type of entity] (“ ”), [Name (Market Participant)], a [State and type of entity] (“ ”), and the Southwest Power Pool, Inc. (SPP) Regional Transmission Organization. Source Balancing Authority, Sink Balancing Authority, Market Participant and SPP are hereinafter referred to individually as a “Party” and collectively as the “Parties.”

WHEREAS, in order to facilitate the foregoing, the Parties desire to establish a new non-physical electrical interconnection point between the balancing authorities of the Sink Balancing Authority and the Source Balancing Authority on the terms and conditions set forth in this Agreement; and

WHEREAS, The Southwest Power Pool (SPP) is a Regional Transmission Organization (RTO) approved by the Federal Energy Regulatory Commission operating an Energy Imbalance Service (EIS) market; and

WHEREAS, Market Participant is responsible for generation outside of the boundaries of the EIS

Market and desires to participate in the EIS Market as an External Resource; and WHEREAS, Market Participant desires to deliver to the Sink Balancing Authority and the Sink

Balancing Authority desires to accept delivery of power into the EIS Market from the Market Participant, energy from the Facility (as defined below) ; and

WHEREAS, Market Participant represents is athe generator that is operator located in the Eastern

Interconnection and physically located within the balancing authority boundaries of the Source Balancing Authority; and

WHEREAS, Market Participant representsis a the generator operator registered with SPP and

meeting all of the SPP qualifications in order to operate in the EIS Market and abiding by all the respective Market Protocols and rules as set forth by SPP; and

WHEREAS, Sink Balancing Authority is a balancing authority that is a Member of SPP, is located

within the footprint of the SPP and a Member participating in the EIS Market;


Page 4 of 12

NOW THEREFORE, in consideration of the mutual covenants and agreements in this Agreement and of other good and valuable consideration, the sufficiency and adequacy of which are hereby acknowledged, the Parties, intending to be legally bound, hereby agree as follows:

1. Creation of Non-Physical Pseudo-Tie Point. From and after the effective date hereof, the point at which non-physical electrical interconnection (pseudo-tie) is made between the Market Participant [NAME OF GENERATION FACILITY] [GENERATION FACILITY LOCATION] (the “Facility”) and the Sink Balancing Authority system, which shall be defined in the one-line diagram attached hereto as Exhibit A, shall be a new non-physical electrical interconnection point between the balancing authorities of the Sink Balancing Authority and the Source Balancing Authority (the “Pseudo-Tie Point”), whereby any energy delivered from the Facility to the Pseudo-Tie Point for the account of the Source Balancing Authority, shall be treated as a balancing authority interchange from the balancing authority of the Source Balancing Authority to the balancing authority of the Sink Balancing Authority (for the avoidance of doubt, whether or not, at the time of delivery of such energy, the metering, data processing, telemetry and other equipment associated with the Pseudo-Tie Point is properly functioning). For the avoidance of doubt, the Sink Balancing Authority will not be taking title to any energy delivered from the Facility to the Pseudo-Tie Point for the account of the Source Balancing Authority. 2. Implementation. Each Party shall design, construct, operate and maintain the equipment for which it is responsible under this Agreement, and shall take all other actions required of it, to create and have the Pseudo-Tie Point recognized by the Southwest Power Pool as a balancing authority interchange from the balancing authority of the Source Balancing Authority to the balancing authority of the Sink Balancing Authority for the purpose of allowing the Facility to be treated as being in the balancing authority of the Sink Balancing Authority. Without limiting the foregoing, each Party shall undertake the design, construction, operation and maintenance for which it is responsible under this Agreement according to North American Electric Reliability Corporation standards. A basic block diagram of the communications equipment required for the Pseudo-Tie Point is set forth in Exhibit B. As among the Parties:

(a) Market Participant shall register with the SPP to become a Market Participant in the EIS Market. Registration shall be done in accordance with the SPP EIS Market Protocols. Each Facility must be registered separately with SPP and registration information shall be provided to both the Source Balancing Authority and the Sink Balancing Authority.

(b) This Agreement does not provide for the reservation or sale of Transmission Service under

the SPP’s Open Access Transmission Tariff (OATT) or on any other transmission system. Market Participant shall secure and pay for all cost associated with transmission service, across all transmission service providers necessary to deliver power from the Facility to the Sink Balancing Authority’s balancing authority within the SPP footprint and consistent with the registration of the resource with SPP. Market Participant shall secure Firm Transmission Service except for the provisions of Section 2 (c), from where it is physically located through the path to the Sink Balancing Authority’s transmission system. SPP shall confirm that the appropriate Transmission Service reservations are in place and maintained prior to granting


Page 5 of 12

participation and for continued participation in the EIS Market. Any External Resource that is on the SPP Transmission System, but outside the Market Footprint, satisfies the requirement for obtaining transmission service to the SPP Transmission System under this Section 2(b).

(c) Market Participant may use non firm service across all transmission service providers

necessary to deliver power from the Facility to the Sink Balancing Authority within the SPP footprint, subject to the following conditions:

i. SPP Operating Reserves may be utilized to support the transaction or; ii. the Source or Sink Balancing Authority and any intermediary transmission service

providers agree to only request an adjustment to the pseudo-tie values under emergency conditions due to the violation of an Interconnection Reliability Operating Limit (IROL) which requires action to be taken more quickly than the Market Operating System (MOS) can recognize the condition.

(d) The use of this Agreement is intended for the purposes of providing Energy Imbalance

Service into the EIS Market. (e) Market Participant is solely responsible for all requirements as set forth for a Market

Participant in the SPP EIS Market Protocols. (f) Market Participant shall design, construct, operate and maintain systems and communications

equipment in order to receive SPP deployment instructions in accordance with the SPP EIS Market Protocols.

(g) Market Participant shall design, construct, operate and maintain real-time and historical

systems and communications equipment, at Market Participant’s expense, in order to provide the Source Balancing Authority and the Sink Balancing Authority with the corresponding real-time pseudo-tie value. Market Participant’s systems shall provide this signal per the Sink Balancing Authority’s ICCP communication standards. Market Participant’s system shall provide this signal to the Source Balancing Authority in a manner mutually agreed to between the Source Balancing Authority and the Market Participant.

(h) SPP, in accordance with the SPP EIS Market Protocols, will provide the Market Participant

with the Dispatch Instruction MW for the next dispatch interval (currently dispatch interval is 5 minutes).

(i) SPP will also provide the EIS Net Schedule Interchange (“NSI”) to the Sink Balancing

Authority on a 4 second basis that includes the impacts of dispatch instructions for all Resources, including the Facility, within the balancing authority area of the Sink Balancing Authority.


Page 6 of 12

(j) The real time pseudo-tie value will be based upon the Dispatch Instruction issued by the SPP

to Market Participant. Market Participant shall calculate and simultaneously provide this value to the Source Balancing Authority and the Sink Balancing Authority. The real-time pseudo-tie value shall be calculated and communicated on a frequency no less than 4 seconds and synchronized with the target interval of the SPP dispatch interval. Any Out of Merit Energy (OOME) requests as defined in the SPP EIS Market Protocols shall be included in the real time pseudo-tie values. SPP will negotiate with the Source and Sink Balancing Authorities as to which balancing authority will provide regulation and imbalance services for the Market Participant participating in the EIS Market. Internal and external generators will be treated in a non-discriminatory manner with regard to the costs of regulation and imbalance services associated with participating in the EIS Market. If parties cannot agree to the provision of regulation and imbalance services, SPP will file, with the Commission, an unexecuted agreement, including all agreed-upon non-conforming deviations.

(k) The Source Balancing Authority and the Sink Balancing Authority will include this real time

pseudo-tie value in their respective calculations of Net Actual Interchange (“NAI”) and Area Control Error (“ACE”).

(l) If communication is lost between any of the Parties (including communication between SPP

and the Market Participant), the Source Balancing Authority and the Sink Balancing Authority will freeze at the last known value and it is the responsibility of the Market Participant to verbally communicate changes of the real time pseudo-tie values with the other Parties consistent with the SPP instructions.

(m) Market Participant shall notify Parties of any real-time circumstances that affect the Market

Participant’s obligation or ability to meet the SPP Dispatch Instructions. If the Market Participant or the Source Balancing Authority deviate from the anticipated real time pseudo-tie value, the Market Participant is responsible for costs incurred by the Sink Balancing Authority External generators will be subject to the same penalties for uninstructed deviations as internal generators under Attachment AE of the SPP Tariff.

(n) The Source Balancing Authority and the Sink Balancing Authority shall integrate the real

time pseudo-tie value on an hourly basis and maintain this information for balancing authority checkout, inadvertent calculations and payback purposes in accordance with the applicable NERC standards. It is the responsibility of the Source Balancing Authority to checkout these hourly integrated values with the Market Participant prior to the Source Balancing Authority’s final daily checkout with the Sink Balancing Authority.

(o) The Sink Balancing Authority shall act as the Meter Agent on behalf of the Market

Participant in the settlement process of the EIS Market in accordance of the SPP EIS Market Protocols. The Sink Balancing Authority shall perform this obligation unless mutually agreed upon by both the Sink Balancing Authority and the Market Participant. The


Page 7 of 12

settlement meter data will be the hourly integrated real time pseudo-tie value as calculated by the Sink Balancing Authority and checked out between the parties.

(p) Except as otherwise provided in this Section 2, failure by the Market Participant to provide

real-time pseudo-tie values in a timely manner and consistent with the SPP dispatch instruction constitutes a basis for the immediate suspension of this Agreement by the Source Balancing Authority or Sink Balancing Authority. In the event of such suspension, the Market Participant shall provide a remedy for the cause of the failure prior to resumption of its participation in the EIS Market. In the event of two suspensions within a thirty day period, this Agreement may be terminated, in accordance with Section 7 of this Agreement, at the sole discretion of the Source Balancing Authority or Sink Balancing Authority.

(q) SPP will provide to the Source Balancing Authority the Market Participant’s Resource Plan.

3. Losses. Market Participant will be responsible for loss compensation to transmission provider(s) to deliver their EIS energy to the SPP market footprint. Pseudo-tie value(s) will be considered net of losses external to SPP. Losses within the SPP market footprint attributable to the Market Participant’s participation in the EIS Market shall be handled in the same manner as other EIS Market transactions. 4. Compensation. Market Participant will compensate the Source Balancing Authority for the reasonable implementation and operations related costs borne by the Source Balancing Authority as a result of this Agreement unless the Market Participant and Source Balancing Authority agree to a different cost arrangement, which shall be filed with the Commission in a non-conforming agreement. SPP shall compensate the Sink Balancing Authority for any and all reasonable implementation and operations related costs borne by the Sink Balancing Authority as a result of this Agreement. 6

5. Auditing. Each Party reserves the right to audit records necessary to permit evaluation and verification of claims submitted, and the other Party’s compliance with this Agreement. The Parties shall retain for a period of three years all information and records relating to the performance of this Agreement. Each Party may examine and copy such information and records at the other Party’s premises during regular business hours and upon advance notice given no less than 15 calendar days prior to such examination.

7

6. Effective Date. The Agreement is effective upon full execution if it is not filed with the Commission. If the Agreement is filed with the Commission, then it is effective upon the later of the date of execution or the date allowed by the Commission.1 If the parties are unable to resolve any issues, SPP shall file an unexecuted agreement with the Commission, including all agreed-upon non-conforming deviations.

___________________________


Page 8 of 12

1The effective date shall not be earlier than the date that SPP has systems in place to effectuate this agreement; SPP currently estimates that such systems will be in place by March 1, 2008. 7. Termination. Notwithstanding 2(p), this Agreement shall terminate on [Date], unless extended by agreement of all the Parties. Any Party shall have the right to terminate this Agreement upon ___ month’s notice, subject to receiving all necessary regulatory approvals for such termination. 8

8. Governing Law. The interpretation and performance of this Agreement and each of its provisions shall be governed and construed in accordance with the applicable Federal and or State laws without regard its conflicts of laws provisions that would apply the laws of another jurisdiction. 9

9. Interpretation. In this Agreement: (a) the words “include”, “includes” and “including” are deemed to be followed by the words

“without limitation”; (b) references to contracts, agreements and other documents and instruments shall be references

to the same as amended, supplemented or otherwise modified from time to time;

(c) references to laws or standards and to terms defined in, and other provisions of, laws or standards shall be references to the same (or a successor to the same) as amended, supplemented or otherwise modified from time to time; and

(d) references to a person shall include its successors and permitted assigns and, in the case of a

governmental or other authority (including the Southwest Power Pool and the North American Electric Reliability Corporation), any person succeeding to its functions and capacities.

10. Severability. If any provision of this Agreement is held invalid, illegal or unenforceable in any jurisdiction, then, the Parties agree, to the fullest extent permitted by law, that the validity, legality and enforceability of the remaining provisions hereof in such or any other jurisdiction and of such provision in any other jurisdiction shall not in any way be affected or impaired thereby. With respect to the provision held invalid, illegal or unenforceable, the Parties will amend this Agreement as necessary to effect the original intent of the Parties as closely as possible.

11. Complete Agreement; Amendments. This Agreement constitutes the entire agreement among the Parties with respect to the subject matter of this Agreement and supersedes other prior agreements and understandings, both written and oral, among the Parties with respect to the subject matter of this Agreement. This Agreement may be amended, supplemented or otherwise modified only by an instrument in writing signed by all Parties.


Page 9 of 12

12. Other Obligations. Nothing in this Agreement is intended to modify or change any obligations or rights under any tariff (including the SPP Tariff), any rate schedule, or any other contract. This Agreement does not in any way provide transmission service or address rates, terms or conditions of transmission service or indicate in any way that transmission service is available or properly awarded. A Party seeking transmission service must still go through the full tariff process to obtain transmission service. This Agreement also does not establish any generation as a designated network resource under the Tariff; the requirements of the Tariff still must be satisfied. Nor does this Agreement make any Party a Market Participant under the SPP Tariff. A Party seeking to become a Market Participant must apply to SPP under the terms of the SPP Tariff and nothing in this Agreement affects its rights or obligations as a Market Participant. 10

13. Commission Filing. If unchanged, a signed version of this form agreement shall not be filed with the Commission. SPP will simply report the existence of a signed agreement in its quarterly reports. If the form agreement is substantively changed, then SPP shall file the revised form agreement with the Commission. The Parties shall be bound to the terms accepted or ordered by the Commission.

11

14. Modification. Nothing in this Agreement is intended to modify or limit the right of SPP to submit under FPA Section 205 or Section 206 unilateral changes to this Agreement (both the form Agreement and any signed agreement); the right of any other Party to seek unilateral changes under FPA Section 206, or the right of the Federal Energy Regulatory Commission to accept any FPA Section 205 filing or to make changes under FPA Section 206 or to initiate proceedings under FPA Section 206. 15. Charges. The provisions in this Agreement providing for compensation do not authorize Commission regulated public utilities to impose charges without a separately filed tariff or rate schedule being accepted by the Commission. 16. Disputes. Any disputes under this Agreement shall first be resolved pursuant to the dispute resolution procedures in the SPP’s Open Access Transmission Tariff. Any disputes may be brought to the Commission.

12

17. Breach. If any Party breaches the terms of this Agreement, then a non-breaching Party may seek any relief it believes is appropriate at the Commission. A breach is considered a substantive violation of this Agreement. Prior to pursuing a remedy at the Commission for a breach, a non-breaching Party shall provide five business days notice of the breach to the breaching Party. If the breaching Party does not eliminate the breach within five business days after the notice is received by the breaching Party, then the non-breaching Party may pursue its remedies at the Commission. 13

18. Counterparts. This Agreement may be executed in one or more counterparts, each of which shall be an original but all of which, taken together, shall constitute only one legal instrument. It shall not be


Page 10 of 12

necessary in making proof of this Agreement to produce or account for more than one counterpart. The delivery of an executed counterpart of this Agreement by facsimile shall be deemed to be valid delivery thereof.

The Parties have caused this Agreement to be signed by their authorized representatives on the day and year first above written. Source Balancing Authority By:_____________________________ Name: Title: Sink Balancing Authority By:_____________________________ Name: Title: Market Participant By:_____________________________ Name: Title: By:_____________________________ Name: Title: Southwest Power Pool, Inc. (SPP)

EXHIBIT A ONE-LINE DIAGRAM

EXHIBIT B

BLOCK DIAGRAM


Page 11 of 12

Proposed Market Protocol Language Revision (Redlined) n/a

Proposed Business Practices Language Revision (Redlined)

n/a


Page 12 of 12

Proposed Criteria Language Revision (Redlined)

n/a

Revisions to Other Corporate Documents (Redlined)

n/a


Page 1 of 4

TRR Number 072 TRR

Title 2013 Offer Cap Calculation Update

Cross Reference # PRR BRR Other (Specify) ______________

Sponsor Name Patti Kelly E-mail Address [email protected] Company SPP Staff Phone Number 501-614-3381 Date 9/20/2012


Section No. Attachment AF - 3.2.4 (a) and (b) Title Calculation of Offer Caps Tariff Version (effective date)


request)


Each year, the offer cap calculation inputs are revised per ER06-451 (March 20, 2006 Order). The calculations are performed by SPP Operations and filed with FERC for approval with an effective date of January 1 of the upcoming year for use in daily offer cap calculation. The numbers that are updates are the total annual fixed cost and the variable O&M cost.

Reason for Revision Required for the EIS Market by FERC.


MWG – 9/18/12 – Approved with one abstention (Golden Spread) BPWG n/a TWG n/a ORWG n/a Other (specify) n/a RTWG – 9/26/12 - Approved unanimously MOPC Board of Directors



No



Page 2 of 4


Yes (Include a summary of impact and/or specific changes & BRR #)

No





No

Credit Implications


No


Yes

No


Page 3 of 4

From Attachment AF of the SPP OATT, Section 3.2.4:

(a) Annual Fixed Cost

The annual fixed cost of a new, natural gas-fired, combustion turbine

peaking generation facility shall be based upon the calculated value of the

annual carrying cost associated with the recovery of the total fixed costs to

develop, build and finance such a facility plus the fixed operation and

maintenance costs. Such costs shall be reviewed annually by the

Transmission Provider with input from Market Participants. Any changes

to such costs, along with justification for the changes, shall be filed with the

Commission for approval after such review. Such costs, along with any

studies justifying the costs, shall be posted electronically by the

Transmission Provider. For calendar year 20122013, the Annual Fixed

Cost shall be equal to $138,490133,800/Megawatt-year.

(b) Variable Non-Fuel O&M Adder

The adder equal to the estimated non-fuel variable operation and

maintenance costs of a new, natural gas-fired, combustion turbine peaking

generation facility shall be based on the non-fuel operating and maintenance

costs of such a facility not included in the calculation of annual fixed costs

as described above. Such cost shall be reviewed annually by the

Transmission Provider with input from Market Participants. Any changes

to such costs, along with justification for the changes, shall be filed with the

Commission for approval after such review. Such costs, along with any

studies justifying the costs, shall be posted electronically by the

Transmission Provider. For calendar year 20122013, the Variable Non-Fuel

O&M Adder shall be equal to $8.4915.79/Megawatt-hour.


Page 4 of 4

Proposed Market Protocol Language Revision (Redlined)




#6c. RTWG TRR Recommendations to MOPC 10-16-12 - for vote-TRR076 Page 1 of 2


Recommendation to the Board of Directors TRR 076

October 29-30, 2012




Background Please see the TRR Recommendation Reports for TRRs 076 that were included in the MOPC October 16-17, 2012 background materials.

Analysis Please see the TRR Recommendation Reports for TRRs 076 that were included in the MOPC October 16-17, 2012 background materials.

Recommendation The MOPC recommends that the BOD approve its request regarding Tariff Revision Requests 076.

Action Requested: Approval of RTWG’s request on TRRs 076.

APPROVED: MOPC October 16-17, 2012

Passed Unanimously


076 Compliance with Order 741 filing due December 31, 2012. SPP intends to seek waiver to request TRR 76 to become effective March 2014 coincident with the Integrated Marketplace.

October 9, 2012


#6c. RTWG TRR Recommendations to MOPC 10-16-12 - for vote-TRR076 Page 2 of 2


Page 1 of 15

TRR Number

TRR 76

TRR Title Compliance with Order 741’s netting requirements


Sponsor Name Matthew Harward E-mail Address [email protected] Company Southwest Power Pool, Inc. Phone Number (501) 614-3560 Date 9/20/2012


Attachment AE ,Definitions – I Attachment AE, 3.1 Attachment AE, New Section 3.8 Attachment AE, New Section 10.6 and 10.7

Requested Resolution

Normal Urgent (provided justification below for urgent request) Compliance with Order 741 filing due December 31, 2012. SPP intends to seek waiver to request TRR 76 to become effective March 2014 coincident with the Integrated Marketplace.


Revise Attachment AE in the following manner: Revise Section 1.1 to include definition of Integrated Marketplace Counterparty. Revision to Attachment AE Section 3.1 to reference Transmission Provider will perform the role of Integrated Marketplace Counterparty. New Section 3.8 added to Tariff to define the Transmission Provider’s role as the Integrated Marketplace Counterparty. New Section 10.6 to provide a netting requirement. New Section 10.7 to define and limit SPP’s liability as counterparty to market transactions.

Reason for Revision

For compliance with netting requirements of FERC’s Order 741. Compliance filing due December 31, 2012. February 2011- Order 741, deadline for netting requirements set at September 2011 January 2012- Commission granted extension of time to all entities for compliance with netting requirements to April 30, 2012. April 30, 2012- SPP motion for extension of time to December 31, 2012 and requested waiver to defer effective date of netting


Page 2 of 15

requirements to coincide with implementation of Integrated Marketplace May 2012- FERC granted extension of time to December 31, 2012 but did not rule on the waiver request.


FC – reviewing 10/11/2012 MWG – reviewing 10/12/2012 RTWG - 10/09/2012 MOPC Board of Directors



No



No



No





No


Page 3 of 15

Credit Implications


No


Yes

No

Proposed Tariff Language Revisions to Attachment AE (Redlined)

1.1 Definitions I Import Interchange Transaction

A schedule for importing Energy into the SPP Balancing Authority Area.

Import Interchange Transaction Offer

A proposal by a Market Participant to provide Energy from a source external to the SPP Balancing

Authority Area at a specified External Interface and period of time.


The Day-Ahead Market, the Real-Time Balancing Market, the Transmission Congestion Rights Market

and the Reliability Unit Commitment processes.

Integrated Marketplace Counterparty


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The Transmission Provider, as counterparty to all Integrated Marketplace transactions (and not in any

other capacity of the Transmission Provider under the Tariff) in accordance with the provisions of Section

3.8 of this Attachment AE.

Interchange Transaction

Any Energy transaction that is crossing the boundary of the SPP Balancing Authority Area and requires

checkout with one or more external Balancing Authority Areas. This includes any Import Interchange

Transaction, Export Interchange Transaction or Through Interchange Transaction.

Intra-Day Reliability Unit Commitment (“Intra-Day RUC”)

The process performed by the Transmission Provider following the completion of the Day-Ahead

Reliability Unit Commitment process and throughout the Operating Day to assess Resource and

Operating Reserve adequacy for the Operating Day, commit or de-commit Resources as necessary, and

communicate commitment or de-commitment of Resources to the appropriate Market Participants as

necessary.

3.0 Transmission Provider Rights and Obligations

3.1 Transmission Provider Scope of Services

The Transmission Provider shall perform the services pertaining to the Integrated

Marketplace specified in this Tariff, including, but not limited to, the following.

(1) Develop and maintain rules, practices and procedures for the Integrated Marketplace.

(2) Operate and administer the Integrated Marketplace.

(3) Function as the Integrated Marketplace Counterparty for all Integrated Marketplace

transactions in accordance with the provisions of Section 3.8 of this Attachment AE.


Page 5 of 15

In addition, the Transmission Provider, in its functional entity roles as the Reliability

Coordinator, Balancing Authority, Transmission Service Provider, Planning Coordinator, Reserve

Sharing Group Administrator, Interchange Authority and Market Operator shall act in compliance

with and perform such functional entity roles as defined by NERC in the Reliability Functional

Model.

3.1.1 Market Hub Establishment and Modification

The Transmission Provider must establish and maintain at least one Market Hub in accordance

with the provisions of this Section. In addition, the Transmission Provider may establish additional

Market Hubs. The Transmission Provider shall review the proposed establishment, modification or

deletion of a Market Hub with stakeholders. The Markets and Operations Policy Committee will consider

the proposed establishment, modification or deletion of a Market Hub and will provide its own

recommendation regarding such action to the SPP Board of Directors for review and approval. After the

start of the Integrated Marketplace, the Transmission Provider shall post any approved establishment,

modification or deletion of a Market Hub at least six (6) months prior to the proposed effective date.

The Transmission Provider shall maintain and facilitate the use of a Market Hub or Market Hubs for the

Day-Ahead Market and the RTBM, comprised of a set of nodes within the SPP Balancing Authority Area,

which nodes shall be identified by the Transmission Provider on the Portal. The Transmission Provider

shall use the following criteria to establish Market Hubs:

(1)Each Market Hub shall contain a sufficient number of nodes to ensure that a Market Hub Locational

Marginal Price (“LMP”) can be calculated for that Market Hub at all times;

(2)Each Market Hub shall contain a sufficient number of nodes to ensure that the unavailability of, or an

adjacent line outage to, any one node or set of nodes would have only a minor impact on the Market Hub

LMP;

(3)Each Market Hub shall consist of nodes with a relatively high rate of service availability; and

(4)Each Market Hub shall consist of nodes among which Transmission Service is relatively

unconstrained.

3.1.2 Forecasting

(1)The Transmission Provider shall develop load forecasts for the SPP Balancing Authority Area for use


Page 6 of 15

in the RUC processes and RTBM. The Transmission Provider shall adjust such forecasts in order to

remove average system losses prior to execution of the market applications in order for the dispatch to

properly reflect the treatment of marginal losses.

(2)The Transmission Provider shall develop output forecasts for wind powered Variable Energy

Resources as defined in the Market Protocols for use in the RUC processes and RTBM.

3.1.3 Reserve Zone Establishment

(1)The Transmission Provider shall establish Reserve Zones on a semiannual basis to ensure the

deliverability of cleared Operating Reserve throughout the SPP Balancing Authority Area.

(2)The Transmission Provider shall identify the need for Reserve Zones within the SPP Balancing

Authority Area through Reserve Zone studies that identify constrained areas that may require a minimum

amount of Operating Reserve procurement and/or that may be limited to a maximum amount of Operating

Reserve procurement to ensure system-wide procurement of Operating Reserve is deliverable when

deployed.

(3)The Transmission Provider may add or reconfigure a Reserve Zone between semiannual updates to

address significant changes in system conditions that would cause adverse reliability impacts absent the

Reserve Zone addition or reconfiguration.

3.1.4 Operating Reserve Requirements

The Transmission Provider shall calculate the amount of Operating Reserves required for the

Operating Day, on both a system-wide and Reserve Zone basis, in order to comply with the reliability

requirements specified in the SPP Criteria. The Transmission Provider shall, on a daily basis:

(1)Calculate the hourly Regulation-Up, Regulation-Down and Contingency Reserve requirements on an

SPP Balancing Authority Area basis and post such results by 0700 hours Day-Ahead for use in the Day-

Ahead Market, Day-Ahead RUC, Intra-Day RUC and RTBM;

(2)Calculate the total minimum and total maximum Operating Reserve requirement for Operating Reserve

deployment in the up direction and for deployment of Operating Reserve in the down direction for each

Reserve Zone. The Transmission Provider may, at its option, set specific Regulation-Up and/or Spinning

Reserve minimum requirements for each Reserve Zone, as needed, to address reliability issues that can

only be alleviated through carrying synchronized reserves. In such cases, the Transmission Provider will


Page 7 of 15

include these minimum Regulation-Up and/or Spinning Reserve requirements when posting the Operating

Reserve requirements by 0700 Day-Ahead;

(3)Estimate each Market Participant’s Operating Reserve obligation in each Reserve Zone and provide

such information to Market Participants by 0700 hours Day-Ahead. The Transmission Provider shall

calculate such estimates by multiplying the system-wide Operating Reserve requirements calculated in (1)

above by the Transmission Provider’s estimate of each Market Participant’s load in each Reserve Zone

divided by the Transmission Provider’s estimate of system-wide load; and

(4)The Transmission Provider may increase Operating Reserve requirements for the Day-Ahead RUC,

Intra-Day RUC and RTBM above the requirements used in the Day-Ahead Market, including changes to

Reserve Zone minimums and maximums, as required to meet increases in reliability requirements caused

by changes in system conditions.

3.1.5 Outage Scheduling and Reporting

The Transmission Provider is responsible for coordinating and approving the scheduling of

outages on all transmission and generation facilities in the Transmission System. Procedures regarding

submittal of requested transmission and generation outages and reporting of unplanned outages through

the Transmission Provider’s outage scheduler are described in Appendix 12 to the SPP Criteria. The

Transmission Provider shall approve all requested outages to the extent that such outage requests can be

accommodated reliably. To the extent that granting a requested outage would cause a reliability issue on

the Transmission System, the Transmission Provider may deny the request. When the Transmission

Provider denies an outage request, the Transmission Provider shall recommend an alternative timeframe

within which the outage can be accommodated reliably.

3.2 Market Protocols

The Transmission Provider shall prepare, maintain and update the Market Protocols consistent with

this Tariff. The Market Protocols shall be posted on the Transmission Provider’s website.

3.3 Integrated Marketplace Operations

The Transmission Provider shall evaluate Offers and Bids submitted by Market Participants for use

in the Day-Ahead Market and Offers submitted for use in the Day-Ahead RUC to ensure sufficient

Resources are committed to meet the SPP Balancing Authority Area projected load and Operating


Page 8 of 15

Reserve requirements for the upcoming Operating Day. For the Intra-Day RUC, the Transmission

Provider shall evaluate Offers to ensure sufficient Resources are committed to meet the SPP Balancing

Authority Area projected load and Operating Reserve requirements throughout the Operating Day. In

performing these processes, the Transmission Provider shall commit Resources on a least cost security

constrained basis and shall clear Energy and Operating Reserve in the Day-Ahead Market on the basis of

security constrained economic dispatch (“SCED”) in accordance with Sections 5 and 6 of this Attachment

AE.

Throughout the execution of the RTBM, the Transmission Provider shall dispatch Energy and clear

Operating Reserve on Resources on the basis of SCED as described under Section 6 of this Attachment

AE.

The Transmission Provider shall conduct the annual Auction Revenue Right (“ARR”) allocation, annual

TCR auction, monthly TCR auction and monthly incremental ARR allocation in accordance with Section

7 of this Attachment AE.

3.4 Violation Relaxation Limit Reporting

Each year, prior to November 1, the Transmission Provider will provide analysis as well as a set of

proposed Violation Relaxation Limits (“VRLs”) for review by the applicable working groups and

committees as described in the Market Protocols. Each year by November 1, VRLs and their associated

values shall be reviewed and approved by the SPP Board of Directors. Any changes to the VRLs or

associated values must be approved by the Commission prior to their implementation. The most recent

Commission approved VRLs and their associated values are listed in Addendum 1 to this Attachment AE.

3.5 Integrated Marketplace Pricing

The Transmission Provider shall calculate Day-Ahead Market and RTBM LMPs for Energy at each

Settlement Location.

The Transmission Provider shall calculate the Reserve Zone Market Clearing Prices (“MCPs”) for

Regulation-Up, Regulation-Down, Spinning Reserve and Supplemental Reserve for the Day-Ahead

Market and RTBM.

The Transmission Provider shall calculate annual and monthly Auction Clearing Prices (“ACPs”) at each

Settlement Location.


Page 9 of 15

3.6 Integrated Marketplace Settlements

For both the Day-Ahead Market and the RTBM, the Transmission Provider shall calculate Energy

and Operating Reserve settlement quantities at each Settlement Location, calculate charges and payments

associated with the provision of Energy and Operating Reserve based upon the settlement quantities and

the associated LMPs and MCPs for each Asset Owner and render invoices to Market Participants

detailing net charges or payments associated with provision of Energy and Operating Reserve.

The Transmission Provider shall calculate charges and payments to ARR and TCR holders based upon the

ARRs determined in the annual allocation and TCRs cleared in the annual and monthly TCR auctions.

Such charges and payments shall be included on the Settlement Statements consistent with the timing of

the Day-Ahead Market settlement and RTBM settlement.

3.7 Integrated Marketplace Participation Readiness

The Transmission Provider shall validate each Market Participant’s ability to provide services for

which the Market Participant has registered in the Integrated Marketplace. Such validation shall include

verification that the Market Participant has met the technical and communications requirements specified

in the Market Protocols and has met the credit requirements specified under Attachment X of this Tariff.

3.8 Integrated Marketplace Counterparty 3.8.1 The Integrated Marketplace Counterparty settles, collects and distributes all charges in the

Integrated Marketplace; and is the contracting party, as a principal and not as an agent, with each Market

Participant for that Market Participant’s Integrated Marketplace agreements and transactions in the TCR

Market, Day-Ahead Market, and Real-Time Balancing Market. Notwithstanding the above, the Integrated

Marketplace Counterparty shall not be a contracting party as described under Section 3.8.3 of this

Attachment AE.

3.8.2 The Integrated Marketplace Counterparty will serve as the counterparty to Transmission

Congestion Rights (“TCRs”) and Auction Revenue Rights (“ARRs”) instruments held by a Market

Participant. The Integrated Marketplace Counterparty shall be the contracting party with respect to the


Page 10 of 15

contractual rights and obligations of the holders of ARRs and TCRs.

3.8.3 Exclusions.

3.8.3.1 The Transmission Provider’s capacity as the Integrated Marketplace Counterparty shall not

include agreements and transactions for Transmission Service, Network Integrated Transmission Service,

or Ancillary Services under Schedules 1 and 2 provided pursuant to Parts II, III and IV, and related rate

Schedules contained in the Tariff.

3.8.3.2 To the extent Market Participants conduct bilateral transactions with other Market Participants,

self-commit or self-supply power and energy to the loads they serve, such bilateral transactions, self-

commitment, self-scheduled, and self-supply arrangements are not transactions with the Integrated

Marketplace Counterparty.

3.8.3.3 The Integrated Marketplace Counterparty shall not be a counterparty to bilateral agreements for

the transfer of ARRs and TCRs between Market Participants.

10.0 Billing

The Transmission Provider shall prepare a billing statement each billing cycle in accordance with

this Section of Attachment AE. Such billing statements shall be prepared for each Market Participant in

accordance with the charges and payments specified in Section 8 of this Attachment AE, and showing the

net amount to be paid or received by the Market Participant in accordance with Sections 10.6 and 10.7 of

this Attachment AE. Billing statements shall provide sufficient detail, as specified in the Market

Protocols, to allow verification of the billing amounts and completion of the Market Participant’s internal

accounting. Unresolved billing disputes shall be settled in accordance with procedures specified in

Section 12 of the Tariff.

10.1 Settlement Statements

(1)The Transmission Provider shall issue a preliminary Settlement Statement for an Operating Day no

later than seven (7) calendar days following the applicable Operating Day unless the seventh (7) day

following the applicable Operating Day is not a business day, in which case, the preliminary Settlement

Statement shall be issued on the first business day thereafter.


Page 11 of 15

(2)The Transmission Provider shall issue a final Settlement Statement for an Operating Day no later than

forty-seven (47) calendar days following the applicable Operating Day unless the forty-seventh (47)

calendar day following the applicable Operating Day is not a business day, in which case, the final

Settlement Statement shall be issued on the first (1) business day thereafter.

(3)The Transmission Provider shall make corrections to the preliminary and final Settlement Statements

for an Operating Day for data errors and Settlement Statement disputes that have been resolved.

Settlement associated with a specific Operating Day shall be considered final at the end of the three

hundred sixty-fifth (365) calendar day following the applicable Operating Day.

(4)To the extent that a Market Participant, or its designated meter agent, does not submit meter data

representing that Market Participant’s actual Resource output and load consumption, either on a five (5)

minute basis or an hourly basis in accordance with the timelines specified in the Market Protocols, the

Transmission Provider shall use estimated data for that Market Participant that is equal to that Market

Participant’s telemetered generation and load for the applicable intervals or State Estimator values if

telemetered values are not available for the purposes of calculating the preliminary statements specified

under Sections 10.1(1). To the extent a Meter Agent does not submit data representing the metering of

each interconnecting tie-line between Settlement Areas, the Transmission Provider will substitute State

Estimator values. In the event that actual meter data is not submitted prior to the issuance of a final

Settlement Statement, the Transmission Provider shall use the best available data, which may include

estimated meter data as developed by the Transmission Provider, for the purposes of calculating final

Settlement Statements.

10.2 Invoices

(1)The Transmission Provider shall issue an invoice detailing all charges and payments specified in

Section 8 of this Attachment AE on a weekly basis in accordance with the invoice issue dates specified in

the Market Protocols.

(2)The Transmission Provider shall make payments to the Market Participant for any net credit shown on

the invoice and the Market Participant shall make payment to the Transmission Provider for any net

charge shown onr the invoice, including disputed amounts. Resolution of disputed amounts shall be

shown as an adjustment on future invoices.


Page 12 of 15

(3)Market Participants shall make payment to the Transmission Provider that is equal to the net charge

shown on the invoice by no later than 5:00 PM on the 3rd business day following the day the invoice was

issued.

(4)The Transmission Provider shall make payment to the Market Participant that is equal to the net credit

shown on the invoice by no later than 5:00 PM on the 5th business day following the day the invoice was

issued subject to the procedures specified under Section V of Attachment L.

(5)All payments to the Market Participant and all payments to the Transmission Provider shall be made

by electronic funds transfer in U.S. dollars.

10.3 Invoice Disputes

In the event that a dispute arises between the Market Participant and the Transmission Provider

concerning any initial, final or resettlement Settlement Statements contained within an invoice that cannot

be resolved to the Market Participant’s satisfaction, such disputes shall be resolved as follows:

(1)In the case of a dispute relating to an initial or final Settlement Statement, the Market Participant must

notify the Transmission Provider within ninety (90) calendar days following the issue date of the

applicable invoice of the items that the Market Participant wishes to dispute. In the case of resettlement

statements, the Market Participant must notify the Transmission Provider within thirty (30) calendar days

following the issue date of the applicable invoice of the items contained in that statement that the Market

Participant wishes to dispute, which issues must relate to incremental changes in data that occurred

between issuance of the final Settlement Statement and the first (1st) resettlement statement or between

resettlement statements.

The notice of dispute must contain the following minimum information:

• Statement type (initial, final, resettlement 1-11, ad hoc resettlement)

• Charge type

• Estimated dispute amount in dollars

• Operating Day

• Start interval

• End interval

• Market Participant


Page 13 of 15

• Asset Owner

• Settlement Location

• Long description

• Short description.

(2)If the Transmission Provider determines that additional information is required concerning a submitted

notice of dispute, the Transmission Provider shall notify the Market Participant no later than thirty (30)

days following the date the notice of dispute was submitted to the Transmission Provider. The Market

Participant must then submit additional information to the Transmission Provider within thirty (30) days

in order to have the notice of dispute considered valid.

(3)The Transmission Provider shall use its best efforts to notify the Market Participant of approval or

denial of the submitted notice of dispute within twenty (20) business days following the close of the

applicable ninety (90) day or thirty (30) day window specified under Subsection 10.3(1) or Subsection

10.3(2). If the Transmission Provider estimates that it will take longer than the twenty (20) business day

window to analyze a specific billing dispute, the Transmission Provider shall notify the Market

Participant and provide an estimate of the amount of time required to complete the analysis.

(4)If the Transmission Provider denies a Market Participant’s notice of dispute or the Market Participant

is not satisfied that it is receiving timely consideration of the dispute, the Market Participant may initiate

the dispute resolution procedures specified under Section 12 of the Tariff.

10.4 Interest on Unpaid Balances

Interest on any unpaid amounts shall be calculated in accordance with the methodology specified

for interest on refunds in the Commission's regulations at 18 C.F.R. § 35.19a(a)(2)(iii). Interest on

delinquent amounts shall be calculated from the due date of the invoice to the date of payment.

10.5 Customer Market Participant Default

Customer dDefaults by a Market Participant will be handled in accordance with Attachments L

(Treatment of Revenues) and X (SPP Credit Policy) of the Tariff.

10.6 Further Clarification Regarding Right to Net

The Integrated Marketplace Counterparty and the Market Participant mayshall discharge mutual

debts and payment obligations for multiple transactions due and owing to each other on the same date


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through netting, in which case all amounts a party owes to the other party under Attachment AE shall be

replaced by a single payment obligation and netted so that only the net amount remaining due shall be

paid by the owing party.

10.7 Integrated Marketplace Counterparty Limitation of Liability

The liability of the Integrated Marketplace Counterparty to settle Integrated Marketplace

transactions shall be limited such that the aggregate of payments owed to a Market Participant shall not

exceed the aggregate amount of payments that has been paid to or recovered by the Integrated

Marketplace Counterparty, from that Market Participant (including by way of realization of financial

security) in respect of that settlement period.



n/a


Page 15 of 15


n/a


n/a


Recommendation to the Board of Directors October 29-30, 2012

FERC Order 1000 Compliance Deadline Extension Request

Organizational Roster The following persons are members of the Seams Steering Committee:

Paul Malone (Chair), NPPD Bary Warren (Vice-Chair), Empire Roy Boyer, SPS Ollie Burke, Entergy Services

Jeff Knottek, CUS Jake Langthorn, OGE Richard Ross, AEP Chris Standifer, KCPL

Background On July 21, 2011, the Federal Energy Regulatory Commission (“FERC”) issued Order 1000 which requires SPP make a compliance filing by April 11, 2013 to demonstrate compliance with the interregional requirements of the order. Order 1000 requires:

1. Each pair of neighboring transmission planning regions must:

a. Share information regarding the respective needs of each region and potential solutions to those needs

b. Identify and jointly evaluate interregional transmission facilities that may be more efficient or cost-effective solutions to those regional needs

2. Neighboring transmission planning regions must have a common interregional cost allocation method for a new interregional transmission facility that the regions select

Analysis SPP Staff, the Seams Steering Committee, the Seams FERC Order 1000 Task Force (SFOTF), and other interested stakeholders have been working diligently to develop the interregional coordinated planning process and cost allocation methodologies to comply with the interregional requirements of the order. SPP has been working with each of its seams neighbors to develop the coordination procedures and cost allocation methodologies, some of whom have been focused on meeting the regional requirements of Order 1000 and are just now turning their attention to the interregional requirements.

As was the case with the regional compliance filing deadline, requesting an extension of the April 11, 2013 compliance deadline will enable SPP to use its April 2013 quarterly Board of Director’s meeting to finalize SPP’s compliance filing for the interregional requirements of Order 1000. SPP expects to make separate compliance filings for each of its neighboring transmission planning regions. It may be necessary to request additional extensions if one or more of the neighboring transmission planning regions requests extensions of their compliance deadlines.

Recommendation The MOPC recommends the Board of Directors to direct SPP staff to request an extension of the deadline to make its compliance filing(s) for the interregional requirements of FERC Order 1000 to May 13, 2013.

APPROVED:

Approved:

MOPC

Passed Unanimously

Seams Steering Committee

October 16-17, 2012

October 5, 2012

Passed Unopposed

Action Requested: Approve Recommendation

Southwest Power Pool, Inc. CORPORATE GOVERNANCE COMMITTEE Recommendation to the Board of Directors

October 30, 2012

Vacancies

Background There are two vacancies on the Finance Committee. In accordance with SPP’s Bylaws, the Corporate Governance Committee recommends a candidate to the Board of Directors for consideration and appointment.

Analysis Trudy Harper retired from Tenaska, and thus from her position on the Finance Committee; Carl Huslig (ITC Great Plains) also resigned his position on the Finance Committee. The members of the Transmission User member sector were notified of the vacancies. The Committee approved Coleen Wells (KEPCo) and Mike Wise (GSEC) to fill these vacancies. The Corporate Governance Committee considered the candidates, his/her backgrounds, and the balance of member representation on the various SPP committees.

Recommendation The Corporate Governance Committee recommends the appointment of Coleen Wells (KEPCo) and Mike Wise (GSEC) to serve on the Finance Committee.

Approved: Corporate Governance Committee:

August 30, 2012

Action Requested: Approve recommendation

Southwest Power Pool, Inc. Corporate Governance Committee

Recommendation to the SPP Board of Directors October 30, 2012

Order 1000 Compliance Filing Recommendation Revisions to the SPP Membership Agreement

Background On July 21, 2011, the Federal Energy Regulatory Commission (“FERC”) issued Order 1000, Transmission Planning and Cost Allocation by Transmission Owning and Operating Public Utilities, Order 1000, III FERC Stats. & Regs., Regs. Preambles ¶ 31,323 (2011). In response to Order 1000, the SPP Board of Directors tasked SPP’s Strategic Planning Committee (“SPC”) with leading SPP’s response to the regional policy requirements contained in Order 1000. The SPC formed the SPCTF, tasked with determining whether SPP’s current transmission planning and cost allocation provisions comply with the requirements and whether additional revisions will be necessary. The SPCTF presented a report of policy recommendations to the SPC on April 9, 2012, and the SPC presented the same policy recommendations to the SPP Board of Directors on April 24, 2012. The SPP Board of Directors approved the SPCTF report and recommendations. Among the SPCTF recommendations approved by the SPP Board of Directors is a recommendation that the SPCTF examine the SPP Membership Agreement and provide suggested revisions to comply with Order 1000 to the CGC by April 30, 2012. See SPC Task Force on Order 1000, Final Report § 4.1 (dated Apr. 3, 2012) (“SPCTF Report”), available at http://www.spp.org/publications/SPC040912.pdf. Analysis Order 1000 requires public utility transmission providers to, among other things, eliminate from their FERC-jurisdictional tariffs and agreements any provisions “that establish a federal right of first refusal (“ROFR”) for an incumbent transmission provider with respect to transmission facilities selected in a regional transmission plan for purposes of cost allocation.” See Order 1000 at P 313. The current SPP Membership Agreement contains a federal ROFR for incumbent transmission owners that SPP must address. Section 3.3(b) of the Membership Agreement, which governs construction obligations, currently states (emphasis added):

If the project forms a connection between the facilities of a single Transmission Owner, that Transmission Owner will be designated to provide the new facilities. If the project forms a connection between facilities owned by multiple parties, all parties will be designated to provide the respective new facilities. The parties will agree among themselves as to how much of the project will be provided by each entity. If agreement cannot be reached, SPP will facilitate the ownership determination process.

Furthermore, Section 3.3(c) of the Membership Agreement states (emphasis added):

A designated provider for a project can elect to arrange for a new entity or another Transmission Owner to build and/or own the project in its place. If the designated provider(s) does not or cannot agree to implement the project in a timely manner, SPP will solicit and evaluate proposals for the project from other entities and select a replacement.

Together, Sections 3.3(b) and 3.3(c) create a federal ROFR. Section 3.3(b) obligates SPP to assign the responsibility to construct new transmission facilities selected in the SPP transmission planning process to incumbent Transmission Owners, and Section 3.3(c) provides the designated Transmission Owner(s) with the option either to construct the project, assign the project to another entity, or decline to construct the project. In reviewing parallel language in Attachment O of the SPP Tariff, FERC determined that the language of Attachment O establishes a federal ROFR for incumbent transmission owners in SPP. See Sw. Power Pool, Inc., 127 FERC ¶ 61,171, at PP 42-43 (2009). SPP also acknowledged that its governing documents contain a federal ROFR in its comments in the rulemaking proceeding that culminated in Order 1000. See Comments of Southwest Power Pool, Inc., Docket No. RM10-23-000, at 15 (Sept. 29, 2010). Recommendation The SPCTF recommends that the CGC approve the revisions to the SPP Membership Agreement set forth in this report below and recommend them to the SPP Board of Directors for approval at the July 31, 2012 Board of Directors and Members Committee meeting. See SPCTF Report at 19-20, 28-29. The SPCTF’s recommendations below seek to minimize changes to existing Membership Agreement language to the extent possible while complying with the Order 1000 requirement to eliminate federal ROFR. Membership Agreement § 3.3(b): As currently drafted, Section 3.3(b) requires SPP to assign the responsibility for construction and ownership of all new transmission facilities to incumbent SPP Transmission Owners (i.e., the Transmission Owner(s) that own the existing transmission facilities to which a new transmission facility will interconnect). Therefore, SPP must modify Section 3.3(b) to remove language suggesting that SPP will assign all transmission facilities to incumbent Transmission Owners. Rather than expand Section 3.3(b) to encompass the various processes SPP will use to assign construction and ownership responsibilities based on whether or not the facility is subject to the requirement to eliminate federal ROFR, the SPCTF recommends modifying Section 3.3(b) to remove the specific language governing how SPP will designate Transmission Owners for each project, and instead include a reference in the Membership Agreement to Attachment O of the SPP Tariff, where the Transmission Owner Selection Process and processes for designating Transmission Owners for transmission projects that retain ROFR rights will be delineated in detail.

3.3(b) After a new transmission project has received the required approvals and been approved by SPP, SPP will direct the appropriate Transmission Owner(s) to begin implementation of the project in accordance with Attachment O of the OATT. If the project forms a connection between facilities of a single Transmission Owner, that Transmission Owner will be designated to provide the new facilities. If the project forms a connection between facilities owned by multiple parties, all parties will be designated to provide their respective new facilities. The parties will agree among themselves as to how much of the project will be provided by each entity. If agreement cannot be reached, SPP will facilitate the ownership determination process.

Membership Agreement § 3.3(c): Because Section 3.3(c) contemplates that a designated Transmission Owner can “refuse” to construct a transmission project (i.e., the Transmission Owner “does not or cannot agree to implement the project”) and because Section 3.3(c) is redundant of existing language in the SPP Tariff, the SPCTF recommends deleting Section 3.3(c) in its entirety. Moreover, the language in Section 3.3(c) indicating that SPP will solicit and evaluate proposals from other entities if the designated provider does not implement the project in a timely manner will be superseded by SPP’s proposal to comply with

the Order 1000 requirement to establish a regional transmission plan re-evaluation process. See Order 1000 at PP 263, 328-329 (establishing transmission plan re-evaluation requirement).

3.3(c) A designated provider for a project can elect to arrange for a new entity or another Transmission Owner to build and/or own the project in its place. If a designated provider(s) does not or cannot agree to implement the project in a timely manner, SPP will solicit and evaluate proposals for the project from other entities and select a replacement.

Together, these revisions remove federal ROFR from the Membership Agreement and eliminate language from the Membership Agreement that is redundant of Tariff language, while limiting modification of the Membership Agreement to the extent possible. Approved: Strategic Planning Committee Task Force on

Order 1000 April 25, 2012

Motion Passed with 1 opposed (ITC) Corporate Governance Committee May 11, 2012 Unanimous

Action Requested: Approve SPCTF recommended revisions to the SPP Membership Agreement to comply with the Order 1000 requirement to remove from all FERC-jurisdictional tariffs and agreements any provisions that establish a federal ROFR for an incumbent transmission provider with respect to transmission facilities selected in a regional transmission plan for purposes of cost allocation.


SPP CORPORATE GOVERNANCE COMMITTEE Recommendation to the SPP Board of Directors

October 30, 2012

SPP MEMBERSHIP AGREEMENT/APPENDIX A

Background Appendix A of the Membership Agreement is in response to FERC’s order granting SPP RTO status. In that order FERC directed SPP to revise its Membership Agreement to provide a detailed description of its proposed allocation of responsibilities between SPP and the control areas and the capabilities of each entity to perform its proposed responsibilities, and to adopt the NERC classification of service functions. See Southwest Power Pool, Inc., 109 FERC ¶ 61,009 (2004).

Analysis SPP recommends deletion from the Membership Agreement the reference to Appendix A in section 2.1.1 and Appendix A, which includes SPP’s Operational Authority Reference Document. With the advent of the Integrated Marketplace and the development of a Consolidated Balancing Authority Agreement, Appendix A no longer will be necessary. SPP will be the Balancing Authority for the entire SPP region and the Consolidated Balancing Authority Agreement will allocate the responsibilities of the former SPP Balancing Authorities and SPP. Among other things, Appendix A includes a NERC Functional Responsibility Matrix, which details each of the tasks associated with the NERC functional model and details how the responsibility for each task is handled within SPP. Appendix A, including the matrix, has become outdated and therefore no longer applicable. Action Requested Approve removal of Appendix A from the SPP Membership Agreement.

Approved: Corporate Governance Committee:

October 25, 2011


2013 BUDGETAS PRESENTED TO FINANCE COMMITTEE

MONDAY, SEPTEMBER 24, 2012

SECTION PAGE

1 INTRODUCTION AND OVERVIEWA. Executive Summary 1-3B. Planning Process 3-4C. Process Improvements 5-8D. Drivers and Assumptions 8-11E. Administrative Fee Calculation 11-12F. Net Revenue Requirement Growth 13G. Prior Year Budget Comparison 14

2 SPP PROJECT DESCRIPTION AND ANALYSISA. Project Overview 15B. Integrated Marketplace and Post-Go-Live Projects 16-17C. Other Projects 17-20D. Capital Cost Projections 21-22E. Complete and Ongoing Projects 23

3 VALUING WORK AND STAFFING ANALYSISA. Valuing Work at SPP 24B. Incremental Staff Analysis 25-27C. Salary Assumptions 28

4 2012 BUDGET DETAIL AND COMMENTARYA. Income Statement Commentary 29-34B. Balance Sheet 35C. Three Year Income Statement Forecast 36D. Three Year Cash Flow Forecast 37

5 SUPPLEMENTAL ANALYSISA. Administrative Fee History 38B. Outside Services by Business Function 39-40C. Interest Expense Detail 41D. Analysis of 2012 Fees & Assessments 42E. Net Revenue Requirement Variance History 43F. Load Variance Sensitivity 44G. Prior Year Forecast Comparison 45H. Business Unit Strategic Initiatives 46-51I. Calculation of Prior Year True-Up 52

2013 Budget

Executive Summary:

Southwest Power Pool (SPP) is a member-driven service provider that creates stakeholder value through: 1) membership collaboration, 2) resource pooling, 3) unbiased region-wide optimization, and 4) provision of leveraged, centralized services. These services, directed and funded by SPP’s diverse customers and membership, are expected to produce regional benefits of over one billion dollars per year upon completion of the Integrated Marketplace.

SPP has completed and documented SPP’s operating and capital budgets for the 2013 fiscal year with forecasts for 2014 and 2015. Total 2013 expenses, excluding depreciation, are $142.3M and represent $7.7M growth over the 2012 budget. Growth in operating expenses as compared to 2012 budget results primarily from staffing ($5.1M) and interest on borrowings for capital expenditures ($4.1M). The 2013 net revenue requirement (NRR), a component for setting the administrative fee rate, is $121.8M. These expense increases, combined with decreasing revenues associated with ICT and ITO contracts ($25.5M), result in a $34.8M increase in the NRR over 2012 budget.

The capital budget includes projects totaling $73.5M for 2013-2015, with $36.0M expected to be incurred in 2013. Integrated Marketplace continues to dominate the capital budget ($105.0M total project, with $26.0M left to spend in 2013 - 2015).

In 2012, SPP established an administrative fee rate of 25.5¢/MWh with the expectation this rate would increase in 2013 to 28.0¢/MWh. The current calculated administrative fee rate for 2013 is 33.8¢/MWh. The recommended administrative fee rate for 2013 is 31.5 ¢/MWh.

2013 Budget

% of Change

Admin Fee Impact

NRR 2013 Prior Projection 98,645 $0.274

Reduction in ICT Revenues 18,515 80% $0.051 Increase in NERC and FERC Funding (671) (3%) ($0.002)

Net Changes in Revenue 17,844 77% $0.049

Increase in Interest Expense 3,696 16% $0.010 Changes in Benefit Calculations 1,697 7% $0.005 Property Tax Increase 782 3% $0.002 Communications & Maintenance 609 3% $0.002 Services Decrease (1,651) (7%) ($0.005) Misc Other 192 1% $0.001

Net Changes in Expenses 5,325 23% $0.015

NRR 2013 Current Projection 121,814 100% $0.338

The 2013 budget assumes SPP no longer provides ICT services under contract to Entergy based on Entergy’s stated desire to have another firm provide those services and based on the pending termination of the contract on December 1, 2012, with no efforts on Entergy’s part to negotiate a continuation. SPP originally staffed the ICT function with 41 staff and has been able to reduce the current number of staff required to fulfill the contract to 25. Originally, the contract revenues resulted in a net benefit of 3¢/MWh to SPP customers; in its final year, SPP’s customers were realizing over 4¢/MWh in net benefits on $18M in contract revenues.

2013 Budget

2013 Budget Metrics 2013 Budget 2012 Budget Change 2012 Forecast Change

Gross Revenue Requirement $155,030 $145,843 $9,187 $142,174 $12,856 Net Revenue Requirement $121,814 $89,560 $32,254 $86,072 $35,742 Billing Units in MWh (000) 360,915 353,453 7,462 361,011 (96)

Calculated Admin Fee/MWh $0.338 $0.253 $0.084 $0.238 $0.099 Capital Expenditures $35,818 $82,034 ($46,215) $84,574 ($48,756) Year Ending Headcount 603 590 13 582 21

Planning Process: A budget is a plan that identifies the financial resources required to achieve programmatic objectives. This plan assists staff and board in managing the organization both programmatically and financially throughout the year. Staff again incorporated a zero-based budgeting approach to help identify each planned expenditure and its alignment with SPP’s three foundational strategies. These strategies were formalized by the Strategic Planning Committee in May 2010, approved by the SPP Board of Directors on July 27, 2010, and are intended to leverage SPP's capabilities and operational processes. Consistent with previous years, in 2012 SPP’s management completed an exercise in which all business units set actionable, dynamic goals and initiatives linked to SPP’s strategic plan. These initiatives then went through a rigorous vetting process of prioritization and capacity measurement (i.e. determining adequate resource levels required to accomplish objectives without adversely impacting higher priority projects). This became the basis of zero-based budgeting justifications and these core foundational strategies are still in place today. Following is a graphical breakdown of the business unit objectives and initiatives by foundational strategy:

2013 Budget

A full list of each business unit objectives and initiatives can be found in the Supplemental Analysis section, pages 47-51.

In order to follow the zero-based budgeting approach, each department at SPP analyzed operational tasks and the corresponding resources needed to accomplish departmental objectives in accordance with the foundational strategies. For example, the engineering group started the 2013 budgeting process by first analyzing the estimated workload required to achieve identified objectives. A thorough analysis of resource requirements (i.e. employees) was performed to identify total estimated workload for 2013. The resulting resource planning led to identification of roles that could be fulfilled by the transitioning ICT employees, therefore reducing the 2013 number of incremental headcount for Engineering to three.

2013 Budget

Process Improvements: The budget cycle for 2013 was launched by development of the formalized budget plan which was rolled out to all levels of management. As in years past, a budget kickoff meeting was held in May 2012 and included discussion on the concept and practical implementation of zero-based budgeting and departmental strategic initiatives.

During the following two months, staffing levels and all other operating expenditures were justified, beginning at the supervisory/manager level. Each budgetary line item was discussed among SPP managers and directors, identifying the need for the expense, the appropriate cost, and the expected benefit. These justification discussions served as a foundation for each of SPP’s business functions. SPP directors justified their operational functions and associated budgets with their executive officers. Once all costs were discussed and approved at the officer level, all functional budgets were consolidated for an organizational view.

A formalized list of business process improvements were identified and incorporated into the current and future years’ financial projections as a result of these efforts. The improvements include both tangible cost reductions and cost-avoidance initiatives. A table of these items is on the following page. The dollar value of improvements is calculated according to the Benefits Tracking Guidelines approved by the SPP Finance Committee, according to which the improvement initiatives become standard practice generally after 1-3 years, and are no longer separately identified as “improvements” for tracking purposes. The benefits of these initiatives are long lasting, however as the new standard practice, their impact is reflected in the zero-based budget.

2013 Budget

SPP Business Process Improvement Initiatives Embedded in SPP’s Zero Based Budget (000's)

2013 2014 2015 Operations Staffing Cost Reductions

Settlements Process Improvements * $72 standard practice

standard practice

Ops Automation and Consolidation of Tariff Admin and Interchange Desks ** 337 514 534

Total Operations Staffing Cost Reductions $409 $514 $534

Capital Non-Staffing Cost Reductions

Unlimited 3-year Oracle Database Agreement** $1,386 $303 standard practice

Microsoft Software Rationalization 39 standard practice

standard practice

Desktop Virtualization 24 standard practice

standard practice

Total Capital Non-Staffing Cost Reductions $1,449 $303 -

Grand Total of Productivity, Cost Reduction and Cost Avoidance Initiatives $1,858 $817 $534

Value of Improvement Initiatives realized in 2011 and 2012*** Prior Years Cumulative Balance $11,425

Cumulative Value of Improvement Initiatives $13,283 $14,100 $14,634 * Four of the five FTE savings contemplated in this initiative were realized in 2012, therefore leaving one FTE saving projected for 2013. ** This project is further described below. *** Value of 2011 and 2012 Improvements taken from 4Q2011 and 3Q2012 Business Process Improvement Tracking reports submitted to the Finance Committee.

2013 Budget

Several meetings were conducted under the direction of the Project Review and Prioritization Committee to evaluate current and newly-proposed project initiatives against projected resource availability in 2013. This was a critical exercise given the significant commitment of existing resources to the Integrated Marketplace project. Internal resource utilization was estimated for projects requiring substantial utilization of IT, Project Management, Operations, and/or Engineering departmental subject matter experts. Because considerable effort is required for the Integrated Marketplace projects, only three new projects were added impacting the 2013 budget. Overall, seven new projects were added for 2013 – 2015 (not including the post-go-live initiatives). Refer to pages 21-22 for complete list of projects.

Business Process Improvement - Operations Automation & Consolidation

The 2013 budget includes both benefits and costs associated with the automation and restructuring initiative of the SPP Operations department. SPP has identified an opportunity to automate manual functions in the Tariff Administration and Interchange desk operations. The opportunities for productivity improvement through automation include the following:

• Enhance the interchange schedule validation process which will minimize the failures of transmission/market schedules that require manual intervention by operators.

• Automate the Transmission Service Administration processes. • Automate the interchange schedule verification and error research, correction and documentation processes

between Interchange Scheduling and Settlements (RTOSS and COS). • Automate HVDC Tie processing – replaces the outdated and ineffective Excel spreadsheet with a more

efficient system.

This improvement initiative was originally included in the 2012-2014 budget presentation with a targeted implementation date of July 2012. Over the past year, there have been delays on the part of OATI in the development of the required automation tools. As a result of these delays, the implementation has been postponed until April 2013. At that time, the automated systems will be implemented in conjunction with the consolidation of the Tariff Administration and Interchange Desks. The implementation of the automated system will facilitate the reassignment of resources to support Integrated Marketplace requirements ((1) Supervisor, (3) Operators and (1) Business Analyst). The original initiative had contemplated eight FTE savings which was reflected in the 2012 budget

2013 Budget

presentation; however, the baseline headcount was revised down by three FTEs during 2012, reducing the net savings expected from this initiative. Due to design of the Integrated Marketplace allowing for more automation in reservations and scheduling of market transactions, a reduction of three FTEs in the baseline headcount is expected to take place regardless of the implementation of the operations automation initiative. The total of eight employees to be released from the Tariff and Interchange desk responsibilities will be re-assigned as Consolidated Balancing Authority (CBA) operators. CBA is a component of the Integrated Marketplace and includes new operational functions such as Reliability Unit Commitment (RUC), Real-Time Balancing Market (RTBM) and Generation Dispatch. Business Process Improvement - Unlimited Oracle Database Licensing Agreement Thru 2010, in terms of SPP’s approach to meeting database needs, SPP operated very much in a physical world. If an Oracle database was needed, a physical server and an Oracle license needed to be purchased, requiring subsequent payments for maintenance. In 2011, a new approach was initiated based on the premise that if SPP deployed Oracle databases on virtual servers instead of on separate physical servers, it would be able to “avoid” the licensing and maintenance costs for each “virtual” Oracle database. This strategy was included as part of the zero based budgeting process for the 2012-2014 budget presentation with a projected savings of over $1.2M thru 2014. In early 2012, additional analysis was performed on the volume of Oracle databases that would be required over the next 3-5 years and compared the existing strategy in place to that of a three year contract for Unlimited Oracle licenses. The cost analysis for the period 2012-2014 revealed $1.7M in additional savings that could be realized by employing the unlimited licensing approach.

Drivers and Assumptions:

Drivers are important factors that provide significant increases in the value of a business as viewed by its stakeholders. For SPP’s 2013 budget, the following drivers have been identified for their significant effect on cost structure and income:

+ Contract Services – The existing ICT agreement with SPP is set to expire on December 1, 2012. As a result, the 2013

budget assumed SPP will cease to serve as the Independent Coordinator of Transmission (ICT) for Entergy for 2013 and beyond.

2013 Budget

During 2012, SPP was able to create significant efficiencies in the ICT operations. While the level of service remained intact, several employees previously dedicated to ICT operations transitioned to new roles in the Engineering and Operations departments. This was achieved due to the level of experience and efficiencies gained in administration of the ICT contract for the past several years. The Operations Department began planning the transition of the contract service employees to perform duties associated with the Regional Transmission Organization (RTO) in 2011 in preparation for the Integrated Marketplace implementation, known internally as Ops 2014. This exercise allowed Operations management to develop a comprehensive plan to utilize the staff of 15.5 FTE ICT employees and 7 FTE ITO(Independent Transmission Organization) employees to limit incremental staffing requirements needed to implement new functions such as Reliability Unit Commitment (RUC), Consolidated Balancing Authority (CBA), Ancillary Service Market, Generation Dispatch, Transmission Congestion Rights (TCR), and Day Ahead market. Operations engineering is also adding additional modeling and analysis capabilities required to support the Integrated Marketplace/CBA (TCR modeling support, M2M support, EMS modeling and data integrity, RTO/RC support, and outage coordination) as a result of transition of 6.5 FTE from ICT Tariff Administration functions. The Engineering Department engaged in resource planning efforts to proactively integrate the ICT staff of 13 employees into functions providing support for the Integrated Marketplace efforts and expanded RTO responsibilities. As the ICT process became more stable and efficient after its implementation period, four ICT resources became available for integration into the Congestion Hedging group. In addition, nine ICT planning resources were transitioned into planning activities within the Engineering Department’s 2012 and 2013 work plan which reflects new regulatory requirements such as FERC’s Order 1000, Attachment AQ, NERC modeling requirements, and several new studies and planning efforts requested by SPP membership. These new efforts include Incremental Benefits Metrics, ITP Dynamic Stability studies, business practice improvements for NTCs with conditions and NTC re-evaluation, ITPNT Load Pocket studies, ITP20 Wind Transfer Voltage studies, and incorporation of Demand Side Management effects.

+ Integrated Marketplace – The 2013 budget includes the continued development efforts for the Integrated

Marketplace, which consists of a group of interrelated projects and tasks which have been combined into a greater program. This program has been identified as the highest priority by SPP’s Membership given the expected annual net benefit of up to $100M. SPP’s Board of Directors approved a capital budget of $105M during the April 2011 meeting. This will fund the design, development and implementation of the following market services:

2013 Budget

• Day-Ahead Market • Transmission Congestion Rights • Reliability Unit Commitment • Real-Time Balancing Market • Operating Reserve Market • Consolidated Balancing Authority

The 2013 budget also identifies capital expenditures and staffing for market related functionality or enhancements to be implemented after the initial, projected go-live date of March 2014. The major initiatives contemplated in the 2013-2015 budget projections are as follows:

• Combined Cycles • Regulation Compensation (FERC Order 755) • Long Term TCRs • AFC Granularity Changes for TSRs • Market to Market

+ Order 1000 – FERC Order 1000 has both regional and interregional planning implications: From the interregional perspective, the Order most notably increases information sharing and coordination between planning regions, and also calls for the development of joint planning studies between neighboring planning regions. SPP’s compliance with the interregional aspects in 2013 requires the addition of 3 new engineers and consulting costs to perform the increased interregional coordinated planning and joint project cost allocation activities. The 2014 forecast calls for an additional engineer necessary to meet SPP’s responsibilities under this order. From the regional perspective, the Order requires the removal from regional tariffs, the federal right of first refusal (“ROFR”) for “green field” transmission construction. Compliance with this requirement dictates SPP will need to implement an RFP (“Request for Proposal”) process to select qualified transmission owners for construction of

2013 Budget

approved transmission projects. SPP expects the RFP process will only apply to projects of 300KV and above. SPP intends to add (1) FTE related to RFP administration and (1) FTE to assist with the legal aspect of the RFP process. Other cost assumptions include RFP tracking software and consulting costs related to an Industry Expert Panel to be employed to evaluate RFP responses. SPP expects to recover the costs related to the RFP process from entities participating in the bidding process.

Administrative Fee Calculation:

SPP’s projected 2013 net revenue requirement (NRR) is $121.8M, as compared to the 2012 budget NRR of $89.6M. The primary drivers of the increase are: 1) reduction in revenue related to the expiration of the ICT and ITO contracts ($5.5M) and ($17.5M); 2) increase in interest expense and principal payments for additional debt ($5.5M); and 3) salaries and benefits for 23 incremental positions, plus merit and promotions in 2013 ($3.1M) and increases in benefits associated with healthcare plans and pension funding ($1.3M). Based on the projected NRR of $121.8M and projected billing determinants of 360,915 MWh, SPP’s 2013 calculated administrative cost is 34.4¢ per MWh. SPP management recommends an administrative fee rate of 31.5¢ per MWh for 2013. Calculation of the administrative fee is outlined on the following page and includes true-ups of 2011 aggregate over-recovery (refer to true-up calculation on page 52). Revenue and expense items used to calculate NRR are outlined in subsequent pages. Billing determinants were forecasted by SPP’s Settlements group using actual trailing 12-month billing units (July 2011 – June 2012) and assumed an insignificant amount of growth in the transmission services footprint in 2013.

2013 Budget

Administrative Fee Calculation (con’t):

$000's 2013

Budget 2012

Budget 2012

Forecast 2013 Prior Year Est**

Operating Expenses $162,626 $151,954 $147,038 $164,603 Debt Service 12,700 11,206 11,206 12,700 Depreciation and Amortization (20,295) (17,317) (16,365) (27,597) Non-Cash SWAP Valuation Adjustment 0 0 295 0

Gross Revenue Requirement $155,030 $145,843 $142,174 $149,706 Less: NERC Expense (11,515) (11,499) (11,738) (11,664) Schedule 12 Expense (FERC Fee) (16,696) (15,410) (14,977) (15,876) Contract Services Revenue (721) (23,758) (24,018) (17,484) Other Revenues (4,284) (5,616) (5,370) (6,037)

Net Revenue Requirement $121,814 $89,560 $86,072 $98,645

Divided by Estimated Billing Determinants/MWh* 360,915,000 353,453,000 361,011,000 359,816,000 Calculated Administrative Fee / MWh $0.338 $0.253 $0.238 $0.274 Calculated True-Up Adjustment *** ($0.022) $0.000 $0.000 $0.000 Recommended Admin Fee / MWh $0.315 $0.255 $0.255 $0.280 Current Tariff Cap on Admin Fee / MWh $0.350 $0.350 $0.350 $0.350

* Defined as coincident peak for network service and capacity for point to point service in MWh ** Refers to 2013 estimate made during 2012 budget presentation *** See true-up detail on page 52

SOUTHWEST POWER POOLNET REVENUE REQUIREMENT GROWTH

2013 2012 2012 2012 2012(000's) Budget Budget Forecast Budget Forecast Comments on Variances to Budget

Income Tariff Administration Service $113,799 $90,131 $92,058 $23,668 26% $21,741 24% Increase in Administrative Fee from $0.255 to $0.340 Fees & Assessments 28,211 26,909 26,715 1,302 5% 1,496 6% Increase in NERC funding ($0.2M) and Schedule12 revenues ($1.2M) Contract Services Revenue 721 23,758 24,018 (23,037) (97%) (23,296) (97%) Contract expirations in 2012: ITO ($5.5M) and ICT ($17.5M) Miscellaneous Income 4,284 5,616 5,370 (1,332) (24%) (1,086) (20%) Decrease in transmission service study activity ICT ($1.4M) and ITO ($1.1M); offset by

cost recovery associated with FERC Order 1000 ($650K) Total Income 147,015 146,414 148,160 602 (1,145) (1%)

Expense Salary & Benefits 77,363 72,222 72,266 (5,140) (7%) (5,096) (7%) 2013 assumes 23 incremental staff and a 6% vacancy factor. Benefits increased due

to incentive compensation calculation, healthcare expenses and pension funding Employee Travel 2,614 3,002 2,586 388 13% (28) (1%) Administrative 5,015 4,212 3,922 (803) (19%) (1,093) (28%) Increase in property taxes Assessments & Fees 16,340 15,410 14,977 (930) (6%) (1,363) (9%) Increase in projected FERC assessment Meetings 1,586 1,445 1,146 (140) (10%) (439) (38%) Increase related to IM outreach workshops and Integrated Market clinics Communications 4,427 4,592 4,396 165 4% (31) (1%) Lower voice/data circuit and long distance costs, partially offset by increased costs

for SPPnet frame costs of 5 Market participants and additional member circuit Leases 386 1,631 1,648 1,245 76% 1,262 77% Majority of leased office space released upon new facility completion Maintenance 10,476 9,312 8,427 (1,164) (12%) (2,049) (24%) Increase in new facility maintenance and increased support agreements driven by

Integrated Marketplace Services 16,003 18,700 15,397 2,698 14% (606) (4%) Reductions in legal and regulatory services, removal of ICT and ITO consultants,

paritally offset by increase in Integrated Marketplace support R i l St t C itt 344 394 527 50 13% 182 35% L lti f MISO / E t t di

Fav/(Unfav) Variance Compared to:

Regional State Committee 344 394 527 50 13% 182 35% Lower consulting expenses for MISO / Entergy studies Depreciation & Amortization 20,295 17,317 16,365 (2,978) (17%) (3,931) (24%) Additional depreciation primarily related to new facility Other Expense 7,777 3,716 5,382 (4,061)

(109%)(2,396)

(45%)Interest expense related to new debt obtained in 2012 for IM not included in prior year budget

Total Expense 162,626 151,954 147,038 (10,672) (7%) (15,588) (11%)

Net Income (Loss) ($15,611) ($5,541) $1,122 ($10,069) 2 ($16,733)

Debt Repayment $12,700 $11,206 $11,206 ($1,494) (13%) ($1,494) (13%) MW/h Forecast 360,915 353,453 361,011 7,462 2% (96) (0%)

Net Revenue Requirement $121,814 $89,560 $86,072 ($32,254) (36%) ($35,742) (42%) Calculated Admin Fee / MWh $0.338 $0.253 $0.238 ($0.084) (33%) ($0.099) (42%) Recommended Admin Fee / MWh $0.315 $0.255 $0.255 ($0.060) (24%) ($0.060) (24%)

Capital Expense $35,818 $82,034 $84,574 Headcount 603 590 582

SOUTHWEST POWER POOL2013 BUDGET COMPARED TO PRIOR YEAR PROJECTIONS

2013 2013 Fav/(Unfav)(000's) Current Prior Variance Comments on Variances

Income Tariff Administration Service $113,799 $100,748 $13,051 13% Change in NRR and Admin Fee Fees & Assessments 28,211 27,540 671 2% NERC $0.2M increase; FERC $0.4M increase Contract Services Revenue 721 17,484 (16,763) (96%) Removal of ICT and ITO revenues Miscellaneous Income 4,284 6,037 (1,752) (29%) Removal of ICT and ITO revenues Total Income 147,015 151,809 (4,794) (3%)

Expense Salary & Benefits 77,363 75,666 (1,697) (2%) Increase in healthcare, pension funding, and incentive comp calculations Employee Travel 2,614 2,611 (3) (0%) Administrative 5,015 4,233 (782) (18%) Property tax on book value of assets Assessments & Fees 16,340 16,181 (160) (1%) Meetings 1,586 1,474 (112) (8%) IM outreach workshops Communications 4,427 4,186 (241) (6%) Increased costs for SPPnet frame costs of 5 Market participants and additional

member circuit growth, offset by lower voice/data circuit and long distance costs Leases 386 475 88 19% Current estimates for 2013 leases more accurate Maintenance 10,476 10,108 (368) (4%) Services 16,003 17,654 1,651 9% Staff augmentation reductions in IT, Regulatory, Legal and Engineering ($3.5M),

offset by increases in staff augmentation related to the Integrated Marketplace and various other initiatives

Regional State Committee 344 339 (5) (2%) Depreciation & Amortization 20,295 27,597 7,302 26% Prior year assumed depreciation during IM testing Other Expense 7,777 4,081 (3,696) (91%) Interest expense associated with $100M issuance in 2012 Total Expense 162,626 164,603 1,978 1%

Net Income (Loss) ($15,611) ($12,794) ($2,817)

Debt Repayment $12,700 $12,700 $0 MW/h Forecast 360,915 359,816 1,099

Net Revenue Requirement $121,814 $98,645 ($23,168) (23%) Calculated Admin Fee / MWh $0.338 $0.274 ($0.063) (23%) Recommended Admin Fee / MWh $0.315 $0.280 ($0.035) (13%)

Capital Expense $35,818 $29,623 ($6,195) Headcount 603 613 (10)

2013 Budget

Projects and Capital Expenditures: The 2013 budget identifies $35.8M in capital expenditures associated with 37 initiatives. Although several initiatives are related to foundation activities, over 60% of the budgeted capital expenditures are associated with development and implementation of the Integrated Marketplace ($21.8M) and ramping up for post-go-live projects associated with the Integrated Marketplace ($1.6M). In addition to the budgeted capital outlay for projects, $4.9M in operating expenses and 11 incremental headcount have been budgeted in 2013 in association with these initiatives. Following is a detail of capital expenditures and operating expenses:

CAPITAL EXPENDITURES

Hardware Software Facilities Consulting Other Total Remaining

Capital Fund * 2013 8,376 4,437 0 20,378 2,627 $35,818 $19,831 2014 4,275 9,968 0 8,311 0 $22,554 ($2,723) 2015 4,279 8,126 0 2,724 0 $15,129 $12,148 ** Total $16,930 $22,531 $0 $31,413 $2,627 $73,501 $29,255

* Beginning capital cash $56M (see pg 36) ** Assumes $30M loan in 2015

OPERATING EXPENSE & HEADCOUNT

Salary & Benefits

Travel & Meetings Consulting Maintenance Other Total Headcount

2013 $1,318 $180 $1,903 $1,351 $115 $4,867 11 2014 1,470 28 1,473 1,613 199 4,783 5 2015 1,851 32 1,280 1,717 120 5,000 3 Total $4,639 $240 $4,656 $4,681 $434 $14,650 19

2013 Budget

The following pages describe the Integrated Marketplace and other noteworthy projects in greater detail. A complete list of initiatives and associated capital and operating budget impacts appear at the end of this section (page 20).

Integrated Marketplace:

Capital Expenditures by Year ($000s) * 2007-10 2011 2012 2013 2014 Total

Marketplace $8,551 $20,889 $47,823 $ 21,006 $ 4,298 $102,567 CBA 192 1,071 464 756 0 2,484

Total $8,743 $21,961 $48,287 $21,762 $4,298 $105,052 * Does not include capitalized interest

The 2013 budget includes the continued development efforts for the Integrated Marketplace. SPP plans to implement the following large-scale initiatives by first quarter 2014:

1. Integrated Marketplace Development • Day-Ahead (DA) Market for Energy and Operating Reserve • Transmission Congestion Rights (TCR) Mechanism • Real-Time Balancing Market (RTBM) for Energy and Operating Reserve

2. Consolidated Balancing Authority

The primary business drivers of the Integrated Marketplace program are to: 1) take further advantage of the diversity of generating unit resource assets, 2) optimize utilization of the transmission system within SPP, and 3) minimize overall costs to consumers. The primary business benefits of the Integrated Marketplace program as determined from the Cost Benefit Task Force cost/benefit analysis are: 1) $45.0M - $100.0M per year net cost benefit to the SPP region based on various gas cost assumptions, and 2) a more efficient utilization of generation assets through centralized unit commitment.

2013 Budget

The program will be considered complete when:

1. SPP has assumed the role of balancing authority from members 2. SPP has implemented and completed a monthly settlement for each of the following markets-

related initiatives: DA Markets, RTBM, Operating Reserves, and TCR Markets Integrated Marketplace Post-Go-Live Projects:

Projected Capital Expenditures by Year

(000's) 2013 2014 2015 Total Combined Cycle Enhancements $ 450 $2,900 $ 450 $3,800 Regulation Compensation (FERC Order 755) 255 3,020 510 3,785 Long-Term TCRs (LTTCRs) 429 1,081 0 1,510 AFC Granularity Changes for TSRs 0 1,363 0 1,363 Market to Market 472 944 0 1,416 Sunset Clause for Load Submittal for Legacy BAs 0 156 0 156 Assets Pseudo-Tying Out of SPP BA 0 130 0 130 Marketplace Data for MPs Post Go-Live 0 50 0 50

Total $1,606 $9,644 $ 960 $12,210 Headcount 4 3 7

While SPP’s first priority is to successfully implement the Integrated Marketplace, work will need to start in 2013 on many of the required, post implementation enhancements. A brief description of each of the significant enhancements is as follows:

2013 Budget

Combined Cycle Enhancements These enhancements will allow market participants to submit resource offers for each configuration of a combined cycle unit. Each configuration will be modeled in the market clearing engine as a separate resource in order to select the most economic configuration for unit commitment and dispatch. Work is expected to commence in 3rd quarter 2013 with completion anticipated in 2nd quarter 2015. Regulation Compensation (FERC Order 755) FERC Order 755 requires RTOs to provide a two-part payment to resources providing regulation service in the Integrated Marketplace. Tariff changes, protocol changes and software changes will be required to comply with this Order. Work is expected to commence in 4th quarter 2013 with completion anticipated in 2nd quarter 2015. Long Term Transmission Congestion Rights (LTTCRs) FERC Order 681 requires Load Serving Entities (LSEs) have priority in the allocation of long-term firm transmission rights. FERC expects most transmission organizations will be able to use their current allocation/auction systems to allow LSEs to nominate source-to-sink transmission rights on a longer-term basis than what is currently available. This project will consist of enhancements to the Nexant software and will establish a process which gives LSEs the ability to nominate LTTCRs for more than one year. Work is expected to commence in 4th quarter 2013 with completion anticipated in 3rd quarter 2014. Market to Market Market to Market coordination logic needs to be added to the Integrated Marketplace system software in order to manage congestion appropriately and efficiently between SPP and MISO. This project adds functionality to the market clearing engine to enable market to market coordination between SPP and MISO which will provide the ability for both markets to request re-dispatch of generation to solve a constraint at a lower cost, therefore reducing the overall cost of congestion. Work is expected to commence in 3rd quarter 2013 with completion anticipated in 3rd quarter 2014. AFC Granularity Changes for TSRs This project will change how the Available Flowgate Capability (AFC) associated with transmission service requests (TSR) will be evaluated to accommodate the SPP Balancing Authority (BA). The change will provide SPP and its members a more accurate evaluation of transmission service impacts once SPP is the BA.

2013 Budget

Changes will most likely be necessary for many applications in Operations, IT, Transmission Planning and Settlements. Work is expected to commence in 1st quarter 2014 with completion anticipated in late 2014. Other Projects: Existing /Carryover Project - IT Netezza Upgrade The Integrated Marketplace has a fundamental requirement to provide a data repository to store significantly larger quantities of data for analysis and reporting compared to the EIS Market. The data volume is expected to be about 3-6 times larger than EIS Market and is forecasted to grow at ten percent per year. The Data Warehouse solution for Integrated Marketplace must address the availability, performance and near real time data access requirement for Integrated Marketplace. The current Netezza Platform will reach end of life in 2015 and is no longer being manufactured and therefore it is recommended to upgrade with the Integrated Marketplace timelines to also include the Integrated Marketplace requirements. The project commenced in June 2012 and is expected to be completed in December 2013. Total project cost is estimated at $3M. Foundation – IT Systems Administration This project is for replacement of old systems going out of warranty. New virtualized servers will be housed within an ESX Host Cluster and when required, new ESX Host(s) must also be purchased. While the main push for server replacement will be virtualization to consolidate hardware, replacement of some physical servers will still be required to replace systems which are not candidates for virtualization. Additional storage is needed at the new facility so more systems can move from the Maumelle Data Center. Total project cost is estimated at $6.6M from 2013 through 2015. Foundation – IT Network Equipment being replaced under this project are those which have been in service for over 3 years, have an increased risk of failure, have reached the end of their life cycle, and/or lack feature sets conducive to achieving the availability required by the Integrated Marketplace and other high availability projects. Additionally, there are upgrades of licensing and

2013 Budget

module/components included which will extend the life of assets already in production that simply lack port density or capacity. All of the equipment associated with this project is located in either the Maumelle Data Center or new Chenal facilities. Total project cost is estimated at $4.3M from 2013 through 2015. Foundation – IT Applications The complexity of the Integrated Marketplace requires more stringent methods of software deployment, managing releases and availability and capability of tools used in development. Customized in-house developed processes and tools have proven to be unreliable for long term deployments, and industry accepted standards, methods, and models have to be used. This initiative will get SPP development processes to that level. Total project cost is estimated at $3.8M from 2013 through 2015. This project will cover the following IT Applications initiatives:

- Increasing the number and capabilities of the requirements/test tools used for the gathering/tracking of requirements, test cases, test results, etc.

- Increasing functionality of Informatica ETL tool - Increasing the availability of Integrated Marketplace databases by decreasing

maintenance windows and downtime - Development of a performance testing process with tools and consultants to be used in

Integrated Marketplace performance testing and beyond - Development of release management processes - Development of software deployment methodology and processes

Q1 2013 Q2 2013 Q3 2013 Q4 20132013

Budget2014

Budget2015

BudgetPrior

Year(s)TOTAL

PROJECTExisting / Carryover ProjectsIT Netezza Upgrade 1,969$ -$ 293$ -$ 2,263$ 177$ 120$ 479$ 3,038$ Centralized Modeling & Model Chg Submission Tools 145 145 65 - 355 - - 2,100 2,455 EMS Marketplace Readiness 90 90 90 90 361 - - 353 714 New ICCP Architecture 123 63 63 63 311 - - 355 665 Ops Automation DC Ties 200 - - - 200 50 - 82 332 Ops Automation OATI 25 25 25 25 100 50 - 30 180

Total Existing / Carryover 2,552$ 323$ 536$ 178$ 3,589$ 277$ 120$ 3,398$ 7,385$ Integrated Marketplace / CBAIntegrated Marketplace 5,201$ 5,546$ 4,796$ 5,463$ 21,006$ 4,298$ -$ 77,263$ 102,567$ Consolidated Balancing Authority 105 615 36 - 756 - - 1,728 2,484

Total Integrated Marketplace / CBA 5,306$ 6,161$ 4,832$ 5,463$ 21,762$ 4,298$ -$ 78,992$ 105,052$ Market Post Go-Live ProjectsCombined Cycle Enhancements -$ -$ 225$ 225$ 450$ 2,900$ 450$ -$ 3,800$

SOUTHWEST POWER POOL2013 - 2015 BUDGET

CAPITAL COST PROJECTIONS ($000)

y $ $ $ $ $ ,$ $ $ ,$Regulation Compensation (FERC Order 755) - - - 255 255 3,020 510 - 3,785 Long-Term TCRs (LTTCRs) - - - 429 429 1,081 - - 1,510 AFC Granularity Changes for TSRs - - - - - 1,363 - - 1,363 Market to Market - - 118 354 472 944 - - 1,416 Sunset Clause for Load Submittal for Legacy BAs - - - - - 156 - - 156 Assets Pseudo-Tying Out of SPP BA - - - - - 130 - - 130 Marketplace Data for MPs Post Go-Live - - - - - 50 - - 50

Total Market Post Go-Live -$ -$ 343$ 1,263$ 1,606$ 9,644$ 960$ -$ 12,210$ IT FoundationSystems Administration 3,278$ 75$ 75$ 75$ 3,503$ 1,464$ 1,614$ -$ 6,582$ Network/Telecom 477 112 617 536 1,742 1,139 1,452 - 4,333 Applications 240 569 - - 809 1,040 1,950 - 3,799 Service Management 264 112 112 112 600 428 360 - 1,387 Service Delivery 291 - - - 291 96 96 - 483 Environmental Ops 15 30 15 40 100 79 83 - 261

Total IT Foundation 4,566$ 898$ 819$ 763$ 7,045$ 4,246$ 5,555$ -$ 16,846$

Q1 2013 Q2 2013 Q3 2013 Q4 20132013

Budget2014

Budget2015

BudgetPrior

Year(s)TOTAL

PROJECT

SOUTHWEST POWER POOL2013 - 2015 BUDGET

CAPITAL COST PROJECTIONS ($000)

Operations FoundationMarketplace MOS Enhancements -$ -$ -$ -$ -$ 750$ 750$ -$ 1,500$ Legacy Applications 50 120 75 55 300 375 325 - 1,000

Total Operations Foundation 50$ 120$ 75$ 55$ 300$ 1,125$ 1,075$ -$ 2,500$ New ProjectsUpgrade ETSE 3.0 Transmission Settlements -$ -$ -$ -$ -$ -$ 3,500$ -$ 3,500$ OPS DTS Upgrade to TTSE - - - - - - 2,908 - 2,908 IT EMS upgrade (2014-2015) - - - - - 1,144 856 - 2,000 IT Data Center Migration 380 - 240 - 620 570 - - 1,190 IT Progress ESB Replacement - 50 - - 50 900 - - 950 IT Portal 174 108 108 108 498 - - - 498 Integration of IssueTrak with Remedy - - - - - 150 - - 150

Total New Projects 554$ 158$ 348$ 108$ 1,168$ 2,764$ 7,264$ -$ 11,196$ Miscellaneous Capital SpendMiscellaneous Capital SpendETS Foundation-Alstom 50$ 25$ -$ -$ 75$ 75$ 75$ -$ 225$ FERC Order 1000 Regional RFP 15 - 150 - 165 30 30 - 225 Stochastic Planning 70 - - - 70 80 50 - 200 Redundant EnFuzion Node and PSSE Lock Ph 2 - 23 - - 23 - - - 23 ITP Data Repository 5 - - - 5 5 - - 10 Update PROMOD to Server Solution 10 - - - 10 10 - - 20

Total Miscellaneous Capital Spend 150$ 48$ 150$ -$ 348$ 200$ 155$ -$ 703$

TOTAL CAPITAL COST PROJECTIONS 13,178$ 7,708$ 7,103$ 7,830$ 35,818$ 22,554$ 15,129$ 82,390$ 155,891$

SOUTHWEST POWER POOLCOMPLETE AND ONGOING PROJECTS

2012 Budget vs. Forecast(in thousands)

Total Project Total Project2012 Budget 2012 Forecast* 2012 Budget

2012 FoundationIT Foundation $3,677 $4,432 $754Ops Foundation 425 425 -

Total Foundation $4,102 $4,857 $754

Completed in 2012New Facilities Construction & Migration $88,553 $83,589 $(4,964)High Availability 5,121 3,089 (2,032)EMS Upgrade 1,266 1,126 (140)e-Tariff Phase II 950 383 (567)Request Management System 273 182 (91)Situational Awareness Enhancements (ETV-E-terra Vision) 193 125 (68)Replace OPS1 Outage Coordination Scheduler 133 365 233Ops Automation #2 RTOSS-Settlements 113 - (113)EDNA Software Replacement ** - 1,000 1,000Standardized Cost Estimate Reporting Template (SCERT) ** - 140 140CIP (Ver 4) Project ** - 51 51

Total Completed in 2012 $96,601 $90,050 $(6,551)

Ongoing Projects

Over/(Under)

Ongoing ProjectsIntegrated Marketplace (Future Markets) $100,999 $102,567 $1,568Consolidated Balancing Authority 4,639 2,484 (2,155)Post-Go-Live Projects 11,800 12,210 410Cent Modeling Tool & Model Chg Submission Tool 1,833 2,454 621Ops Automation DC TIES 364 332 (32)Ops Automation OATI 210 180 (30)Netezza Upgrade ** - 3,038 3,038EMS Marketplace Readiness ** - 714 714ICCP Architecture ** - 665 665

Total Ongoing Projects $119,846 $124,645 $4,799

TOTAL $220,549 $219,551 $(998)

* As of July 2012 forecast** Unbudgeted in 2012

2013 Budget

Valuing Work at SPP:

The 2012 end of year Staff to Management Ratio is projected to be 5:1. The planned staffing projection for the end of 2013 will increase this ratio to 5.3:1. As part of the ongoing effort to optimize SPP’s overall performance, Human Resources is working on organizational alignment initiatives and development strategies to move toward a higher Staff to Management ratio. SPP’s strategy for improving this ratio includes clarifying responsibilities of management roles at all levels, from supervisor to director, and further enhancing guidelines for the professional (i.e. non-management) career track. The management career track is centered on one’s scope of responsibility regarding strategic influence, asset management, and organizational impact. While asset management includes both financial and human resources, uniform guidelines will be established regarding functional criteria for which each level of management should be accountable. Plans are also underway to develop a standard set of prerequisites in the areas of education and experience to accompany competency demonstration as a threshold for management-level roles. For the professional career track, a model will be structured which facilitates and supports employee engagement, career development, and continuous learning. Retention and job satisfaction will be the focus of this initiative. This project will be facilitated by HR’s Talent Management Team by collecting and managing data related to knowledge, skills, and abilities (KSA’s) possessed by each individual employee in addition to those KSA’s required for each job role. Proper use of this data will assist directors and managers in the development of succession and pipeline plans. In parallel, the data will be used to support employees in developing and pursuing individual career plans.

2012 2013 Incremental Positions 2013 2014 2015Department Name Forecast Foundation Project Total Budget Budget BudgetSPP Compliance & Communications 36 1 0 1 37 39 39Process Integrity 46 1 1 2 48 48 48Reg Policy & General Counsel 23 1 0 1 24 24 24Officers & Corporate Services 37 3 0 3 40 40 40Administration 40 0 1 1 41 42 42SPP Regional Entity 32 0 0 0 32 32 32Market Development & Analysis 6 0 0 0 6 6 6Information Technology 137 6 0 6 143 147 148Operations 155 0 3 3 158 161 164Engineering 68 3 3 6 74 79 79

TOTAL 580 15 8 23 603 618 622Project / Foundation

Market 26 0 4 4 4 0 0Post-Market 0 0 0 0 0 4 3FERC Order 1000 0 0 4 4 4 1 0Stochastic Planning 0 0 2 2 2 3 0Foundation 24 13 0 13 13 7 1

SOUTHWEST POWER POOL2013 BUDGET INCREMENTAL POSITIONS

Foundation 24 13 0 13 13 7 1Total Incremental 50 13 10 23 23 15 4

The 2013 budget includes 10 incremental positions related to various projects. Overall incremental headcount for 2013 is 23; which matches the proposed incremental for 2013 in during the2012 budget. The net increase over the 2012 budget is only 13, as the following positions were eliminated during 2012: IT (2), Engineering (7) and Operations (2) (offset by one HR position added after the 2012 budget was submitted).

Staffing increases are related to the following:

SPP Compliance & Security: (1) Communications Specialist for additional responsibilites related to Energy Emergency Alerts (CBA function) and expanded support of member working groups, investor relations, and employee engagement in 2013; and (1) Sr. Compliance Analyst-Member Audits for increased compliance demands associated with NERC-registered Centralized Balancing Authority (CBA)requirements and (1) Market Monitor II for activities related to FERC Order 670, both in 2014

Process Integrity : (1) LMS Support and Web/CBT Developer and (1) Customer Support Specialist for Integrated Marketplace support; and (1) Customer Trainer (Regional Operations) to address demand for additional reliability-related training, NERC required training, and training on new/updated operator tools.

Regulatory Policy & Legal: (1) Attorney to lead the legal support of SPP's compliance with and implementation of FERC Order 1000 requirements, and to address legal matters associated with the implementation and operation of the Integrated Marketplace Note: Outside legal expenses were reduced by $1.6M from the 2012 budget.

SOUTHWEST POWER POOL2013 BUDGET INCREMENTAL POSITIONS

Officers and Corporate Services: (1) Sr. VP, Governmental Affairs and Public Relations; (1) Talent Management Administrator; and (1) Talent Management Specialist to assist in development and delivery of ongoing professional, managerial, and leadership training as part of SPP's talent management strategy to engage and retain career employees.

Administration: (1) Business Analyst to assist with RFP process required under FERC Order 1000. (1) Sr. Staff Accountant position for 2014 for increased workload associated with Integrated Marketplace and various other reporting and analysis responsibilities

Information Technology : (1) Sr. Data Warehouse Developer to focus on development and maintenance of EADS ETL flows, processes and tool administration; (5) IT Analysts in 2013 to support various systems (CMS, POPS, EBS, Portal, TCR, Settlements, Marketplace, and CMT); and additional staff to cover additional IT growth needs in 2014 (4) and 2015 (1). Note: (2) positions were eliminated in 2012.

Operations: (1) Sr. Operator; (1) Market Analyst I; and (1) Operator III-Day Ahead Market related to IM functions. (3) Incremental positions associated with Market to Market, plus (3) positions to maintain the Dispatcher Training Simulator (DTS) and Training and Testing Simulated Environment (TTSE), which will be implemented in 2015 Note: Shift Supervisors (3) originally budgeted for 2013 were accelerated to 2012; however it is anticipated the positions will be filled with existing staff, without replacements, resulting in no incremental headcount. Operator-In-Training positions (2) were also eliminated in 2012.

Engineering: (3) Engineer positions in 2013 and (1) Engineer position in 2014 related to FERC Order 1000 Additional positions for 2013 include: (1) Manager and (1) Sr. Engineer related to Stochastic Planning and (1) Engineer I-Modeling (funded by RE). In 2014, (1) position to support Long-Term TCRs (LTTCRs) and (2) additional for Stochastic Planning. Note: (7) Engineering positions were eliminated in 2012 for various ICT functions, which will be absorbed by outside contractors in the event Entergy's contract is renewed or extended.

2012 2013 2014 2012 2013 2014Department Name Forecast Budget Forecast Budget Forecast Forecast 2012 2013 2014SPP Compliance & Communications 36 37 39 36 38 38 0 (1) 1Process Integrity 46 48 48 46 48 49 0 0 (1)Reg Policy & General Counsel 23 24 24 23 24 24 0 0 0Officers & Corporate Services 37 40 40 36 36 36 1 4 4Administration 40 41 42 40 41 41 0 0 1SPP Regional Entity 32 32 32 32 34 34 0 (2) (2)Market Development & Analysis 6 6 6 6 6 6 0 0 0Information Technology 137 143 147 139 145 149 (2) (2) (2)Operations 155 158 161 157 158 158 (2) 0 3Engineering 68 74 79 75 83 85 (7) (9) (6)

Change

SOUTHWEST POWER POOL2013 BUDGET INCREMENTAL POSITIONS COMPARED TO 2012 PROJECTIONS

2012 Budget2013 Budget

TOTAL 580 603 618 590 613 620 (10) (10) (2)

Project / FoundationMarket 26 4 0 26 4 0 0 0 0Post-Market 0 0 4 0 0 0 0 0 4FERC Order 1000 Regional RFP 0 4 1 0 0 0 0 4 1Stochastic Planning 0 2 3 0 0 0 0 2 3Foundation 24 13 7 24 19 7 0 (6) 0

Total Incremental 50 23 15 50 23 7 0 0 8

Original 2012 Budget 590Net Reduction in IT -2Net Reduction in Engineering -7Net Reduction in Operations -2Additional HR Generalist (in 2012) 1

Revised 2012 Forecast 580

Expense Staff2013 SalarySalary as of May 15, 2012 (provided by HR) $47,263 545

Promotions & Non-Merit Pay Increases after May 15th 355May 2012 Open Positions Forecast 3,345 35

2012 Ending Balance 50,964 5802013 Incremental Expense 1,732 23Merit Increase (2.0%) & Promotions (0.75%) 1,363Estimate for Premium Pay (2.67%) 1,580Vacancy (6.0%) (3,244)

Total $52,395 603

Expense Staff2014 SalaryFY Salary Beginning January 31 2014 $53 788 * 603

SOUTHWEST POWER POOL2013 Salary Expense Assumptions

(in $000)

2013 Budget

2014 Forecast

FY Salary Beginning January 31, 2014 $53,788 6032014 Incremental Expense 1,163 15Merit Increase (2.0%) & Promotions (0.75%) 1,479Estimate for Premium Pay (2.67%) 1,436Vacancy (6%) (3,386)

Total $54,480 618

Expense Staff2015 SalaryFY Salary Beginning January 31, 2015 $56,060 * 618

2014 Incremental Expense 308 4Merit Increase (2.0%) & Promotions (0.75%) 1,542Estimate for Premium Pay (2.67%) 1,497Vacancy (6%) (3,475)

Total $55,931 622

* Beginning balance excludes prior year adjustments for vacancy and overtime

2015 Forecast

SOUTHWEST POWER POOL2013 BUDGET - SUMMARY INCOME STATEMENT & COMMENTARY

Fav/(Unfav) Variance Compared to:2013 2012 2012

($000's) Budget Budget Forecast

TOTAL REVENUE Tariff Administration Service $113,799 $90,131 $92,058 $23,668 26% $21,741 24%

Fees & Assessments 28,211 26,909 26,715 1,302 5% 1,496 6%

Contract Services Revenue 721 23,758 24,018 (23,037) (97%) (23,296) (97%)

Miscellaneous Income 4,284 5,616 5,370 (1,332) (24%) (1,086) (20%)

Total Revenue $147,015 $146,414 $148,160 $602 0% ($1,145) (1%)

Billing Determinants in MWh 360,915 353,453 361,011 7,462 2% (96) 0%

Budget2012

Forecast2012

Total Revenue has increased over the 2012 Budget and Forecast. SPP classifies its revenue streams into 4 major categories:

• Tariff Administration Service is calculated by multiplying SPP’s administrative fee by prior year coincident peak for network service and capacity for point-to-point service in MWh. The increase in Tariff Administration Service is due to the increase in SPP’s administrative fee rate from 25 5¢ to 34 0¢ per MWhadministrative fee rate from 25.5¢ to 34.0¢ per MWh.

• Fees & Assessments consists of Schedule 12 fees collected to fund annual FERC assessments and NERC Regional Entity funding. Both revenue amounts are considered pass-through in which there are specific offsetting expenditures. The 2013 FERC fee is estimated at $16.3M, and will be collected in 2013 and paid in 2014. The 2013 NERC revenue recognition amount is $11.5M, however due to prior period funding true-ups, only $8.5M will be collected from SPP's registered entities. The remaining revenue of $402K is related to annual membership dues.

• Contract Services Revenue formerly consisted of revenues associated with the ICT and ITO contracts. The 2013 budget assumes theICT contract will not be renewed after 2012. No revenues are included for the ITO contract, which expired in August 2012.

• Miscellaneous Income includes engineering studies, member training, and other various revenues. The 2013 Engineering budget includes a decrease in revenue from ITO and generation interconnection service study products due to the expiration of the ITO contract and the decreased need for outside consultants to perform study related activities. These products include the SPP aggregate study (ATSS), delivery point transfer screening (DPT) studies, long-term screening studies (LTSR), and affected system studies. The decrease in study revenue will be partially offset by the revenue expected from FERC Order 1000.

Billing determinants were forecasted by SPP’s Settlements group using actual trailing 12-month billing units (July2011 – June 2012). An insignificant amount of growth was assumed in the transmission services footprint for the 2013 budget.



($000's) Budget Budget Forecast Budget2012

Forecast2012

TOTAL SALARIES, BENEFITS, TAXES & HEADCOUNT

Salaries, Benefits & Taxes 77,363 72,222 72,226 (5,141) (7%) (5,137) (7%)

Salaries 52,395 50,289 49,515 (2,106) (4%) (2,880) (6%)

Incentive Compensation 7,622 6,706 7,006 (916) (14%) (616) (9%)

Benefits & Taxes 17,345 15,227 15,705 (2,119) (14%) (1,640) (10%)

Headcount 603 590 582 (13) (2%) (21) (4%)

Employee costs are the single largest component of SPP's annual operating budget, comprising approximately 48% of SPP's annual gross revenue requirement for 2013. Incremental staffing in 2013 related to various projects and increased workloads caused salaries, benefits and taxes to exceed the 2012 Budget and Forecast. Staff increased by 23, resulting in an approximate net increase of $2.3M.Increases in health care expenses ($1.2M) and pension funding ($0.4M) contribute to the unfavorable variance from 2012. A correction c eases ea ca e e pe ses ($ . ) a d pe s o u d g ($0. ) co bu e o e u a o ab e a a ce o 0 . co ec o for calculating incentive compensation was made in 2013 (the 2012 budget was understated due to this error in calculation), which also caused an increase in benefits ($0.8M). Merit increases budgeted at 2.0% and promotions at 0.75% contribute to the remaining increase over 2012.

Staffing detail and analysis can be found on pages 25-28.

The 2013 Budget includes a vacancy factor of 6% which is reflective of SPP's historically low turnover rate. SPP’s performance compensation plan is budgeted at 15% of salaries. Cash outflows for performance compensation earned in 2013 will occur in February 2014. Funding for SPP's defined benefit retirement plan and retiree healthcare plan is $4.0M and $0.5M, respectively. Funding for SPP’s matching contribution to the 401(k) plan is estimated at 4% of salary.

SPP maintains a self-funded healthcare insurance program for employees. The self-funded healthcare program provides SPP and employees more economic benefit as compared to a traditional fully insured plan. The program is budgeted on a net basis: medical claims less employee contributions and contains a maximum claim limit as well as a claim per employee limit. Increased claims in 2012 resulted in an increase in expense estimates for 2013 of $1.2M.




Forecast2012

TOTAL TRAVEL & MEETINGS Employee Travel 2,614 3,002 2,586 388 13% (28) (1%)

Meetings 1,586 1,445 1,146 (140) (10%) (440) (38%)

Total Travel & Meetings 4,200 4,447 3,733 248 6% (468) (13%)

As Integrated Marketplace activities continue to progress as scheduled, travel and meetings costs are expected to increase due to internal/external training activities, market participant outreach, and completion of system development and factory acceptance testing. SPP continues to monitor travel costs to mitigate the increase in budgeted travel expenditures associated with vendor site visits, which are often located in larger cities that can be significantly more expensive to travel (ex. Seattle, San Francisco, Minneapolis, etc.).

TOTAL ADMINISTRATIVE & LEASE EXPENSE Administrative 5,015 4,212 3,922 (803) (19%) (1,093) (28%)

Leases 386 1,631 1,648 1,245 76% 1,262 77%

Total Administrative & Leases 5,401 5,843 5,570 442 8% 170 3%

Administrative expense is expected to increase in 2013 due to additional O&M costs associated with SPP's new campus. Offsetting the increases resulting from occupancy of the new campus is a significant reduction in lease expense following the expiration of SPP's lease of the Plaza West space in the third quarter of 2012. SPP's lease on the GMAC office space expires in April 2013, with no agreement reached to extend the lease. In order to continue to accommodate the testing and parallele operations phases of theIntegrated Marketplace, SPP plans to relocate resources to the main corporate facility for the duration of the project.




Forecast2012

TOTAL COMMUNICATIONS & MAINTENANCE EXPENSE Communications 4,427 4,592 4,396 165 4% (31) (1%)

Maintenance 10,476 9,312 8,427 (1,164) (12%) (2,049) (24%)

Total Comm & Maintenance 14,903 13,904 12,823 (999) (7%) (2,080) (16%)

Communications expense includes all expenditures related to SPP’s internal and external networks and telecommunications. These expenses are expected to decrease in 2013 mostly due to lower voice/data circuit costs associated with the elimination of Plaza West and GMAC office space, and lower long distance and wireless service expenses. This is partially offset by member circuit growth and increased SPPnet frame costs of five market participants.

Maintenance expense includes all hardware and software support, annual licensing fees and building maintenance. These expenses are expected to increase signicicantly in 2013 primarily due to new maintenance support agreements which will go into effect in 2013related to the Integrated Marketplace (including TCR iHedge maintenance, Credit Management System maintenance and post-operations / pre-settlements maintenance). Other maintenance costs include various corporate facility expenses such as janitorial

TOTAL OUTSIDE SERVICES Outside Services 16,003 18,700 15,397 2,698 14% (606) (4%)

p / p ) p y p jexpense, landscape maintenance and preventative maintenance, which have also increased over the prior year.

Outside services consist of third-party expertise to assist SPP in the deployment of its services, provide legal representation, and satisfy audit requirements. As compared to the 2012 budget, total outside services expense is expected to decrease in 2013 primarily as a result of reductions in regulatory consulting and legal support ($1.6M) and the elimination of consultants associated with the ICT and ITO contracts ($1.3M). Over the past two years, legal staff has been increased in an ongoing effort to reduce outside consulting needs. Other miscellaneous reductions in staff augmentation in Regional Entity, IT and Process Integrity departments also contribute to the decrease ($0.4M). Offsetting these variances is an increase in staff augmentation related to the Integrated Marketplace project ($0.6M).




Forecast2012

TOTAL REGIONAL STATE COMMITTEE Regional State Committee 344 394 527 50 13% 182 35%

TOTAL DEPRECIATION & AMORTIZATION Depreciation & Amortization 20,295 17,317 16,365 (2,978) (17%) (3,931) (24%)

Total Regional State Committee (RSC) remains relatively flat to the 2012 budget. The 2012 forecast increased slightly as a result of consulting for the Brattle Study Group related to Entergy / MISO; however, this expense is not expected to continue in 2013.

Although Depreciation and Amortization are not components of SPP’s administrative fee, they are significant factors in SPP’s GAAP based budget Depreciation and Amortization expense is expected to increase in 2013 primarily due to the full year depreciation

TOTAL OTHER EXPENSE Other Expense 7,777 3,716 5,382 (4,061) (109%) (2,396) (45%)

based budget. Depreciation and Amortization expense is expected to increase in 2013 primarily due to the full year depreciation expense for the new corporate campus and related equipment purchases that were completed in July 2012, as well as hardware and software purchases for the planned capital projects.

Other Expenses include interest expense, interest income, and other extraordinary gains or losses. Interest expense of $3.1M has been added in 2013 for new borrowings of $50M (2nd quarter of 2012) and $50M (4th quarter of 2012). A portion of the interest expenseincurred in 2012 and 2013, $4.2M and $2.7M respectively, will be capitalized in association with new facilities construction andIntegrated Marketplace development. The decrease in expected capitalized interest is due to the completion of new facilities construction in 2012.




Forecast2012

TOTAL DEBT REPAYMENT Debt Repayment 12,700 11,206 11,206 (1,494) (13%) (1,494) (13%)

SPP will make $5.5M in principal payments on the 2014 Senior Note, $6M in principal payments on the 2016 Senior Note and $1.0M on the 2042 Senior Notes. Additionally, SPP will make quarterly principal payments for the mortgage on the Maumelle facility.

($000) 12/31/2012 12/31/2013ASSETS Current Assets Cash & Equivalents $81,755 $46,023 Restricted Cash Deposits 39,050 42,550 Accounts Receivable (net) 18,495 19,370 Other Current Assets 7,706 10,379 Total Current Assets 147,006 118,322 Total Fixed Assets 183,531 201,778 Total Other Assets 1,265 1,109 Investments 844 844TOTAL ASSETS 332,646 322,053

LIABILITIES & EQUITY Liabilities Current Liabilities Accounts Payable (net) 10,433 23,207 C t D it 39 050 42 550

SOUTHWEST POWER POOL2013 BUDGET - BALANCE SHEET

Customer Deposits 39,050 42,550 Current Maturities of LT Debt 12,700 22,998 Other Current Liabilities 26,342 28,196 Deferred Revenue 6,514 5,519 Total Current Liabilities 95,039 122,470

Long Term Liabilities US Bank Floating Senior Note - 2014 5,500 0 US Bank 5.45% Senior Notes - 2016 15,000 9,000 US Bank Maumelle Mortgage - 2027 3,752 3,547 Campus 4.82% Senior Notes - 2042 64,006 62,963 Integrated Marketplace 3.55% Senior Notes - 2024 70,000 64,750

Capital Funding 3.00% - 2024 50,000 46,250Capital Funding 3.25% - 2024 50,000 48,750

Other Long Term Liabilities 7,649 8,234 Total Long Term Liabilities 265,907 243,494

Net Income 1,122 (15,611) Members' Equity (29,422) (28,300)

Total Members' Equity (28,300) (43,911)

TOTAL LIABILITIES & EQUITY $332,646 $322,053

2013 2014 2015Budget Forecast Forecast

IncomeTariff Administration Service $113,799 $137,545 $143,586Fees & Assessments 28,211 29,143 30,002Contract Services Revenue 721 721 721Miscellaneous Income 4,284 4,115 4,225

Total Income 147,015 171,524 178,534

ExpenseSalary & Benefits 77,363 80,767 82,908Employee Travel 2,614 2,401 2,375Administrative 5,015 5,456 5,559Assessments & Fees 16,340 17,157 18,015Meetings 1,586 1,525 1,459Communications 4,427 4,482 4,467Leases 386 144 144Maintenance 10,476 15,259 15,428Services 16,003 15,736 14,466Regional State Committee 344 353 361

SOUTHWEST POWER POOL2013 BUDGET - THREE YEAR FORECAST

Regional State Committee 344 353 361Depreciation & Amortization 20,295 47,017 54,017Other Expense 7,777 9,103 10,491

Total Expense 162,626 199,399 209,690

Net Income (Loss) ($15,611) ($27,875) ($31,156)

Debt Repayment $12,700 $22,998 $24,299MW/h Forecast 360,915 371,743 382,895

Net Revenue Requirement $121,814 $141,401 $145,024

Projected Over / (Under) Recovery ($7,845) ($1,101) $508

Calculated Admin Fee / MWh $0.338 $0.380 $0.379

Recommended Admin Fee / MWh $0.315 $0.370 $0.375

Tariff Cap on Admin Fee $0.350 $0.350 $0.350

Capital Expense $35,818 $22,554 $15,129Headcount 603 618 622

Fixed Charge Coverage Ratio 1.57 3.07 3.15

($000) QTR 1 QTR 2 QTR 3 QTR 4 Total2013 2013 2013 2013 2013 2014 2015

OPERATING CASH (000)Beginning Cash on Hand $5,234 ($7,363) ($6,704) ($4,156) $5,234 ($2,611) ($3,711)

Income Tariff Administration Service 26,148 28,422 29,559 29,559 113,688 137,545 143,586 NERC Fees 2,879 2,879 2,879 2,879 11,515 12,091 12,695

Annual Dues 402 0 0 0 402 402 402 Contract Services Revenue 121 253 174 174 721 721 721 Studies and Other Income 1,040 890 815 890 3,634 4,765 4,225Operating Income 30,589 32,444 33,426 33,501 129,961 155,524 161,629

Expense Salaries Expense 17,914 11,062 11,116 11,086 51,178 53,680 55,931 Employee Benefits & Taxes 6,599 6,293 5,975 6,023 24,891 26,286 26,977 Employee Travel 665 718 650 581 2,614 2,401 2,375 Administrative Expense 1,024 1,438 988 1,422 4,872 5,456 5,559 Meetings Expense 352 417 421 396 1,586 1,525 1,459 Communications Expense 1 053 1 093 1 131 1 149 4 427 4 482 4 467

SOUTHWEST POWER POOLTHREE YEAR FORECASTED CASH FLOW

Communications Expense 1,053 1,093 1,131 1,149 4,427 4,482 4,467 Maintenance Expense 5,936 1,430 1,458 2,205 11,028 14,461 14,592 Leases Expense 218 97 36 36 386 144 144 Outside Services Expense 4,112 3,982 3,947 3,962 16,003 15,736 14,466 Regional State Committee Expense 75 98 73 98 344 353 361 Interest Income & Expense 2,067 1,986 1,906 1,818 7,777 9,103 10,491 Debt Service 3,170 3,173 3,176 3,179 12,700 22,998 24,299Operating Expense 43,187 31,785 30,878 31,956 137,806 156,625 161,122

Ending Cash on Hand ($7,363) ($6,704) ($4,156) ($2,611) ($2,611) ($3,711) ($3,204)

Recommended Admin Fee MW/h $0.315 $0.315 $0.315 $0.315 $0.315 $0.370 $0.375

CAPITAL CASH (000)Beginning Cash on Hand $59,266 $46,088 $38,380 $31,278 $59,266 $23,448 $894 Capital Expenditures 13,178 7,708 7,103 7,830 35,818 22,554 15,129 Capital Financing 0 0 0 0 0 0 30,000Ending Cash on Hand $46,088 $38,380 $31,278 $23,448 $23,448 $894 $15,765

TOTAL ENDING CASH (000) $38,725 $31,676 $27,122 $20,837 $20,837 ($2,818) $12,561

SOUTHWEST POWER POOLADMINISTRATIVE FEE HISTORY

$0.100

$0.150

$0.200

$0.250

$0.300

$0.350

$0.400

Budgeted NRR / Budget Load

Actual Admin Fee

Actual NRR / Actual Load

Budgeted NRR / Budget Load 0.175$ 0.177$ 0.183$ 0.197$ 0.170$ 0.205$ 0.229$ 0.253$ 0.338$ Actual Admin Fee 0.160$ 0.160$ 0.190$ 0.190$ 0.170$ 0.195$ 0.210$ 0.255$ 0.340$ Actual NRR / Actual Load 0.141$ 0.165$ 0.159$ 0.196$ 0.182$ 0.191$ 0.222$ 0.238$ 0.340$

2005 2006 2007 2008 2009 2010 2011 2012 2013

Budgeted Net Revenue Required 44,391$ 45,688$ 52,819$ 61,462$ 56,478$ 68,358$ 78,638$ 89,560$ 121,814$ Budgeted Load 253,489 258,556 288,649 312,496 331,360 333,458 343,000 353,453 360,915 Budgeted NRR / Budget Load 0.175$ 0.177$ 0.183$ 0.197$ 0.170$ 0.205$ 0.229$ 0.253$ 0.338$

Actual Admin Fee 0.160$ 0.160$ 0.190$ 0.190$ 0.170$ 0.195$ 0.210$ 0.255$ 0.340$

Actual Net Revenue Required 37,706$ 47,140$ 47,998$ 58,081$ 59,837$ 63,496$ 75,761$ 86,072$ Actual Load 267,239 286,446 301,098 296,135 328,175 331,610 341,440 361,011 Actual NRR / Actual Load 0.141$ 0.165$ 0.159$ 0.196$ 0.182$ 0.191$ 0.222$ 0.238$ Actual Revenue Recovery from 42,758$ 45,831$ 57,209$ 56,164$ 55,325$ 64,277$ 71,702$ 92,058$

Schedule 1A & Assessments

EIA-411 Load Growth Forecast 3.05% -0.60% 1.80% 2.10% 2.40% -1.00% 2.21%

Actual Load Growth 8.82% 7.19% 5.12% -1.65% 10.82% 1.05% 2.96% 5.73%

2005 2006 2007 2008 2009 2010 2011 2012 2013

2013 2012DESCRIPTION OF SERVICES BUDGET BUDGET Inc / (Dec) Description of 2013 Expense

Contract ServicesICT regulatory support, reimburseable -$ 1,125$ (1,125)$ ITC Contract expirationITO regulatory support - 165 (165) ITO Contract expiration

Total Contract Services -$ 1,290$ (1,290)$

Legal and regulatory support 3,706$ 5,338$ (1,632)$ Regulatory and legal support (lower due to permanent staff added in on-going effort to reduce outside consulting needs)

AdministrativeBoard of Directors Fees, audits, etc. 1,229$ 1,266$ (37)$ Board of Directors fees ($527); Boston Pacific ($200); Business Process Improvement

(BPI)audit of business continuity plans ($35); financial and benefit plan audits ($143); SSAE 16 audit ($325)

Corporate services 1,303 1,117 185 Campus maintenance vendors ($288); medical clinic ($265); Human Resource programs ($237); security ($206); compensation survey ($150); credit and system fees ($123); insurance fees ($115)

Communications and training 351 248 103 Training material development ($100) and transition of DTS to TTSE ($50); Human Resouce training programs ($71); various operator certification training ($68); miscellaneous communications services ($44)

SOUTHWEST POWER POOLOUTSIDE SERVICES BY BUSINESS FUNCTION

(in thousands)

($ )FERC Order 1000 235 - 235 New FERC requirement in 2013

Total Administrative 3,118$ 2,632$ 487$

Engineering & OperationsEngineering studies, planning 912$ 1,000$ (89)$ Planning ($467); Demand Side Management and PMU ($300); Eastern

Interconnect Planning Commission (EIPC) ($100); various other ($195)Engineering studies, ITO - 150 (150)$ ITO Contract expirationEngineering studies, reimbursable 600$ 840$ (240)$ GEN studies (decreased to to lower requests and more responsibilities assumed by

SPP staff)Engineering ITP, modeling, stochastic planning 324 225 99 Various planning and modeling consultantsOperations 150 - 150 IDC Reliability tool, a service formerly funded by NERC ($150)

Total Engineering & Operations 1,985$ 2,215$ (230)$

Integrated Marketplace 1,516$ 932$ 584$ Staff augmentation in Training ($654), Ops Performance Support training development ($452); MMU metrics for Marketplace ($250) SSAE 16 readiness assessment for IM ($250) (new to 2013)

2013 2012DESCRIPTION OF SERVICES BUDGET BUDGET Inc / (Dec) Description of 2013 Expense

SOUTHWEST POWER POOLOUTSIDE SERVICES BY BUSINESS FUNCTION

(in thousands)

Information TechnologyOATI Monthly service fee 1,395$ 1,271$ 124$ After hours monitoring of IT Command Center 305 360 (55) Operations Wind Forecasting Analysis 280 248 32 Misc. IT services (cabling, storage, asset disposal) 135 181 (46)

Total Information Technology 2,115$ 2,060$ 55$

Staff augmentationInformation Technology 1,621$ 1,992$ (371)$ Additional support for Keeping the Lights On projects (KTLO)PMO, Process Mgmt, Training - 477 (477) PMO augmentation in 2013 relates to IM capital expenseEngineering, ITP 140 - 140 Resources to address peak activity in ITPMarket Design 300 - 300 Modifications for protocols and tariff from FERC compliance orders and training

materialsTotal Staff Augmentation 2,061$ 2,469$ (408)$

Regional Entity hearings and audits 1,501$ 1,765$ (263)$

TOTAL SPP OUTSIDE SERVICES 16,003$ 18,700$ (2,698)$

SOUTHWEST POWER POOLINTEREST ON LONG-TERM DEBT

Actual Interest Payments: Current Budget:2013 Effect on Interest 2013 Effect on

Budget Admin Fee Capitalization* Budget Admin Fee

5.31% notes due 2014 475 0.001 475 0.0015.45% notes due 2016 1,035 0.003 1,035 0.0035.51% notes due 2027 217 0.001 217 0.0014.82% construction notes due 2042 3,115 0.009 3,115 0.0093.55% integrated markets notes due 2023 2,485 0.007 (2,485) (0) (0.000)3.00% capital funding notes due 2024 1,500 0.004 (239) 1,261 0.0033.25% capital funding notes due 2024 1,625 0.005 1,625 0.005

Total Interest $10,452 $0.029 ($2,724) $7,728 $0.021 * Capitalization of interest on long-term debt associated with the development of future markets results in a reduction to the admin fee of $0 021 This assumes the capitalized interest is not deemed to be impaired in a reduction to the admin fee of $0.021. This assumes the capitalized interest is not deemed to be impaired.

SOUTHWEST POWER POOLANALYSIS OF 2012 FEES & ASSESSMENTS

2012 2012 VarianceForecast Budget Fav/(Unfav) Note

SPP Regional Entity Revenue $9,722 $11,411 ($1,689)

Revenue for SPP RE is recognized as earned based on expense totals. In 2012, the RE expects to be favorable in comparison to their total expense budget, resulting in lower corresponding revenues.

FERC Fee Assessments (Sch.12) 16,597 15,120 1,477

FERC Fee Assessment revenue is recognized as collected. The Schedule 12 rate increased in 2012 but was not reflected in the 2012 budget due to timing iissues.

Fees & Assessments Revenue 26,319 26,531 (212)

Fees & Assessments Expense 14,977 15,410 433

FERC Fees & Assessments expense is estimated based on prior year assessment plus a growth rate. The current year run rate is adjusted once the annual bill is received in June, causing variance to budget.

Southwest Power PoolNet Revenue Requirement: Actual vs. Budget

For Years 2004 - 2012

$30,000

$50,000

$70,000

$90,000

Actual NRR

Budget NRR

Variance

2005 2006 2007 2008 2009 2010 2011 2012Actual NRR $37,706 $47,140 $47,998 $58,081 $59,837 $63,496 $75,761 $86,072

Budget NRR $44,391 $45,688 $52,819 $61,462 $56,478 $68,358 $78,368 $89,560

Variance ($6,685) $1,452 ($4,821) ($3,381) $3,359 ($4,862) ($2,607) ($3,488)(15%) 3% (9%) (6%) 6% (7%) (3%) (4%)

The graph and table above highlight the range of variance between SPP's actual and budgeted Net RevenueRequirement (NRR) by year. As SPP's NRR has increased over the years, the variances between actual andbudget remained relatively small.

($10,000)

$10,000

2005 2006 2007 2008 2009 2010 2011 2012

SOUTHWEST POWER POOLRATE SENSITIVITY TO LOAD VARIANCES

$0.310

$0.320

$0.330

$0.340

$0.350

$0.360

-6% -4% -2% 0% 2% 4% 6%

Recommended Admin Fee

Calculated Rate

Load Variance -6% -4% -2% 0% 2% 4% 6%Billing Determinants 339,260 346,478 353,697 360,915 368,133 375,352 382,570Year Ending Operating Cash $2,442 $3,236 $3,958 ($2,611) $3,344 $3,813 $4,210Over/(Under) Recovery at $.315 per MWh ($14,947) ($12,673) ($10,400) ($8,126) ($5,852) ($3,578) ($1,304)Recommended Admin Fee $0.350 $0.345 $0.340 $0.315 $0.325 $0.320 $0.315Calculated Rate $0.359 $0.352 $0.344 $0.338 $0.331 $0.325 $0.318

This graph depicts the impact on SPP's admin fee due to variances in expected billing determinants. SPP has estimated its billing determinants to be 360,915 MWh for 2013. With a Net Revenue Requirement (NRR) of $121,814, SPP recommends its administrative fee to be $0.315 per MWh resulting in an estimated year ending operating cash balance of ($2,611).

Assuming NRR remained the same and billing determinants were estimated at 368,133 MWh, a 2% increase, SPP would recommend an administrative fee of $0.325, but would have approximately $3,344 in operating cash at the end of 2013. If billing determinants were estimated at 375,352 MWh, SPP would change the adminstrative fee recommendation to $0.320 and would expect to have approximately $3,813 in operating cash at the end of 2013. The results are reversed if billing determinants are estimated at less than 360,915 MWh.

Southwest Power PoolComparison of Prior Year Budget Estimations

2008 2009 2010 2011 2012 2013 2014 20152008 2009 2010 2011 2012 2013 2014 2015

Net Revenue Required Estimations2008 Budget - NRR Estimations $61,462 $64,503 $71,1512009 Budget - NRR Estimations $56,478 $68,411 $75,0792010 Budget - NRR Estimations $68,358 $90,106 $94,8702011 Budget - NRR Estimations $78,637 $86,698 $94,6432012 Budget - NRR Estimations $89,560 $98,645 $113,6202013 Budget - NRR Estimations $121,814 $141,401 $145,024

Actual NRR $58,081 $59,837 $63,496 $75,761 $86,072

Billing Unit Estimations2008 Budget - Billing Units Estimations 312,498 319,058 325,7582009 Budget - Billing Units Estimations 331,360 346,434 353,3632010 Budget - Billing Units Estimations 333,458 338,060 342,7252011 Budget - Billing Units Estimations 343,000 345,039 349,8362011 Budget Billing Units Estimations 343,000 345,039 349,8362012 Budget - Billing Units Estimations 353,453 359,816 366,2922013 Budget - Billing Units Estimations 360,915 371,743 382,895

Actual Billing Units 296,135 328,175 329,626 341,440 361,011

Ad i i t ti F E ti tiAdministrative Fee Estimations2008 Budget - Admin Fee Estimations $0.190 $0.200 $0.2002009 Budget - Admin Fee Estimations $0.170 $0.170 $0.1702010 Budget - Admin Fee Estimations $0.195 $0.270 $0.2802011 Budget - Admin Fee Estimations $0.210 $0.255 $0.2802012 Budget Admin Fee Estimations $0 255 $0 280 $0 3002012 Budget - Admin Fee Estimations $0.255 $0.280 $0.3002013 Budget - Admin Fee Estimations $0.338 $0.380 $0.379

Actual Admin Fee $0.190 $0.170 $0.195 $0.210 $0.255

This table attempts to quantify the year-to-year changes in SPP’s three year projections made during each budget cycle as required by the membership agreement. Accuracy of these projections can be significantly This table attempts to quantify the year-to-year changes in SPP’s three year projections made during each budget cycle as required by the membership agreement. Accuracy of these projections can be significantly influenced by both internal and external pressures such as board and committee directives, incremental membership, environmental factors, etc.

Detailed Business Unit Strategic Objectives and Initiatives

Develop Efficient Market ProcessespOrg Strategic Objective or Initiative Timing

ALL Support the development, testing, training, implementation and operation of the Integrated Marketplace program. Mar. 2014

MD Provide QA function to assure Integrated Marketplace implementation is consistent with market rule intent. Ongoing L l/ C l ti f ll fili t hi FERC d St t l f th ti f th I t t d 2013 2014Lgl/Reg

Completion of all necessary filings to achieve FERC and State approvals for the operation of the Integrated Marketplace and the Consolidated Balancing Authority and make tariff revisions for implementation.

2013 - 2014

IT Provide Design, Integration, Testing, Trial and Deployment support for Integrated Marketplace systems. 2012-2014

IT Complete Data Center migration in a timely manner to enable Integrated Marketplace testing to occur without delay. State of the art data center will help ensure the high availability required for Marketplace operation.

2012

IT S t th R li bilit t l ti t t th C lid t d B l i A th it 2012 2014IT Support the Reliability systems evolution to support the Consolidated Balancing Authority. 2012-2014OPS Provide operational support of current EIS Market while supporting the testing, trials and organizational design to

support future operations.2012-2014

FIN Provide Settlements and Credit Risk design, testing and mock trial support and the organizational design to support future operations while supporting current Settlements/Credit processes.

2012-2014

Engr Support Integrated Marketplace through a implementation of the Transmission Congestion Rights (TCR) process 2012/ 2013Engr Support Integrated Marketplace through a implementation of the Transmission Congestion Rights (TCR) process. 2012/ 2013

PI Provide Project Management support for multiple Integrated Marketplace workstreams. 2012-2014PI Facilitate Market Participant on-boarding and support Customer Relations inquiries in preparation for IM go-live. 2012-2014

PI Design, develop and deliver customer training needed to prepare market participants for effectively utilizing the Integrated Marketplace

2012-2014Integrated Marketplace.

COM Support the Market Design to minimize opportunities for market manipulation and/or gaming and design, develop and implement Market Monitoring processes for the future environment.

2012-2014

COM Provide audit advisory services for SPP departments designing operations and processes for future operations. 2012-2014COM Provide Communications support for the Integrated Marketplace program. 2012-2014

COM I l t d t d f i li ith NERC St d d (t i l d CBA) d FERC 2012 2014COM Implement updated processes for ensuring compliance with NERC Standards (to include CBA) and FERC Compliance.

2012-2014

MD Review MPRR’s to assure that they are required and prioritized OngoingMD Provide support to Phase II enhancement of Marketplace functionality not included in Phase I scope. 2014-2015MD Participate in RTO Council/FERC initiatives to influence market policy/regulation supporting SPP Market

ff tiOngoing

effectiveness.COM Continue to monitor the EIS market and produce and Annual “State of the Market” report. Ongoing

Build a Robust Transmission SystemyOrg Strategic Objective or Initiative Timing

Engr On-time implementation of the Authorization to Plan (ATP) and Conditional Notifications to Construct (CNTC) processes.

WG 2012Impl 2013

E P I t f A t St di d G ti I t ti D 2012Engr Process Improvement for Aggregate Studies and Generation Interconnection studies.

Dec 2012

Engr Completion of ITP NT for 2013 Dec 2012

Engr Assess the potential benefits of incorporating Stochastic Modeling analysis into SPP Jun 2012Transmission planning processes.

Engr Enhance “Robustness” metrics to the value of ITP projects can be more quantitatively recognized.

Aug 2012

Engr Analyze how to incorporate anticipated regulatory changes (EPA regulations and C O )

Draft 2012FERC Order 100) into interregional planning and cost allocation methodologies. Final 2013

Lgl/Reg In conjunction with Engineering, support efforts to comply with multiple aspects of FERC Order 1000 – working with the RSC and SSC and other interregional partners in developing interregional planning and cost allocation. Support from a legal and

l t fili t d i t

Region Apr 12, Interreg Apr 13

regulatory filing standpoint.Engr Work with the Seams Steering Committee (SSC) to enhance our ability to understand

how cooperative efforts beyond our borders can be of benefit to our stakeholders.2012

Engr Completion of EPA ITP10 2012

MD Develop market design rules consistent with promoting/supporting the development of a robust transmission system.

Ongoing

PI Increase member participation and relationship development in industry events/committees impacting the robustness of inter-regional Transmission

Ongoing

systems.Lgl/Reg Provide the leadership to educate and facilitate processes to address issues related

to Regional Cost Allocation and Recovery.Ongoing

Create Member Value

Org Strategic Objective or Initiative TimingALL Implement the Integrated Marketplace program on time and within budget. Mar 2014

PI Implement an SPP-wide Business Process Improvement (BPI) capability that empowers SPP staff improve process ff ti lit d ffi i ( il t j t i 2012/2013 d SPP id i 2014)

2012/13 & 2014effectiveness, quality and efficiency (pilot projects in 2012/2013 and SPP-wide in 2014). 2014

ALL Improve support of Committees, Working Groups and Task Forces while implementing best practices for facilitation, communication and effectiveness.

2012

Engr Develop highly skilled and cross trained staff to provide support in multiple departments within Engineering. Sep 2012

Engr Develop and implement Engineering Resource and Work Planning processes. Sep 2012gOPS Automate the RTO Tariff and Scheduling functions and prepare for the consolidation of (2) operations desks into (1). 2Q13

PI Develop enhanced processes for planning and managing overall shared human resources (development and maintenance projects).

Req 2Q13Impl TBD

PI Increase member participation in the industry to better leverage SPP stakeholders to influence regulations/standards impacting them.

Ongoingregulations/standards impacting them.

PI/FIN Implement improved customer service processes and support technology to enhance effectiveness of stakeholder communications with SPP and increase customer satisfaction levels.

2012

PI Design/develop needed customer training solutions and deliver effective training programs. OngoingPI Update the SPP Member Value Statement and communicate it to staff and members to increase awareness of the

value of membership4Q12

value of membership.PI Create an ongoing program and processes to assure that SPP has a current and tested Business Continuity

capability to protect member assets.3Q/4Q12

MD Support the Western Interconnect interest in an energy market without endangering higher priority objectives. Aug 2012IT Complete the Data Center and Office Migration to the new SPP campus which will position SPP for more efficient July 2012

and effective operations.IT Implement an effective Enterprise Data Management solution – architecture, systems, processes and philosophies

to support the internal and external needs for storage, access, retrieval and analysis of data to create increased value for members.

2014

IT Continue to pursue multiple business process improvement and process automation initiatives to reduce cost, Ongoingreduce risk and increase efficiencies in IT.

Lgl/Reg Support SPP efforts to grow membership & support potential service expansion (WECC EIS market operation). Ongoing

Lgl/Reg Support initiatives to reduce costs and increase efficiencies through Business Process Improvement. 2012-2015

Create Member Value

Org Strategic Objective or Initiative TimingFIN Implement and Integrated Financial Planning/Reporting System 2Q13

FIN Improve processes for procurement and receiving. 3Q13

FIN Successful relocation of employees to new corporate campus. Jul 2012

FIN Continued improvement of Human Resource programs to support employee attraction, development, retention and support, including management training, career development, succession planning, and retirement planning.

Dec 2012 Ongoing

FIN Continued process improvement, efficiency and effectiveness of Settlements processes. 2012-2013FIN Assure SPP compliance with credit regulatory requirements 2013

COM Improve the user experience and value of spp.org Nov 2012

COM Engage with multiple elements of the SPP organization to increase the effectiveness of internal and external 2012g g gCommunications efforts to improve effectiveness.

COM Continue to improve Market Monitoring programs and effectiveness to assure that opportunities for market manipulation and gaming are minimized.

2012-2014

COM Provide member value by developing and maintaining a flexible Annual Audit Plan that addresses potential risk exposure for SPP.

2012-2015p

COM Assist SPP in achieving and sustaining SSAE audits without unmitigated exceptions and/or qualifications. 2012-2015

COM Continue to proactively provide Compliance support to members by establishing a Compliance Support site, Member Evidence review processes and sharing of best practices.

2012 Ongoing

COM Evaluate the feasibility of expanding Compliance Outreach Services to include Function Specific training, Mock 2012-2014COM Evaluate the feasibility of expanding Compliance Outreach Services to include Function Specific training, Mock Audits and Mitigation planning support.

2012 2014

COM Working with MCG, evaluate the feasibility of expanding the SPP role to support SPP Region NERC Registration Reviews.

2012-2014

COM Evaluate the feasibility of SPP leveraging economies of scale by becoming the Regional Compliance Department for members This could also expand to being a “contract service” for non-members

2013-2015members. This could also expand to being a contract service for non-members.

Mission: Keeping the Lights Onp g gOrg Strategic Objective or Initiative TimingOPS Enhance the Reliability Coordination function – develop and implement improved capabilities in

the areas of voltage, stability, and Var reserve assessments.1Q13

OPS Provide Reliability Coordination, Market Operation and related operational services while supporting the Integrated Marketplace development program and designing and preparing for the implementation of the Future State Operations organization.

2012-1Q14

OPS Continue to enhance the quality and reliability of SPP Operations by implementing an enhanced 2012Quality Assurance function.

PI Proactively participate in industry Reliability Standards development efforts to make sure that implementation creates the maximum value for stakeholders.

Ongoing

PI Create an ongoing program and processes to assure that SPP has a current and tested Business 3Q/4Q12PI Create an ongoing program and processes to assure that SPP has a current and tested Business Continuity capability to protect member assets.

3Q/4Q12

IT Maintain systems uptime – establishing a 24x7 Command Center to proactively monitor operations and manage issues, incidents and problems.

IT In conjunction with other SPP functions will evaluate and enhance SPP’s processes and OngoingIT In conjunction with other SPP functions, will evaluate and enhance SPP’s processes and procedures for responding to and recovering from cyber events.

Ongoing

COM Develop seasonal crisis communication readiness plans to support our effectiveness in “keeping the lights on”

Ongoing

COM Assist SPP management in formalization/maturation of SPP risk assessment/management processes.

2012-2013

2013 Budget

2004 2005 2006 2007 2008 2009 2010 2011

Operating Expense 36,410 48,374 64,922 84,507 99,238 117,530 115,844 128,016 Less

Depreciation 5,341 2,871 3,726 15,389 18,067 20,597 14,243 13,107 Impairment Loss 2,485 1,008 1,473 - - - - - FERC Fees - 8,226 10,384 9,112 9,525 13,104 14,101 16,639 Interest Income 306 945 1,172 1,360 648 305 56 157 Contract Serv ices - 182 4,684 16,170 19,032 22,705 23,251 26,549 NERC Revenue - 708 858 3,633 4,408 5,180 6,806 8,386 Miscellaneous 5,042 3,962 2,569 3,162 4,917 6,834 6,636 6,951

PlusPrincipal Payments 5,000 5,000 5,000 10,154 12,206 8,206 9,206 13,205 Interest Expense 5,170 2,382 2,089 2,155 2,756 2,879 3,619 6,307 Other Expense (1,338) (148) (5) 8 478 (53) (79) 21

Net Revenue Requirement 32,068$ 37,706$ 47,140$ 47,998$ 58,081$ 59,837$ 63,496$ 75,761$ Schedule 1A Revenue 36,836 42,758 45,831 57,209 56,164 55,325 64,277 71,702

Over/(Under) Collection 4,768$ 5,052$ (1,309)$ 9,211$ (1,917)$ (4,512)$ 781$ (4,059)$ Cumulative 4,768 9,820 8,511 17,722 15,805 11,293 12,074 8,015$ Admin Fee Impact 0.022$

Net Revenue Requirement Historical AnalysisCumulative Over 2005 - 2011


FINANCE COMMITTEE

Recommendation to the Board of Directors

October 30, 2012

2013 Budget


The following persons are members of the Finance Committee:

Harry Skilton Larry Altenbaumer Coleen Wells Mike Wise Sandra Bennett Kelly Harrison

Director Director Kansas Electric Power Coop Golden Spread Electric Coop American Electric Power Westar Energy

Background

Section 6.5 of the SPP Bylaws identifies establishment of annual and long‐term budgets as a primary duty of the Finance Committee.

Analysis

The Finance Committee met on September 13, 2012, September 24, 2012 and October 11, 2012 to review SPP’s proposed budget for 2013. SPP’s management proposed a 2013 budget to include expenditures as follows:

$000 Operating Expense (incl. dep. & am.) $162,626 Debt Repayment $12,700 FERC Assessments $16,340 Capital Expenditures $35,818

SPP management utilized a “zero‐based” budget approach to prepare the 2013 budget.

The most significant cost drivers for 2013 are the ramp up of resources to build, test, and ultimately operate the services described in the Integrated Marketplace project; the expected increase in occupancy related expenditures associated with the opening of SPP’s corporate campus; and the elimination of revenue associated with the LG&E contract. SPP expects to add 23 incremental staff positions during 2013 bringing total staff to over 600. SPP expects increased costs in the areas of meeting facilitation, travel, maintenance, and consulting to support the Integrated Marketplace project efforts.

Recommendation

The Finance Committee recommends the SPP Board of Directors approve the 2013 SPP operating and capital budgets as submitted provided that should the Stochastic Planning process not proceed thorough SPP’s stakeholder groups the budget for stochastic planning shall be removed from the 2013 budget. Additionally, SPP staff is directed to focus additional efforts on its business process improvement initiatives to accelerate recognition of cost efficiencies and shall report to the Committee the results of these enhanced efforts.

Approved: Finance Committee



FINANCE COMMITTEE


October 30, 2012

2013 Administrative and Assessment Fee Rate


The following persons are members of the Finance Committee:

Harry Skilton Larry Altenbaumer Coleen Wells Mike Wise Sandra Bennett Kelly Harrison

Director Director Kansas Electric Power Coop Golden Spread Electric Coop American Electric Power Westar Energy

Background

Section 8.4 of the SPP Bylaws requires SPP to annually develop an assessment rate based on budgeted expenditures for the upcoming fiscal year and estimated billing determinants for that year.

Analysis

The 2013 SPP operating budget indicates a net revenue requirement (“NRR”) for the year of $121.8 million and estimated billing determinants of 360,915,000 MWh. The rate is determined by dividing the NRR by the estimated billing determinants which results in a rate of 33.8¢/MWh. NRR is derived by adjusting SPP’s gross cash outflows (exclusive of capital expenditures) by all non administrative fee revenue forecast to be earned in the year. The billing determinants are calculated by analyzing the current year to date transmission usage and estimating usage through the remainder of the year.

SPP’s cash forecast indicates a rate of 31.5¢/MWh is sufficient to fully fund SPP’s operations during the 2013 year; and increase to 37.0¢/MWh in 2014 and 37.5¢/MWh in 2015. Funding requirements in 2013 and beyond are based on numerous assumptions, should real time experience differ meaningfully from these assumptions, SPP’s ability to operate at its current forecasted administrative fee may be jeopardized.

Recommendation

The Finance Committee recommends the SPP Board of Directors establish an assessment rate and tariff administrative fee (schedule 1‐A) of 31.5¢/MWh beginning on January 1, 2013.

Approved: Finance Committee


1

Finance Committee Report

October 30, 2012

Harry Skilton – Chair

SPP Finance Committee Roster

Harry Skilton, Chair Director

Larry Altenbaumer Vice Chair DirectorLarry Altenbaumer, Vice Chair Director

Mike Wise Golden Spread

Coleen Wells KEPCo

Sandra Bennett AEP

Kelly Harrison Westar

2

2

2013 Budget Assumptions

• Zero‐Based Budget

• ICT & ITO contract expirationsICT & ITO contract expirations

• Vacancy assumption of 6%

• Merit increases of 2.0%

• Promotions 0.75%

• Principal Repayments for 2013‐2015: $13, $23, & $24

3

p p y $ , $ , $

2013 Budget Metrics(In Millions of Dollars except Billing Determinants, Rates, and Headcount)

VariancesVariances2013 2012 2012 2012 2013Budget Budget Fcst Fcst to Bud Bud to '12Fcst

Gross Revenue Required $155 $146 $142 ($4) $13

Net Revenue Required $122 $90 $86 ($4) $36

Billing Units (Thousand GWh) 360.9 353.5 361.0 7.6 (0.1)

Calculated Admin Fee/GWh 33.8¢ 25.3¢ 23.8¢ (1.5¢) 10.0¢

Capital Expenditures $36 $82 $85 $3 ($49)

4

Year Ending Headcount 603 590 580 (10) 23

3

Net Revenue Requirement Components

Variances2013 2012 2012 2012 20132013 2012 2012 2012 2013Budget Budget Fcst Fcst to Bud Bud to '12Fcst

Operating Expenses $163 $152 $147 ($5) $16

+ Debt Service 13 11 11 (0) 1

‐ Depreciation and Amort (20) (17) (16) 1 (4)


‐ Fees & Assessments (28) (27) (27) 0 (1)

C t t S i R (1) (24) (24) (0) 23

5

‐ Contract Services Rev (1) (24) (24) (0) 23

‐ Other Revenues (4) (6) (5) 0 1


Operating Expenditure Components% Variances

2013 2012 2012 2012 2013Budget Budget Fcst Fcst to Bud Bud to '12Fcst

S l & B fi $77 $72 $72Salary & Benefits $77 $72 $72 0% 7%Assessments & Fees 16 15 15 ‐3% 9%Services 16 19 15 ‐18% 4%Depreciation & Amort 20 17 16 ‐5% 24%Other 33 28 28 ‐1% 16%

Operating Expenses $163 $152 $147 ‐3% 11%

� Salary and Benefits increases:

6

� y � 23 incremental staff positions � Claims experience for health benefits � Changes for pension valuation� ICT and ITO positions absorbed to support RTO� Increased interest expense for add'l financing� Maintenance for corp campus and new market systems

4

Incremental Positions

7

Administrative Fee Proposal(In Millions of Dollars except Units and Fees)

Variances2013 2012 2012 2012 20132013 2012 2012 2012 2013Budget Budget Fcst Fcst to Bud Bud to '12Fcst



Billing Units (Thousand GWh) 360.9 353.5 361.0 7.6 (0.1)

Calculated Admin Fee/GWh 33.8¢ 25.3¢ 23.8¢ (1.5¢) 10.0¢

Capital Expenditures $36 $82 $85 $3 ($49)

Year Ending Headcount 603 590 580 (10) 23

8

g ( )

Actual Approved / Proposed Fee 31.5¢ 25.5¢ 25.5¢ 6.0¢

5

Comparison of Prior Year Budget Estimates

Administrative Cost Projections

Budget Year 2008 2009 2010 2011 2012 2013 2014 20152008 Budget 19.7¢ 20.2¢ 21.8¢2009 Budget 17.0¢ 19.7¢ 21.2¢2010 Budget 20.5¢ 26.7¢ 27.7¢2011 Budget 22.9¢ 25.1¢ 27.1¢2012 Budget 25.3¢ 27.4¢ 31.0¢2013 Budget 33.8¢ 38.0¢ 37.9¢

9

gActual Cost per MWh 19.6¢ 18.2¢ 19.1¢ 22.6¢ 23.8¢ 33.8¢Approved Admin Fee Rate 19.0¢ 17.0¢ 19.5¢ 21.0¢ 25.5¢ 31.5¢

Changes from 2012 Budget Projections for 2013

% of Change

Admin Fee Impact

NRR 2013 Prior Projection * $98.6 27.4¢

Reduction in ICT Revenues $18.5 80% 5.1¢Increase in NERC and FERC Funding (0.7) (3%) (0.2¢)Net Changes in Revenue 17.8 77% 4.9¢

Increase in Interest Expense 3.7 16% 1.0¢Changes in Benefits & Employee Healthcare 1.7 7% 0.5¢Property Tax Increase 0.8 3% 0.2¢Communications & Maintenance 0.6 3% 0.2¢

10

Services Decrease (1.7) (7%) (0.5¢)Misc Other 0.2 1% 0.1¢Net Changes in Expenses $5.3 23% 1.5¢

NRR 2013 Budget $121.8 100% 33.8¢

* Calculated NRR from 2012 Budget Projections for 2013

6

RTO Comparison

Cost per MWh RTO Staffing Levels

$0.00

$0.20

$0.40

$0.60

$0.80

$1.00

$1.20

$ pe

r MWh

0

100

200

300

400

500

600

700

800

# of Employee

s

11

SPP’s costs and staffing estimates are based on 2014 budget projections to reflect full market functionality. Other RTOs are based on their 2012 budgets.

SPP Staffing Trend

700Year Ending Headcount

2009 2010 2011 2012 2013 2014 2015400450500550600650

12

Average tenure for SPP staff for 2011‐2013 is:5.4yrs, 5.6yrs, and 5.8yrs, respectively

2009 2010 2011 2012 2013 2014 2015Total 423 458 540 580 603 618 622

7

Capital Expenditures

$80$90

Capital Expenditures

2010 2011 2012 2013 2014 2015$0

$10$20$30$40$50$60$70$80

13

Total CapEx Spend $22 $79 $85

Integrated Marketplace $22 $4 $0

Marketplace 2.0 $2 $10 $1

IT Hardware Refresh $7 $4 $6

New Projects '13‐'15 $1 $3 $7

Other $4 $2 $1

Existing Principal Payment Obligations

$20

$25

$5

$10

$15

14

$02012 2013 2014 2015 2016 2017 2018

Integrated Marketplace Corporate Campus Other CapEx

EIS Market Maumelle Facility Marketplace & Future CapEx

8

SPP Administrative Fee History & Projections

$0.350

$0.400

$0.150

$0.200

$0.250

$0.300

15

$0.100

$

2010 2011 2012 2013 2014 2015 2016 2017

Budgeted NRR / Budget Load Actual Admin Fee Actual NRR / Actual Load

Resulting Initiatives:

• Re‐energize the Business Process Improvement ProgramProgram

• Reconsider staffing increases at Quarterly Reviews in 2013

• Develop in year “scorecard” to measure financial impact of member initiatives

i h i d i

16

• Investigate approach to recognize expected increases in staff efficiency in future budgets

9

SPP Finance Committee 2013 Budget

Finance Committee Recommendations

Approve the 2013 SPP operating and capital budgets as submitted.

Establish an assessment rate and tariff administrative charge rate (schedule 1A) of 31.5¢/MWh effective January 1, 2013.

17

Questions and Discussion

18

10

Changes from 2012 Forecast to 2013 Budget% of

ChangeAdmin Fee Impact

NRR 2012 Projection $86 23.8¢

Increase in Billing Determinants 0.4¢ICT & ITO Contract Revenues $24 68% 6.5¢Studies decrease 2 5% 0.5¢2012 FERC Penalty Settlement (1) (3%) (0.3¢)Increase in NERC and FERC Funding (1) (4%) (0.4¢)Net Changes in Revenue $23 66% 6.7¢

Salary & Benefits 5 15% 1.4¢Maintenance, Facility and Market 2 6% 0.6¢Increased Interest, Capitalized Interest 2 7% 0.7¢

19

pFERC Assessment Increase 1 4% 0.4¢Property Tax, Utilities Increase 1 3% 0.3¢Services Increase 1 2% 0.2¢Lease Terminations (1) (4%) (0.3¢)Net Changes in Expenses $12 34% 3.2¢

NRR 2013 Budget $122 100% 33.8¢

SPP Administrative Fee History & Projections

2007 2008 2009 2010 2011 2012 2013Budgeted Net Revenue Required $52.8 $61.5 $56.5 $68.4 $78.6 $89.6 $121.8Budgeted Load 288.6 312.5 331.4 333.5 343.0 353.5 360.9 Budgeted NRR / Budget Load 18.3¢ 19.7¢ 17.0¢ 20.5¢ 22.9¢ 25.3¢ 33.8¢

Actual Admin Fee 19.0¢ 19.0¢ 17.0¢ 19.5¢ 21.0¢ 25.5¢ 31.5¢

Actual Net Revenue Required $48.0 $58.1 $59.8 $63.5 $75.8 $86.1Actual Load 301.1 296.1 328.2 331.6 341.4 361.0 Actual NRR / Actual Load 15.9¢ 19.6¢ 18.2¢ 19.1¢ 22.2¢ 23.8¢

d h

20

EIA‐411 Load Growth Forecast 1.8% 2.1% 2.4% ‐1.0% 2.2%

Actual Load Growth 5.1% ‐1.6% 10.8% 1.0% 3.0% 5.7%

11


Net Revenue Required Projections

2008 2009 2010 2011 2012 2013 2014 20152008 Budget ‐ NRR Estimations $61 $65 $712009 Budget ‐ NRR Estimations $56 $68 $752010 Budget ‐ NRR Estimations $68 $90 $952011 Budget ‐ NRR Estimations $79 $87 $952012 Budget ‐ NRR Estimations $90 $99 $1142013 Budget ‐ NRR Estimations $122 $141 $145

21

Actual NRR $58 $60 $63 $76 $86


Billing Unit Projections

2008 2009 2010 2011 2012 2013 2014 20152008 Budget ‐ Billing Units 312 319 3262009 Budget ‐ Billing Units 331 346 3532010 Budget ‐ Billing Units 333 338 3432011 Budget ‐ Billing Units 343 345 3502012 Budget ‐ Billing Units 353 360 3662013 Budget ‐ Billing Units 361 372 383

22

Actual Billing Units 296 328 330 341 361

12

2013 Budget

• Significant Increase In The Administrative Fee i 2013in 2013

Drivers:

• Expiration Of The ICT And ITO Contracts

• Increased Headcount To Meet The Integrated Marketplace Requirements

23

Marketplace Requirements

2013 Budget

Significant Issues……….….Going Forward

• Implementation Of Integrated Marketplace

• Transitioning Of The ICT/ITO Personnel

• Business Process Improvement

• Low hanging fruit has been taken

24

• Slow down due to market implementation priorities

1

MOPC Report to Board of Directors / Members CommitteeOctober 31, 2012

Todd Fridley – Vice‐Chair

• Action Items

– MWG ‐MPRR090 –

• Information Items

– MWG – Integrated

Agenda

Establish Market Hubs

– RTWG – TRR077 –Compliance w/ Order 1000

– CBASC – CBA Agreement

Marketplace Software Change

– Balanced Portfolio

– Probabilistic Planning

• Consent Agenda– ESWG – Metrics for RCAR

– Staff

Aggregate Study Waivers

Project Tracking Review

2

2

Action Items

3

MWG

4

3

MPRR90—Market Hubs Establishment

• Establishes the rules of Market Hubs and the addition of new hubs (Resource Hubs, Trading Hubs)

– North and South Hubs have been analyzed.

• MWG approved with modifications 9/18/2012 (One abstention, SPS)

• ORWG approved with no Reliability impact on 10/4/2012

• MOPC approved MPRR90 and the establishment of the North and South Hubs for market trials, pending RTWG with 4 No votes (Westar, KG&E, KPP, and SWEPCO)

• MOPC recommends the BOD approve MPRR90 and the tariff languages changes.

5

RTWG

6

4

TRR 077 ‐ Order 1000 Compliance Filing

• Recognize the hard work to accomplish the filing:

– Order 1000 Drafting Task Force

Worked with Staff and W&T to get draft Tariff changes to RTWG

Charles Locke, David Kays, Paul Malone, Terri Gallup, Dennis Reed, Susan Polk, Brenda Fricano, Matt Binette

– RTWG – met weekly for two days starting in late July for 5 weeks with at least one conference call per week

Rich Andrysik, Luke Haner, Tom Hestermann, Robert Jansen, David Kays Lloyd Kolb Tom Littleton Bernie Liu Charles Locke PaulKays, Lloyd Kolb, Tom Littleton, Bernie Liu, Charles Locke, Paul Malone, Robert Pennybaker, Dennis Reed, Neil Rowland, Keith Tynes, John Varnell, Bary Warren, Mitch Williams, Brenda Fricano, Susan Polk

Other Participants: Terri Gallup, Kip Fox, Steve Gaw, Dave Litton, Matt Binette, Walt Cecil

7

Impacts of Order 1000• Order 1000 impacts transmission planning and who builds approved projects

(Reinforces Order 890)

• SPP already met most of Order 1000 requirements (i.e. regional planning andSPP already met most of Order 1000 requirements (i.e. regional planning and cost allocation)

• Requires elimination of the Federal Right of First Refusal (ROFR) for any projects approved through a regional plan for purposes of regional funding

– Elimination of the ROFR is not universal

– Affects new lines over new right‐of‐ways (“green field” projects)

– ROFR is retained for most projects (Upgrades/ or rebuilds of existing facilities)

If required by State or local laws

Does not receive Regional Funding (i.e. multi zonal)

• Must include Public Policy as a “need” in the planning process

– Already in ITP process, but concept is reinforced

– Clarify that Public Policy requirements are included in local planning

8

5

Tariff Goals

• To implement policies approved by the BOD

– SPC Final Report – April 2012

– SPC 2nd Final Report – July 2012

SPP Proposal for Transmission Owner Selection Criteria

Order 1000 Financial Requirements ‐ Finance Committee

• The RTWG did change some of the terminology for Tariff purposes – References to entities that applied or were qualified to participate in the RFP process as “TOs” couldqualified to participate in the RFP process as TOs could be confusing

– Applicant TO (ATO) = Applicant

– Qualified TO (QTO) = Qualified RFP Participant (QRP)

– Selecting a DTO = Selecting an RFP proposal9

What you won’t see in the Tariff Language

• Many details in implementation issues in the SPC papers reports were not included in the Tariff excluded

– Tariff only contains deals with the “Rates, Terms and Conditions” for transmission service

– Additional Details will need to be put incorporated into Business Practices

Detailed Project Proposals (create new process)

TO Selection (remove current BP and create new)

QRP details | IEP grading details | RFP details | Selection results

NTC and Project Cost Tracking (reviewed for impacts)

• BPWG has action item to develop BPs 10

6

Order 1000 Process

G ti

ITP

C t Si

BOD Approves Projects

Host TO builds and

Does the Project meet criteria?

TO(s) Selected TO S l ti

Y

N

TransmissionService

GenerationInterconnect

Customer Signs Agreement

Customer Signs Agreement

NTC (s) issues as needed (ROFR)

Host TO builds and NTC(s) issued as needed (ROFR)

Is NTCC Needed?

NTCC issued

( )using current process (ROFR)

TO Selection Process

Y

N

Sponsored Projects

Sponsor Agrees to pay

All Projects Published in STEP

NTC issued

11

Project Tracking

Cost OK?

Review Project‐Still proceed?

Cancel Project

Y

Y

N

N

Attachment O

Sections I and IIOpening and general information

Section IIIITP Planning

Attachment Y:Transmission Owner Designation Process

Section I: OverviewDescribes the subsequent Sections of the AttachmentsDefines which projects go through TO Selection Process in Section IIIAll other projects go through Incumbent TO process Section IV

Section II: Definitions

ITP Upgrades

ondi

tion

ion

Tariff MapTariff Map

Section VSTEP Report and approval /

gPublic Policy requirementsITP and Local Area Planning

Section III.8 (b)Detailed Project Proposal

** NEW **

Section IVOther Planning Processes

Section III: TO Selection Process for Competitive Upgrades

Qualification ProcessSelection Process/RFP/Scoring

Incentive Points (Detailed Project Proposal)Selected DTO can not assign project Default by DTO

Section IV: Incumbent TO Selection ProcessBasically, current Attachment O, Section VI.6 language.Maintains ability of TO to assign a project

GI UpgradesWhen needed

QRP can getIncentive pointsFor DPP Mee

ts c

o

Doe

s no

t Mee

t con

diti

etsp pp

endorsement of projects

Remaining Sections VII to XI

12

Section VIConstruction of Transmission

Facilities(Parts moved to Attachment Y)

Maintains ability of TO to assign a project

Section V: Notification to ConstructBasically the same as in current Tariff, Attachment O, Section VI.6All entities being assigned a project through either Section III or Section IV will get an NTCDefines an NTC for a cost estimate

Section VI: Project Tracking ProcessAll projects are tracked by the TPProject costs changes are reported

Sponsored UpgradesWhen needed

Sele

cted

ent

ity g

eAn

NTC

7

TRR077 Recommendation

• Passed unanimously by the RTWG at its October 4 conference call

• MOPC approved with one abstention (SPS)

• MOPC recommends approval of TRR077 for filing at FERC.

• SPP Reviewing Order 1000‐B to see if there are any issues with the filing materials.ssues t t e g ate a s.

13

CBASC

14

8

CBA Agreement

• CBASC asked a Legal Task Force to address member changes to the Agreement

• MOPC approved positions on two issues:

– Accept the LTF recommendation on indemnification (79.7%)

– Leave language in Section 10 as presented, with application of penalties through Attachment AP.

• MOPC recommends that the BOD approve the CBA Agreement

15

ESWG

16

9

Metrics for use in RCAR

• Regional Cost Allocation Review (RCAR) Timeline:

– September 2012: scoping and preparation for the p p g p preview

– Today: formal approval of metrics

– January 2013: draft Regional Cost Allocation Review report

– July 2013: Regional Cost Allocation Review completey g p

17

Benefits identified by the RARTF

• APC Benefit Enhancements

• Positive Impact on Capacity Required for Lossesp p y q

• Improvements in Reliability

• Remedy Benefits

• Reduction in Emission Rates and Values

• Reduced Operating Benefit

• Improvements to Import Export Limits

• Public Policy Benefits

18

10

Recommended Metrics

• At least one metric has been developed for each of the benefits

• Five (5) metrics currently used by the ITP process

– Minor improvements only

• Eight (8) new metrics developed by the ESWG

– Capture monetary value of transmission expansion

• Eight (8) other metrics considered

– Not ready for “prime‐time”

19

Overview of benefits & metrics

Benefit MTF Metric NameCurrent or New?

APC benefits Adjusted Production Cost (APC)

Marginal energy losses benefits

Mitigation of transmission outage costs

Positive impact on capacity required

Reduced capacity expansion costs due to capacity required

for lossesreduced transmission losses on peak

20

Current metric used in the ITPMTF recommended new metric

11



Improvements in reliability

Avoided or delayed reliability projects

Capital savings due to reduction of members’ Minimum Required Capacity Margin

Reduced loss of load probability

Reducing the cost of extreme events

Assumed benefit of mandated reliability projects

21




Reduction of Emission Rates and Values

Reduction of emission rates and values

Reduced Operating

Reserves Benefits

Savings due to lower ancillary service needs and production costs

*

Improvements to Import/Export

Increased wheeling through and out Import/ xport

Limitsrevenues

Public Policy Benefits

Benefit from meeting public policy goals

22


* MTF has made improvements

12

Metrics for RCAR Recommendation

• ESWG approved on 9/13/2012, the Metrics Task Force report as amended by the ESWG in response to the request from the RARTF and further offers the developed metrics for use in whole or in part in the Regional Cost Allocation Review.

• MOPC approved the Metrics Task Force report and instructs SPP staff to use all of the metrics listed in the RCARRCAR.

• MOPC recommends that the BOD approve the use of all the metrics listed in the RCAR.

23

STAFF

24

13

Neligh Transformer

• Approved in 2012 ITP10

– Part of Neligh to Hoskins 345 kV project

– 2019 need date

• 345/115 kV

E t d E&C C t• Expected E&C Cost: $5,244,000

25

Waiver Request

• Neligh 345/115 kV transformer

– Predominate flows from low to high voltageg g

• MOPC approved with one abstention (SPS)

• MOPC recommends that the BOD approve the NPPD requested waiver for Base‐Plan Funding of the Neligh 345/115 kV transformer

26

14

3rd Quarter Project Tracking Review

• Altoona East Cap bank still needed

• MOPC approved un‐suspending the NTC unanimouslypp p g y

• MOPC recommends that BOD un‐suspend the NTC for the Altoona East Cap bank.

27

4th Quarter Project Tracking Review

• Afton Transformer 161/69 kV (GRDA)

– Staff recommended suspending the NTC and to p gcomplete re‐evaluation in January 2013 ITPNT

– MOPC approved to suspend uanimously

– MOPC recommends the BOD suspend the Afton Transformer NTC for re‐evaluation.

• No NTC modification or re‐evaluationHeizer – Mullergren 115 kV Tie Line (MIDW)

Kinsley Capacitor 115 kV (MIDW)

Pawnee Capacitor 115 kV (MIDW)

28

15

Information Items

29

MWG

30

16

ARR Self Conversion Software Change

• Testing during and after Mock TCR Auction revealed that current ARR Self Conversion design may expose ARR holders to uplift

• MWG discussed three options to correct the problem:

– Lower the minimum bid limit

– Treat ARR self conversion as pre‐injection with limit expansion if necessary

– Perform a pre‐run to ensure self‐convert feasibility using the minimum obligation of ARR clearing

• MWG recommend and MOPC approved Option 3, the TCR software change and a $40k cost.

31

Integrated Marketplace Deployment Settlements Approach• Integrated Marketplace Parallel Operations Testing scheduled

for November 2013 to January 2014

• During Parallel Operations testing, Marketplace systems will operate as a single Balancing Authority– Operate in parallel with the EIS Market for a minimum of five separate

deployment test periods

– Length of time for each test period is a minimum of two hours

• Goal of each deployment test is to:O h M k l RTBM i h i

32

– Operate the Marketplace RTBM with no issues

– Prove that SPP and Member systems/interfaces work as intended

– Perform the Balancing Authority function through successful regulation deployment

• Readiness goal is to have one successful deployment test per month

17

Integrated Marketplace Deployment Settlements Approach

• Settlement assumptions:– EIS Market will continue to operate normally during all p y gParallel Operations tests

• LIPs will be calculated based on EIS Market Resource Offers

• EIS Market LIPs will be used for all Energy Settlement during deployment tests

– EIS RSS will continue to create RSS schedules if an actual RSS Event occurs during a deployment test.

33

– Uninstructed Resource Deviation penalties will not apply in the EIS Market Settlements during deployment tests.

• MOPC approved the Integrated Marketplace Deployment Settlements Approach

BALANCED PORTFOLIO

34

18

Balanced Portfolio

• Portfolio of economic upgrades

– 300 kV or higher g

• Net benefits to entire SPP region

– 10‐year Economic Analysis

– B/C ≥ 1.0 held for each transmission owner

– Balance can be achieved through revenue adjustments

– Projected study benefits held fixed

35

Portfolio 3‐E Adjusted

‐12.5%19.0%

$692M

75.0%

46 1%

‐3.9%

86 5%

36

46.1%

36.5%

86.5%

19

Balance Portfolio PV over 10 Year ATRR Cost Estimates and Transfers ‐ Current Cost Estimates

Zone PortfolioBenefits

Portfolio 10 Year ATRR

B/CBefore

Transfer ATRR Cost from Zones

Allocation of Regional

ATRR

Net Benefit after

Allocation of B/C After Transfers

(in millions)

Benefits Costs Transfers from Zonesto Region Transfers to

ZonesATRR

Transfers

Transfers

AEPW $224.2 $192.5 1.2 $92.7 $124.5 $0.0 1.0EMDE ($2.5) $22.6 (0.1) $39.6 $14.6 $0.0 1.0GRDA $6.2 $16.7 0.4 $21.4 $10.8 $0.0 1.0KCPL $60.8 $66.1 0.9 $48.1 $42.8 $0.0 1.0MIDW $95.7 $6.2 15.5 $0.0 $4.0 $85.6 9.4MIPU ($11.7) $34.7 (0.3) $68.7 $22.4 $0.0 1.0MKEC $86.9 $9.6 9.1 $0.0 $6.2 $71.1 5.5OKGE $193.1 $121.4 1.6 $6.8 $78.5 $0.0 1.0SPRM ($1.0) $13.3 (0.1) $22.9 $8.6 $0.0 1.0SUNC $24.2 $9.1 2.6 $0.0 $5.9 $9.1 1.6SWPS $406.8 $98.8 4.1 $0.0 $63.9 $244.0 2.5WEFA $57.9 $27.1 2.1 $0.0 $17.5 $13.3 1.3WRI $106.7 $98.9 1.1 $56.1 $64.0 $0.0 1.0

NPPD $40.3 $68.6 0.6 $72.7 $44.4 $0.0 1.0OPPD $15.9 $53.2 0.3 $71.7 $34.4 $0.0 1.0LES ($25.3) $16.4 (1.5) $52.3 $10.6 $0.0 1.0Total $1,278.4 $855.3 1.5 $553.1 $553.1 $423.1 1.5 38

20

Balanced Portfolio Review ‐ Conclusions

• PCWG determined that project costs have stabilized

– All line projects have established routes (highest cost p j ( grisk)

• Overall B/C ratio for the portfolio remains on track for a relatively high 1.5 value

• Revenue transfers continue as tariff provisions have outlined for the portfolio

• MOPC discussed whether the analysis meets tariff review criteria

• MOPC took no further actions at this time.

39

STAFF

40

21

What is Probabilistic Planning?

• Transmission planning methodology that utilizes statistical analysis to quantify the inherent uncertainty of variables used in power system analysis

– Range of values for study parameters (load, price, variable generation)

– Determine ‘likelihood’ and ‘consequence’

– Quantify cost of an unreliable system

– Enhanced data to improve confidence in decision making

41

Probabilistic Planning Value

Optimization: Avoid under/over building transmission

42

22

Implementation Level Estimated CostsLevel Cost Type Cost to Implement (k$) Cost to Operate (k$)

Level 1: Labor 205 205

Capital Expenditure 70 30

Phase 1 Total 275 235

Program Total: 275 235

Level 2: Labor 417 417




Phase 3: Labor 417 417


Consulting 350 200



43

Estimated Benefits

• Benefits estimated annually over 10 years with 8% discount rate

• Assumed $27.5M pool of funds saved

• Annual access of 0‐10% of pool funds based on program level implemented and years of maturity

• Maximum of 10% of funds accessible annually

• Cumulative NPV of benefits is calculated for each• Cumulative NPV of benefits is calculated for each program year

44

23

Implementation Level Benefit/Cost Ratios

3

3.5

Conservative Comprehensive Cutting‐edgeLevel 1 Level 2 Level 3

1

1.5

2

2.5

3

45

0

0.5

Year 2012‐13

Year 2013‐14

Year 2014‐15

Year 2015‐16

Year 2016‐17

Year 2017‐18

Year 2018‐19

Year 2019‐20

Year 2020‐21

Year 2021‐22

Phased Level 1 Implementation Plan

• Phase 1: January – December 2013Research and Process Development

Minimal Stakeholder Engagement

• Phase 2: January – December 2014

– Pilot studies of processes and techniques

– Moderate Stakeholder Engagement

MOPC d d th d l t f th b i• MOPC endorsed the development of the business case for the probabilistic planning case with budget expenditures for 2013 with third parties to be approved by the MOPC.

• Budgeting will include Phase 1 only for the present.46

24

Probabilistic Planning Research Project

• Collaborated with consultant (PowerTech Labs Inc.)

• Developed probabilistic planning implementation plan

– Primary focus on probabilistic aspects of:

Production cost modeling

Transmission reliability assessment

– Additional considerations for:

Data, tools, resources, stakeholders

Phases, tasks, schedule, roles

Cost‐benefit analysis, budget & resource requirements

47

Project Cost Base Lining

• Study estimate provided at time of project approval

– Expected final cost is +30%

― Projects >$20M and >100kV issued with condition

― All others issued with no conditions

• NTC Project (NPE)/NTC‐C Project (CPE)

― Expected final cost is +20%

/― submitted by DTO in response to CNTC/NTC issuance

― established as baseline for project cost variance

48

25

Study Estimate: $25,845,600

Auburn Road CPE Evaluation

$25.8 M $33.6 M$18.1 M

$32,211,913

$32.2 M $38.7 M

NTC‐C Project Estimate:

30%30%

$25.8 M

49

SPP Re‐evaluation and BOD ReviewAction:

This is a product of the business practice developed by the PCWG

2012 ITP NTC Projects

Total Study Estimate Cost (BOD Approved) $203,424,788

Total NPE Cost $266,026,915

Percent Increase 30.77%

Total Number of NTC Projects 38

50

NPEs Over Bandwidth 13

NPEs Under Bandwidth 5

NPEs Within Bandwidth 20

26

NPEs Exceeding BandwidthProject Owner Study NPE Variance % Variance

Curry ‐ Bailey 115kV SPS $9,132,270 $35,099,588 $25,967,318 284.35%

Kress Interchange ‐ Kiser ‐ Cox 115 kV SPS $20,188,805 $29,272,481 $9,083,676 44.99%

Project Owner Study NPE Variance % Variance



Project Owner Study NPE Variance % Variance



Ellsworth ‐ Bushton ‐ Rice 115 kV MKEC/MIDW $19,459,597 $27,485,183 $8,025,586 41.24%

Bowers ‐ Howard 115 kV SPS $17,407,520 $23,709,821 $6,302,301 36.20%

Haggard ‐ Ingalls 115 kV Ckt 1 MKEC $12,530,103 $23,377,556 $10,847,453 86.57%

Cedar Lake Interchange 115 kV SPS $10,027,742 $13,224,520 $3,196,778 31.88%

Move lines from Lea Co. to Hobbs 230/115 kV SPS $8,270,297 $10,608,509 $2,338,212 28.27%

Convert Muleshoe East 69 kV to 115 kV SPS $1,634,119 $4,673,759 $3,039,640 186.01%

Drinkard 115 kV Capacitor SPS $1,349,807 $2,225,089 $875,282 64.84%













51

Drinkard 115 kV Capacitor SPS $1,349,807 $2,225,089 $875,282 64.84%

Bushland Interchange 230 kV Capacitor SPS $1,071,475 $1,714,505 $643,030 60.01%

Line ‐Maid ‐ Redden 69 kV GRDA $1,092,500 $1,419,469 $326,969 29.93%

Maid ‐ Pryor Foundry South 69 kV GRDA $1,064,300 $1,374,534 $310,234 29.15%

Kolache 69 kV Capacitor OGE $440,081 $523,888 $83,807 19.04%

SPP Staff re‐evaluating projects as part the 2013 ITP Near‐Term study process

8 projects selected for re‐evaluation

Preliminary review of 3 projects indicated continuing need

NPEs Under Bandwidth

Project Owner Study NPE Variance%

Variance

Randall County Interchange ‐South Georgia Interchange 115 kV

SPS $6,921,313 $3,618,651 ($3,302,662) ‐47.72%

Eddy County Interchange 230/115kV Transformer

SPS $6,761,086 $4,863,725 ($1,897,361) ‐28.06%

Hereford Interchange ‐ Northeast Hereford Interchange 115 kV

SPS $5,631,390 $4,139,406 ($1,491,984) ‐26.49%

Crosby 115 kV Capacitor SPS $1,336,466 $985,519 ($350,947) ‐26.26%

Lula 69 kV Capacitor OGE $605,551 $377,797 ($227,754) ‐37.61%

33

27

Consent Agenda Items

53

MWG

54

28

PRRs – Integrated MarketplaceMPRR74—DVER Clarification• MPRR 74 clarifies that Dispatchable Variable Energy Resources are not

eligible for Up products but are only eligible for Regulation‐Down

• It further clarifies that the dispatch flag will be set to “ignore” by default

– Dispatch flag will be set to “follow” if the DVER is dispatched below its max operating limit or if it is cleared for Regulation‐Down.

• “Nameplate Maximum” is changed to “Emergency Maximum Capacity Operating Limit”

• Working Group Voting Results

– MWG unanimously approved on June 20, 2012.

– RTWG approved with modifications on July 25, 2012.

– ORWG approved July 26, 2012.

• MWG recommends that the MOPC approve MPRR74.55

PRRs – Integrated MarketplaceMPRR76—Clarification on How to Handle Not Participating

Resources in RTBM• MPRR 76 clarifies that MPs with Resources with a Commitment Status of

“Not Participating” in the Day‐Ahead Market who apply that offer to the Real‐Time Balancing Market will have their offer rejected

– The MP must submit a new, valid offer


– MWG unanimously approved on June 20, 2012.

– RTWG approved with modifications on July 25, 2012 and approved with pp y , ppmodifications again September 26, 2012.

– ORWG approved on July 26, 2012.

• MWG recommends that the MOPC approve MPRR76.

56

29

PRRs – Integrated MarketplaceMPRR77—New Charge Types for Settlement of Demand

Reduction (FERC Order 745)• When Demand Response is dispatch‐effective and cost‐effective then p p

demand Response must be compensated at LMP.

• MPRR 77 adds charge types to provide host load demand reduction credits.

– It allocates the cost of these credits on a system‐wide basis.

– It allocates the costs to Load Serving Entities based on load ratio share.


MWG d ith difi ti A t 14 2012 ith iti– MWG approved with modifications on August 14, 2012 with one opposition (Midwest) and one abstention (Tenaska).

– Pending RTWG approval.

– ORWG approved with no Reliability Impact on September 12, 2012.

• MWG recommends that the MOPC approve MPRR77 pending RTWG approval. 57

PRRs – Integrated MarketplaceMPRR86—XML Instructions Clarification• MPs must have capability to receive and follow XML instruction in case all

ICCP connections go down.

– MPRR 86 clarifies that, in case of ICCP failure, XML will be used as backup.

– Energy only will be communicated via XML.

Operating Reserve events will be communicated manually through Out‐Of‐Merit instructions.

– MPs are not required to integrate XML with their system controls.


– MWG approved on July 24, 2012.

– RTWG approved with no Tariff implications on September 26, 2012.

– ORWG approved with modifications on August 23, 2012.


58

30

PRRs – Integrated MarketplaceMPRR88—Non‐Conforming Load and Demand Response Load

Aggregate Exception• Currently, there are industrial processes that are served by multiple busses.y, p y p

– MPs must register separate loads and submit separate load forecasts for each Non‐Conforming or Demand Response PNode even if it is one actual load.

• MPRR 88 allows MPs to register Non‐Conforming and Demand Response loads as Aggregated PNodes.

– The load MUST be a single load at one location being served by multiple busses.

– Only one load forecast will be necessary.


– MWG unanimously approved with modifications on August 15, 2012.

– RTWG approved on September 26, 2012.

– ORWG approved on September 12, 2012.

• MWG recommends that the MOPC approve MPRR88. 59

PRRs – Integrated MarketplaceMPRR89—Net Benefits Test (Order No. 745 Compliance)• FERC Order 745 requires SPP to perform a test that measures the threshold

for when the benefit of dispatching a load reduction type Demand Response Resource outweighs the cost.

– When the LMP is above the threshold point, as determined by the Net Benefits Test and the DRR has been dispatched, the Resource must be compensated at the full LMP.

• MPRR 89 outlines the steps that will be taken by SPP in calculating the net benefits test consistent with FERC Order 745.

• Working Group Voting Results• Working Group Voting Results


– Pending RTWG approval.


• MWG recommends that the MOPC approve MPRR89.60

31

RTWG

61

TRR 076COMPLIANCE WITH ORDER 741

NETTING REQUIREMENTS(ACTION ITEM)(ACTION ITEM)

62

32

Background• FERC issued its final rule on credit reforms in the organized

wholesale electric markets on October 21, 2010 and issued an order on rehearing on February 17 2011order on rehearing on February 17, 2011.

• The purpose of these reforms is “to improve the management of risk and the subsequent use of credit in the organized wholesale electric markets.”• FERC was concerned that an RTO/ISO operating a “day‐a‐

head” market would not have full standing as a creditor if an entity filed for bankruptcy

63

y p y• SPP requested an exemption on meeting the full requirements

of Order 741 until the start of the Integrated Marketplace• FERC granted the extension of time to December 31, 2012• Did not rule on exemption request

Background• To comply with Order 741, the Finance Committee approved

the concept of having SPP become a Counterparty to all transactions done in the IM

• Includes TRRs and ARRs

• SPP will not be a counterparty for:

• Transmission Service

• Self‐supply arrangement

• Bilateral agreements

64

• Insures that SPP will have standing in a bankruptcy court if one of the parties defaults

• Only the “net” value of debts and payments will be at risk

33

Changes to the Tariff

• Contained in Attachment AE

– Defines the Integrated Marketplace Counterparty g p p y(Section 3.8)

– Defines how the IM Counterparty works for billing (Section 10.6)

Allows netting of payments and obligations

• As of the time of this posting, the MWG has not seen this TRR

– Not sure of needed Protocol changes

65

• Passed by the RTWG at its October ___ conference call

RTWG Recommendation

RTWG recommends approval of TRR 076 as presented to the MOPC

66

TRR 076 as presented to the MOPC

34

SSC

67

Recent Accomplishments and Activities

• Reviewed new JOA between SPP and the Integrated System of Western Area Power Administration, Basin Electric, and Heartland Consumers

– Filed at FERC in April and accepted in September

• Advising SPP staff regarding dispute with MISO over unaccounted for market flow

• Joint Coordinated System Planning activities y gthroughout 2012 with both AECI and MISO

• Guiding SPP’s response to the interregional requirements of FERC Order 1000

68

35

ORDER 1000 OVERVIEW OF RESPONSIBILITIES

69

FERC Order 1000

Regional Interregional

Coordinated Planning

Cost Allocation

70

36

Policy Development Responsibilities

• Regional State Committee (RSC)Cost• Interregional Cost Allocation Task Force (IRCATF)

Cost Allocation

• Seams Steering Committee (SSC)C di t d

71

• Seams Steering Committee (SSC)• Seams FERC Order 1000 Task Force (SFOTF)

Coordinated Planning

Internal SPP Development Efforts

SSC: Interregional Coordinated Planning Policy• Developed & approved SPP’s proposal for planning coordination

IRCATF: Interregional IRCATF: Interregional Cost Allocation Policy• Developed and approved principles for interregional cost allocation

IRCATF & SSC Coordination• After IRCATF approved principles, SFOTF took responsibility of negotiating cost allocation and coordination

72

coordination

37

SPP’S PROPOSED INTERREGIONAL COORDINATED PLANNING PROCESS

73

Interregional Coordination Requirements

Info/Data Sh i

Coordinated Pl i TransparencySharing

Annual Data Sharing

Planning

Use Common Models,

Assumptions, & Criteria

Transparency

Stakeholder input into interregional coordination procedures

74

Sharing of Regional “Needs”

& Solutions

Joint Evaluation of Interregional

Solutions

Website for Interregional Materials

38

Proposed Process

• Must be negotiated with each applicable neighboring planning region: MISO, Southeastern Regional Transmission Planning (AECI), MAPP (WAPA)

– May vary by region

• Applicable projects

– Tie lines

– Regional projects that provide significant value to moreRegional projects that provide significant value to more than one planning region (exceeds Order 1000 requirements)

75

Interregional Committees

• Interregional Planning Stakeholder Committee (IPSAC)

• Joint Planning Committee (JPC)

(IPSAC)

– Stakeholders from each region

– For SPP, comprised of the SSC and other interconnected TO’s

– Staff committee

– Decision making committee

– Requires agreement of both regions

interconnected TO s

– Advisory group

– Provides recommendations and feedback to the JPC

76

39

Proposed Process

77

Proposed Process cont.

78

40

Proposed Process cont.

79

INTERREGIONAL COST ALLOCATION

80

41

FERC’s Order 1000 Cost Allocation Principles

Cost “roughly commensurate” with

benefits

If you don’t receive benefit you may not be

allocated any cost

Benefit‐to‐cost ratios, if used, must not exceed

1.25

Transparent process for Option for different cost allocation

81

No involuntary allocation of costs

p pallocation methodology and identification of

benefits

cost allocation methods for different types of transmission

projects

Cost Allocation

• Interregional Cost Allocation

– Methodology to allocate costs between two gyplanning regions

– Flexible methodology that recognizes differing drivers with neighboring planning regions

• Regional Cost Allocation of Interregional Projects

– Methodology to regionally allocate the cost of SPP’s gy g yportion of an interregional project

– CAWG is discussing and will make recommendation to RSC

– SSC opinion is the SPP portion of Interregional Projects should be allocated to “Highway” 82

42

SPP MISOMin. Project Cost $0 $20 Million

Project Eligibility and Cost Allocation Proposals

Voltage Threshold NonePrimarily 345kV (at least 50% of project cost must

be 345kV)

Project Types ConsideredEconomic, Reliability,

Public PolicyMarket Efficiency

(Economic)

Min. B/C Ratio 1.0 1.25

1 Adjusted Production 1 Adjusted Production

Metrics Considered

1. Adjusted Production Cost

2. Reliability3. Increase in transfer

capability4. Reduced Losses5. Reduced Emissions

1. Adjusted Production Cost

83

PATH TO COMPLIANCE

84

43

Utilize Two Avenues

JOA Updates OATT RevisionsJOA Updates OATT Revisions

New Project RTWGCoordinated Planning Process

SSC Review JOAs filed with FERC

85

Interregional Cost

Allocation

New Project Type & Regional Review

RTWG, MOPC,

CAWG, RSC, & Board

Proposed Compliance Timeline

January 2013 Policy

Decisions

RTWG Finalize

April 2013 MOPC & Board

Approval

Make FERC Filings on May 13, 2013

OATT Changes and Staff,

working with SSC, Finalize JOA Language

86

44

Policy Decisions for January MOPC

• Interregional coordinated planning process

• New Interregional Project type in SPP Tariffg j yp

– Regional review process

– Approval process to qualify for a Notification to Construct (NTC)

• Interregional Cost Allocation

87

Decisions for Today

• Approve SSC charter revisions to reflect role in IPSAC

• Request MOPC recommend that SPP Board direct SPP qstaff to request extension of compliance deadline to May 13, 2013

– Need to accommodate April cycle of meetings similar to extension request on regional requirements

88

45

Backup Slides

89

MWG

90

46

PRRs – Integrated MarketplaceMPRR72—Regulation Deployment Priority Assignment

• When a large number of Resources receive a small MW Regulation deployment, no change in output is seen as it is noise for Resources.

– MPRR 72 proposes a priority approach to Regulation deployment where fewer Resources are deployed by priority group to achieve higher outputs above noise.

– A priority group is assigned each interval based on three criteria.

1) Reserve Zone, 2) Ramp Rate, and 3) Configurable Number of Groups

Default settings work like deployment today: 1) OFF 2) OFF 3) 1 group

If SPP changes a criteria, it will need MWG and MOPC approval

91

PRRs – Integrated MarketplaceMPRR72—Regulation Deployment Priority Assignment


– MWG unanimously approved with modifications on August 14, 2012.y pp g


– ORWG approved with modifications on September 13, 2012.

– MWG did not change the MPRR based on ORWG comments.

SPP can reliably operate the System no matter which of the 3 criteria is used for priority groups.


92

47

PRRs – Integrated MarketplaceMPRR85—Provision of Wind Forecast Clarification• SPP needs Wind Generator Resource data to produce the wind forecasts.

• MPRR 85 stateswhat data should be submitted andwho should submit itMPRR 85 states what data should be submitted and who should submit it.

– Generation Interconnect Customer must provide Real‐Time data.

Weather Data, Real‐Time Turbine Availability, Outage and Availability Data

– The MP who registered the WGR must submit static data.

Geographical Data, Turbine Data, ICCP Object ID, Contact Information


– MWG approved with modifications on July 24, 2012 with five oppositions (Constellation, KCPL, OG&E, OPPD, Excel Energy) and four abstentions (GSEC, KMEA, LES, OMPA).

– Neither RTWG nor ORWG have voted on MPRR 85.

• MWG recommends that the MOPC remand MPRR85 back to MWG.

93

PRRs – Integrated MarketplaceMPRR62—Settlement Area Data Submittal Clarification• MPRR 62 clarifies that the Meter Agent is responsible for submitting

telemetered Settlement Area load data and actual hourly settlement metered interchange between:

– Settlement Areas

– Settlement Areas and External BAs

• Corrects improper use of Meter Data Settlement Location to Meter Data Submittal Location


– MWG unanimously approved with modifications on June 19, 2012.

– RTWG approved with no Tariff implications on July 25, 2012.

– ORWG approved with no Reliability Impact July 26, 2012.


94

48

PRRs – Integrated MarketplaceMPRR79—Clarifications to the PRR Process• MPRR 79 proposes to exclude changes in Appendix F (Settlement Examples)

from the PRR process.

• A correction was made in section 9.2.7 where “expedited” was used instead of “urgent”.




– ORWG approved with no Reliability Impact on September 12, 2012.ORWG approved with no Reliability Impact on September 12, 2012.


95

PRRs – Integrated MarketplaceMPRR81—Over‐Collected Losses Distribution Amount• MPRR 81 corrects various typographical errors and definitions.

– A “/” left out of “$/MW” was corrected.A / left out of $/MW was corrected.

– Erroneous references to “Loss Pool” were deleted where it was not part of the settlement determinant.




– ORWG approved with no Reliability Impact on September 12 2012– ORWG approved with no Reliability Impact on September 12, 2012.


96

49

PRRs – Integrated MarketplaceMPRR83—Time Values• SPP Operations stores the time values from the offer parameters in minutes

instead of a fraction of hours.

– MPRR 83 corrects various references to clarify this point.

• MPRR 83 also removes “Not available on Settlement Statement” from the Day‐Ahead Minimum Run Time.

– This makes it consistent with the Real‐Time Minimum Run Time definition.


– MWG unanimously approved on August 14, 2012.MWG unanimously approved on August 14, 2012.




97

PRRs – Integrated MarketplaceMPRR84—Correction to Desired Energy Amount Calculation

in RUC Make‐Whole Payment• Currently, when calculating Desired Energy amount, the upper limit of the y, g gy , pp

integral can fall below the lower limit of the integral, causing the sign to change to negative.

– MPRR 84 changes the calculation to keep the upper limit from going below the lower limit, making the minimum Desired Energy amount zero – not negative.


– MWG unanimously approved on August 14, 2012.




98

50

Order 745 Net Benefits Test Compliance Filing

• FERC required each RTO/ISO to undertake a study on the impacts of implementing a dynamic net benefits test and file the study by 9/21/12

– SPP joined with 6 other RTOs/ISOs to perform the study

• Result of study was that a dynamic net benefits test has significant consequences and should not be implemented

• SPP other RTOs/ISOs and the Inter‐RTO Council made

99

SPP, other RTOs/ISOs and the Inter RTO Council made filings on 9/21/12

• SPP Staff Report included in MOPC background materials

Order 755 – Regulation Compensation

• Current RTO compensation practices are unduly discriminatory because resources are compensated at the same level even h idi diff t t f f l tiwhen providing different amounts of frequency regulation

service

• Order No. 755 requires RTOs to modify their tariffs to provide for a two‐part payment to remedy the undue discrimination

• Capacity

P f

100

• Performance

• MWG will begin drafting the MPRR on the October 12th

conference call

• Targeting the January 2013 MOPC meeting for approval

51

Combined Cycle Enhancements

• Allows MPs to submit Resource Offers for each configuration of a combined cycle unit

• Post Go‐Live Enhancement for March 1, 2015

• Staff received feedback from CAISO and ERCOT on their market design

• MWG will begin drafting MPRR on the October 12th

f ll

101

conference call

• MWG is targeting the January 2013 MOPC meeting for approval of the market design

Long‐Term TCRs

• RSC requested MWG consider Long‐Term TCRs for Integrated Marketplace

• FERC Order 681 required RTOs to incorporate long‐term firm transmission rights into existing financial transmission rights markets

• Staff developing a proposal to present to the MWG at the January meeting

102

the January meeting

• MWG targeting April 2013 MOPC meeting for approval

52

Integrated Marketplace Reserve Sharing Group Process• Staff developed draft RSG process and presented it at the Joint Working Group meeting on 8/30/12

• Process covers:

– Registration and Credit requirements

– Energy price and Settlements

– Transmission Service charges

103

• MWG will develop an MPRR and update the Integrated Marketplace Protocols with the process

• Staff currently contacting external RSG Members to review the process with them

Integrated Marketplace Protocols Traceability Report• SPP updated the Protocols Traceability Report with version 11 of the Protocols

• Purpose of the report is to trace the Marketplace Protocols to the SPP software requirements, desk procedures and design documents– Protocols traceability shows that SPP is implementing the market design with the development of its software

t

104

systems

• Traceability Report is included in the MOPC background materials

53

Mitigated Offer Task Force (MOTF)

• MOTF is responsible for development of Appendix G of the Marketplace Protocols– Appendix G contains Mitigated Offer Development Guidelines

• MOTF will draft first version of Mitigated Offer Development Guidelines and establish the process for future changes to the guidelines

T k F ill th PJM C t D l t G id li

105

• Task Force will use the PJM Cost Development Guidelines as the baseline

• MWG targeting the April MOPC for approval of the guidelines

RTWG

106

54

• Section I: Overview– If Upgrade meets the following conditions, then the project is

considered a Competitive Upgrade and TO selected in

Attachment Y

accordance with Section IIIA transmission upgrade identified from an ITP assessment and approved for constructionNominal operating voltage of >= 300 kVNot a rebuild or expansion of existing facilitiesMust not violate relevant law

– Otherwise SPP uses the process in Section IV (Incumbent TO)SPP may select a TO for a Competitive Upgrade using Section– SPP may select a TO for a Competitive Upgrade using Section IV (incumbent TO) if it meets the following criteria

If needed for reliability of the gridIf the need date can not be met if Section III is followedNo other transmission or non‐transmission mitigation existsRequires BOD approval

107

• Section III.1: Application and Qualification Process– Any entity which desires to participate in the RFP process

must pre‐qualify (Qualified RFP Participant or QRP), including

Attachment Y: Section IIIT.O. Selection Process for Competitive Upgrades

existing T.O.sApplication must be to SPP by June 30Minimum level qualifications are defined– Managerial and Financial Criteria– Must be willing to join SPP as a TO if not a TO already– Annual application fee equal to membership fee ($6,000), but the fee is waived if already a member

– Detailed application is good for 5 yearsDetailed application is good for 5 yearsMust submit an recertification letter by June 30 each year attesting that no material changes to its information has occurred

– QRP status may be terminated by SPP if a material adverse change has occurred

108

55

• Section III.2: T.O. Selection Process

– Industry Expert Panel (IEP)


Pool of Industry Experts approved by BODOversight Committee forms IEP

– RFP TimelineRFP sent to all QRPsQRP must submit its RFP proposal(s) within 90 days with a complete set of information and RFP fee

– RFP FeeFee is paid for each proposal submittedDesigned to cover the costs of the selection processBased on actual cost– Initial fee is estimated and “trued up” at the end of the process

109

• Section III.2(f): Scoring– Industry Expert Panel (IEP) will score each RFP proposal

1000 base points


p– 200 Engineering– 200 Project Management– 250 Operations– 225 Rate Analysis/Cost to customers– 125 Financial Viability and Creditworthiness

– 100 incentive points The entity which submitted the RFP proposal must have been the stakeholder to suggest the project and the project qualified as a Detailed Project Proposal (DPP) in accordance with Section III.8(b), Attachment O [new process discussed later]This is a all or nothing incentive

110

56

• Section III.2: Selection of the Designated Transmission Owner– IEP submits a full report to SPP based on the data it received

through the RFP process


The IEP shall recommend one RFP proposal plus an alternate (if more than one response to the RFP is received)SPP will produce two reports– The BOD report which has all the information, but with the names of the

RFP respondents redacted– The public report which is the BOD report, with any confidential

information redacted as well

– The BOD will select one proposal, plus an alternatep p , pThe entity which submitted the selected proposal has 7 days to accept the project and sign any necessary paperworkIf the first entity declines, then the entity which submitted the alternate proposal has 7 days to acceptIf neither entity accepts, then the SPP goes to the Incumbent TO process to select a TO

111

• Section III.2(g): Failure of the DTO to complete the Upgrade


Upgrade– If the DTO is unwilling or unable to complete the

Competitive Upgrade then SPP can either:Reevaluate the project to determine if neededSelect another TO to complete the Competitive Upgrade– Through the Section III process if time allows or– Through Section IV

112

57

• Section IV:– Maintains current Tariff language from Attachment O, Section

VI.6DTO is the owner of the facility or is the owner of the facility the

Attachment Y: Section IVIncumbent T.O. Designation Process

DTO is the owner of the facility or is the owner of the facility the upgrade is connecting to (no change)

– Gives 90 days for the T.O. to respond to an NTC (no change)– Maintains the ability of the T.O. to assign the NTC to another

entity (no change)The entity getting the assignment must meet the T.O. Qualifications listed in Section III

– If the DTO declines the NTC, and does not assign it, SPP will findIf the DTO declines the NTC, and does not assign it, SPP will find another TO using the selection process in Section III (Competitive Process)

If no other entity can be found to build the project, the incumbent must construct it in accordance with the membership agreementNo change from current language except SPP uses the Section III process for finding a DTO rather than the current Business Practice

113

• Generally maintained current Tariff language from Attachment O, Section VI.6 for NTCs

• Made NTCs its own Section to make clear any project where the TO is selected through either the TO Selection Process (Section III) or the

Attachment Y: Section VNotification to Construct Process

selected through either the TO Selection Process (Section III) or the Incumbent Process (Section IV) of Attachment Y must receive an NTC– Basic NTC information (no change)– DTO must accept NTC within either 7 days (Section III) or 90 days

(Section IV)• Defined that an NTC may be issued to get a better cost estimate (new)

– Follows the current Business Practice although Tariff does not use the term “NTCC”If th i d t ti t i ithi d fi d b d idth– If the revised cost estimate is within a defined bandwidth

Baseline cost is set and a construction NTC is issued– If the revised cost estimate is outside a defined bandwidth, SPP may:

Accept the refined cost estimateModify the projectReplace the project with an alternative solutionCancel the project

114

58

• The TO must use due diligence to complete the project as specified in the NTC

• The TO must report to SPP if it can not meet one or more of

Attachment Y: Section VNotification to Construct Process

the terms in the NTC

• SPP Staff will study the issue(s) and propose a course of action to the BOD, including but not limited to:– Accept the changes as proposed

– Withdraw the NTC from the original TO and give it to another TO

i hd h d l i i h l i l i– Withdraw the NTC and replace it with an alternative solution or

– Withdraw the NTC and cancel the project

115

• All transmission projects approved for construction under the Tariff shall be tracked by SPP– Follows current Business Practice

Attachment Y: Section VIProject Tracking Process

Follows current Business Practice– Includes Competitive Upgrades– DTO will submit cost and schedule updates at least

quarterly– If the project cost varies significantly from the baseline

cost, the project can be reevaluatedAlso allows for “resetting” the baseline cost if approved by the BOD

– Changes in completion date will also be reviewed and possible action taken

116

59

• Several new defined terms: DTO, NTC and Oversight Committee

• Modified definition of TO to work with TO Selection

Other Changes to the Tariff

Process and proposed changes to the Membership Agreement

• Attachment O, Public Policy Requirements – Section II.5 – Local planning criteria– Section III.3 (ITP20), III.4 (ITP10), III.5 (ITP‐NT), III.6 (ITP

input)• Attachment O, Section VI

– Removed TO selection process (Section VI.4)– Created pointers to Attachment Y for ITP, GI and TSR

upgrades

117

• Attachment O, Section III.8– Added a process for stakeholders to submit a Detailed Project

Proposal (DPP) as part of the ITP Process• A project must be a DPP to qualify for Incentive points as part of

Attachment O – Detailed Project Proposal

p j q y p pthe TO selection process of Attachment Y, (Section III.8(b) of Attachment O)

• A DPP project must be submitted during a 30 day window identified by SPP as part of the ITP planning process– A list of specific information must be supplied by the stakeholder

submitting the proposal– A DPP must solve one or more issues identified by SPP for that ITP

study– A fact that a project was submitted will be held in confidence until the

30 day window closes –Only the information necessary for SPP to explain why the DPP was, or was not, included in the final plan will be made available.

– It is possible for more than one entity to submit the same project118

60

• If a DPP is approved, the stakeholder(s) which submitted the DPP remains the sole entity qualified for incentive points for that DPP for any ITP study done for the

Attachment O – DPP (cont)

remainder of the 3 year ITP cycle– The stakeholder must update the information related to a

previous DPP for any subsequent ITP study for it to be considered a DPP for the subsequent ITP study

– If the stakeholder does not update the information, SPP may still use the project as a solution, but the stakeholder i t lifi d f i ti i tis not qualified for incentive points

119

Detailed Project Proposal‐Example 1

ITP 20 ITP 10

ITP NT #1 ITP NT #2 ITP NT#3

• If a DPP is submitted in ITPNT#1, the stakeholder can receive incentive credits if an NTC for the project is issued from the ITPNT#1.

3 years

• The stakeholder is the only entity that can receive incentive points for the DPP during the ITP cycle, IF it updates the information for ITP20, ITP10, ITPNT#2 and ITPNT#3

120

61

Detailed Project Proposal‐Example 2

ITP 20 ITP 10

ITP NT #1 ITP NT #2 ITP NT#3

• If a DPP is submitted in ITPNT#2, the stakeholder can receive incentive credits if an NTC for the project is issued from the ITPNT#2.

3 years

• The stakeholder is the only entity that can receive incentive points for the DPP during the remainder of the ITP cycle, IF it updates the information for ITP10, ITPNT#3

121

• How Approved Upgrades are constructed under the Tariff is still handled in Section VI

• Section VI.1 – clean up items

Attachment O – Section VI Construction of Transmission Facilities

p• Split Section VI.2 into 2 numbered paragraphs• Section VI.4 – Sponsored Upgrades (was VI.3)

– Sponsor must be willing to pay for the upgrade and put the facility under the Tariff

– Sponsor is eligible for Credits under Attachment Z2– If the Sponsored Upgrade is an upgrade of an existing facility, the

f th f ilit f th downer of the facility performs the upgrade– If the Sponsored Upgrade is a new facility:

Allows the sponsor of a Sponsored Upgrade to be the TO for the upgrade if it qualifies to become a TO as defined in Attachment Y, Section IIIIf the sponsor can not qualify as a TO or does not want to be the TO, SPP will select a TO in accordance with Section IV of Attachment Y

122

62

ESWG

123

Calculation details & examples

8 NEW METRICS

124

63

Components to each metric

• Each metric is monetize‐able through the combination of these components:

• A technical simulation method

• Assumption(s) regarding the $/unit

• Each metric must be allocated back to the zones directly or indirectly

• No double‐counting!!!• No double‐counting!!!

125

• Improves production cost simulations by reflecting reduced energy (MWh) losses on transmission lines

4.2 Marginal energy losses benefits

• Uses the Marginal Loss Component (MLC) from production cost simulations

• Relatively modest benefit expected

Production Cost Simulation

Post‐processing of MLC

Additional $$$ captured

126

64

• Improves production cost i l i b i l di

4.3 Mitigation of transmission outage costs

simulations by including typical transmission outages

• Typical outages to be determined by ORWG

l l f

Typical Outages

Production Cost

Additional $$$

captured

• Relatively significant benefit expected

Simulations

127

• Captures reductions to capital expenditures only if SPP d h h i i i d i

5.1 Capital savings due to reduction of Minimum Required Capacity Margin

mandates a change to the Minimum Required Capacity Margin due to transmission expansion

• Calculation not expected in upcoming studies

Reduction in capacity margin

requirement (MW)

Net Cost of New Entry ($/MW)

Additional $$$ captured

128OR

65

• Captures the Value of Lost Load (VOLL) independently from any

5.2 Reduced loss of load probability

Important! overlaps reduction in the Minimum Required Capacity Margin.

• Relatively significant benefit possible

with previous metric; use only one of the three.

Expected

129

VOLL ($/MWh)

Expected Unserved Energy (MWh)

Additional $$$

captured

OR

5.4 Assumed benefit of mandated reliability projects

• Benefits will be set equalf

Important! overlaps with previous metric;

to costs for:

– Regional Reliability projects

– Avoided reliability projects identified in the ITP process

• Production cost (economic) effects of reliability upgrades will be allowed

use only one of the three.


130

66

• Improves production cost simulations by including the impact of extreme events

5.3 Reducing cost of extreme events

• Probability and duration of historical events that have occurred in SPP


l hFind related Multiply savings andSelect 2 to 5 historic

events in SPP; assign probabilities

production cost savings due to transmission expansion

Multiply savings and probabilities to

capture additional $$$

131

• Captures effect of transmission expansion upon i i f h i h

5. Increased wheeling through and out revenues

transmission revenues for those transactions that come into and leave SPP

• Utilize historic rates & simulated transactions

• Relatively modest benefit expected

Historic wheeling

rate ($/MWh)

Change in export flows across tie lines (MW)

Additional $$$

captured

132

67

6. Public Policy Benefits

• Benefits will be set equal to costs for:

– The cost‐effective portion of transmission projects p p jrequired to meet public policy goals

• If a zone has no public policy mandate or has already met its mandate this benefit will not apply

• Production cost (economic) effects of these upgrades will be allowed


133

Metric Summary Difficulty to perform

Expected benefit

1. Marginal energy loss benefit Easy Low

2. Mitigation of transmission outage costs Medium High

3a.Capital Savings from reduced capacity margin requirement

Easy Medium

3b. Reduced loss of load probability Very Hard High/Low

3c. Assumed benefits of reliability projects Medium Medium

4. Reduced cost of extreme events Very Hard Medium/Low

5.Increased wheeling through and out revenues

Easy Medium

6. Public policy benefits Medium Medium

134

68

BALANCED PORTFOLIO

135

• MOPC July Action Item 195

– PCWG directed to review Balanced Portfolio cost estimates

PCWG Review of Balanced Portolio Costs

to determine if they are expected to Stabilize

• Please note that PCWG was not asked to review the reasonableness of the cost estimate increases

• Balanced Portfolio estimated costs have stabilized based on information provided by the DTOs

136

69

• SCERT estimates had to be developed by DTOs because Balanced Portfolio projects pre‐dated the new cost estimation process

Issues Encountered

• There were changes in the issued NTCs from the Balanced Portfolio Report assumptions– Scope changes (2000A to 3000A, 200 to 600 MVA)

– Ownership differences from SPP NTC issuance assumptions

• Numerous requests for information/explanation to obtain consistency among responses

• Limited timeframe required additional PCWG meetings

• PCWG review process under development

137

• SCERT with Upgrade level costs

• Map of final route (original & current route segments)

P t f l ti

Information Requested

• Percentage of completion (Material Procurement, Construction, Siting and Routing, Environmental Studies, Engineering, Permit Status)

• Factors that could lead to final cost variance exceeding +/‐20% of current cost estimate

• Factors for cost estimate increase / decrease

– If more than one factor, estimated percentage impact of each cause contributing to the change

• Expenditures to Date

138

70

139

Cost Comparison

ProjectOriginal Cost Estimate (BODApproval)

NTC IssueCost Estimate (June 2009)

NTC Acceptance Cost Estimate (Sept 2009)

Estimate As Of 9/1/2012

1A Gracemont (Anadarko) Sub 345 kV (OGE) $8,000,000 $8,000,000 $8,000,000 $13,954,860

1B Gracemont (Anadarko) Tap 138 kV (WFEC) N/A $2,000,000 $200,000 $966,210

2A Sooner ‐ Cleveland 345 kV (OGE) $33,530,000 $17,000,000 $47,200,000 $55,912,524

2B Cleveland Terminal Upgrades 345 kV (GRDA) N/A $17,000,000 $1,806,000 $2,780,000

3 Swissvale ‐ Stilwell Tap 345 kV (KCPL) $2,000,000 $2,000,000 $2,000,000 $1,922,840

4 Stateline‐ Axtell 345 kV (NPPD) $71,377,015 $71,377,015 $71,377,015 $59,050,000

5 Spearville ‐ Post Rock (Knoll) ‐ Stateline 345 kV (ITCGP) $165,180,000 $168,000,000 $168,000,000 $148,000,000

6 S i l M k 345 kV (OGE) $129 000 000 $131 000 000 $131 000 000 $176 100 000

140

6 Seminole ‐Muskogee 345 kV (OGE) $129,000,000 $131,000,000 $131,000,000 $176,100,000

7 Tuco – Border 345 kV (SPS)† $133,847,500 $133,847,500 $133,847,500 $185,745,462

8 Border ‐Woodward 345 kV (OGE)† $93,880,000 $93,880,000 $134,880,000 $147,000,000

9 Iatan ‐ Nashua 345 kV (KCPL/GMO) $54,444,000 $54,444,000 $54,444,000 $64,800,000

Total $691,258,515 $698,548,515 $752,754,515 $856,231,896

†Original cost estimate values reflect the assignment of Border reactor substation by SPS to OGE on 9/27/2010

71

Cost Overview

ProjectCurrent In‐Service

Date

Original Cost Estimate*

Estimate As Of

9/1/2012

Cost Variance

% Change

1 Gracemont (Anadarko) Sub 345 kV (OGE/WFEC) 10/12/2012 $8,000,000 $14,921,070 $6,921,070 86.5%1 Gracemont (Anadarko) Sub 345 kV (OGE/WFEC) 10/12/2012 $8,000,000 $14,921,070 $6,921,070 86.5%

2 Sooner ‐ Cleveland 345 kV (OGE/GRDA) 12/31/2012 $33,530,000 $58,692,524 $25,162,524 75.0%

3 Swissvale ‐ Stilwell Tap 345 kV (KCPL) 12/31/2012 $2,000,000 $1,922,840 ($77,160) ‐3.9%

4 Stateline ‐ Axtell 345 kV (NPPD) 12/31/2012 $71,377,015 $59,050,000 ($12,327,015) ‐17.3%

5 Spearville ‐ Post Rock (Knoll) ‐ Stateline 345 kV (ITCGP) 6/1/2013^ $165,180,000 $148,000,000 ($17,180,000) ‐10.4%

6 Seminole ‐Muskogee 345 kV (OGE) 12/31/2013 $129,000,000 $176,100,000 $47,100,000 36.5%

7 Tuco – Border 345 kV (SPS)† 5/19/2014 $133,847,500 $185,745,462 $51,897,962 38.8%

8 Border Woodward 345 kV (OGE)† 5/19/2014 $93 880 000 $147 000 000 $53 120 000 56 6%

141

8 Border ‐Woodward 345 kV (OGE)† 5/19/2014 $93,880,000 $147,000,000 $53,120,000 56.6%

9 Iatan ‐ Nashua 345 kV (GMO/KCPL) 6/1/2015 $54,444,000 $64,800,000 $10,356,000 19.0%

Total $691,258,515 $856,231,896 $164,973,381 23.9%

*Cost estimates sourced from page 45 of Balanced Portfolio report

†Original cost estimate values reflect the assignment of Border reactor substation by SPS to OGE on 9/27/2010^Spearville – Post Rock portion completed and in‐service on 6/28/2012

Project ExpendituresProject

Current In‐Service Date

Estimate as of 9/1/2012

Expenditures as of

8/16/2012

Expenditures as % of Latest Estimate

1 Gracemont (Anadarko) Sub 345 kV (OGE/WFEC) 10/12/2012 $14,921,070 $14,165,964 94.9%

2 Sooner Cleveland 345 kV (OGE/GRDA) 12/31/2012 $58 692 524 $41 377 430 70 5%2 Sooner ‐ Cleveland 345 kV (OGE/GRDA) 12/31/2012 $58,692,524 $41,377,430 70.5%

3 Swissvale ‐ Stilwell Tap 345 kV (KCPL) 12/31/2012 $1,922,840 $1,260,500 65.6%

4 Stateline ‐ Axtell 345 kV (NPPD) 12/31/2012 $59,050,000 $50,700,000 85.9%

5 Spearville ‐ Post Rock (Knoll) ‐ Stateline 345 kV (ITCGP) 6/1/2013^ $148,000,000 $140,253,109 94.8%

6 Seminole ‐Muskogee 345 kV (OGE) 12/31/2013 $176,100,000 $22,942,813 13.0%

7 Tuco – Border 345 kV (SPS) 5/19/2014 $185,745,462 $11,282,463 6.1%

8 Border ‐Woodward 345 kV (OGE) 5/19/2014 $147,000,000 $6,777,337 4.6%

9 Iatan ‐ Nashua 345 kV (GMO/KCPL) 6/1/2015 $64,800,000 $2,274,842 3.5%

T t l $856 231 896 $291 034 458 33 9%

142

Total $856,231,896 $291,034,458 33.9%

^Spearville – Post Rock portion completed and in‐service on 6/28/2012

33.99%

66.01%

Expenditures (as of 8/16)

Estimated Unspent

Total Portfolio Expenditures

72

Estimated Completion Percentage

Project

Engine

ering

Material

Procurem

ent

Environm

ental

Stud

ies

Siting

and

Routing

Perm

it Status

Construction

1A Gracemont (Anadarko) Sub 345 kV (OGE) 100% 100% 100% 100% 100% 100%

1B Gracemont Tap 138 kV (WFEC) 100% 90% 100% 100% 100% 85%

2A Sooner ‐ Cleveland 345 kV (OGE) 100% 100% 100% 100% 100% 35%

2B Cleveland Terminal Upgrades 345 kV (GRDA) 80% 40% 100% N/A 100% 0%

3 Swissvale ‐ Stilwell Tap 345 kV (KCPL) N/A N/A N/A N/A N/A 67%

4 Stateline ‐ Axtell 345 kV (NPPD) 100% 100% 100% 100% 100% 90%

5A Spearville ‐ Post Rock 345 kV (ITCGP) 100% 100% 100% 100% 100% 99%

5B Post Rock ‐ Stateline 345 kV (ITCGP) 100% 100% 100% 100% 100% 90%

5C Post Rock 345/230kV Transformer (ITCGP) 100% 100% 100% 100% 100% 100%

143

/ ( )

6 Seminole ‐Muskogee 345 kV (OGE) 99% 88% 99% 99% 90% 3%

7A Tuco – Border 345 kV (SPS) 38% 7% 50% 95% 35% 0%

7B Tuco 345/230 kV Transformer (SPS) 85% 7% N/A N/A N/A 25%

8 Border ‐Woodward 345 kV (OGE) 25% 0% 10% 100% 60% 0%

9A Iatan ‐ Nashua 345 kV (KCPL/GMO) 66% 15% N/A 100% 5% 6%

9B Nashua 345/161 Substation (KCPL) 0% 0% N/A N/A 0% 0%

$140,000,000

$160,000,000

$180,000,000

$200,000,000

Balanced Portfolio Expenditures

$

$20,000,000

$40,000,000

$60,000,000

$80,000,000

$100,000,000

$120,000,000

$ , ,

Latest Estimate

Expenditures (as of 8/16)

144

$0

73

Projects with Remaining Uncertainty

ProjectCurrent In‐Service Date

Estimate as of 9/1/2012

Expenditures as of 8/16

Estimated Unspent

Expenditures as % of Latest Estimate

Seminole ‐Muskogee 345 kV (OGE) 12/31/2013 $176,100,000 $22,942,813 $153,157,187 13.0%

Tuco – Border 345 kV (SPS) 5/19/2014 $185,745,462 $11,282,463 $174,462,999 6.1%

Border ‐Woodward 345 kV (OGE) 5/19/2014 $147,000,000 $6,777,337 $140,222,663 4.6%

Iatan ‐ Nashua 345 kV (GMO/KCPL) 6/1/2015 $64,800,000 $2,274,842 $62,525,158 3.5%

Total $573,645,462 $43,277,455 $530,368,007 7.5%

145

• Potential future cost increase factors are listed on additional background slides (28 through 33) for these projects

• DTOs have indicated that total future costs are expected to remain within 20% of current estimates

Conclusions

• The PCWG has determined that estimated costs have stabilized for the Balanced Portfolio, based on the following:

– Projects that comprise 33% of the current estimated cost of the Balanced Portfolio have stable future cost projections to completion

– The remaining 67% of the Balanced Portfolio projects are expected to be within 20% of their latest respective cost estimates (see slide 13)

146

Of the total $565 million of unspent Balanced Portfolio cost, the four projects with remaining cost uncertainty listed on slide 13 account for $530 million

The project scopes of the projects have been clearly defined

74

Conclusions (cont’d)

• The PCWG has determined that estimated costs have stabilized for the Balanced Portfolio based on the information provided by the DTOs and reviewed by PCWG

• PCWG defined stabilized at +20% of the current cost estimates used for its review

• For the 4 projects with remaining uncertainty, the DTOs /

147

believe their projects will fall within the +/‐20% bandwidth compared to the latest cost estimates

Balanced Portfolio Conceptual Overview• Portfolio of economic upgrades

– 345 kV or higher

– May include lower voltage

• 10‐year Economic Analysis

– Costs allocated to each zone

– Benefits determined for each zone

• Must provide net benefits to entire SPP region• Must provide net benefits to entire SPP region

– B/C ≥ 1.0 for each transmission owner

– May adjust revenue requirements to achieve balance

148

75

Stakeholder Process• Cost Allocation Working Group (CAWG)

– Reviewed and approved study assumptions

– Recommended approval of final portfolio

• MOPC

– Reviewed and endorsed in 2009

• Regional State Committee

Approved the cost allocation methodology in 2009– Approved the cost allocation methodology in 2009

• SPP Board of Directors

– Approved projects in 2009

– Staff issued NTCs after report was finalized in June 2009149

Portfolio Development

• Development timeframe was August 2007 – April 2009

• Economic Analysis horizon was 2012‐2021

• Several portfolios were evaluated

– Candidate projects submitted and individually screened

– Portfolios developed based on different objectives

– A variety of analyses performedA variety of analyses performed

• The chosen portfolio had a B/C ratio of 1.87

150

76

Balanced Portfolio Study Assumptions

Financial• Fuel Price

Operational• Plant Outages• Demand Side

• Environmental Costs• Hurdle Rates• Market Structure

Demand Side Management

• Flowgates• DC Tie Profiles• Wind Profiles• Load Profiles• RMR Requirements• Operating Reserves• Topology

Planning• Load Forecast• Resource Plans

151

Key Drivers of Benefits

Gas Price ($/MMBtu)

Resource Plans

Load Forecast

Market Structure($/MMBtu)

2012 = 6.50

2022 = 8.16

Plans

Wind = 2,600 MW

No Carbon Tax

Forecast

2012 –49,400 MW

2017 –53,900 MW

Structure

Single balancing authority

Day‐ahead market

152

No EPA Impacts

2022 –58,300 MW

77

Benefits Determination

• Production cost savings analysis performed using PROMODPROMOD

• APC savings by zone derived from 2012, 2017, & 2022 models

• Benefits for remaining years determined by interpolating APC savings from 2012, 2017, & 2022

153

• Sum of the annual benefits discounted using an 8% discount rate

Costs Determination

• Project cost estimates (E&C) supplied by transmission ownersowners

• ATRRs estimated based on the supplied cost estimates and applicable fixed charge rates

• ATRR for the portfolio allocated to each zone based on region‐wide load ratio share forecast

154

• Sum of the ATRRs discounted using an 8% discount rate

78

Annual 10yr Zonal BenefitsZone Portfolio BenefitsAEPW $30,939EMDE ‐$340GRDA $857$KCPL $8,394MIDW $13,211GMO ‐$1,608MKEC $11,990OKGE $26,639SPRM ‐$140SUNC $3,338

Data as of June 2009

155

All numbers are in thousands of dollars

SWPS $56,134WEFA $7,986WRI $14,730NPPD $5,562OPPD $2,199LES ‐$3,486Total $176,406

Balanced Portfolio Estimate Trend

FERC Filing

FERC Filing

FERCFiling

156

79

Balanced Portfolio (“BP”) Cost Allocation Overview

(1) SPP OATT Requirements

(2) Example of how transfers work ‐ Hypothetical Regional Transmission Organization (“HRTO”)

(3) Actual SPP Transfer Amounts by Zone

(4) Status of SPP’s BP filings at FERC

(5) SPP OATT Provision relating to BP Unintended Consequences Review & Reconfiguration

(6) Next Steps for SPP Members

157

(1) SPP OATT REQUIREMENTS3 Aspects to Review

• Development of Portfolio of Balanced Portfolio f P j [A h O S i IV (3) (5)]of Projects – [Attachment O, Section IV (3)‐(5)]

• Allocation of Cost to Achieve a Balance –[Attachment J, Section IV (A)]

• Unintended Consequences Review –[Attachment J, Section IV (B)]

• At the End of the Presentation158

80

Development of Portfolio of Balanced Portfolio of Projects – [Attachment O, Section IV (3)‐(5)]

HIGHLIGHTS of BP Process

• For the purpose of determining Revenue Requirements,p p g q ,all of the upgrades are simultaneously available to thepower system

• Transmission Owners provide the pertinent informationsuch as cost estimates

• Transmission Provider uses the Transmission Ownera s ss o o de uses t e a s ss o O efixed charge rate to estimate revenue requirement

• The estimated cost for each Zone shall be allocatedbased on its Region‐wide Load Ratio Share forecastedover the ten year period analyzed.

159

Allocation of Transfers to Achieve a Balance –[Attachment J, Section IV (A)]

HIGHLIGHTS of BP Transfers

• Transfers begin when 10% of the Revenue Requirementare in rates

• Phased in at 20% per year over initial five years.

• Transfers are calculated using the same benefitsestimated at the time the Portfolio was approved.pp

160

81

Phase‐in Transfers at 20% per year over five years

Years

2nd Year

3rd Year4th Year

5thYear

6‐10True Up

161

1st Year

ea

Overview

• Calculation of Balanced Portfolio Transfers for the HRTOusing same BP methodology as prescribed in SPP’s OATT

• Present Value levelized over 10 years for Portfolio Costs and associated B/C Ratios, before and after Transfers, and Transfer Amounts

• Annualized Portfolio Costs and associated B/C Ratios, before and after Transfers, and Transfer Amounts

162

82

HRTO BP UPGRADES

LRS = 41.76% FCR = 13.5%

LRS = 25.00% FCR = 15.1%

LRS = 16.67% FCR = 15.1% LRS = 13.33% FCR = 12.1%

LRS = 3 33%

163

3.33%

Steps to Calculate Levelized Annual Transmission Revenue Requirement (“ATRR”) Per Year

HRTO Upgrade List with Levelized Cost Calculations and Fixed Charge Rate Estimates

(b) ( ) * (b)

UID ZONE DESCRIPTION(a)

COST

(b) Levelized

FCR

(a) * (b) Levelized ATRR

A1 A Line from Zone A to Border of Zone B $100,000,000 13.50% $13,500,000

A2 ATransformer at Substation on Border of Zone A and Zone B $5,000,000 13.50% $675,000

B1 BLine from Substation on Border of Zone A and Zone B to Main City in Zone B $63,000,000 15.10% $9,513,000

D1 D Line Inside of Zone D $22,500,000 12.10% $2,722,500C1 C Line inside Zone C $3 000 000 15 10% $453 000

Estimated Costs multiplied by Levelized Fixed Charge Rate (“FCR”) yields levelized Annual Transmission Revenue Requirement per year

164

C1 C Line inside Zone C $3,000,000 15.10% $453,000B2 B Line in Zone B $6,500,000 15.10% $981,500

Total of Cost Estimates ($) $200,000,000 Total

Levelized ATRR ($/yr)

$27,845,000

83

10 Year Levelized Cost ‐ Sum the PV of 10 years ATRR of Balanced Portfolio Costs

Sum of 10 years of Balanced Portfolio Costs

Levelized

• Discount Rate per 2009 BP Report

YearDiscount Factor

Levelized ATRRLevelizedATRR

Discounted1 1.000000 $27,845,000 $27,845,000 2 0.925926 $27,845,000 $25,782,407

3 0.857339 $27,845,000 $23,872,599 4 0.793832 $27,845,000 $22,104,259 5 0.735030 $27,845,000 $20,466,906 6 0.680583 $27,845,000 $18,950,839

p

• AnnualizationFactor of 7.246888 = sum of 10 years of discount factors at 8%

Basis for Calculation of BP Benefit / Cost Ratio and

7 0.630170 $27,845,000 $17,547,073

8 0.583490 $27,845,000 $16,247,290

9 0.540269 $27,845,000 $15,043,787 10 0.500249 $27,845,000 $13,929,432

7.246888 $201,789,594 165

Cost Ratio and Transfer Allocation

Initial Present Value Dollars Over 10 Years of Levelized Costs and Benefits, Before Transfers

HRTO Initial PV$ Over 10 Years of Levelized Costs and Benefits

(in millions)

Zone

a b a less b a divided by bLoadRatio Share

PortfolioBenefits

Portfolio 10 Year ATRRCosts

BenefitsBefore Transfers

B/CBefore Transfers

A $156.9 $84.1 $72.8 1.87 41.67%B ‐$2.5 $50.5 ‐$53.0 ‐0.05 25.00%C $6 3 $33 6 $27 3 0 19 16 67%

166

C $6.3 $33.6 ‐$27.3 0.19 16.67%D $60.8 $26.9 $33.9 2.26 13.33%E $8.4 $6.7 $1.7 1.25 3.33%

Total $229.9 $201.8 $28.1 1.14 100.00%

* Portfolio Benefits are computed over 10 years in PV$ to match costs**Total of 10 years of PV of FC$. Costs allocated per LRS.

84

Impact of Transfers on B/C (PV over 10 years)

HRTO After Balancing Transfer Adjustments PV$ Over 10 Years of Levelized Costs and Benefits

(in millions)All ti

Zone Portfolio Benefits


Costs

B/CBefore

Transfers

Transfer ATRR Cost

from Zones to Region

Allocation of

Regional ATRR

Transfers to Zones

B/C After Transfers

A $156.9 $84.1 1.87 $0.0 $59.6 1.09B -$2.5 $50.5 (0.05) $88.7 $35.7 1.00

167

C $6.3 $33.6 0.19 $51.2 $23.8 1.00D $60.8 $26.9 2.26 $0.0 $19.1 1.32E $8.4 $6.7 1.25 $3.1 $4.8 1.00

Total per

Year $229.9 $201.8 1.14 $142.9 $142.9 1.14

Phase‐in of $19.7M Annualized Transfers HRTO

YearsYears 6‐10True Up

168

85

B/C Ratios Before and After Transfers

2009 BP Report Est. at the Time of SPP Filing August 2012

Current 10 Year ATRR Cost Estimates

ZoneB/C

Before B/C After Transfers

B/CBefore B/C After

Transfers

B/CBefore B/C After

Transfers

Balanced Portfolio PV$ Over 10 Years ATRR Costs (in millions)

Transfers Transfers Transfers Transfers Transfers Transfers

AEPW 1.5 1.1 1.1 1.0 1.2 1.0EMDE (0.1) 1.0 (0.1) 1.0 (0.1) 1.0GRDA 0.5 1.0 0.4 1.0 0.4 1.0KCPL 1.1 1.0 0.9 1.0 0.9 1.0MIDW 18.7 14.1 14.8 8.1 15.5 9.4MIPU (0.3) 1.0 (0.3) 1.0 (0.3) 1.0MKEC 11.1 8.3 8.6 4.7 9.1 5.5OKGE 2.0 1.5 1.5 1.0 1.6 1.0SPRM (0 1) 1 0 (0 1) 1 0 (0 1) 1 0SPRM (0.1) 1.0 (0.1) 1.0 (0.1) 1.0SUNC 3.6 2.7 2.5 1.4 2.6 1.6SWPS 5.1 3.9 3.9 2.2 4.1 2.5WEFA 2.7 2.0 2.0 1.0 2.1 1.3WRI 1.3 1.0 1.0 1.0 1.1 1.0

NPPD 0.7 1.0 0.6 1.0 0.6 1.0OPPD 0.4 1.0 0.3 1.0 0.3 1.0LES (1.7) 1.0 (1.5) 1.0 (1.5) 1.0Total 1.9 1.9 1.4 1.4 1.5 1.5 169

Balance Portfolio PV over 10 Year ATRR Cost Estimates and Transfers ‐ 2009 BP Report

Zone Portfolio Portfolio 10 Year ATRR

B/CBefore

Transfer ATRR Cost f


ATRR

Net Benefit after

Allocation of B/C After

(in millions)

Zone Benefits Year ATRR Costs

Before Transfers from Zones

to Region

ATRR Transfers to

Zones

Allocation of ATRR

Transfers

Transfers

AEPW $224.1 $154.5 1.5 $0.0 $50.8 $18.8 1.1 EMDE ($2.5) $18.1 (0.1) $26.5 $6.0 $0.0 1.0 GRDA $6.2 $13.4 0.5 $11.7 $4.4 $0.0 1.0 KCPL $60.8 $53.1 1.1 $9.8 $17.5 $0.0 1.0 MIDW $92.7 $4.9 18.7 $0.0 $1.6 $86.2 14.1 MIPU ($9.6) $27.8 (0.3) $46.6 $9.2 $0.0 1.0 MKEC $85.5 $7.7 11.1 $0.0 $2.5 $75.2 8.3 OKGE $192.9 $97.5 2.0 $0.0 $32.1 $63.4 1.5 $ $ $ $ $SPRM ($0.7) $10.7 (0.1) $14.9 $3.5 $0.0 1.0 SUNC $26.8 $7.3 3.6 $0.0 $2.4 $17.0 2.7 SWPS $406.5 $79.4 5.1 $0.0 $26.1 $301.1 3.9 WEFA $57.8 $21.7 2.7 $0.0 $7.1 $28.9 2.0 WRI $103.0 $79.4 1.3 $2.6 $26.1 $0.0 1.0

NPPD $39.8 $55.1 0.7 $33.4 $18.1 $0.0 1.0 OPPD $16.3 $42.7 0.4 $40.5 $14.1 $0.0 1.0 LES ($22.4) $13.2 (1.7) $39.9 $4.3 $0.0 1.0 Total $1,277.3 $686.8 1.9 $225.9 $225.9 $590.5 1.9 170

86

Phase‐in Transfers at 20% per year over five years per BP Report

Years

2nd Year

3rd Year4th Year

5th Year

6‐10True Up

• $18.6M

• $24.8M• $31M

171

1st Year

ea• $12.4M

• $6.2M

Balance Portfolio PV over 10 Year ATRR Cost Estimates and Transfers ‐ SPP 2012 Filing



B/CBefore



ATRR

Net Benefit after


(in millions)


ZonesATRR

Transfers

Transfers



87

Phase‐in Transfers at 20% per year over five years per SPP 2012 Filing

Years

2nd Year

3rd Year4th Year

5th Year

6‐10True Up

• $61.5M

• $82M

• $102.6M

173

1st Year

ea

• $20.5M

• $41M

M

Balance Portfolio PV over 10 Year ATRR Cost Estimates and Transfers ‐ Current Cost Estimates



B/CBefore



ATRR

Net Benefit after


(in millions)


ZonesATRR

Transfers

Transfers



88

Phase‐in Transfers at 20% per year over five years per Current Estimate of Costs

Years

2nd Year

3rd Year4th Year

5th Year

6‐10True Up

• $45.9M

• $61.2M

• $76.3M

175

1st Year

ea

• $15.3M

• $30.6M

Regulatory Filings• April 16, 2012 – Docket No. ER12‐1552

– Year One Balanced Portfolio Transfer filing in accordance with Attachment J of the SPP OATT.

Required because 10% Threshold was met.

Subsequently withdrawn due to errors found in Reliability Benefits calculations wherein benefits were allocated to the wrong Transmission Owner.

• August 2 2012 – Docket No ER12‐2387• August 2, 2012 – Docket No. ER12‐2387

– Year One Balanced Portfolio Transfer filing, using cost estimates provided by May 25, 2012. Cost estimates are fluid. Current estimates reflect lower costs than included in the August 22, 2012 filing.

176

89

Regulatory Filings

• September 26, 2012 – Docket No. ER12‐2387

– Year One Balanced Portfolio Transfer filing, using g, gcost estimates provided by May 25, 2012. Cost estimates are fluid. The filing was made to account for Empire District Electric’s formula rate template revenue requirement not being effective until January 1, 2013, per FERC order.

177

Future Filings• Annual transfer filings 2013 – 2016, Years two through

five Balance Transfers.

• It is anticipated all projects included in the Portfolio• It is anticipated all projects included in the Portfolio will be completed on or before year 6 following the trigger date. At that time, final costs and carrying charges will be updated, including a NPV calculation of the phase in amounts during the prior years transfers.

178

90

MOPC Directives to SPP Staff for BP Review

• Presentation of Transfer Mechanism & Transfers through ATRR

• Determine current ATRR in rates for Balance Portfolio Projects ($36.4M)

• Original Estimated Transfers by Zone

• August 2012 Estimated Transfers by Zone

• Transfers by Zone based on Current 10 Year ATRR Cost• Transfers by Zone based on Current 10 Year ATRR Cost Estimates

179

BOD Directive October 2012

• BOD approves TRR068, with the understanding that further analysis by the MOPC of the unintended consequences of the cost changes and allocation in the balanced portfolio and the required FERC filing will state that this analysis is being performed with initial report expected in October 2012.

180

91

Conditions Under Which an Approved Balanced Portfolio may be Reconfigured – [Att. J, Sec. IV (B)(1)]

• Under certain conditions, the Transmission Provider shall review an approved Balanced Portfolio for unintended consequences and may recommend reconfiguring a previously approved Balanced Portfolio. Conditions that would initiate such review include but are not limited to:

i. Cancellation of an upgrade that is part of an approved Balanced Portfolio;

ii Unanticipated decreases in benefits or increases in the costs ofii. Unanticipated decreases in benefits or increases in the costs of upgrades that are part of an approved Balanced Portfolio or increases in the costs of third party impacts under Section IV.3.c of Attachment O; and

iii. Significant unanticipated changes in the transmission system.181

(5) SPP OATT PROVISION RELATING TO RECONFIGURATION [ATT. J, SEC. IV (B)(2)]

Reconfiguration of a Balanced Portfolio shall be evaluated based upon the following general factors, including but not limited to, the impact of thefollowing general factors, including but not limited to, the impact of the reconfiguration on:

• Cost Beneficial: The sum of the benefits of the potential Balanced Portfolio must equal or exceed the sum of the costs.

• Balanced: For each Zone, the sum of the benefits of the potential Balanced Portfolio must equal or exceed the sum of the costs.

• The amount that needs to be transferred from the deficient Zone(s) to the ( )Balanced Portfolio Region‐wide Annual Transmission Revenue Requirement in order to balance the reconfigured portfolio; and

• The increase in the overall cost of the reconfigured Balanced Portfolio, if upgrades are added to the portfolio.

182

92

(6) Next Steps for SPP Stakeholders

Option 1: Do not proceed with any additional Review at this time

Option 2: Perform a review

a) SPP Perform a Review of the BP projects per the OATT (with new assumptions) and make a recommendation to the MOPC on Reconfiguration

b) Include the BP projects in the Regional Cost Allocation Review (RCAR)

183

Comparison of BP Key Drivers with Current

Gas Price Gas Price Resource Resource Load LoadGas Price ($/MMBtu)

2012 = 6.50

2022 = 8.16

Gas Price ($/MMBtu)

2012 = 3.82

2022 = 5.47

Resource Plans

Wind = 2,600 MW

No Carbon Tax

No EPA

Resource Plans

Wind = 9,200‐

25,000 MW

Carbon Tax (Future 4)

Load Forecast

2012 –49,400 MW

2017 –53,900 MW

2022 –

Load Forecast

2012 –51,600 MW

2017 –55,100 MW

2022 –

184

No EPA Impacts EPA Impacts 2022

58,300 MW 2022

58,800 MW

Balanced Portfolio

2013 ITP 20

93

Background• Altoona East 69 kV Capacitor Bank – 6 MVAR

– Issued as a result of SPP‐2007‐AG1

Project Type NTC Issue DateRTO Determined

Need DateProjected In‐Service

DateLead Time

transmission service 9/18/2009 6/1/2014 6/1/2014 18 Months

NTC Cost Estimate

2nd Quarter 2012 Cost Estimate

3rd Quarter 2012 Cost Estimate

Cost Change (Q3‐Q2)

Cost Change % (Q3/Q2)

Cost Change (Q3‐NTC)

Cost Change % (Q3/NTC)

$607,500 $607,500 $1,045,000 $437,500 72.0% $437,500 72.0%

• SPP Board directed re‐evaluation of this project in July 2012

– Detailed engineering review revealed additional needed substation work not included in original estimate

185

Afton Transformer 161/69 kV (GRDA)

Project Type NTC Issue DateRTO Determined

Need DateProjected In‐Service

DateLead Time

regional reliability 2/8/2010 6/1/2010 8/1/2013 24 Months

• Cost Increase Justification

NTC Cost Estimate

3rd Quarter 2012 Cost Estimate

4th Quarter 2012 Cost Estimate

Cost Change (Q4‐Q3)

Cost Change % (Q4/Q3)

Cost Change (Q4‐NTC)

Cost Change % (Q4/NTC)

$2,500,000 $3,000,000 $8,020,000 $5,020,000 167.33% $5,520,000 220.8%

186

– NTC scope did not include conversion of bus configuration at substation to breaker‐and‐a‐half scheme

• Expenditure to date approx. $720,000

94

Carl A. MonroeEVP & COO501‐614‐[email protected]

187


MARKETS AND OPERATIONS POLICY COMMITTEE Recommendation to the Board of Directors

MPRR 90 Market Hubs Establishment October 29-30, 2012


The following members represent the Market Hubs Task Force:

Mike Mushrush, OMPA, Chairman Eric Alexander, GRDA Will Amos, OGE Holly Black, City Utilities, Springfield, MO Jessica Collins, Xcel Energy Jim Flucke, KCPL Rene Garza, AEP Josh Kirby, WFEC Matt Moore, Golden Spread Electric Cooperative Ron Thompson, NPPD Rick Yanovich, OPPD

Background

The Marketplace Hubs Task Force (MHTF) is responsible for the development of the criteria and processes for establishing hubs in the Integrated Marketplace. The scope of the MHTF was to:

1. Develop and recommend Marketplace Protocols for the establishment of hubs.

2. Propose the hub(s) to be implemented at the start of the Integrated Marketplace, including Market Trials.

3. Conduct analysis on hub rules and selection process, as appropriate, in other regions and provide justification for the recommendation of the hub practices for Marketplace.

Analysis

The MHTF conducted analysis on PJM and MISO hub practices and rules in the development of the SPP Market Hubs Establishment process.

The MHTF recommends establishing Market Hubs that consist of Resource Hubs and Trading Hubs. A Resource Hub is a Settlement Location representing an aggregation of Resource PNodes as defined by the Market Hubs Establishment process. A Trading Hub is a Settlement Location consisting of an aggregation of Price Nodes developed for financial and trading purposes.

The following criteria will be used to establish all Market Hubs:

1. Each Market Hub shall contain a sufficient number of PNodes to ensure that a Market Hub Locational Marginal Price (LMP) can be calculated for that Market Hub at all times;

#7n. MPRR 90 Recommendation to the MWG Page 1 of 2

#7n. MPRR 90 Recommendation to the MWG Page 2 of 2

2. Each Market Hub shall contain a sufficient number of PNodes to ensure that the unavailability of, or an adjacent line outage to, any one PNode or set of PNodes would have only a minor impact on the Market Hub LMP;

3. Each Market Hub shall consist of PNodes with a relatively high rate of service availability; and 4. Each Market Hub shall consist of PNodes among which Transmission Service is relatively unconstrained.

The MHTF discussed Resource Hubs and identified two reasons for establishing a Resource Hub. The reasons for a Resource Hub are 1) for use as a Settlement Location for Bilateral Settlement Schedules and 2) for use as a Settlement Location for the ARR/TCR Market. The MHTF reviewed the Trading Hub Analysis performed by TEA and SPP. Based on the SPP analysis, the group recommends two Trading Hubs – a North Hub and a South Hub. The North Hub consists of 496 PNodes from LES, NPPD, and OPPD. The South Hub consists of 537 PNodes from CSWS, OKGE, WFEC, and GRDA. The SPP analysis process that was used to develop the Trading Hubs is as follows:

1. Performed Cluster Analysis to discover SPP PNode price clusters. 2. Performed Best Fit Analysis to determine the most satisfactory clusters for hub candidates. 3. Performed Correlation Analysis to verify that the hub candidates show consistent internal price

movements over multiple sample periods. 4. Performed Stress Testing to verify external factors have little impact on the hub candidates.

The MHTF developed the Protocol language that supports their recommendation for establishing Resource Hubs and Trading Hubs. The Market Hubs Establishment MPRR is attached to the recommendation report. The recommended timeline for the MPRR approval and the deadline for Market Hub proposals to be included for the start of Market Trials is shown in the table below.

Septem

ber

7‐Sep MWG Teleconference Review MPRR and review Hubs Analysis

18‐Sep MHTF Possibly not needed

18‐Sep MWG Present final proposal ‐ Hubs MPRR ‐ Seek MWG Approval

19‐Sep ORWG Present final proposal ‐ Hubs MPRR

26‐Sep RTWG Present final proposal ‐ Hubs MPRR

Octob

er 16‐Oct MOPC Present final proposal ‐ Hubs MPRR ‐ Seek MOPC Approval

Novem

ber

1‐Nov Hub proposals need to be submitted to SPP in order to be included at the start of Market Trials

Recommendation

The MOPC recommends that BOD approve the Market Hubs Establishment MPRR 90.

APPROVED: MOPC October 16-17, 2012 Approved with five opposed- AEP SWEPCO, KEPC, KGE-Westar, Westar Energy, Xcel Energy; two abstentions- Empire District and Entergy Asset Mgmt.

Action Requested: MWG Approval of the Market Hubs Establishment MPRR.

#7o. MPRR 90 Recommendation Report 10/1/2012 Page 1 of 11



Title Market Hubs Establishment




Approve Reject


Defer Refer




Section No.: 1., 4.3.1.1; 4.5.2.3; 4.5.2.3.1 (new); 4.5.2.3.1.1 (new); 4.5.2.3.1.2 (new); 4.5.5.1; 5.2.3; 5.4.3; Appendix F (1.2). Title: Glossary, DA Market Inputs, Settlement Locations, Hubs Establishment, Resource Hubs, Trading Hubs, Calculation of LMP at a Hub Settlement Location, Simultaneous Feasibility, Monthly TCR Auction Clearing and Simultaneous Feasibility, Definition of Terms Protocol Version: 11.0



Revision Description There are currently no rules around the establishment of Market Hubs in the Integrated Marketplace. This MPRR is to establish the rules for the addition of Market Hubs, and to update the name of Hubs to match the Tariff naming convention of Market Hubs.


Yes – Section No: (Include a summary of impact and/or specific changes) Attachment AE: 3.1.1 Market Hub Establishment and Modification

No


Date of Vote: 9/18/2012—Approved with modifications All Segments present for the vote: Yes No Segment of Parties that voted No or Abstained: Abstained – Excel

RTWG Review

ORWG Review 10/4/2012—Approved with no reliability impact

MOPC Recommendation

Board Review

EIS Market



Date 8/31/2012

Sponsor Name Nick Parker on behalf of the MHTF E-mail Address [email protected] Company Southwest Power Pool Phone Number 501.614.3574

Comments Received Comment Author MWG Date 9/19/2012

Comment Description

The weighting factors for Trading Hubs will be determined by SPP while the weighting factors for Resource Hubs will be determined by SPP after coordinating with the MP. The language was changed to clarify this difference. Changes were made to show that the establishment of a new Trading Hub will not follow the MPRR process. A Trading Hub proposal will be submitted to the MWG and will require approval by MOPC. Since an MP can nominate any path in round three of the ARR process, language was changed regarding Resource Hubs and sinks to reflect this flexibility.

Comment Status The MPRR was approved as modified. The approved language is reflected in this recommendation report.


1. Glossary Market Clearing Price (MCP)

The price used for settlements of an Operating Reserve product in each Reserve Zone. A separate price is calculated for Regulation-Up, Regulation-Down, Spinning Reserve and Supplemental Reserve.

Market Hub

A Resource Hub or Trading Hub.

Market Participant

As defined in the SPP Tariff.

Resource

An asset that is located internal to the SPP Balancing Authority Area or that is Pseudo-Tied into the SPP Balancing Authority Area that injects Energy into the transmission grid, or which reduces the withdrawal of Energy from the transmission grid.



Resource Hub

A Settlement Location consisting of an aggregation of Resource Price Nodes developed for financial and trading purposes.

Resource Offer

For a Resource, the combination of its Start-Up Offer, No-Load Offer, Energy Offer Curve, Regulation-Up Offer, Regulation-Down Offer, Spinning Reserve Offer and Supplemental Reserve Offer.

Through Interchange Transaction

A Market Participant schedule submitted between two External Interfaces for use in the DA Market or RTBM for moving Energy through the SPP Balancing Authority Area.

Trading Hub

A Settlement Location consisting of an aggregation of Price Nodes developed for financial and trading purposes.

Transmission Congestion Right (TCR)

A financial right that entitles the holder to a share of the congestion revenue collected in the Day-Ahead Market.

4.3.1.1 DA Market Inputs Inputs to the DA Market algorithm consist of:

(1) DA Market Offers and Bids as submitted by Market Participants prior to 1100 hours Day-Ahead;

(a) For Demand Bids, Virtual Energy Bids and/or Virtual Energy Offers submitted at a Load Settlement Location that contains more than one PNode, SPP distributes the Bid MW down to the associated PNodes using weighting factors for modeling purposes as described under Section 4.1.2.1.6.

(b) For Virtual Energy Bids and/or Virtual Energy Offers submitted at a Market Hub Settlement Location and confirmed Interchange Transactions submitted at an External Interface, SPP uses a common set of weighting factors to distribute the Bid and/or Offer MWs down to PNodes included in the Market Hub or External Interface for modeling purposes. These weighting factors are determined by SPP at the time the MarketTrading Hub or External Interface is created and are not dependent upon historical injections/withdrawals. Resource Hub weighting factors are determined by SPP after coordinating with the requesting Market Participant.

(2) Resource Offers for long lead time Resources selected by SPP for commitment during the Operating Day during the Multi-Day Reliability Assessment process;

(3) Through Interchange Transactions as submitted by Market Participants and confirmed prior to 1100 hours Day-Ahead;


(4) SPP Operating Reserve requirements (system-wide and Reserve Zone min and max);

(5) SPP Transmission System topology consistent with Network Model in place for current Operating Day, including adjustments to RCF firm flow entitlements if applicable;

(6) Transmission System outages;

(7) Parallel Flow forecasts; and

(8) Resource outages.

4.5.2.3 Settlement Locations

Settlement Locations represent the next hierarchical level in the Commercial Model and have a relationship to a single PNode or APNode. Energy supply and demand is financially settled at the Settlement Locations based on the appropriate PNode or APNode LMP and Settlement Location energy injection or withdrawal level. There are four five (45) types of Settlement Locations: Resource, Load, Resource Hub, Trading Hub, and Interface.

4.5.2.3.1 Hubs Establishment

Any Market Participant may utilize a Market Hub for financial and trading purposes in the DA Market, Real-Time Balancing Market, and/or ARR/TCR process. A Market Hub is a Settlement Location representing an aggregation of PNodes as defined by this Hubs Establishment process. SPP will post the identification of any approved Market Hub prior to the proposed effective date. The effective date of any initial Market Hub will be consistent with the start of the TCR Market.

SPP shall use the following criteria to establish all Market Hubs:

(1) Each Market Hub shall contain a sufficient number of PNodes to ensure that a Market Hub

Locational Marginal Price (LMP) can be calculated for that Market Hub at all times;

(2) Each Market Hub shall contain a sufficient number of PNodes to ensure that the

unavailability of, or an adjacent line outage to, any one PNode or set of PNodes would have

only a minor impact on the Market Hub LMP;

(3) Each Market Hub shall consist of PNodes with a relatively high rate of service availability;

and

(4) Each Market Hub shall consist of PNodes among which Transmission Service is relatively

unconstrained.

If approved by MOPC, SPP shall post the approved Market Hub at least 45 days prior to the proposed

effective date. Any newly approved Market Hub will be added to the commercial model consistent with

the commercial model updates for existing Market Participants set forth in Section 6.4, provided that the

45 day window has been met.


4.5.2.3.1.1 Resource Hubs

A Resource Hub is a Settlement Location representing an aggregation of Resource PNodes as defined by the Hubs Establishment process. SPP will not limit the number of Resource Hubs established at any one time. The Resource Hub proposal may be comprised of any combination of Resource PNodes that the requesting Market Participant represents, consistent with the criteria defined in the Hubs Establishment process in Section 4.5.2.3.1. Proposals for creation of Resource Hubs shall be submitted by the Market Participants via the SPP Market Registration Portal within the Settlement Location update duration set forth in Appendix E. SPP Market Monitoring Unit will review the proposed Resource Hub for consistency with the criteria defined in the Hubs Establishment process in Section 4.5.2.3.1.

4.5.2.3.1.2 Trading Hubs

SPP must establish and maintain at least one Trading Hub in accordance with the criteria specified in the Hubs Establishment process in Section 4.5.2.3.1. In addition, any Market Participant may propose the establishment of a Trading Hub through the submission of a hub proposal to the MWG. SPP will not limit the number of Trading Hubs established at any one time. The approval process for a Trading Hub as proposed by either SPP or a Market Participant is as follows:

(1) Submission of proposal of a Trading Hub via MPRRa Trading Hub proposal to the MWG;

(2) MWG review to determine if the proposed Trading Hub should be considered for further analysis;

(3) If approved for consideration, the Trading Hub proposal will be analyzed by SPP staff based on the criteria listed in 4.5.2.3.1;

(4) SPP will bring back the results of the analysis at a subsequent meeting of the MWG for review to determine approval or rejection of the proposed Trading Hub;

(5) If approved by the MWG, the proposal will go to the MOPC for approval. following the MPRR process detailed in Section 9.0. If not approved by the MWG, the MPRRTrading Hub proposal is considered rejected;

4.5.5.1 Calculation of LMP at a Market Hub Settlement Location

SPP calculates an LMP for each Market Hub based on the LMPs for the set of PNodes that comprise the Market Hub. These Market Hub LMPs are the weighted average of the LMPs at the PNodes that comprise the Market Hub. The weighting factors for Market Hubs are pre-determined and remain fixed as described under Section 4.3.1.1. These applicable weighting factors are applied for calculating an LMP, MCCMCP and MLC at a Market Hub for both the DA Market and RTBM.

The LMP for Hubj is:

LMPHubj = ∑k

(Wk * LMPk )


The MCC for Hubj is:

MCCHubj = ∑k

(Wk * MCCk )

The MLC for Hubj is:

MLCHubj = ∑k

(Wk * MLCk )

Where:

(1) Wk is the weighting factor for Pnode PNode k which is part of Hub j. The sum of the weighting factors for all Pnodes PNodes k must sum to 1.0;

(2) LMPk is the LMP for Pnode PNode k which is part of Hub j;

(3) MCCk is the Marginal Congestion Component of the LMP for Pnode PNode k which is part of Hub j;

(4) MLCk is the Marginal Losses Component of the LMP for Pnode PNode k which is part of Hub j.

5.2.3 Simultaneous Feasibility

A Simultaneous Feasibility Test (SFT) analysis is performed in each round to ensure that the nominated candidate ARRs, with nominated candidate ARR MW modeled as generation injection at the source and a corresponding load withdrawal at the sink, do not violate any normal transmission line thermal ratings under normal system conditions and do not violate short-term Emergency transmission line thermal ratings following a single contingency (N-1 contingency analysis). The SFT is performed consistent with the transmission system loading analysis that is performed as part the Security Constrained Economic Dispatch process in the DA Market and includes consideration of the impact of Parallel Flow.

(1) The SPP Transmission System topology used in the SFT is the most up-to-date Network Model for all allocation periods, updated for forecasted transmission topology changes including planned maintenance outages.

(a) For withdrawals at sink Settlement Locations containing more than one PnodePNode, SPP will distribute the Settlement Location withdrawal down to the Pnode PNode level using load distribution percentages from the peak hour of the corresponding most recent historical period (i.e. June, July, August, September, Fall, Winter and Spring). These load distribution percentages are calculated using the methodology described under Section 4.1.2.1.6.


(b) For injections at Resource Hub source locationsMarket Hubs, SPP will distribute the Resource Hhub injection down to the PNode level on a pro-rata basis using the weighting factors defined when the Resource Hhub is created.

(2) Prior to assessing simultaneous feasibility, the normal and emergency ratings of all flowgates and monitored transmission system elements are adjusted as follows to arrive at an SPP Residual Transmission System Capability:

(a) Adjusted Monitored Transmission Line Rating (normal and Emergency) =

(Monitored Transmission Line Rating (normal and Emergency – Parallel Flow impact)

(b) Adjusted Flowgate Rating (normal and Emergency) =

(Flowgate Rating – Parallel Flow impact)

Every six (6) months for the first two (2) years after implementation of the Integrated Marketplace, SPP will analyze the net funding of TCRs through the Day-Ahead Market and report to the MWG. In the event the cumulative funding is at or below 90% or above 100%, MWG may approve an additional adjustment of all subsequent monthly auctions and the month of June in the annual auction of the normal and emergency ratings of all flowgates and monitored transmission system elements in (2) above.

5.4.3 Monthly TCR Auction Clearing and Simultaneous Feasibility

The Auction is performed using a Linear Program algorithm to maximize the total TCR auction value while ensuring that the cleared TCRs are also simultaneously feasible:

(1) The SPP Transmission System topology used in the SFT will be the most up-to-date Network Model updated for forecasted transmission topology changes, including planned maintenance outages, for the auction month;

(a) For withdrawals at sink Settlement Locations containing more than one PnodePNode, SPP will distribute the Settlement Location withdrawal down to the Pnode PNode level using load distribution percentages from the peak hour of the corresponding most recent historical period (i.e. June for the month of July). These load distribution percentages are calculated using the methodology described under Section 4.1.2.1.6.

(b) For injections at ResourceMarket Hubs source locations, SPP will distribute the Resource Huhub injection down to the PNode level on a pro-rata basis using the weighting factors defined when the Resource Hhub is created.

(2) The SFT is performed as described under Section 5.2.3 with TCR Bid MW modeled as an injection at the source and a corresponding withdrawal at the sink. TCR Offers associated with the sale of an existing TCR are modeled as an injection at the sink and a withdrawal at the source. Residual SPP Transmission System Capability includes the most up to date Parallel Flow assumptions.


(a) For Round 1, all TCRs awarded in the Annual TCR Auction for the month are modeled as fixed injections and withdrawals. To the extent that the fixed injections and withdrawals representing TCRs awarded in the Annual TCR Auction are not feasible, SPP will increase the ratings of the applicable transmission lines to ensure feasibility prior to the Round 1 auction. SPP will report back to the MWG on a quarterly basis regarding the number of times that that transmission line ratings had to be adjusted to ensure feasibility;

(b) For Round 2, all TCRs previously awarded for the month are modeled as fixed injections and withdrawals prior to clearing the TCR Bids and Offers.

Appendix F - Settlement Examples

1.2 Definition of Terms

Acronym Term Definition

AO Asset Owner The middle tier of financial entities in the CM, used for settlement statements.

BA Balancing Authority A boundary defined by internal generation control to an instantaneous NAI signal

BDR Block Demand Response Behind the meter load reduction which requires calculated response

CBA Consolidated Balancing Authority

Approach assumes the footprint will retain existing SAs for determining residual load while supplying NSI & NAI for the entire footprint to calculate the impact of NI

CC Combined Cycle (Resource)

Resource comprised of many operational configurations such as 1 gas turbine & 1 steam turbine or 2 gas turbines and 1 steam turbine etc.

CM Commercial Model The financial entities, network elements and relationships between them constructing the backbone of the market

CP Commitment Period The date/time range of a DA market or RTBM resource Market or Self commitment

COS Commercial Operations Systems

A suite of market applications including settlements, customer service and the portal

DA Day Ahead (Market) The future forward market for energy and operating reserves

DDR Dispatchable Demand Response Load reduction which can be metered

DRL Demand Response Load

A meter location discretely representing the load behind which a demand response resource is located. A DRL is not necessarily associated with a SL which will be settled, its primary function is for acceptance of metering which supports the calculated method for BDRs & BDRs

DRR Demand Response Resource BDR or DDR

EIS Energy Imbalance Service The current SPP market

FM Future Market SPP’s DA Market, RTBM and TCR Market for energy and Operating Reserves planned for implementation Q4 2012



EMS Energy Management System SPP repository and dashboard for MP SCADA data

JOU Joint Owned Unit Ownership of a physical resource shared among multiple financial entities

LRS Load Ratio Share The % of load at a single SL relative to the SPP total

MA Meter Agent Entity responsible for submittal of revenue quality interchange, resource and load meter data to settlements via the market portal

MDSL Meter Data Settlement Location

A child of SL – the level at which meter data is submitted. It is usually 1:1 with SL, but in certain cases multiple MLs may relate to a single SL. MLs are confined to a single SA (necessary for the purpose of residual & calibration calculation) while a SL may span multiple SAs.

MP Market Participant The highest tier of financial entities in the CM, used for invoicing and credit.

MS Market Settlements The system built to implement new market protocols MTR Meter Revenue Quality MWP Make Whole Payment Cost guarantees during periods of SPP economic resource commitment

MWEP Make-Whole Eligibility Period The settlement subset of a CP considered in MWP calculations

NAI Net Actual Interchange The actual net flow into or out of CBA or SA

NI Net Inadvertent The difference between the actual and scheduled net flow into or out of SPP

NSI Net Scheduled Interchange The scheduled net flow into or out of CBA or SA

OCL Over Collected Losses Settlement surplus related to marginal loss pricing, which is rebated based on payment of marginal losses.

OD Operating Day The day boundary for a single settlement period OR Operating Reserves Capacity held for regulation, spinning and supplemental reserve

POP Post Operations Processor

A rudimentary system which consists primarily of a market system database dump, and bridges the gap between RT Operations and MS

RUC Reliability Unit Commitment

Operations process and algorithm for determining which units should be started

RTBM Real Time Balancing Market

Future market for dispatch of energy and operating reserves to meet current demand

RTOSS Regional Transmission Organization Scheduling System

Manages interchange schedule data and NSI / NAI for the footprint

RNU Revenue Neutrality Uplift Market charge type for balancing daily settlement

RUC Reliability Unit Commitment

Market process for committing resources needed to meet the load forecast

SA Settlement Area A boundary within the market footprint which defines the load balance equation to determine the residual quantity

SCADA Supervisory Control And Data Acquisition 4 second resource and load bus signals from MP equipment sent to SPP

SE State Estimator An operations system which smoothes, replaces and repairs SCADA data to create complete snapshots of the transmission system every 5 minutes

SL Settlement Location Pricing points in the footprint: Resource, Load, Interface, Trading Hub & Resource Hub types



TCR Transmission Congestion Rights

The market (or instrument) for transmission planning and forward hedging of congestion rents

UOM Unit of Measure MW or MWh data submitted in 5-minute intervals

URD Uninstructed Resource Deviation Performance outside of a tolerance band from the dispatch setpoint


Add Trading Hubs and Resource Hubs definitions to the Tariff.

3.1.1 Market Hub Establishment and Modification

The Transmission Provider must establish and maintain at least one Market Hub in

accordance with the provisions of this section. In addition, the Transmission Provider may

establish additional Market Hubs. The SPP Market Monitoring Unit shall review the proposed

establishment or modification of a Resource Hub as defined in Section 4.5.2.3.1.1 of the

Protocols. The Transmission Provider shall review the proposed establishment or, modification

or deletion of a Market Trading Hub with stakeholders as defined in Section 4.5.2.3.1.2 of the

Protocols. The Markets and Operations Policy Committee will consider the proposed

establishment or, modification or deletion of a Market Hub and will provide its own

recommendation regarding such action to the SPP Board of Directors for review and approval.

After the start of the Integrated Marketplace, tThe Transmission Provider shall post any

approved establishment or, modification or deletion of a Market Hub at least six (6) months45

days prior to the proposed effective date.

The Transmission Provider shall maintain and facilitate the use of a Market Hub or

Market Hubs for the Day-Ahead Market and the RTBM, comprised of a set of nodes within the

SPP Balancing Authority Area, which nodes shall be identified by the Transmission Provider on

the Portal. The Transmission Provider shall use the following criteria to establish Market Hubs:

(1) Each Market Hub shall contain a sufficient number of nodes to ensure that a Market Hub

Locational Marginal Price (“LMP”) can be calculated for that Market Hub at all times;

(2) Each Market Hub shall contain a sufficient number of nodes to ensure that the

unavailability of, or an adjacent line outage to, any one node or set of nodes would have

only a minor impact on the Market Hub LMP;

(3) Each Market Hub shall consist of nodes with a relatively high rate of service availability;

and


(4) Each Market Hub shall consist of nodes among which Transmission Service is relatively

unconstrained.


#5g. RTWG TRR077 Recommendations to MOPC 10-16-12 - for vote Page 1 of 2


Recommendation to the Board of Directors TRR 077

October 29-30, 2012




Background Please see the TRR Recommendation Reports for TRRs 077 that were included in the MOPC October 16-17, 2012 background materials.

Analysis Please see the TRR Recommendation Reports for TRRs 077 that were included in the MOPC October 16-17, 2012 background materials.

Recommendation The MOPC recommends that the BOD approve its request regarding Tariff Revision Requests 077.

Action Requested: Approval of RTWG’s request on TRRs 077.

APPROVED MOPC October 16-17, 2012

TRR 077 Approved with one abstention-Xcel Energy


077

Compliance with the Public Policy Requirements of FERC Order 1000 for Transmission Planning Process and Transmission Owner Designation Process to be filed early November 2012.

October 4, 2012


#5g. RTWG TRR077 Recommendations to MOPC 10-16-12 - for vote Page 2 of 2


TRR Number 077 TRR

Title Order 1000 Compliance Language


Sponsor Name Dennis Reed E-mail Address [email protected] Company Westar Energy Phone Number Date 10/5/2012


Section No. Attachments O and Y Titles Tariff Version (effective date)


request)

Revision Description In order to comply with the Public Policy Requirements of FERC Order 1000,

Reason for Revision The Proposed Tariff language implements the Policies approved by the BOD regarding Order 1000


MWG BPWG (n/a) TWG (n/a) ORWG (n/a) Other (specify) (n/a) RTWG - 10/4/2012 – Approved Unanimously MOPC Board of Directors



No




No



No





No

Credit Implications


No


Yes

No


Proposed Tariff Language Revision (Redlined) D - Definitions

Delivering Party: The entity supplying capacity and energy to be transmitted at Point(s) of Receipt.

Delivery Point Transfer: The transfer of responsibility for serving an existing delivery

point from one Network Customer or Transmission Customer to a different Network Customer or Transmission Customer.

Designated Agent: Any entity that performs actions or functions required under the

Tariff on behalf of the Transmission Provider, a Transmission Owner, an Eligible Customer, or the Transmission Customer.

Designated Resource: Any designated generation resource owned, purchased or leased

by a Transmission Customer to serve load in the SPP Region. Designated Resources do not include any resource, or any portion thereof, that is committed for sale to third parties or otherwise cannot be called upon to meet the Transmission Customer's load on a non-interruptible basis.

Designated Transmission Owner (“DTO”): A Transmission Owner that has been

designated by the Transmission Provider pursuant to Attachment Y of this Tariff to construct a transmission project.

Directly Assigned Upgrade Costs: An Eligible Customer’s share of the cost of a Service Upgrade or a Project Sponsor’s share of the cost of a Sponsored Upgrade, determined in accordance with Attachments J and Z1, including: (i) any costs directly assigned to an Eligible Customer for a Service Upgrade in excess of the normally applicable transmission access charges for the associated transmission service; (ii) any costs directly assigned to an Eligible Customer that are in excess of the Safe Harbor Cost Limit for Service Upgrades associated with new or changed Designated Resource; and (iii) any costs directly assigned to a Project Sponsor for a Sponsored Upgrade.

Direct Assignment Facilities: Facilities or portions of facilities that are constructed by

any Transmission Owner(s) for the sole use/benefit of a particular Transmission Customer or a particular group of customers or a particular Generation Interconnection Customer requesting service under the Tariff. Direct Assignment Facilities shall be specified in the Service Agreements that govern service to the Transmission Customer(s) and Generation Interconnection Customer(s) and shall be subject to Commission approval.

Tariff Revision Request (TRR) Recommendation Report N - Definitions Native Load Customers: The wholesale and retail power customers of the Transmission

Owner(s) on whose behalf the Transmission Owner(s), by statute, franchise, regulatory requirement, or contract, has (have) undertaken an obligation to construct or operate the Transmission Owner's(s') system(s) to meet the reliable electric needs of such customers. In addition, Native Load Customers also may include the customers of the Federal Government on whose behalf the Government, by policy, statute, regulatory requirement, or contract, delivers Federal capacity and energy to meet all or a portion of the reliable electric needs of such customers.

Network Customer: An entity receiving transmission service pursuant to the terms of

the Transmission Provider's Network Integration Transmission Service under Part III of the Tariff.

Network Integration Transmission Service: The transmission service provided under

Part III of the Tariff. Network Load: The load that a Network Customer designates for Network Integration

Transmission Service under Part III of the Tariff. The Network Customer's Network Load shall include all load served by the output of any Network Resources designated by the Network Customer. A Network Customer may elect to designate less than its total load as Network Load but may not designate only part of the load at a discrete Point of Delivery. Where an Eligible Customer has elected not to designate a particular load at discrete points of delivery as Network Load, the Eligible Customer is responsible for making separate arrangements under Part II of the Tariff for any Point-To-Point Transmission Service that may be necessary for such non-designated load.

Network Operating Agreement: An executed agreement that contains the terms and

conditions under which the Network Customer shall operate its facilities and the technical and operational matters associated with the implementation of Network Integration Transmission Service under Part III of the Tariff.

Network Resource: Any designated generating resource owned, purchased or leased by

a Network Customer under the Network Integration Transmission Service Tariff. Network Resources do not include any resource, or any portion thereof, that is committed for sale to third parties or otherwise cannot be called upon to meet the Network Customer's Network Load on a non-interruptible basis, except for purposes of fulfilling obligations under a reserve sharing program.

Network Upgrades: All or a portion of the modifications or additions to transmission-

related facilities that are integrated with and support the Transmission Provider's overall Transmission System for the general benefit of all Users of such Transmission System.

Next-Hour-Market Service: Non-firm transmission service that (a) is reserved for one

clock hour and (b) is requested within sixty (60) minutes before the start of the next clock hour for service commencing at the start of that clock hour.

Tariff Revision Request (TRR) Recommendation Report Non-Firm Point-To-Point Transmission Service: Point-To-Point Transmission

Service under the Tariff that is reserved and scheduled on an as-available basis and is subject to Curtailment or Interruption as set forth in Section 14.7 under Part II of this Tariff. Non-Firm Point-To-Point Transmission Service is available on a stand-alone basis for periods ranging from one hour to one month.

Non-Firm Sale: An energy sale for which receipt or delivery may be interrupted for any

reason or no reason, without liability on the part of either the buyer or seller.

Notification to Construct (“NTC”): A written notice from the Transmission Provider directing an entity that has been selected to construct one or more transmission project(s) to begin or continue implementation of the transmission project(s) in accordance with Attachment Y.

P - Definitions

Part I: Tariff Definitions and Common Service Provisions contained in Sections 2

through 12.

Part II: Tariff Sections 13 through 27 pertaining to Point-To-Point Transmission

Service in conjunction with the applicable Common Service Provisions of Part I and

appropriate Schedules and Attachments.

Part III: Tariff Sections 28 through 36 pertaining to Network Integration Transmission

Service in conjunction with the applicable Common Service Provisions of Part I and

appropriate Schedules and Attachments.

Part IV: Tariff Sections 37 through 39 pertaining to special Tariff provisions related to

the applicability of the Tariff during and after the Transition Period.

Part V: Tariff Sections 40 through 42, and related Schedules and Attachments,

pertaining to recovery of costs for Base Plan Upgrades and approved Balanced Portfolios.

Tariff Revision Request (TRR) Recommendation Report Parties: The Transmission Provider and the Transmission Customer receiving service

under the Tariff.

Point(s) of Delivery: Point(s) on the Transmission Provider's Transmission System

where capacity and energy transmitted by the Transmission Provider will be made

available to the Receiving Party under Part II of the Tariff. The Point(s) of Delivery shall

be specified in the Service Agreement for Long-Term Firm Point-To-Point Transmission

Service.

Point(s) of Receipt: Point(s) of interconnection on the Transmission Provider's

Transmission System where capacity and energy will be made available to the

Transmission Provider by the Delivering Party under Part II of the Tariff. The Point(s) of

Receipt shall be specified in the Service Agreement for Long-Term Firm Point-To-Point

Transmission Service.

Point-To-Point Transmission Service: The reservation and transmission of capacity

and energy on either a firm or non-firm basis from the Point(s) of Receipt to the Point(s)

of Delivery under Part II of the Tariff.

Power Purchaser: The entity that is purchasing the capacity and energy to be

transmitted under the Tariff.

Pre-Confirmed Application: An Application that commits the Eligible Customer to

execute a Service Agreement upon receipt of notification that the Transmission Provider

can provide the requested Transmission Service.

Project Sponsor: One or more entities that voluntarily agree to bear a portion or all of

the costs of a Sponsored Upgrade.


Public Policy Requirements: Requirements established by local, state or federal laws or

regulations, including duly enacted statutes or regulations promulgated by a relevant

jurisdiction, whether within a state or at the federal level.

O - Definitions Open Access Same-Time Information System (OASIS): The information system and

standards of conduct contained in Part 37 of the Commission's regulations and all additional requirements implemented by subsequent Commission orders dealing with OASIS.

Oversight Committee: The organizational group defined in Section 6.4 of the SPP Bylaws.

Tariff Revision Request (TRR) Recommendation Report T - Definitions

Third-Party Sale: Any sale for resale in interstate commerce to a Power Purchaser that

is not designated as part of Network Load under the Network Integration Transmission Service.

Transition Period: The period from the Effective Date of this Tariff for the provision of

Network Integration Transmission Service to the last day of the fifth year thereafter. The Transition Period for a Member that is a Nebraska public-power entity shall be the period from the effective date of the transfer of functional control to the last day of the fifth year thereafter.

Transmission Customer: Any Eligible Customer (or its Designated Agent) that (i)

executes a Service Agreement, or (ii) requests in writing that the Transmission Provider file with the Commission, a proposed unexecuted Service Agreement to receive transmission service under Part II of the Tariff. This term is used in the Part I Common Service Provisions to include customers receiving transmission service under Part II and Part III of this Tariff.

Transmission Owner: Each Member of SPP: that has executed an SPP Membership Agreement as a Transmission Oowner and therefore has the obligation to construct, own, operate, and maintain transmission facilities as directed by the Transmission Provider, and: (i) whose Tariff facilities (in whole or in part) make up the Transmission System; or (ii) who has accepted a Notification to Construct but does not yet own transmission facilities under SPP’s functional control. Those Transmission Owners that are not regulated by the Commission shall not become subject to Commission regulation by virtue of their status as Transmission Owners under this Tariff; provided, however, that service over their facilities classified as transmission and covered by the Tariff shall be subject to Commission regulation.

Transmission Provider: The Southwest Power Pool, Inc., as agent for and on behalf of

the Transmission Owners. Transmission Provider's Monthly Transmission System Peak: The maximum firm

usage of the Transmission Provider's Transmission System in a calendar month. Transmission Service: Point-To-Point Transmission Service provided under Part II of

the Tariff on a firm and non-firm basis. Transmission System: The facilities used by the Transmission Provider to provide

transmission service under Part II, Part III and Part IV of the Tariff.

ATTACHMENT O TRANSMISSION PLANNING PROCESS

[EXCERPTED]

II. Roles and Responsibilities

References to the “stakeholder working group” is a generic term that references those working group(s) as defined in the SPP Bylaws, Sections 3 through 6 that are charged with the transmission planning process. The current names of all the working groups shall be posted on the SPP website.

1. Division of Responsibilities

a) The rights, powers and obligations for planning are set forth in the SPP Membership Agreement in (i) Article 2.0 for the Transmission Provider and (ii) Article 3.0 for the Members. The division of responsibility between the Transmission Provider and the Members is set forth in the SPP Criteria and in this Attachment O. The SPP Membership Agreement, the SPP Criteria and the Tariff shall be posted on the SPP website.

b) The Transmission Provider shall be responsible for developing the list of

projects in accordance with the stakeholder process set forth in Sections II, III and V of this Attachment O, and including inter-regional coordination set forth in Section VIII of this Attachment O.

c) The Transmission Provider shall perform transmission planning studies to

assess the reliability and economic operation of the Transmission System in accordance with Section III of this Attachment O.

d) As inputs to the planning process, the Transmission Provider shall include

and maintain requirements to serve existing commitments for long-term transmission service and interconnection service in accordance with Section III.7 of this Attachment O and any applicable roll-over rights as set out in Section 2.2 of the Tariff. It shall also take into account all previously approved projects.

e) The Transmission Provider shall review, and include as appropriate, all

local area upgrades to meet local area reliability criteria as proposed by the Transmission Owners including those plans developed by Transmission Owners that have their own FERC approved local planning process to ensure coordination of the projects set forth in such plans with the potential solutions developed in the regional planning process.


f) The Transmission Provider shall review and include, as appropriate, all reasonable expected demand resource, transmission, or generation options identified by stakeholders.

g) The Transmission Provider shall describe the details regarding expansion

planning methodology, criteria, assumptions and data in the SPP Transmission Expansion Planning Manual which shall be posted on the SPP website.

h) In accordance with its NERC reporting requirements, the Transmission

Provider shall publish an annual reliability report that shall include a list of the following:

i) Regional upgrades required to maintain reliability in accordance

with the NERC Reliability Standards and SPP Criteria; ii) Zonal upgrades required to maintain reliability in accordance with

more stringent individual Transmission Owner planning criteria; and

iii) Inter-regional upgrades developed with neighboring Transmission

Providers to meet inter-regional needs, including results from the coordinated system plans.

2) Stakeholder Working Groups

a) The purpose of the stakeholder working groups is to provide technical advice, assistance and oversight to the Transmission Provider in all aspects of the regional, sub-regional and local planning process, including but not limited to:

i) Review and development of coordinated planning among the

Transmission Provider and the Transmission Owners including accepted Network Upgrades developed by those Transmission Owners that have their own FERC approved local planning process to meet local area reliability criteria;

ii) Review and development of regional planning criteria; iii) Review and development of Available Transfer Capability related

calculation criteria as specified in Attachment C to the Tariff; iv) Review and development of transmission rating criteria;


v) Compliance with NERC Reliability Standards concerning transmission assessment, transfer capability and ratings of transmission facilities; and.

vi) Review and development of the list of transmission needs driven in

whole or in part by Public Policy Requirements for which transmission solutions will be evaluated.

b) All the stakeholder working group representation shall be appointed and

chaired in accordance with Article 3.0 of the SPP Bylaws. All meetings of the stakeholder working groups are open to all entities.

c) Voting in the various stakeholder working groups shall conform to Article

3.9 of the SPP Bylaws. d) The data, information, and technical support necessary for the

Transmission Provider to perform studies as required by the planning process and to develop the regional reliability projects are provided by the Transmission Owners, Transmission Customers and Generation Interconnection Customers and other entities. This process is described in Section VII of this Attachment O.

e) Stakeholder working groups that work with the Transmission Provider on

transmission planning shall meet at least quarterly and additional meetings, web conferences and teleconferences shall be scheduled as needed. Teleconference capability will be made available for stakeholder working group meetings. Notice of meetings of the stakeholder working groups shall be posted on the SPP website and distributed via email distribution lists. Meeting agendas and minutes shall be posted on the SPP website.

3) Participation by State Regulators

In accordance with the SPP Bylaws, any regulatory agency having utility rates or services jurisdiction over a Member may participate fully in all SPP planning activities.

4) Adherence to Regional Planning Criteria

i) The regional planning criteria are comprised of the NERC Reliability Standards and SPP Criteria.

ii) The regional planning criteria may change from time to time based upon

the then current process for changing reliability criteria. iii) The individual Transmission Owners shall be obligated under the NERC

Reliability Standards and SPP Criteria to resolve reliability violations and


compliance needs identified by the Transmission Provider or by the individual Transmission Owners themselves in accordance with these standards and criteria. The SPP Criteria shall be posted on the SPP website.

5) Use of Local Planning Criteria

i) Individual Transmission Owners within the SPP Region may develop

company-specific planning criteria that, at a minimum, conform to the NERC Reliability Standards and SPP Criteria.

ii) For each annual planning cycle, Transmission Owners, including those

Transmission Owners that have their own FERC approved local planning process, must provide to the Transmission Provider at least once a year, by April 1st, their company-specific planning criteria in order for the need for Zonal Reliability Upgrades to be assessed and included in the SPP Transmission Expansion Plan.

iii) Transmission Owner planning criteria and assumptions may be modified

at any time provided that, if the planning criteria are made more stringent, the increased requirements will not apply retroactively to studies previously completed or studies already underway by the Transmission Provider. Access to the individual Transmission Owner’s planning criteria shall be made available via an electronic link on the SPP website.

iv) The individual planning criteria of each Transmission Owner, including

those Transmission Owners that have their own FERC approved local planning process, shall be the basis for determining whether a reliability violation exists for which a need for a new Zonal Reliability Upgrade should be considered.

v) The Transmission Owner shall apply its local planning criteria comparably to all

load in its service territory. vi) Transmission Owners’ company-specific planning criteria and local

planning processes must provide for: (a) the identification of transmission needs driven in whole or in part by Public Policy Requirements; and (b) specifythe evaluation of potential solutions to meet those needs.

Tariff Revision Request (TRR) Recommendation Report III. The Integrated Transmission Planning Process

The ITP process is an iterative three-year process that includes 20-Year, 10-Year and Near Term Assessments. The 20-Year Assessment identifies the transmission projects, generally above 300 kV, and provides a grid flexible enough to provide benefits to the region across multiple scenarios. The 10-Year Assessment focuses on facilities 100 kV and above to meet the system needs over a ten-year horizon. The Near Term Assessment is performed annually and assesses the system upgrades, at all applicable voltage levels, required in the near term planning horizon.

1) Commencement of the Process

At the beginning of each calendar year the Transmission Provider shall notify stakeholders as to which part(s) of the integrated transmission planning cycle will take place during that year and the approximate timing of activities required to develop the SPP Transmission Expansion Plan. Notice of commencement of the process shall be posted on the SPP website and distributed via email distribution lists.

2) Transmission Planning Forums

The transmission planning forums include planning summits and sub-regional planning meetings and these are conducted as follows:

a) Planning Summits

i) The purpose of the planning summits is for the Transmission Provider and the stakeholders to share current SPP transmission network issues, develop the study scopes, provide solution alternatives and review study findings. These summits also provide an open forum where all stakeholders have an opportunity to provide advice and recommendations to the Transmission Provider to aid in the development of the SPP Transmission Expansion Plan.

ii) The planning summits shall be open to all entities.

iii) The Transmission Provider shall chair and facilitate the planning summits.

iv) Planning summits shall be held at least semi-annually, including sub-regional breakout sessions of the SPP Region. Teleconference


capability will be made available for planning summits. Planning summit web conferences shall be held as needed.

v) Notice of the planning summits and web conferences shall be posted on the SPP website and distributed via email distribution lists.

b) Sub-regional Planning Meetings

i) The Transmission Provider shall define sub-regions from time to time to address local area planning issues.

ii) The purpose of the sub-regional planning meetings is to identify unresolved local stakeholder issues and transmission solutions at a more granular level. The sub-regional planning meetings shall provide stakeholders with local needs the opportunity to provide advice and recommendations to the Transmission Provider and to the Transmission Owners. The sub-regional planning meetings shall provide a forum to review local planning criteria and needs as specified in Section II of this Attachment O.

iii) The sub-regional planning meetings shall be open to all entities.

iv) The Transmission Provider shall facilitate the sub-regional planning meetings.

v) A planning meeting shall be held at least annually for each individual sub-region.

vi) The sub-regional planning meetings shall be held in conjunction with the stakeholder working group meetings. Teleconference capability will be made available for sub-regional planning meetings. Sub-regional planning web conferences shall be held as needed.

vii) Notice of the sub-regional planning meetings, teleconferences and web conferences shall be posted on the SPP website and distributed via email distribution lists.

3) Preparation of the 20-Year Assessment


a) The Transmission Provider shall perform a 20-Year Assessment once every three years. The timing of this assessment shall generally be in the first half of each three-year cycle.

b) The 20-Year Assessment shall review the system for a twenty-year planning horizon and address, at a minimum, facilities 300 kV and above needed in year 20. This assessment is not intended to review each consecutive year in the planning horizon. The Transmission Provider shall work with stakeholders to identify the appropriate year(s) to study in developing the assessment study scope.

c) The 20-Year Assessment shall assess the cost effectiveness of proposed solutions over a forty-year time horizon.

d) The Transmission Provider shall develop the assessment study scope with input from the stakeholders. The study scope shall take into consideration the input requirements described in Section III.6.

e) The assessment study scope shall specify the methodology, criteria, assumptions, and data to be used.

f) The Transmission Provider, in consultation with the stakeholder working groups, shall finalize the assessment study scope.

g) The assessment study scope shall be posted on the SPP website and will be included in the published annual SPP Transmission Expansion Plan report. The assessment study scope shall include an explanation of which transmission needs driven by Public Policy Requirements will be evaluated for potential solutions in the local and regional transmission planning process, as well as an explanation of why other suggested transmission needs will not be evaluated.

h) In accordance with the assessment study scope, the Transmission Provider shall analyze potential solutions following the process set forth in Section III.8.

4) Preparation of the 10-Year Assessment

a) The Transmission Provider shall perform a 10-Year Assessment once every three years as part of the three year planning cycle. The timing of this assessment shall generally be in the second half of the three-year planning cycle.


b) The 10-Year Assessment shall review the system for a ten-year planning horizon and address, at a minimum, facilities 100 kV and above needed in year 10. This assessment is not intended to review each consecutive year in the planning horizon. The Transmission Provider shall work with stakeholders to identify the appropriate year(s) to study in developing the assessment study scope.

c) The 10-Year Assessment shall assess the cost effectiveness of proposed solutions over a forty-year time horizon.

d) The Transmission Provider shall develop the assessment study scope with input from the stakeholders. The study scope shall take into consideration the input requirements described in Section III.6.

e) The assessment study scope shall specify the methodology, criteria, assumptions, and data to be used.

f) The Transmission Provider, in consultation with the stakeholder working groups, shall finalize the assessment study scope.

g) The assessment study scope shall be posted on the SPP website and will be included in the published annual SPP Transmission Expansion Plan report. The assessment study scope shall include an explanation of which transmission needs driven by Public Policy Requirements will be evaluated for potential solutions in the local and regional transmission planning process, as well as an explanation of why other suggested transmission needs will not be evaluated.

h) In accordance with the assessment study scope, the Transmission Provider

shall analyze potential solutions, including those upgrades approved by the SPP Board of Directors from the most recent 20-Year Assessment, following the process set forth in Section III.8.

5) Preparation of the Near Term Assessment

a) The Transmission Provider shall perform the Near Term Assessment on an annual basis.

b) The Near Term Assessment will be performed on a shorter planning horizon than the 10-Year Assessment and shall focus primarily on identifying solutions required to meet the reliability criteria defined in Section III.6.


c) The assessment study scope shall specify the methodology, criteria, assumptions, and data to be used to develop the list of proposed near term upgrades.

d) The Transmission Provider, in consultation with the stakeholder working groups, shall finalize the assessment study scope. The study scope shall take into consideration the input requirements described in Section III.6.

e) The assessment study scope shall be posted on the SPP website and will be included in the published annual SPP Transmission Expansion Plan report. The assessment study scope shall include an explanation of which transmission needs driven by Public Policy Requirements will be evaluated for potential solutions in the local and regional transmission planning process, as well as an explanation of why other suggested transmission needs will not be evaluated.

f) In accordance with the assessment study scope, the Transmission Provider shall analyze potential solutions, including those upgrades approved by the SPP Board of Directors from the most recent 20-Year Assessment and 10-Year Assessment, following the process set forth in Section III.8.

6) Policy, Reliability, and Economic Input Requirements to Planning Studies

The Transmission Provider shall incorporate, as appropriate for the assessment being performed, the following into its planning studies:

a) NERC Reliability Standards;

b) SPP Criteria;

c) Transmission Owner-specific planning criteria as set forth in Section II;

d) Previously identified and approved transmission projects;

e) Zonal Reliability Upgrades developed by Transmission Owners, including those that have their own FERC approved local planning process, to meet local area reliability criteria;

f) Long-term firm Transmission Service;

g) Load forecasts, including the impact on load of existing and planned demand management programs, exclusive of demand response resources;

h) Capacity forecasts, including generation additions and retirements;


i) Existing and planned demand response resources;

j) Congestion within SPP and between the SPP Region and other regions and balancing areas;

k) Renewable energy standards;

l) Fuel price forecasts;

m) Energy efficiency requirements;

n) Other relevant environmental or government mandates;

o) Transmission needs driven by Public Policy Requirements identified by the Transmission Provider and stakeholders and;

op) Other input requirements identified during the stakeholder process.

pq) In developing the long term capacity forecasts, the studies will reflect generation and demand response resources capable of providing any of the functions assessed in the SPP planning process, and can be relied upon on a long-term basis. Such demand response resources shall be permitted to participate in the planning process on a comparable basis. These studies will consider operational experience gained from markets operated by the Transmission Provider.

7) Inclusion of Upgrades Related to Transmission Service and Generator Interconnection in Planning Studies

a) Transmission upgrades related to requests for Transmission Service are described in Sections 19 and 32 of the Tariff and Attachment Z1 to the Tariff. These upgrades are included as part of the future expansion of the Transmission System, upon the execution of the various Service Agreements with the Transmission Customers. Transmission upgrades related to an approved request for Transmission Service may be deferred or supplemented by other upgrades based upon the results of subsequent studies. Changes in planned upgrades do not remove the obligation of the Transmission Provider to have adequate transmission facilities available to start or continue the approved Transmission Service.

b) Interconnection facilities and other transmission upgrades related to requests for generation interconnection service are described in


Attachment V. These upgrades are included as part of the future expansion of the Transmission System upon the execution of the various interconnection agreements with the Generation Interconnection Customers. Transmission upgrades related to an approved interconnection agreement may be deferred or supplemented by other upgrades based upon the results of subsequent studies. Changes in planned upgrades do not remove the obligation of the Transmission Provider to have adequate transmission facilities available to start or continue the approved interconnection service.

c) The studies performed under this Section III of Attachment O shall accommodate and model the specific long-term firm Transmission Service of Transmission Customers and specific interconnections of Generation Interconnection Customers no later than when the relevant Service Agreements and interconnection agreements are accepted by the Commission.

8) Process to Analyze Transmission Alternatives for each Assessment

The following shall be performed, at the appropriate time in the respective planning cycle, for the 20-Year Assessment, 10-Year Assessment and Near Term Assessment studies:

a) The Transmission Provider shall perform the required studies to analyze the potential alternatives for improvements to the Transmission System, provided by the Transmission Provider and by the stakeholders, in order to address the final assessment study scope agreed to with the stakeholders. This analysis shall consider the current and anticipated future needs of the SPP Region within the parameters of the study scope. The analysis shall also consider the value brought to the SPP Region by incremental changes to the proposed solutions.

b) After the study scope has been approved, the Transmission Provider shall notify stakeholders of identified transmission needs and provide a transmission planning response window of thirty (30) days during which any stakeholder may propose a detailed project proposal (“DPP”). The Transmission Provider shall track each DPP and retain the information submitted pursuant to Section III.8.b(i). If the project described in a DPP is included in the ITP plan, the submitting stakeholder may qualify for incentive points as described in Section III of Attachment Y of this Tariff. A stakeholder that submits a DPP that is equivalent to a DPP or Transmission Provider identified project submitted in a previous


assessment during the current three (3) year planning cycle shall not be eligible for incentive points.

i) The information supplied by the stakeholder must be sufficient to allow the Transmission Provider to evaluate the project described in the DPP. At a minimum, the DPP must include the following information:

a. description of the project including one-line diagrams, configuration(s), proposed line routing, preliminary transmission line and substation engineering and design data;

b. description of the needs identified in the ITP process to be addressed;

c. proposed project schedule including, at a minimum timelines for completing regulatory, right-of-way, environmental, engineering, procurement and construction activities;

d. description of any known or anticipated risks to the project schedule and any recommended mitigation plans;

e. description of any known or anticipated environmental impacts;

f. engineering and modeling data required by the Transmission Provider;

g. identification and justification of any changes in modeling assumptions from those used in the current ITP process;

h. results of transmission project economic or reliability analysis, if applicable; and

i. any other information available to support the evaluation of the project.

ii) Any Stakeholder providing a DPP that meets the requirements set forth in Section III.8.b(i) of this Attachment O will be recorded by the Transmission Provider for the ITP planning assessment for the which the DPP was submitted, including the contact information of the stakeholder that submitted the DPP.


iii) If the Transmission Provider, in its sole discretion, determines that the information provided in a DPP is incomplete, the Transmission Provider shall provide written notice to the stakeholder that submitted the DPP. The stakeholder shall be permitted to cure the such deficiency by the later of the end of the transmission planning response window or 10 days after the Transmission Provider issues such notice. Failure to cure the deficiency shall result in the submission being disqualified as a DPP.

iv) The Transmission Provider shall hold all DPPs in confidence until the thirty (30) day transmission planning response window has closed. Subsequent to the close of the transmission planning response window, information contained in a DPP shall be disclosed to stakeholders only as the Transmission Provider determines is necessary for review and documentation of the reason(s) why the DPP was or was not chosen in the current ITP assessment. The remaining information in the DPP will remain confidential.

v. A stakeholder that submits a DPP may remain eligible for incentive points, in accordance with Section III of Attachment Y of this Tariff, for the remainder of the current three (3) year planning cycle of the ITP process. In order for the stakeholder to maintain its eligibility for incentive points in any subsequent ITP assessment within the current three (3) year planning cycle, the stakeholder must resubmit the information required by Section III.8.b(1) of this Attachment O, including identification of the need(s) in the ITP assessment that the DPP is proposed to solve. If the stakeholder does not provide the updated information, the stakeholder will not be eligible for incentive points for the DPP for that subsequent assessment; however, the stakeholder would be eligible for incentive points in any other ITP assessment during the current three (3) year planning cycle, provided that the stakeholder updates the DPP information for that assessment.

bc) For all potential alternatives provided by the stakeholders, including reliability upgrades that Transmission Owners (which, includesing those Transmission Owners that have their own FERC approved local planning process), propose to address violations of company-specific planning


criteria pursuant to Section II.5 of this Attachment O, and upgrades to address transmission needs driven in whole or in part by identified Public Policy Requirements, the Transmission Provider shall determine if there is a more comprehensive regional solution to address the reliability needs, and economic needs, and needs driven by Public Policy Requirements identified in the assessment.

cd) In addition to recommended upgrades, the Transmission Provider will consider, on a comparable basis, any alternative proposals which could include, but would not be limited to, generation options, demand response programs, “smart grid” technologies, and energy efficiency programs. Solutions will be evaluated against each other based on a comparison of their relative effectiveness of performance and economics.

de) The Transmission Provider shall assess the cost effectiveness of proposed solutions. Such assessments shall be performed in accordance with the Integrated Transmission Planning Manual, which shall be developed by the Transmission Provider, in consultation with stakeholders, and approved by the Markets and Operations Policy Committee. SPP shall post this manual on its website.

ef) The analysis described above shall take into consideration the following:

i) The financial modeling time frame for the analysis shall be 40 years (with the last 20 years provided by a terminal value).

ii) The analysis shall include quantifying the benefits resulting from dispatch savings, loss reductions, avoided projects, applicable environmental impacts, reduction in required operating reserves, interconnection improvements, congestion reduction, and other benefit metrics as appropriate.

iii) The analysis shall identify and quantify, if possible, the benefits related to any proposed transmission upgrade that is required to meet any regional reliability criteria.

iv) The analysis scope shall include different scenarios to analyze sensitivities to load forecasts, wind generation levels, fuel prices, environmental costs, and other relevant factors. The Transmission Provider shall consult the stakeholders to guide the development of these scenarios.


v) The results of the analysis shall be reported on a regional, zonal, and state-specific basis.

vi) The analysis shall assess the net impact of the transmission plan, developed in accordance with this Attachment O, on a typical residential customer within the SPP Region and on a $/kWh basis.

fg) The Transmission Provider shall make a comprehensive presentation of the preferred potential solutions, including the results of the analysis above, to the stakeholder working groups and at a planning summit meeting or web conference. The presentation shall include a discussion of all the Transmission Provider and stakeholder alternatives considered and reasons for choosing the particular preferred solutions.

gh) The Transmission Provider shall solicit feedback on the solutions from the stakeholder working groups and through the stakeholders attending the various planning summits. The Transmission Provider will also include feedback from stakeholders through other meetings, teleconferences, web conferences, and via email or secure web-based workspace. Stakeholders may propose any combination of demand resources, transmission, or generation as alternate solutions to identified reliability and economic needs.

hi) Upon consideration of the results of the cost effectiveness analysis and feedback received in the subsequent review process, the Transmission Provider shall prepare a draft list of projects for review and approval in accordance with Section V.

VI. Construction of Transmission Facilities

1) The Transmission Provider shall not build or own transmission facilities. In accordance with Section VI of this Attachment O and Attachment Y of this Tariff, Tthe Transmission Provider, with input from the Transmission Owners and other stakeholders, shall designate one or more entities to assume the responsibilities of a Transmission Owner for all Network Upgrades approved for construction under this Tariff. in a timely manner within the SPP Transmission Expansion Plan (“STEP”) one or more Transmission Owners to construct, own, and/or finance each project in the plan.

2) Any owner of Transmission Facilities, as defined in Attachment AI of this Tariff,

which are or are capable of being used by the Transmission Provider to provide transmission service pursuant to Part II and Part III of this Tariff, shall have the right to sign the SPP Membership Agreement as a Transmission Owner and


thereby acquire all of the rights and obligations of a Transmission Owner described therein, including all of the rights and obligations of a Transmission Owner described in this Tariff and specifically this Section VI.

3) Each Transmission Owner and DTO every other entity designated to construct a

project by the Transmission Provider pursuant to this Section VI shall use due diligence to construct transmission facilities as directed by the SPP Board of Directors subject to such siting, permitting, and environmental constraints as may be imposed by state, local and federal laws and regulations, and subject to the receipt of any necessary federal or state regulatory approvals. Such construction shall be performed in accordance with Good Utility Practice, applicable SPP Criteria, industry standards, the applicable Transmission Owner’s specific reliability requirements and operating guidelines (to the extent these are not inconsistent with other requirements), and in accordance with all applicable requirements of federal or state regulatory authorities. Each Transmission Owner shall be fully compensated to the greatest extent permitted by the Commission for the costs of construction undertaken by such Transmission Owner in accordance with this Tariff.

34) A specific endorsed Sponsored Upgrade in the SPP Transmission Expansion Plan

will be deemed approved for construction upon execution of a contract that financially commits a Project Sponsor to such upgrade. The Transmission Owner responsible for the Sponsored Upgrade shall be determined as follows: a) If the Sponsored Upgrade is a rebuild of an existing facility or utilizes

rights-of-way where facilities exist, the Sponsored Upgrade will be assigned to the Transmission Owner of the existing facility;

b) If the Sponsored Upgrade is a new transmission facility, the entity

sponsoring the Sponsored Upgrade may become the Transmission Owner of the facility if it meets the qualifications to become a Transmission Owner set forth in Section III.1(b) of Attachment Y, including executing an SPP Membership Agreement as a Transmission Owner; or

c) If the Transmission Owner is not determined under subsections (a) and (b)

above, the Transmission Provider will follow the process contained in Section IV of Attachment Y.

4) After a new transmission project is (i) approved under the SPP Transmission

Expansion Plan or (ii) required pursuant to a Service Agreement or (iii) required by a generation interconnection agreement to be constructed by a Transmission Owner(s) other than the Transmission Owner that is a party to the generation interconnection agreement, the Transmission Provider shall direct the appropriate Transmission Owner(s) to begin implementation of the project for which financial


commitment is required prior to the approval of the next update of the SPP Transmission Expansion Plan. At the discretion of the SPP Board of Directors, the Transmission Provider may direct the appropriate Transmission Owner(s) to begin implementation of other such approved or required transmission projects for which financial commitment is not required prior to approval of the next SPP Transmission Expansion Plan. The direction from the Transmission Provider shall be provided in writing to the Transmission Owner(s) designated to construct the project (“Designated Transmission Owner(s)”). The written notification to the Designated Transmission Owner(s) shall include but not be limited to: (1) the specifications of the project required by the Transmission Provider and (2) a reasonable project schedule, including a project completion date (“Notification to Construct”). If the project forms a connection with facilities of a single Transmission Owner, that Transmission Owner shall be designated to construct the project. If the project forms a connection with facilities owned by multiple Transmission Owners, the applicable Transmission Owners will be designated to provide their respective new facilities. If there is more than one Transmission Owner designated to construct a project, the Designated Transmission Owners will agree among themselves which part of the project will be provided by each entity. If the Designated Transmission Owners cannot come to a mutual agreement regarding the assignment and ownership of the project the Transmission Provider will facilitate their discussion. Each project or segment of a project being built by a single Designated Transmission Owner shall be considered a separate project for purposes of Section VI.6 and each Designated Transmission Owner will receive a separate Notification to Construct for each project or segment of a project they are responsible to construct.

5) Network Upgrade(s) and Distribution Upgrades (as defined in Attachment V to

the Tariff) identified in a generation interconnection agreement will be constructed pursuant to the generation interconnection agreement or pursuant to Section VI.4 of this Attachment OY of this Tariff. Network Upgrades and Distribution Upgrades (as defined in Attachment V to the Tariff) identified in a generation interconnection agreement required to be constructed by the Transmission Owner who is a party to the generation interconnection agreement shall be constructed pursuant to the generation interconnection agreement. All other Network Upgrades and Distribution Upgrades (as defined in Attachment V to the Tariff) identified in a generation interconnection agreement to be constructed by Transmission Owners not a party to the generation interconnection agreement shall be constructed pursuant to Section VI.4I IV of this Attachment OY of this Tariff.

6) In order to maintain its right to construct the project, the Designated Transmission

Owner shall respond within ninety (90) days after the receipt of the Notification to Construct with a written commitment to construct the project as specified in the Notification to Construct or a proposal for a different project schedule and/or alternative specifications in its written commitment to construct (“Designated Transmission Owner’s proposal”). The Transmission Provider shall respond to


the Designated Transmission Owner’s proposal within ten (10) days of its receipt of the proposal. If the Transmission Provider accepts the Designated Transmission Owner’s proposal, the Notification to Construct will be modified according to the accepted proposal and the Designated Transmission Owner shall construct the project in accordance with the modified Notification to Construct. If the Transmission Provider rejects the Designated Transmission Owner’s proposal, the Designated Transmission Owner’s proposal shall not be deemed an acceptable written commitment to construct the project. However, the Transmission Provider’s rejection of such proposal shall not preclude a Designated Transmission Owner from providing a written commitment to construct the project after such rejection, provided the subsequent written commitment to construct the project is made within the ninety day time period after the issuance of the Notification to Construct.

If a Designated Transmission Owner does not provide an acceptable written commitment to construct within the ninety (90) day period, the Transmission Provider shall solicit and evaluate proposals for the project from other entities and select a replacement designated provider. The Transmission Provider shall solicit proposals from entities that meet certain specified legal, regulatory, technical, financial and managerial qualifications, specifically including the following: i) Entities that have obtained all state regulatory authority necessary to

construct, own and operate transmission facilities within the state(s) where the project is located,

ii) Entities that meet the creditworthiness requirements of the Transmission

Provider, iii) Entities that have signed or are capable and willing to sign the SPP

Membership Agreement as a Transmission Owner upon the selection of its proposal to construct and own the project, and

iv) Entities that meet such other technical, financial and managerial

qualifications as are specified in the Transmission Provider’s business practices.

The Transmission Provider shall evaluate each proposal with regard to the cost, reliability and timeliness of the proposed construction of the project and shall make a recommendation to the Board of Directors. The Board of Directors shall thereafter select an entity making a proposal and arrange for that entity to construct the project and become the Designated Transmission Owner. At any time, a Designated Transmission Owner may elect to arrange for another entity or another existing Transmission Owner to build and own all or part of the project in its place subject to the qualifications in Subsections i, ii, iii, and iv above.


Nothing in this Section VI.6 shall relieve a Transmission Owner of its obligation to construct an upgrade as specified in Section VI.2 of this Attachment O and Section 3.3(a) of the SPP Membership Agreement in the event that no other qualified entity can be found to construct the project.

Tariff Revision Request (TRR)

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ADDENDUM 2 TO ATTACHMENT O

ENROLLMENT IN THE SPP TRANSMISSION PLANNING REGION The following entities have elected to become part of the SPP transmission planning region: [LIST OF TOs and SWPA]

ATTACHMENT Y TRANSMISSION OWNER DESIGNATION PROCESS

I. OVERVIEW OF TRANSMISSION OWNER DESIGNATION PROCESS

1) The Transmission Provider shall designate a Transmission Owner in accordance

with the process set forth in Section III of this Attachment Y for transmission facilities approved for construction by the SPP Board of Directors that meet all of the following criteria: a) Transmission facilities that are ITP Upgrades or high priority upgrades; b) Transmission facilities with a nominal operating voltage of 300 kV or

greater; c) Transmission facilities that are not a rebuild of an existing facility and do

not use rights-of-way where facilities exist; and d) Transmission facilities located where the selection of a Transmission

Owner pursuant to Section III of this Attachment Y does not violate relevant law where the transmission facility is to be built.

2) For any upgrade meeting the specifications listed in Section I.1 of this Attachment

Y, the Transmission Provider may, subject to approval by the SPP Board of Directors, designate the Transmission Owner(s) in accordance with Section IV of this Attachment Y if the following conditions are met: (i) the transmission facility is needed for the reliability of the grid; (ii) the transmission facility has a need date that cannot be met if the Transmission Owner Selection Process in Section III of this Attachment Y is followed; and (iii) no other transmission or non-transmission mitigation options are available to relieve the reliability issue to allow sufficient time for the Transmission Owner Selection Process to proceed.


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3) For any upgrade not defined in Section I.1 of this Attachment Y, the Transmission Provider shall designate the Transmission Owner(s) in accordance with the process set forth in Section IV of this Attachment Y.

4) The designation from the Transmission Provider shall be provided pursuant to

Section V of this Attachment Y. 5) The Transmission Provider shall track all projects that are approved for

construction in accordance with Section VI of this Attachment Y.

II. DEFINITIONS

The terms used in this Attachment Y shall have the meanings as defined in this Section II or as otherwise defined in this Tariff. Applicant: An entity that has submitted an application to the Transmission Provider to be a Qualified RFP Participant.

Competitive Upgrades: Those upgrades defined in Section I.1 of this Attachment Y or an upgrade for which the Transmission Provider must select a replacement Transmission Owner pursuant to Section IV.3 of this Attachment Y.

Guaranty: This term shall have the meaning given in Attachment X of this Tariff. Guarantor: This term shall have the meaning given in Attachment X of this Tariff. Industry Expert Panel: The panel of industry experts designated by the Oversight Committee to review and evaluate proposals submitted in response to any Request for Proposals in the Transmission Owner Selection Process.

Not-For-Profit: This term shall have the meaning given in Attachment X of this Tariff.

Qualified RFP Participant (“QRP”): An entity that has been determined by the Transmission Provider to satisfy the qualification criteria set forth in Section III.1 of this Attachment Y.

Transmission Owner Selection Process: The process of determining the Transmission Owner for Competitive Upgrades pursuant to Section III.2 of this Attachment Y.


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III. TRANSMISSION OWNER SELECTION PROCESS FOR COMPETITIVE

UPGRADES 1) Application and Qualification Process

a) Application

Any entity that desires to participate in the Transmission Owner Selection Process outlined in this Section III must submit an application and supporting materials to demonstrate that it satisfies the qualification criteria set forth in this Section III. The Transmission Provider will evaluate the Applicant’s application and supporting materials to determine whether the Applicant satisfies the qualification criteria to be a QRP and participate in the Transmission Owner Selection Process in accordance with the timeline set out in Section III.1(c) of this Attachment Y.

i) Any entity wishing to participate in the Transmission Owner

Selection Process, whether a current Transmission Owner or another entity, must submit an application to the Transmission Provider in the form provided on the Transmission Provider’s website. The initial application must be received no later than June 30 of the year prior to the calendar year in which the Applicant wishes to begin participation in the Transmission Owner Selection Process. The Applicant shall submit an application fee with its application equal to the amount of the SPP annual membership fee. If the Applicant is a Member of SPP and is current in payment of its annual membership fee, then no application fee shall be required. The amount of the application fee shall be posted on the Transmission Provider’s website as part of the application form.

ii) After the Transmission Provider determines that the entity is

qualified to be a QRP, the entity shall remain a QRP for the five calendar years starting January 1 subsequent to that determination, subject to the annual certification process in Section III.1(d) of this Attachment Y and termination process set forth in Section III.1(e) of this Attachment Y. To be considered for continuation of QRP status for the subsequent five (5) year period, the QRP must submit a full application package in accordance with Section III.1(a)(i) of this Attachment Y by June 30 of the fifth year of the current period. The Transmission Provider shall evaluate the application in accordance with Section III.1(c) of this Attachment Y.


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iii) Any application from an Applicant will be posted on the

Transmission Provider’s website no later than July 15 of each year, subject to any applicable confidentiality protections.

b) Qualification Criteria

An Applicant must demonstrate that it meets the following qualification criteria:

i) SPP Membership Criterion

An Applicant must be a Transmission Owner or be willing to sign the SPP Membership Agreement as a Transmission Owner if the Applicant is selected as part of the Transmission Owner Selection Process.

ii) Financial Criteria

An Applicant must demonstrate that it meets one of the following financial criteria:

(1) A senior unsecured investment grade rating or an issuer

rating of BBB- or equivalent from a “nationally recognized statistical rating organization” as defined in Attachment X of this Tariff. If an Applicant maintains a rating from all three approved nationally recognized statistical rating organizations, it must maintain at least two ratings in the investment grade range. If an Applicant maintains a rating from two of the approved nationally recognized statistical rating organizations, it must maintain at least one of those ratings in the investment grade range.

(2) If the Applicant does not satisfy the requirement set forth in

(1) above, the Applicant may submit to the Transmission Provider a Guaranty from its parent or affiliated organization that possesses an investment grade rating or an issuer rating of BBB- or equivalent from a “nationally recognized statistical rating organization” as defined in Attachment X of this Tariff. A Guaranty obligates the Guarantor to satisfy the obligations of the guarantee entity. Parent Guaranties are acceptable where the Applicant is a subsidiary, joint venture, or affiliate of the parent


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Guarantor. The Guaranty may be cancelled at any time that the Applicant establishes an investment grade rating as discussed in Section III.1(b)(ii)(1) of this Attachment Y. The Guaranty will be in a form consistent with Appendix D of Attachment X of this Tariff and must satisfy the following requirements:

(a) Be duly authorized by the Guarantor and

signed by an officer of the Guarantor; (b) State a minimum effective period of five (5)

years, or provide for automatic renewal subject to cancellation with no less than sixty (60) days notice, provided that in all events the Guaranty is effective for all obligations of the Applicant undertaken prior to cancellation;

(c) Include a certification by the corporate

secretary of the Guarantor that the execution, delivery, and performance of the Guaranty have been duly authorized;

(d) Certify that the Guaranty does not violate

other undertakings or requirements applicable to the Guarantor and is enforceable against the Guarantor in accordance with its terms;

(e) Obligate the guarantor to submit a

representation letter annually indicating any material changes from the information provided in the Applicant’s application related to the Guarantor and Guaranty, and representing that the Guarantor continues to satisfy the financial criteria;

(f) Secure all obligations of the Applicant under

or in connection with this Tariff and other agreements with the Transmission Provider;

(g) Be supported by adequate consideration and

be otherwise binding as a matter of law; and


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(h) Include as an attachment a resolution of the

board of directors or other governing body of the Guarantor authorizing the Guaranty.

(3) If the Applicant does not satisfy the requirements set forth

in (1) or (2) above, the Applicant may submit to the Transmission Provider a formal letter of reference from a commercial bank evidencing an existing line of credit from commercial banks (or access to an existing line of credit through Inter-company agreements with a Parent or Affiliate), or bonding indication letter from an insurance or surety company either of which indicate a willingness to extend credit to the Applicant in an amount of at least $25,000,000 (for bank) or willingness to provide a surety bond in the amount of at least $25,000,000 (for an insurance or surety company). Commercial bank reference letters acceptable to the Transmission Provider must be issued by a financial institution organized under the laws of the United States or any state of the United States or the District of Columbia or a branch or agency of a foreign commercial bank located in the United States, with a minimum corporate debt rating of A- or equivalent from a “nationally recognized statistical rating organization” as defined in Attachment X of this Tariff and total assets of at least $10 billion. Bonding indication letters acceptable to the Transmission Provider must be issued by an insurance or surety company with a minimum financial strength rating of A- and a minimum financial size category of X from the A.M. Best Company.

(4) If the Applicant is a municipality, a cooperative, or other

Not-For-Profit entity, the Applicant may satisfy the financial criteria requirement by providing evidence of direct rate-setting authority or taxing authority. The Applicant must possess this authority and cannot rely on an affiliation with another entity that possesses rate-setting or taxing authority.

iii) Managerial Criteria


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An application must show that the Applicant has requisite expertise by describing its capability, experience, and process to address the following areas:

(1) Transmission Project Development

(a) engineering, permitting, environmental, equipment and material procurement, project management (including cost control, scope, and schedule management), construction, commissioning of new facilities, new or emerging technologies; and

(b) routing, surveying, rights-of-way, eminent domain,

and real estate acquisition, including process for obtaining easements.

(2) Internal safety program, contractor safety program, safety

performance record and program execution.

(3) Transmission Operations: control center operations, NERC compliance process and compliance history, registration or the ability to register for compliance with applicable NERC Reliability Standards, storm/outage response and restoration plan, record of past reliability performance, statement of which entity will be operating completed transmission facilities, staffing, equipment, and crew training.

(4) Transmission Maintenance: staffing and crew training,

transmission facility and equipment maintenance, record of past maintenance performance, NERC compliance process and history, statement of which entity will be performing maintenance on completed transmission facilities.

(5) Ability to comply with Good Utility Practice, SPP Criteria,

NERC Reliability Standards, industry standards, and applicable local, state, and federal requirements.

(6) Any other relevant project development experience that the

Applicant believes may demonstrate its expertise in the above areas.


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An Applicant can demonstrate that it meets the managerial criteria either on its own or by relying on an entity or entities with whom it has a corporate affiliation or contractual relationship (“Alternate Qualifying Entity(ies)”). If the Applicant seeks to satisfy the managerial criteria in whole or in part by relying on one or more Alternate Qualifying Entity(ies), the Applicant must submit: (1) materials demonstrating to the Transmission Provider’s satisfaction that the Alternate Qualifying Entity(ies) meet(s) the managerial criteria for which the Applicant is relying upon the Alternate Qualifying Entity(ies) to satisfy; and (2) an executed agreement that contractually obligates the Alternate Qualifying Entity(ies) to perform the function(s) for which the Applicant is relying upon the Alternate Qualifying Entity(ies) to satisfy.

c) Determination of Qualifications

i) Upon receiving an application, the Transmission Provider shall review the application to determine whether the Applicant satisfies the qualification criteria set forth in Section III 1(b) of this Attachment Y. The Transmission Provider shall notify each Applicant of its determination no later than September 30 of the year in which the application was submitted.

ii) If the Transmission Provider determines that the Applicant fails to

satisfy one or more of the qualification criteria, the Transmission Provider shall inform the Applicant of such deficiency(ies), and the Applicant shall be allowed to cure any deficiency(ies) within thirty (30) calendar days of notice from the Transmission Provider by providing any additional information that the Applicant believes cures the deficiency(ies). The Transmission Provider shall review the information provided by the Applicant and render a final determination of whether the Applicant satisfies the qualification criteria within forty-five (45) calendar days of the Transmission Provider’s receipt of the additional information. If, after attempting to cure the deficiency(ies), the Applicant still has not satisfied the qualification criteria, the Applicant shall be disqualified from the Transmission Owner Selection Process for the following year.

iii) Upon the Transmission Provider’s determination that an Applicant

satisfies the qualification criteria, the Transmission Provider shall notify the Applicant that it has been determined to be a QRP and can participate in the Transmission Owner Selection Process


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effective January 1 of the following calendar year. By December 31 of each year, the Transmission Provider shall post on its website a list of all QRPs that are eligible to participate in the following calendar year for any Competitive Upgrade.

d) Annual Recertification Process and Reporting Requirements

i) By June 30 of each year, each QRP must submit to the Transmission Provider a notarized letter signed by an authorized officer of the QRP certifying that the QRP continues to meet the current qualification criteria or indicating any material changes to the information provided in its application. The QRP shall pay an annual certification fee equal to the amount of the SPP annual membership fee. If the QRP is a Member of SPP and is current in payment of its annual membership fee, then no certification fee will be required.

ii) If at any time there is a change to the information provided in its

application, a QRP shall be required to inform the Transmission Provider within seven (7) calendar days of such change so that the Transmission Provider may determine whether the QRP continues to satisfy the qualification criteria. Upon notification of any such change, the Transmission Provider shall have the option to: (a) determine that the change does not affect the QRP’s status; (b) suspend the QRP’s eligibility to participate in the Transmission Owner Selection Process until the QRP has cured any deficiency in its qualifications to the Transmission Provider’s satisfaction; (c) allow the QRP to continue to participate in the Transmission Owner Selection Process for a limited time period, as specified by the Transmission Provider, while the QRP cures the deficiency to the Transmission Provider’s satisfaction; or (d) terminate the QRP status in accordance with Section III.1(e) of this Attachment Y.

e) Termination of QRP Status

The Transmission Provider may terminate a QRP’s status if the QRP: (1) fails to submit its annual certification letter; (2) fails to pay the applicable fee as required by Section III.1(d) of this Attachment Y; (3) experiences a change in its qualifications and the Transmission Provider determines that it may no longer be a QRP; or (4) informs the Transmission Provider that it no longer desires to be a QRP; or (5) fails to notify the Transmission


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Provider of a change to the information provided in its application in accordance with Section III.1(d) of this Attachment Y.

f) Dispute Resolution

If the Applicant or QRP (“Affected Party”) disagrees with the Transmission Provider’s determination regarding its qualifications under Section III.1 of this Attachment Y, the Affected Party may initiate dispute resolution procedures. Any such dispute shall first be referred to a designated senior representative of the Transmission Provider and a senior representative of the Affected Party for resolution on an informal basis as promptly as practicable. In the event the designated representatives are unable to resolve the dispute within thirty (30) calendar days (or such other period upon which the Transmission Provider and the Affected Party may agree) by mutual agreement, such dispute may be submitted to arbitration and resolved in accordance with the arbitration procedures set forth in Sections 12.2 through 12.5 of this Tariff.

2) Transmission Owner Selection Process a) Overview

Once a Competitive Upgrade has been approved by the SPP Board of Directors, the Transmission Provider shall issue a Request for Proposals (“RFP”) for the Competitive Upgrade as specified in this Section III of Attachment Y.

b) Industry Expert Panel

i) On an annual basis, the Oversight Committee or its successor shall identify a pool of candidates to serve as industry experts on one or more Industry Expert Panel(s) (“IEP”) to evaluate proposals that are submitted in response to any RFP issued by the Transmission Provider pursuant to this Section III of Attachment Y. IEP candidates shall have documented expertise on file with the Transmission Provider in one or more of the following areas: (1) electric transmission engineering design; (2) electric transmission project management and construction; (3) electric transmission operations; (4) electric transmission rate design and analysis; and (5) electric transmission finance.


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ii) Each industry expert must disclose to the Oversight Committee any affiliation with any SPP stakeholder or any QRP. In the event an affiliation exists, the Oversight Committee will evaluate whether the affiliation may adversely impact an industry expert’s ability to independently evaluate RFP proposals, and the Oversight Committee may disqualify that industry expert.

iii) The Oversight Committee shall present its recommended pool of

IEP candidates to the SPP Board of Directors for approval. The name and qualifications of each recommended candidate shall be posted on the Transmission Provider’s website prior to SPP Board of Directors approval. Approval of the IEP candidate pool shall be made prior to the meeting in which a Competitive Upgrade is to be approved.

iv) The Oversight Committee shall create an IEP from the IEP

candidate pool to evaluate proposals resulting from the RFPs. The IEP shall consist of three (3) to five (5) industry experts such that the IEP will have expertise in all five (5) areas listed in Section III.2(b)(i) of this Attachment Y. Upon SPP Board of Directors approval, the Oversight Committee may create additional IEPs. Each IEP member must sign a confidentiality agreement prior to participating in the Transmission Owner Selection Process.

v) If a member of a designated IEP becomes affiliated with a

stakeholder or QRP, the IEP member shall immediately notify the Transmission Provider and the Oversight Committee. The Oversight Committee shall evaluate whether any affiliation between a member of a designated IEP and a stakeholder or QRP may adversely impact the IEP member’s ability to independently evaluate RFP proposals reviewed by that IEP. In such event, the Oversight Committee may remove the IEP member from that IEP. If necessary, the Oversight Committee may designate a replacement IEP member from the IEP candidate pool.

vi) The Transmission Provider shall facilitate the IEP’s efforts to

develop recommendations to the SPP Board of Directors. The IEP will evaluate all aspects of each proposal submitted for its review. Once all evaluations are complete, the IEP will develop a single recommendation for the SPP Board of Directors consisting of its recommended RFP proposal and an alternate RFP proposal for each Competitive Upgrade.


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c) Request for Proposals

The Transmission Provider shall issue an RFP for each Competitive Upgrade, which shall contain information including, but not limited to:

i) An overview of the purpose for the RFP including the need for the

Competitive Upgrade, regulatory context and authority, and other necessary information.

ii) A deadline for all RFP proposal submissions and minimum RFP

proposal submission requirements.

iii) Minimum design specifications. iv) The date regulatory approvals are required to be completed as

determined by the Transmission Provider.

v) A requirement that the QRP provide the following information specific to the Competitive Upgrade for which it submits a proposal:

(1) financial information, including but not limited to

demonstration of financing (including a reasonable contingency), detailed engineering and construction cost estimate, itemized revenue requirement calculations, and financial and business plans, including the nature of any FERC incentives the QRP intends to request;

(2) engineering information, including but not limited to

engineering design of the project and technical requirements;

(3) construction information, including but not limited to

anticipated project timeline including timeline for all necessary regulatory approvals, equipment acquisition, description of applicable rights-of-way and real estate acquisition, description of routing, description of permitting, description of outage clearance(s), and identification of the party responsible for construction;

(4) operations and maintenance information, including but not

limited to demonstration of operations, statement of which entity will be operating and maintaining the transmission


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facility, storm and outage response plan, maintenance plan, staffing, equipment, crew training, and record of past maintenance and outage restoration performance;

(5) safety information, including but not limited to

identification of the internal safety program, contractor safety program, and safety performance record; and

(6) identification of information in the RFP proposal that the

RFP respondent considers to be confidential.

vi) A requirement that the QRP demonstrate its financial strength by providing one of the following:

(1) demonstration that the QRP continues to satisfy the

financial criteria set forth in Section III.1(b)(ii)(1) or (2) of this Attachment Y and that the Competitive Upgrade does not exceed 30% of the total capitalization of the QRP or its parent Guarantor;

(2) a performance bond from an insurance/surety company

acceptable to the Transmission Provider in an amount equal to the total cost of the Competitive Upgrade, including financing costs, and a 30% contingency;

(3) a letter of credit from a financial institution acceptable to

the Transmission Provider in an amount equal to the total cost of the Competitive Upgrade, including financing costs, and a 30% contingency; or

(4) a demonstration that the QRP would otherwise be

designated by the Transmission Provider as a DTO for the Competitive Upgrade pursuant to Section IV of this Attachment Y.

vii) Information exchange requirements including but not limited to,

identification of data required to be provided to the Transmission Provider in accordance with NERC reliability standards and CEII requirements.

viii) A description of the proposal evaluation procedure, including the

statement of proposal evaluation methodology and criteria for acceptable proposals.


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ix) A requirement that the QRP agrees to pay the RFP fee for each

RFP proposal submitted, as outlined in Section III.2(e) of this Attachment Y, including the initial deposit at the time of submission of the RFP proposal.

x) A requirement that the QRP disclose any credit rating changes,

bankruptcies, dissolutions, mergers, or acquisitions within the past five (5) years of the QTO or its parent, controlling shareholder, or entity providing a Guaranty pursuant to Section III.1(b)(ii)(2) of this Attachment Y.

d) RFP Process and Timeline

i) The Transmission Provider shall issue each RFP by or before the later of: (1) seven (7) calendar days after approval of the Competitive Upgrade by the SPP Board of Directors; or (2) eighteen (18) months prior to the date that anticipated financial expenditure is needed for a Competitive Upgrade. The RFP shall be issued only to QRPs.

ii) Each RFP respondent shall submit a complete proposal in response

to the RFP within ninety (90) calendar days from the date the RFP is issued (“RFP Response Window”).

iii) The Transmission Provider shall not disclose any information

contained in any RFP proposal, except to the IEP, until the issuance of the IEP reports in accordance with Section III.2(d)(vi)(2) of this Attachment Y.

iv) Upon receipt of an RFP proposal, the Transmission Provider shall

immediately review the proposal for completeness, and shall promptly notify the RFP respondent if its proposal is incomplete. The RFP respondent may submit information in order to complete the proposal if such submittal is made within the RFP Response Window. Any RFP respondent that fails to submit a complete proposal within the RFP Response Window will be deemed to have waived its right to respond to the RFP.

v) If the Transmission Provider does not receive any complete

proposals in response to an RFP, the Transmission Provider shall inform the SPP Board of Directors and shall select the DTO in


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accordance with the process set forth in Section IV of this Attachment Y.

vi) Upon the closing of the RFP Response Window, the Transmission

Provider shall provide the RFP proposals to the IEP. The IEP shall review, score, and rank all RFP proposals and submit its recommendation to the SPP Board of Directors based upon selection criteria outlined in Section III.2(f) of this Attachment Y. The identity of RFP respondents that submitted the RFP proposals shall not be disclosed to the SPP Board of Directors as part of the IEP’s recommendation. The IEP’s recommendation shall be submitted to the SPP Board of Directors within sixty (60) calendar days of the initiation of the IEP’s review (“Review Period”). Upon IEP request, the Oversight Committee may extend the Review Period an additional thirty (30) calendar days. Notification of such extension shall be provided to the SPP Board of Directors and posted on the Transmission Provider’s website.

(1) During its review, the IEP may initiate communication with

RFP respondents to obtain answers to any additional questions about proposals, and any such communications shall be documented by the IEP. Lobbying of the IEP by, or on behalf of, any RFP respondent is prohibited, and may result in disqualification of the RFP respondent by the Transmission Provider from the RFP process. The IEP shall score and rank each RFP proposal in a non-discriminatory manner based upon the information supplied in the RFP proposal or obtained during the Review Period.

(2) The IEP shall compile an internal report for the

Transmission Provider detailing the process, data, results of its deliberations, and its recommended RFP proposal and an alternate RFP proposal for each Competitive Upgrade. The Transmission Provider shall be responsible for producing two redacted versions of the internal report, a Board of Directors report and a public report. The Board of Directors report shall exclude the names of the RFP respondents. The public report shall exclude the names of RFP respondents and any confidential information obtained during the Transmission Owner Selection Process. No later than fourteen (14) calendar days prior to the SPP Board of Directors meeting during which the SPP Board of Directors will consider the IEP recommendation, the public report


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shall be posted on the Transmission Provider’s website and the Board of Directors report shall be provided to the SPP Board of Directors.

vii) The SPP Board of Directors shall select an RFP proposal

(“Selected RFP Proposal”) and an alternate RFP proposal for each Competitive Upgrade based primarily on the information provided by the IEP. The Transmission Provider shall notify the RFP respondent that submitted the Selected RFP Proposal that it has been chosen by the SPP Board of Directors to become the DTO for the Competitive Upgrade (“Selected RFP Respondent”) and the Transmission Provider shall issue an NTC for the Competitive Upgrade pursuant to Section V of this Attachment Y. To become the DTO for the Competitive Upgrade, the Selected RFP Respondent must, within seven (7) calendar days of receiving such notice: (1) sign any necessary agreement(s) to assume all of the responsibilities of a Transmission Owner related to the Competitive Upgrade pursuant to the SPP Membership Agreement and this Tariff; (2) submit to the Transmission Provider a deposit in accordance with Section III.2(d)(xii) of this Attachment Y; and (3) provide written notification to the Transmission Provider that it accepts the NTC.

viii) The Selected RFP Respondent shall be deemed to have waived its

right to become the DTO if, within seven (7) calendar days of receiving such notice, the Selected RFP Respondent: (1) does not respond to such notice from the Transmission Provider; (2) notifies the Transmission Provider that it is no longer willing to become the Transmission Owner for the Competitive Upgrade; (3) fails to sign the necessary agreement(s); (4) fails to provide a deposit in accordance with Section III.2(d)(xii) of this Attachment Y; or (5) fails to provide written notification to the Transmission Provider that it accepts the NTC. In such circumstances, the Transmission Provider shall notify the SPP Board of Directors.

ix) If the Selected RFP Respondent has waived its right to become the

DTO pursuant to Section III.2(d)(viii) of this Attachment Y, the Transmission Provider shall notify the RFP respondent that submitted the alternate RFP proposal that it has been chosen by the SPP Board of Directors to become the DTO for the Competitive Upgrade, and the Transmission Provider shall issue an NTC for the Competitive Upgrade pursuant to Section V of this Attachment Y. To become the DTO for the Competitive Upgrade, the RFP


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respondent that submitted the alternate RFP proposal must, within seven (7) calendar days of receiving such notice: (1) sign any necessary agreement(s) to assume all of the responsibilities of a Transmission Owner related to the Competitive Upgrade pursuant to the SPP Membership Agreement and this Tariff; (2) submit to the Transmission Provider a deposit in accordance with Section III.2(d)(xii) of this Attachment Y; and (3) provide written notification to the Transmission Provider that it accepts the NTC.

x) The RFP respondent that submitted the alternate RFP proposal

shall be deemed to have waived its right to become the DTO if, within seven (7) calendar days of receiving such notice, the RFP respondent that submitted the alternate RFP proposal: (1) does not respond to such notice from the Transmission Provider; (2) notifies the Transmission Provider that it is no longer willing to become the Transmission Owner for the Competitive Upgrade; (3) fails to sign the necessary agreement(s); (4) fails to provide a deposit in accordance with Section III.2(d)(xii) of this Attachment Y; or (5) fails to provide written notification to the Transmission Provider that it accepts the NTC. In such circumstances, the Transmission Provider shall notify the SPP Board of Directors, and the Transmission Provider shall determine the DTO in accordance with the process set forth in Section IV of this Attachment Y.

xi) The DTO for a Competitive Upgrade cannot assign the

Competitive Upgrade to another entity.

xii) When accepting the responsibilities of being a DTO for a Competitive Upgrade, the Selected RFP respondent shall provide the following to the Transmission Provider:

(1) a cash deposit representing 2% of the estimated cost

of the Selected RFP Proposal; and (2) a firm capital commitment acceptable to the

Transmission Provider that is sufficient to complete the Competitive Upgrade.

The cash deposit shall be held in escrow by the Transmission Provider. Upon reaching the 50% completion milestone of the Competitive Upgrade, as determined by the Transmission Provider, the Transmission Provider shall refund the deposit, plus


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any interest the deposit accrued while in escrow, to the DTO. If the DTO fails to reach the 50% completion milestone of the Competitive Upgrade in accordance with Section III.2(g) of this Attachment Y, then the DTO shall forfeit the deposit and any accrued interest. The Transmission Provider shall then select a new DTO in accordance with Section III.2(g) and apply the deposit and accrued interest to reduce the final cost of the Competitive Upgrade. If the Transmission Provider cancels the Competitive Upgrade through no fault of the DTO, then the Transmission Provider shall refund the deposit and accrued interest to the DTO.

e) RFP Fee

Each RFP proposal shall be assessed a fee to compensate the Transmission Provider for all costs incurred to administer the RFP process for each Competitive Upgrade. Initially, each RFP respondent shall submit a deposit with each proposal, which shall be equal to the Transmission Provider’s estimate of the fee for participation in the RFP process. The actual RFP costs will be determined at the completion of the process, and all RFP respondents will make additional payments or obtain refunds based on the reconciliation of deposits collected and actual RFP costs. The costs shall be allocated to each proposal on a pro-rata share basis, calculated by taking the total RFP process costs for each Competitive Upgrade and dividing by the number of proposals submitted for that Competitive Upgrade.

f) Transmission Owner Selection Criteria and Scoring

i) The IEP will develop a final score for each RFP proposal and

provide its recommended RFP proposal and an alternate RFP proposal to the SPP Board of Directors for each Competitive Upgrade. The IEP evaluation and recommendation shall not be administered in an unduly discriminatory manner. The RFP proposal with the highest total score may not always be recommended. The IEP may recommend that any RFP proposal be eliminated from consideration due to a low score in any individual evaluation category.

ii) The IEP may award up to one thousand (1000) base points for each

RFP proposal. Additional details on each evaluation category are provided in the Transmission Provider’s business practices. An


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additional one hundred (100) points shall be available to provide an incentive for stakeholders to share their ideas and expertise to promote innovation and creativity in the transmission planning process.

iii) Base Points: The evaluation categories and maximum base points

for each category are listed below.

(1) Engineering Design (Reliability/Quality/General Design), 200 points: Measures the quality of the design, material, technology, and life expectancy of the Competitive Upgrade. Criteria considered in this evaluation category shall include, but not be limited to:

(a) Type of construction (wood, steel, design loading, etc.); (b) Losses (design efficiency); (c) Estimated life of construction; and (d) Reliability/quality metrics.

(2) Project Management (Construction Project Management), 200 points: Measures an RFP respondent’s expertise in implementing construction projects similar in scope to the Competitive Upgrade that is the subject of the RFP. Criteria considered in this evaluation category shall include, but not be limited to:

(a) Environmental; (b) Rights-of-way acquisition; (c) Procurement; (d) Project scope; (e) Project development schedule (including obtaining necessary regulatory approvals); (f) Construction; (g) Commissioning; (h) Timeframe to construct; and (i) Experience/track record. (3) Operations (Operations/Maintenance/Safety), 250 points:

Measures safety and capability of an RFP respondent to operate, maintain, and restore a transmission facility. Criteria considered in this evaluation category shall include, but not be limited to:


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(a) Control center operations (staffing, etc.); (b) Storm/outage response plan; (c) Reliability metrics; (d) Restoration experience/performance; (e) Maintenance staffing/training; (f) Maintenance plans; (g) Equipment; (h) Maintenance performance/expertise; (i) NERC compliance-process/history; (j) Internal safety program; (k) Contractor safety program; and (l) Safety performance record (program execution). (4) Rate Analysis (Cost to Customer), 225 points: Measures an

RFP respondent’s cost to construct, own, operate, and maintain the Competitive Upgrade over a forty (40) year period. Criteria considered in this evaluation category shall include, but not be limited to:

(a) Estimated total cost of project; (b) Financing costs; (c) FERC incentives; (d) Revenue requirements; (e) Lifetime cost of the project to customers; (f) Return on equity; (g) Material on hand, rights-of-way approval, assets on

hand; and (h) Cost certainty guarantee. (5) Finance (Financial Viability and Creditworthiness), 125

points: Measures an RFP respondent’s ability to obtain financing for the Competitive Upgrade. Criteria considered in this evaluation category shall include, but not be limited to:

(a) Evidence of financing; (b) Material conditions; (c) Financial/business plan; (d) Pro forma financial statements; (e) Expected financial leverage; (f) Debt covenants; (g) Projected liquidity;


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(h) Dividend policy; and (i) Cash flow analysis

iv) Incentive Points: Each RFP respondent that submitted a

detailed project proposal (“DPP”) in accordance with Attachment O Section III. 8(b) of this Tariff that was selected and approved

for construction as a Competitive Upgrade shall receive one hundred (100) incentive points in the Transmission Owner Selection Process for that Competitive Upgrade, which shall be added to the total base points awarded by the IEP. To demonstrate eligibility for the incentive points, the RFP respondent must document in its RFP response that it submitted a DPP for that Competitive Upgrade. The eligibility for the incentive points may only be awarded to the RFP respondent if the DPP was submitted during the ITP assessment from which the Competitive Upgrade was approved. The Transmission Provider shall confirm such eligibility in accordance with Attachment O Section III.8(b) of this Tariff and inform the IEP.

g) Failure of a Transmission Owner to Complete the Competitive Upgrade

If, after accepting the NTC, the DTO cannot or is unwilling to complete

the Competitive Upgrade as directed by the Transmission Provider, the Transmission Provider shall evaluate the status of the Competitive Upgrade and may designate a new DTO for the Competitive Upgrade in accordance with Section V.4 of this Attachment Y. If the Transmission Provider has determined that there is sufficient time for the Transmission Owner Selection Process to be completed and the Competitive Upgrade placed in service prior to the required need date as determined by the Transmission Provider, the process described in Section III of this Attachment Y shall be used to designate another entity to become the DTO for the Competitive Upgrade. If sufficient time is not available, the Transmission Provider shall designate a new DTO for the Competitive Upgrade in accordance with Section IV of this Attachment Y.

IV. INCUMBENT TRANSMISSION OWNER DESIGNATION PROCESS

1) If a project forms a connection with facilities of a single Transmission Owner,

that Transmission Owner shall be selected to be the DTO. If a project forms a connection with facilities owned by multiple Transmission Owners, the applicable


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Transmission Owners shall be selected to be the DTOs. If there is more than one Transmission Owner selected to construct a project, the DTOs will agree among themselves which part of the project will be provided by each entity. If the DTOs cannot come to a mutual agreement regarding the assignment and ownership of the project, the Transmission Provider will facilitate their discussion. Each DTO will receive an NTC, in accordance with Section V of this Attachment Y, for each project or segment of a project that the DTO is responsible to construct.

2) In order to maintain its right to construct a project, the DTO shall respond within

ninety (90) days after the receipt of the NTC with a written commitment to construct the project as specified in the NTC or a proposal for a different project schedule and/or alternative specifications in its written commitment to construct (“DTO’s proposal”). The Transmission Provider shall respond to the DTO’s proposal within ten (10) days of its receipt of the proposal. If the Transmission Provider accepts the DTO’s proposal, the NTC will be modified according to the accepted proposal, and the DTO shall construct the project in accordance with the modified NTC. If the Transmission Provider rejects the DTO’s proposal, the DTO’s proposal shall not be deemed an acceptable written commitment to construct the project. However, the Transmission Provider’s rejection of such proposal shall not preclude a DTO from providing a written commitment to construct the project after such rejection, provided the subsequent written commitment to construct the project is made within the ninety (90) day time period after the issuance of the NTC.

3) If a DTO does not provide an acceptable written commitment to construct within

the ninety (90) day period, the Transmission Provider shall select a replacement Transmission Owner in accordance with Section III of this Attachment Y.

4) At any time after accepting an NTC, a DTO that was designated under this

Section IV of Attachment Y may assign a project by arranging for another entity to build and own all or part of the project in its place subject to the following conditions:

a) Prior to starting its construction activity, the entity must have obtained all

state regulatory authority necessary to construct, own and operate transmission facilities within the state(s) where the project is located;

b) The entity meets the financial requirements of the Transmission Provider

as specified in Section III.1(b)(ii) of this Attachment Y;

c) The entity has signed or is capable and willing to sign the SPP Membership Agreement as a Transmission Owner; and


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d) The entity must meet such other qualifications as specified in Section III.1(b) of this Attachment Y.

5) Nothing in this Section IV shall relieve a Transmission Owner of its obligations

specified in Section VI.3 of Attachment O of this Tariff and Section 3.3(a) of the SPP Membership Agreement.

V. NOTIFICATION TO CONSTRUCT PROCESS 1) Once a Transmission Owner is selected to construct a project through Section III

or Section IV of this Attachment Y, the Transmission Provider shall issue an NTC for project(s) for which financial commitment is required prior to the approval of the next annual SPP Transmission Expansion Plan report. At the discretion of the SPP Board of Directors, the Transmission Provider may issue an NTC to the appropriate Transmission Owner to begin implementation of other such approved or required transmission project(s) for which financial commitment is not required prior to approval of the next annual SPP Transmission Expansion Plan report.

2) The Transmission Provider shall issue an NTC to each entity selected to become

the DTO for each transmission project. The NTC shall include, but not be limited to: (1) the specifications of the project required by the Transmission Provider, and (2) a reasonable project schedule, including a project need date.

3) Request for refined cost estimate

a) The Transmission Provider may issue an NTC that requires a refined cost estimate within a stated timeframe defined in the NTC. Such NTC shall direct the entity selected to become the DTO only to perform detailed engineering and cost studies. In complying with this NTC, the DTO shall be authorized to expend only those funds necessary to perform such studies. The entity selected to become the DTO shall provide to the Transmission Provider a written commitment that it: (1) accepts the obligation to construct the transmission facility subject to issuance of an NTC authorizing construction in accordance with Section III or Section IV of this Attachment Y; and (2) will provide the Transmission Provider a refined cost estimate within the Transmission Provider’s stated timeframe or state its inability to provide the refined cost estimate in the stated timeframe.

b) The Transmission Provider shall compare the refined cost estimate to the

project cost estimate approved by the SPP Board of Directors. If the refined cost estimate falls within bandwidth of the approved project cost


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estimate, the Transmission Provider shall issue an NTC authorizing construction and setting the refined cost estimate as the baseline cost for cost tracking purposes pursuant to Section VI of this Attachment Y. The bandwidth shall be defined by the Transmission Provider and stated in the Transmission Provider’s business practices.

c) If the refined cost estimate falls outside of the bandwidth defined by the

Transmission Provider, the Transmission Provider shall re-evaluate the project using the refined cost estimate and provide a recommendation to the SPP Board of Directors at its next scheduled quarterly meeting. The Transmission Provider’s recommendation could be, but is not limited to, one of the following actions: (i) Accept the refined cost estimate; (ii) Modify the project; (iii) Replace the project with an alternative solution; or (iv) Cancel the project.

The SPP Board of Directors shall determine the action to be taken regarding the transmission project. If the SPP Board of Directors determines to proceed with the project, the Transmission Provider shall issue an NTC authorizing construction and setting the refined cost estimate of the project as the baseline cost. If the SPP Board of Directors determines not to proceed with the project, the DTO shall be notified that the project has been cancelled and the DTO is eligible to pursue recovery of its study costs in accordance with Section VIII of Attachment J of this Tariff.

4) Any Transmission Owner that has accepted an NTC in accordance with this Tariff shall use due diligence to meet the terms contained in the NTC. If at any time the Transmission Owner cannot meet one or more of the terms agreed to in the NTC or cannot meet the regulatory approval need date set forth in the RFP for a Competitive Upgrade if applicable, it shall notify the Transmission Provider in a timely manner. The Transmission Owner may suggest changes to the NTC and present the reasons why the changes should be approved. The Transmission Provider shall review the proposed changes and determine a course of action to propose to the SPP Board of Directors, including, but not limited to: a) Accept changes negotiated with the Transmission Owner; b) Withdraw the NTC and issue an NTC for the same project to

another entity that shall be determined in accordance with this Attachment Y;


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c) Withdraw the NTC and replace the project with an alternative solution; or

d) Withdraw the NTC and cancel the project.

The SPP Board of Directors shall determine the action to be taken regarding the project.

VI. PROJECT TRACKING PROCESS

Costs and schedules related to all projects approved for construction under the Tariff shall be tracked by the Transmission Provider 1) Upon the acceptance of an NTC by a DTO, other than an NTC issued for refined

cost estimation, the baseline cost of the project will be set. The baseline cost shall be the estimated cost of the project as agreed to between the DTO and the Transmission Provider at the time such NTC was accepted.

2) The DTO shall submit updates of the estimated costs and schedules to the

Transmission Provider on at least a quarterly basis in a standard format and method defined by the Transmission Provider.

3) If at any time the cost projection significantly exceeds the estimated baseline cost,

the Transmission Provider shall investigate the reason for the change in cost and report to the SPP Board of Directors the reason for the change in cost and its recommendation on whether to accept the change in cost and reset the baseline cost. The SPP Board of Directors shall make the final determination as to the action that will be taken up to and including the cancellation of the project and withdrawal of the NTC.

4) If at any time the project schedule significantly changes, the Transmission

Provider shall investigate the reason for the change and may take action in accordance with Section V.4 of this Attachment Y.



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October 5, 2012 NOTE FOR MOPC: SECTIONS 10 AND 12 CONTAIN THE REMAINING TWO ISSUES WHERE CONSENSES HAS NOT BEEN REACHED: INDEMNITY AND ALLOCATION OF PENALTIES AND FINES. SEE SECTIONS 10 AND 12 FOR FURTHER DISCUSSION AND POSITIONS OF THE PARTIES.

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AGREEMENT BETWEEN SOUTHWEST POWER POOL, INC. AND PARTICIPANTS RELATING TO THE IMPLEMENTATION OF THE CONSOLIDATED BALANCING

AUTHORITY

Southwest Power Pool, Inc., (“SPP”) and the Participants in the Consolidated Balancing Authority (as such terms are defined below) agree to the following terms.

1. RECITALS

1.1 In its May 1, 2007 Order in Southwest Power Pool, Inc., Docket No. ER06-451-020, the FERC approved the EIS Agreement which provided for the performance of Balancing Authority responsibilities relating to implementation of the EIS Market through the SPP Open Access Transmission Tariff.

1.2 Through the EIS Agreement the Parties set out in detail the division and transfer of certain responsibilities between those entities identified as SPP Balancing Authorities in the EIS Agreement, and SPP relating to implementation of the EIS Market through the SPP OATT.

1.3 The Parties are replacing the EIS Agreement to accommodate the development and implementation of the SPP Integrated Marketplace and SPP becoming the Balancing Authority for the entire Consolidated Balancing Authority Area.

1.4 The Parties believe that this Agreement is in the public interest.

2. DEFINITIONS

2.1 ACTUAL INTERCHANGE. The metered interchange over a specific interconnection, including pseudo-ties, between two directly interconnected BAs.

2.2 ADJACENT BALANCING AUTHORITY. As defined in the NERC Glossary of Terms.

2.3 AGREEMENT. This “Agreement Between Southwest Power Pool, Inc. And Participants Relating To The Implementation Of The Consolidated Balancing Authority.”

2.4 AREA CONTROL ERROR (ACE). As defined in the NERC Glossary of Terms.

2.5 AUTOMATIC GENERATION CONTROL (AGC). As defined in the NERC Glossary of Terms.


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2.6 BALANCING AUTHORITY (BA). As defined in the NERC Glossary of Terms.

2.7 BA OPERATING PROTOCOLS. The operating protocols entitled “BA Operating Protocols of the Participants and SPP” that are developed by the CBA, as may be amended from time to time, to describe in more detail the obligations of the Parties to implement this Agreement.

2.8 BULK ELECTRIC SYSTEM. As defined in the NERC Glossary of Terms.

2.9 CONSOLIDATED BALANCING AUTHORITY (CBA). The responsible entity registered with the ERO as the BA, and that performs all the functions of the BA in the CBAA on behalf of the Parties to this Agreement.

2.10 CONSOLIDATED BALANCING AUTHORITY AREA (CBAA). The CBAA consists of the transmission system, load and generation resources interconnected to the SPP Transmission System, as defined under the SPP OATT, that: (a) function as a centrally coordinated system and (b) operate subject to the single set of dispatch instructions determined and issued by the CBA. The CBA maintains load-resource balance within its CBAA.

2.11 DYNAMIC SCHEDULE. As defined in the NERC Glossary of Terms.

2.12 EFFECTIVE DATE. The effective date of this Agreement as specified in Section 16.2 of this Agreement.

2.13 EIS AGREEMENT. The “Agreement Between Southwest Power Pool, Inc. And Southwest Power Pool Balancing Authorities Relating To Implementation Of The EIS Market.

2.14 ERO. The Electric Reliability Organization approved by FERC.

2.15 ERO BALANCING AUTHORITY RELIABILITY STANDARDS. Those reliability standards and requirements applicable to Balancing Authorities as those standards and requirements exist or are hereafter modified or adopted by the ERO.

2.16 ERO RELIABILITY STANDARDS. Standards developed by the ERO and approved by the Commission to ensure reliability of the Bulk Power System, violation of which may result in the imposition of mitigation programs or monetary penalties.

2.17 FERC or the COMMISSION. The Federal Energy Regulatory Commission or any successor agency.


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2.18 GENERATOR OPERATOR (GOP). As defined in the NERC Glossary of Terms.

2.19 GENERATOR OWNER (GO). As defined in the NERC Glossary of Terms.

2.20 GOOD UTILITY PRACTICE. Any of the practices, methods and acts engaged in or approved by a significant portion of the electric utility industry during the relevant time period, or any of the practices, methods and acts which, in the exercise of reasonable judgment in light of the facts known at the time the decision was made, could have been expected to accomplish the desired result at a reasonable cost consistent with good business practices, reliability, safety and expedition. Good Utility Practice is not intended to be limited to the optimum practice, method, or act to the exclusion of all others, but rather to the acceptable practices, methods, or acts generally accepted in the region.

2.21 GOVERNING DOCUMENTS. The following documents as may be amended from time to time: (a) Southwest Power Pool, Inc. OATT; (b) Southwest Power Pool, Inc. Membership Agreement; (c) Southwest Power Pool, Inc. Bylaws; (d) Joint Operating Agreement Between the Midwest Independent Transmission System Operator, Inc. and Southwest Power Pool, Inc.; (e) Joint Operating Agreement Among And Between Southwest Power Pool, Inc. and Associated Electric Cooperative Inc.; (f) Seams Agreement Between Entergy Services, Inc. and Southwest Power Pool, Inc.; and (g) any joint operating agreements or seams agreements executed by SPP after the filing of this Agreement with the FERC.

2.22 INTEGRATED MARKETPLACE. The Day-Ahead Market, the Real-Time Balancing Market, the Transmission Congestion Rights Market and the Reliability Unit Commitment processes.

2.23 INTERCONNECTION. The Eastern Interconnection as defined by the NERC Glossary of Terms.

2.24 LOAD SERVING ENTITY (LSE). As defined in the NERC Glossary of Terms.

2.25 MARKET MONITOR. The entity that is responsible for performing the monitoring and mitigation activities described in Attachments AF and AG to the SPP OATT.

2.26 MARKET PARTICIPANT. As defined in the SPP OATT.

2.27 MEMBERSHIP AGREEMENT. The Membership Agreement of the Southwest Power Pool, Inc., an Arkansas non-profit corporation.

2.28 NET ACTUAL INTERCHANGE. As defined in the NERC Glossary of Terms.


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2.29 NET SCHEDULED INTERCHANGE. As defined in the NERC Glossary of Terms.

2.30 NORTH AMERICAN ELECTRIC RELIABILITY CORPORATION (NERC). The North American Electric Reliability Corporation or its successor organization.

2.31 OPEN ACCESS TRANSMISSION TARIFF (OATT). FERC approved Pro-Forma Open Access Transmission Tariff.

2.32 OPERATING COMMITTEE. A committee comprised of one member from each of the Parties to this Agreement and which shall perform the duties identified in Section 18.4.

2.33 PARTICIPANT. An operational entity, which is: (a) a Party to this Agreement, excluding SPP, and (b) shown in Appendix A to this Agreement. For purposes of this Agreement, a Participant may have previously been registered as a BA under the EIS Agreement.

2.34 PARTICIPANT AREA. The collection of generation, transmission, and loads that are within the metered boundaries of the Participant.

2.35 PARTIES. The Participant and SPP that have executed this Agreement. SPP and Participant may be individually referred to as a “Party.”

2.36 PURCHASING AND SELLING ENTITY (PSE). As defined in the NERC Glossary of Terms.

2.37 RESOURCE PLAN. A Market Participant’s plan to meet its energy obligations including specification of resource operating characteristics.

2.38 SOUTHWEST POWER POOL (SPP). Southwest Power Pool, Inc., or any successor organization, that is designated as the CBA under this Agreement.

2.39 SPP ADJACENT BALANCING AUTHORITY. An Adjacent Balancing Authority that is interconnected to SPP.

2.40 SPP CRITERIA. SPP’s approved operating and planning criteria.

2.41 TIE LINE. As defined in the NERC Glossary of Terms.

2.42 TRANSMISSION OPERATOR (TOP). . As defined in the NERC Glossary of Terms.

2.43 TRANSMISSION OWNER (TO). As defined in the NERC Glossary of Terms.


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3. GENERAL

3.1 PURPOSE. The purpose of this Agreement is to delineate the responsibilities between SPP, as the CBA, and the Participants to establish the CBAA that facilitates the Integrated Marketplace to be implemented under the SPP OATT.

3.2 OBLIGATIONS. In carrying out obligations under this Agreement, SPP and the Participants shall (a) follow Good Utility Practice, (b) comply with applicable policies, standards and requirements of the ERO Reliability Standards and SPP Criteria and their successors, and (c) follow applicable laws, regulations, and orders.

3.3. REGISTRATION AND CERTIFICATION. SPP shall be the CBA. The CBA will comply with the ERO’s applicable BA registration and certification requirements. Participants shall support those functions consistent with the tasks and responsibilities assigned under this Agreement.

3.4. RELATIONSHIP TO MEMBERSHIP AGREEMENT. Nothing in this Agreement shall be construed or intended to cause or effect a modification to the Membership Agreement. This Agreement is intended to be separate from the Membership Agreement. All rights and obligations currently existing under the Membership Agreement remain.

3.5 RELATIONSHIP TO EIS AGREEMENT. This Agreement shall supersede the EIS Agreement upon the effective date specified in the Agreement; provided, however, this shall not eliminate any rights or obligations relating to prior actions, which shall survive the EIS Agreement including, but not limited to, rights or obligations arising under the following provisions: (a) indemnification; (b) waivers of liability; (c) no agreement to jurisdiction; (d) default; (e) cost recovery; and (f) obligations upon termination by entities that terminated their participation in the EIS Agreement without executing this Agreement. Notwithstanding the foregoing in this Section 3.5, the SPP and the Participants shall maintain the functionality necessary to comply with the EIS Agreement for a transition period after Integrated Marketplace start-up as determined by the Operating Committee.

4. SPP RESPONSIBILITIES.

4.1 SPP AS THE BA. SPP shall perform all tasks necessary to fulfill the role as the CBA, including adherence to all applicable ERO BA Reliability Standards and requirements except as delineated in Section 5 of this Agreement.

4.2 SPP NORMAL OPERATIONS

4.2.1 SPP shall be responsible for the identification of its critical assets and related critical cyber assets necessary to support reliable operation of the Bulk Electric


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System. SPP shall have no responsibility to identify critical assets or related critical cyber assets of any Participant.

4.2.2 SPP shall be responsible for maintaining its internal telecommunications facilities in an adequate and reliable manner for the exchange of interconnection and operating information necessary to maintain reliability within its respective scope of operations. SPP shall have no responsibility for maintaining any Participant’s internal telecommunications facilities for the exchange of interconnection and operating information of any Participant.

5. PARTICIPANT RESPONSIBILTIES

5.1 TIE LINE METERING AND TELEMETRY. Each Participant that has or is taking actions to have, one or more Tie Line(s) with an SPP Adjacent Balancing Authority shall have, or cause to have, the Tie Line metering and telemetry responsibilities as set forth in this Section 5.1.

5.1.1 Each Participant having one or more Tie Line(s) with an SPP Adjacent Balancing Authority shall provide all Tie Line flows to the CBA.

5.1.1.1 Each Participant shall ensure that the Tie Line megawatt (MW) metering is telemetered to the SPP control center.

Such Participant shall maintain and provide to SPP suitable documentation (i.e. prints, equipment specifications, records) that verifies Tie Line MW metering physical location and actual metering point

The Participant shall operate such that the MW-hour data is telemetered or reported to the CBA at the end of each hour.

5.1.1.2 Each Participant shall ensure the power flow measurements transmitted to SPP from the Tie Line meters are not filtered prior to transmission, except anti-aliasing Filters of Tie Lines.

5.1.1.3 Each Participant shall ensure the installation of common metering equipment where Dynamic Schedules or pseudo-ties are implemented between SPP and an another Balancing Authority where applicable to account for the delivery of the output of units located external to the CBAA or to serve remote load physically external to the CBAA.

5.1.1.4 Each Participant shall operate such that its sampling rate of data is compatible with the SPP’s sampling rate of data, as specified by SPP.


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5.1.1.5 Each Participant shall provide SPP an inventory of all Tie Line(s) with SPP Adjacent Balancing Authority(ies), including maps, prints, electrical drawings and diagrams, equipment descriptions as requested by SPP.

5.1.1.6 The Participant shall timely inform SPP of any modifications, changes, status, and operability of the Tie Line metering equipment.

5.1.1.7 SPP and Participant shall agree on the specific Tie Line (including pseudo ties), surrounding the CBAA.

5.1.1.8 Each Participant shall maintain, re-calibrate and otherwise insure proper operation and accuracy of the Tie Line metering equipment at a frequency determined by SPP and documented in applicable SPP policies, procedures, and/or documents. Documents verifying such actions shall be provided to SPP as requested by SPP.

5.1.1.9 If SPP suspects inaccuracies or malfunction of Tie Line metering, SPP shall inform the Participant. The Participant shall take action necessary to verify timely Tie Line metering equipment accuracy and/or performance of the suspect Tie Line metering and take actions to restore data accuracy.

5.1.2 The addition of a Party or the withdrawal of a Party may result in the designation of an existing line as a Tie Line with an SPP Adjacent Balancing Authority or result in an existing Tie Line with an SPP Adjacent Balancing Authority to be no longer a Tie Line. If either event should occur, SPP shall so notify the affected Participant. SPP and the impacted Party(ies) shall determine actions to be taken by SPP and/or the Party(ies) to conform to this Agreement in a timely manner.

5.2 FREQUENCY MEASUREMENTS. As may be reasonably requested by SPP, Participants may be requested to supply SPP with frequency measurements from locations agreed to by the Parties. Participants that are designated to provide frequency measurements to SPP shall provide accurate frequency measurements from these location(s) with measurement quality indication.

Participants shall perform annually, against a common reference, checks and calibrations of its time error and frequency devices used to supply SPP with data used by SPP to perform BA functions (“Actions”). For purposes of this section, “annually” shall mean “within a calendar year, with the calendar year beginning on January 1 and ending on December 31;” however, the period between subsequent annual checks and calibrations under this section shall not exceed


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fifteen (15) months. Documents verifying such Actions shall be provided to CBA as requested by SPP.

6. IMPLEMENTATION OF EMERGENCY OPERATING PLANS

6.1 SPP and each Participant shall coordinate preparation and implementation of respective emergency operating plans. This coordination shall include, but not be limited to,

6.1.1 Participant actions to interruption of load and/or exports as directed by SPP associated with capacity deficiencies; and,

6.1.2 Participant actions to implement public appeals, voltage reductions, curtailment of interruptible and/or firm load as directed by SPP associated with capacity deficiencies.

7. BA OPERATING PROTOCOLS AND SPECIFIC ERO REQUIREMENT ASSIGNMENT

7.1 INITIAL ASSIGNMENT OF TASKS. Sections 4 and 5 of this Agreement set forth the tasks and responsibilities of the Parties to establish the single BA for the CBAA.

7.2 NEW OR MODIFIED RESPONSIBILITIES. When new and/or modified applicable responsibilities are required including those that might be initiated by the ERO, the Parties will negotiate in good faith to determine whether SPP and/or the Participants shall ensure the performance of the new or modified responsibilities, and will amend this Agreement accordingly, pursuant to Section 17.4.

7.3 BA OPERATING PROTOCOLS. The CBA shall develop and maintain BA Operating Protocols that provide for operational requirements under this Agreement.

8. DATA EXCHANGE

8.1 PARTIES’ DATA EXCHANGE. Each Participant and SPP shall provide the information and data that a Party reasonably believes it needs and requests in order to carry out its responsibilities under this Agreement.

8.2 CONFIDENTIALITY. All data provided under this Section shall be considered information subject to the confidentiality provisions of Section 13 herein.

9. PARTICIPANT COST RESPONSIBILITY. Each Participant shall be responsible for all costs incurred by it to implement the provisions of this Agreement.


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10. SANCTIONS, INQUIRIES AND ALLOWED ACTIONS

10.1 SANCTIONS. In the event the ERO assesses a monetary penalty against SPP as the Registered Entity BA for a violation of a Reliability Standard, SPP shall seek to recover the costs associated with the sanctions and/or monetary penalties pursuant to Attachment AP of the SPP OATT.

Member Entity Position:

Attachment AP does not address “penalty stacking,” whereby entities may be charged with substantially higher penalties due to another entities’ earlier violation of same standard.

SPP position:

Spreading of all penalties and sanctions amongst all Participants, regardless of fault or cause, is a method to resolve “penalty stacking.” SPP will implement policy as directed by the stakeholder process.

10.2 INQUIRIES. To the extent a Participant’s actions implementing SPP actions or directives pursuant to this Agreement are questioned, investigated or sanctioned by the ERO, the Market Monitor, or by an applicable regulatory agency, SPP shall aid the Participant in responding to the inquiry, investigation, or sanctions.

10.3 ALLOWED ACTIONS. To the extent that the ERO, FERC or applicable regulatory agency determines that a Participant’s actions taken pursuant to this Agreement were inappropriate, SPP shall not require the Participant to take such actions in the future. If the ERO, FERC or applicable regulatory agency requires that a Participant take action inconsistent with this Agreement, SPP will allow such actions.

11. LIMITATIONS ON SPP ACTIONS

11.1 GOVERNING DOCUMENTS. Without limiting the generality of obligations provided in Section 3.2, SPP shall not issue any orders to any Party pursuant to this Agreement or take any action pursuant to this Agreement that SPP knows or should know is not in accordance with the Governing Documents.

11.2 APPLICABLE LAWS. SPP shall not issue any order to any other Party pursuant to this Agreement or take any action pursuant to this Agreement that SPP knows or should have known would cause a violation of applicable laws or tariffs.


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12. INDEMNIFICATION, LIABILITIES, INSURANCE

12.1 (CURRENT) INDEMNIFICATION. Each Participant shall at all times indemnify and save other Parties to this Agreement harmless from, any and all damages, losses, including but not limited to injury to or death of any person or damage to property, recoveries, costs and expenses, court costs, attorney fees, and all other obligations to third parties, to the proportional extent resulting from the Participant’s negligent performance of obligations under this Agreement, except to the extent such damages, losses or claims are the result of the gross negligence or intentional wrongdoing by the indemnified Party as set forth in Section 12.2.

(REVISED) INDEMNIFICATION. The SPP shall at all times indemnify, defend, and save harmless other Parties to this Agreement and their officers, shareholders, directors, agents, contractors, employees, and members (i.e., cooperative members and municipal joint action agency members) from and against any and all damages, losses, claims, including without limitation claims and actions relating to injury to, or death of, any person, or damage to property, demands, suits, recoveries, costs and expenses, court costs, attorney fees, and all other obligations by or to third parties or other Parties, arising out of or resulting from the Party’s performance of its obligations under this Agreement or the SPP’s performance of its obligations under this Agreement, except in cases of gross negligence or intentional misconduct by the Party.

Member Entity position:

SPP should indemnify all Participants against third party claims (see Revised 12.1 above); but Participants do not indemnify SPP or other Participants. Revised language is based upon the MISO Local Balancing Authority Agreement.

SPP position:

The MISO agreement involves a much different functional paradigm, including Load Balancing BAs with a joint NERC registration. Under the CBA Agreement, SPP is the sole NERC registrant. SPP’s recommendation is to maintain indemnification and limitation of liability consistent with the current OATT, Bylaws and Membership Agreement (see below for specific sections). Simply put, the governing documents do not expressly provide that SPP indemnifies Customers or Transmission Providers from third party claims. In actuality, SPP is indemnified by customers against third party claims, except in cases of gross negligence or intentional misconduct. Additionally, SPP’s liability is limited to customers and members, except in cases of gross negligence and intentional/willful misconduct.

If SPP is required to indemnify the Consolidated Balancing Authority Participants, an issue will be whether SPP may recover sanctions, penalties and financial liabilities from the membership when SPP is obligated to hold those same Members harmless from loss. SPP


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does have Errors and Omissions Liability insurance for damages that are a result of SPP’s gross negligence or willful misconduct; however, SPP cannot get insurance to cover civil penalties.

**NOTE: In the absence of a prescribed method of recovery, Members are financially responsible for any penalties and liabilities SPP may incur through the indemnification of the Member Participants.

1) OATT

§ 10.2: SPP not liable to any customer or user except to the extent SPP is grossly negligent or commits intentional misconduct.

§ 10.3: Customer shall indemnify SPP from third party claims arising out of SPP’s performance of obligations on behalf of customer. This section does not apply to SPP’s performance which is grossly negligent or intentional misconduct.

§ 10.4: SPP is not liable for damages arising out of services provided under Tariff including, but not limited to, any act or omission that results in an interruption, deficiency or imperfection of service, occurring as a result of conditions or circumstances beyond SPP’s control.

2) SPP Bylaws

§ 3.15.1: These requirements do not apply to unlawful actions, bad faith or gross negligence or willful misconduct.

(a) SPP not liable to Members for damages arising out of or related to any directive, order, procedure, action or requirement of SPP.

(b) Members waive future claims it might have against SPP resulting from any directive, order, procedure, action or requirement of SPP

§ 8.7.1 (c): a Member’s existing obligations include the principal amounts of all SPP financial obligations.

3) SPP Membership Agreement

§ 3.8 (a): Member agrees to comply with and abide by the provisions of the SPP Bylaws and pay when due, any dues, assessments, OATT charges, and other amounts owing to SPP.


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12.2 (CURRENT) LIMITATION OF LIABILITY IN AGREEMENT. No Party shall be liable for money damages or other compensation to any other Party for actions or omissions by the Party in performing its obligations under this Agreement, except to the extent such act or omission by the Party is found to result from its gross negligence or intentional wrongdoing. A Party may not seek to enforce any claims against the directors, members, shareholders, officers, employees or agents of another Party solely by reason of their status as directors, members, shareholders, officers, employees or agents of the other Party. In no event shall the Parties be liable for any incidental, consequential, punitive, special, exemplary or indirect damages, loss of revenues or profits, arising out of, or connected in any way with the performance or non-performance under this Agreement.

The Parties shall not be liable for damages arising out of services provided under this Agreement including, but not limited to any act or omission that results in an interruption, deficiency or imperfection of service, occurring as a result of conditions or circumstances beyond the control of the Party, as applicable, or resulting from electric system design common to the domestic electric utility industry or electric system operation practices or conditions common to domestic electric utility industry. Participant shall not be liable for acts or omissions done in compliance or good faith attempts to comply with directives of SPP, except in cases of gross negligence or intentional misconduct.

(REVISED) No Party shall be liable to the SPP for any damages whatsoever, including, without limitation, direct, indirect, incidental, special, multiple, consequential (including without limitation attorneys’ fees and litigation costs), exemplary, or punitive damages arising out of or resulting from any act or omission in any way associated with the performance of the Party’s responsibilities under this Agreement, except to the extent, and only to the extent, that the Party is found liable for gross negligence or intentional misconduct, in which case the Party shall not be liable for any indirect, incidental, special, multiple, consequential (including without limitation attorneys’ fees and litigation costs), exemplary or punitive damages. The SPP shall not be liable to any Party for any indirect, incidental, special, multiple, consequential (including without limitation attorneys’ fees and litigation costs), exemplary or punitive damages.

Member Entity Position: The Limitation of Liability provision from MISO’s Local Balancing Authority Agreement should be the baseline term for SPP’s CBA Agreement. SPP Position: For the reasons stated above in 12.1, SPP recommends keeping the limitation of liability consistent with the OATT and Bylaws.


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12.3 (CURRENT) INSURANCE. Each Party shall be self-insured and/or obtain adequate insurance coverage to cover the indemnifications and liabilities under this Agreement to be effective as of the effective date of this Agreement.

(REVISED) The SPP shall obtain and maintain adequate insurance coverage to cover the indemnifications and liabilities under this Agreement subject to its ability to secure such coverage at a reasonable cost. Before obtaining, changing or renewing such coverage, the SPP shall consult with the Parties, with that consultation to take place no later than ninety (90) days prior to the renewal date or changes in coverage.

Member Entity position: The Insurance provision from MISO’s Local Balancing Authority Agreement should be the baseline term for SPP’s CBA Agreement. SPP position: Members are financially responsible for any penalties and liabilities SPP may incur through its indemnification of the Member Participants. If insurance cannot be procured to cover these obligations at a “reasonable cost” it is unclear what mechanism will SPP utilize to recover these financial liabilities.

12.4 LIMITATION OF SCOPE. In interpreting the indemnification and waiver of

liability provisions in Sections 12.1 and 12.2, the Parties intend that these provisions shall not apply in instances in which the Participant is acting outside the scope of this Agreement.

13. STANDARDS OF CONDUCT, INFORMATION SHARING, CONFIDENTIALITY

13.1 PARTICIPANTS. This Agreement does not require any Participant to separate Participant personnel from marketing personnel; nor does this Agreement waive any requirement of the Commission’s Standards of Conduct or exempt any public utility Participant from the Standards of Conduct. This Section 13.1 applies to both the public utility Participants and the non-public utility Participants that are signatories to this Agreement.

13.1.1 In general, personnel of an Participant performing functions under this

Agreement shall keep all information received from SPP or other entities relating to its performance under this Agreement confidential and shall not disclose such information to Market Participants (including marketing personnel that are part of the same company as the Participant) or entities which it reasonably believes may become Market Participants. Notwithstanding the foregoing, and subject to subparagraph (b) below, an Participant with personnel who perform both Participant and market


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functions may disclose information received from the SPP or other entities to its personnel.

13.1.2 SPP shall have the right to limit the sharing of market sensitive

information related to non-affiliated Market Participants to an Participant with personnel who perform both functions under this agreement and market functions; except when: (a) no other Market Participant under the Integrated Marketplace with

registered resource(s) controls generation connected to a Party’s facilities, or

(b) the Participant is a signatory to the North American Electric

Reliability Council Confidentiality Agreement for Electric System Operating Reliability Data and Annex 1 thereto (Limited Operating Reliability Data Agreement for Small Bundled Entities). Each Participant with personnel performing such dual functions shall notify SPP of that fact, and, to the extent permitted by law, the Participant shall not disclose confidential information to third party Market Participants or third parties which it reasonably believes may become Market Participants.

13.1.3 Notwithstanding the above, SPP shall provide, to the extent necessary,

information to allow the Participant to perform its functions under this Agreement and to comply with ERO and regional reliability requirements.

13.1.4 There shall be no requirement to keep information confidential if such

information is in the public domain or subject to open records laws. In addition, if the ERO requires that the Participant provide information required to be confidential under this provision, the Participant may provide such information to the requesting entity, provided that the Participant shall make a good faith attempt to maintain the confidentiality of the information, notwithstanding the information request, and provided further that, in the case of a request by a state regulatory agency for confidential information, the Participant may provide confidential information to such state regulatory agency as necessary to satisfy state regulatory responsibilities and, subject to applicable law, only to the extent that the state regulatory agency executes a non-disclosure agreement.

13.2 SOUTHWEST POWER POOL. SPP, its directors, officers, employees,

contractors, and agents shall adhere to the SPP Standards of Conduct with regard to all activities related to this Agreement.


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14. DISPUTE RESOLUTION

14.1 GENERAL. These procedures are established for the equitable, efficient and expeditious resolution of disputes consistent with SPP’s Bylaws. These procedures are intended to cover disputes between any two or more Participants, or between SPP and any Participant(s). SPP and Participant(s) are strongly encouraged to take part in the complete process herein described prior to litigation or the utilization of other dispute resolution processes. SPP administrative involvement in the proceeding is to coordinate with an appropriate firm or panel to facilitate the resolution of the dispute and to provide meeting coordination and facilities. These procedures do not apply to disputes that are covered by the dispute resolution procedures of the SPP OATT.

14.2 INSTIGATION. Any Participant may begin these dispute resolution procedures by notifying the SPP President in writing. The SPP President will inform the SPP Board of Directors of the initiation of any dispute resolution proceedings. This written notification must contain the authorized signatures of all Parties to the dispute. The notification must contain: (a) a statement of the issues in dispute; (b) the positions of each of the Parties relating to each of the issues; (c) the specific dispute resolution procedure desired; and (d) any agreed-upon modifications or specific additions to the proceedings described in this Agreement by which the dispute may be resolved.

14.3 DISPUTE RESOLUTION PROCESS.

14.3.1 In the event SPP is a party to the dispute, the parties shall engage a firm specializing in alternative dispute resolution to administer the dispute resolution process. The firm will be mutually determined by the parties and the process will be administered in accordance with this Agreement and such other SPP governing documents as may be relevant to the proceeding. In the event the parties cannot mutually agree to the engagement of a firm, the dispute resolution process will be abandoned and other available means for resolution will be pursued.

14.3.2 In the event SPP is not a party to the dispute, the parties to the dispute may engage a firm specializing in alternative dispute resolution to administer the dispute resolution process. The firm will be mutually determined by the parties and the process will be administered in accordance with this Agreement and such other SPP governing documents as may be relevant to the proceeding. In the event the parties cannot mutually agree to the engagement of a firm, and do not determine some other mutually acceptable procedure, the President of SPP shall provide to each party to the dispute a list of candidates to be used in forming a three-person dispute resolution panel. The candidates shall be persons meeting the requirements for the SPP Board of Directors. The President shall then call a telephone conference meeting during which each party shall alternate striking


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names from the list until those remaining constitute the dispute resolution panel. This panel shall select a chair from its membership. Should any candidate decline to serve or resign from a current appointment for any reason, the candidate whose name was last struck from the list shall be contacted to serve. The President shall assign a Staff representative to assist the panel as secretary. The President shall manage the panel selection process to ensure its timely completion.

14.4 RESOLUTION PROCEDURES. The types of proceedings available for the resolution of disputes are:

(a) an advisory proceeding to assist each party through discussion and advice, on a separate and individual basis without active participation in the joint discussions and negotiations, to resolve the dispute informally by mutual agreement;

(b) a mediation proceeding to assist the parties through active participation in the joint discussions and negotiations (including specific recommendations of the issues in dispute) through which the parties indirectly attempt to resolve the dispute informally by mutual agreement;

(c) a non-binding dispute resolution proceeding to hear formal evidence on factual matters related to the issues submitted, make written findings and conclusions of fact, and issue specific written recommendations for resolution of each issue in dispute;

(d) a binding dispute resolution proceeding, provided the parties to the dispute agree to the proceeding, to hear formal evidence on factual matters related to the issues submitted, make written findings and conclusions of fact, and issue directives and awards for resolution of each issue in dispute.

The panel chair or representatives of the alternative dispute resolution firm (the “Facilitator”) shall determine meeting arrangements and format necessary to efficiently expedite the resolution of the dispute, and the SPP staff secretary shall notify the parties of these details. Each party to the dispute must have at least one representative present at all related meetings with full authority to resolve the dispute. Upon conclusion of this process, the Facilitator shall notify the SPP President of its outcome. After consultation with the parties to the dispute and the Facilitator to determine the completion of the process as described herein, and/or as modified by the parties, the SPP President shall discharge the panel or firm, and notify the SPP Board of Directors of the results. The parties to the dispute agree to complete the process within 90 days from selection of the panel or firm. The SPP staff secretary shall maintain minutes of the panel meetings, which shall become part of SPP’s historical records.


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14.5 EXPENSES. The parties to the dispute shall share equally all reasonable charges for the meeting location, administrative costs, and related travel expenses of panel members. The parties to the dispute shall also share equally all reasonable compensation for time and service of panel members and related incremental expenses of the SPP staff. The President shall determine reasonableness of time and service costs for panel members prior to process implementation. The SPP staff secretary shall account for these expenses. Each party to the dispute shall be responsible for their respective associated expenses.

14.6 LIABILITY. The parties to any dispute which is the subject of these dispute

resolution procedures shall hold harmless SPP, its Members, Organizational Groups and each of their directors, officers, agents, employees or other representatives, and the panel members from any liabilities, claims, or damages resulting from any agreement or lack of agreement as a result of the dispute resolution proceedings. The foregoing hold harmless right shall not be extended to the parties to any given dispute or to their directors, officers, agents, employees, or other representatives.

15. NON-PERFORMANCE AND DEFAULT

15.1 NON-PERFORMANCE. Except as provided in Section 18.9, any failure to carry out any term of this Agreement shall be considered non-performance. A Party alleging non-performance shall provide written notice of such non-performance within seven calendar days to the alleged non-performing Party. The alleged non-performing Party then shall have seven calendar days (or some other time period agreed to by the Parties) to correct the non-performance or to dispute the non-performance pursuant to the provisions of Section 14. Each Party shall designate a person to receive notice and provide such designation to the other Parties.

15.2 DEFAULT. If a Party fails to correct the non-performance or fails to dispute the

allegation of non-performance as provided in Section 14, or the Party is found to be a non-performing Party through the dispute resolution provisions in Section 14 and fails to take adequate corrective action, then the Party shall be considered to be in Default.

15.3 REMEDY FOR DEFAULT. One or more Parties, individually or collectively,

may seek appropriate remedies in court, including, but not limited to, specific performance and equitable relief, in the event of a Default by another Party.

16. TERM, TERMINATION, EFFECTIVENSS, WITHDRAWAL

16.1 EFFECTIVE DATE AND TERM. This Agreement shall commence on the Effective Date of this Agreement as provided in Section 16.2. This Agreement shall remain in effect for two (2) years from the Effective Date and shall remain


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in effect from year to year thereafter unless either: (a) SPP or (b) three-fourths of the Participants then subject to this Agreement give one year advance notice in writing that they wish to terminate this Agreement. Termination of this Agreement is subject to approval by a regulatory agency with proper jurisdiction, including, but not limited to, FERC.

16.2 DETERMINATION AND LIMIT OF EFFECTIVENESS. The Agreement shall become effective on the date the Integrated Marketplace begins operations provided that the following events have occurred: (a) the ERO has certified, including on a conditional basis, that SPP can begin operations as the BA of the CBAA to comply with the ERO Balancing Authority Reliability Standards; (b) FERC accepts or approves the Agreement; and (c) any modifications ordered by FERC are accepted consistent with Sections 17.2 and 17.4 of this Agreement.

16.3 FILING. SPP has concluded that this Agreement must be filed with FERC under the Federal Power Act and its implementing regulations. Should FERC require any modification to this Agreement that adversely affects the rights or obligations of a Party, the Party may withdraw its participation in this Agreement consistent with the provisions of Section 16.5.

16.4 TERMINATION BY SPP. In the event SPP gives notice to terminate this Agreement, such termination shall not be effective until suitable arrangements for the provisions of its BA responsibilities are in place. Suitability of the arrangements will be determined by the BA Committee.

16.5 WITHDRAWAL. An Participant may withdraw from this Agreement if: (a) the Participant or entity of which Participant is a part withdraws from SPP membership under the withdrawal provisions of the Membership Agreement; or (b) the Participant or the entity of which Participant is a part removes its transmission facilities from the SPP OATT subject to any applicable regulatory requirements; or (c) the Participant unilaterally terminates its participation in the Agreement in its sole discretion. The Participant shall provide at least one hundred eighty (180) days notice (or shorter time period if required by a regulatory authority with jurisdiction, or by law, or as agreed to by SPP) to SPP of such withdrawal, which withdrawal may not be effective any earlier than the date upon which the applicable conditions set forth in Section 16.5 are fully satisfied.

16.6 CONTINUING OBLIGATIONS. A Participant and SPP shall be subject to the rights and responsibilities under this Agreement for any actions or inactions occurring prior to the effective date of the Participants withdrawal or termination of this Agreement.

16.7 SURVIVABILITY. The provisions of this Agreement related to any indemnification obligation or any continuing obligation under Section 16 shall survive the termination of this Agreement under Section 16 or the withdrawal of a


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Party under Section 16 to the full extent necessary for their enforcement and the protection of the Party in whose favor they run with regard to actions or inactions occurring prior to the effective date of the termination or withdrawal, except that in the case of withdrawal of an Participant, no action or claim against that Participant related to this Agreement shall commence more than three years from the effective date of the withdrawal.

17. MODIFICATIONS AND AMENDMENTS

17.1 RESERVED.

17.2 OTHER MODIFICATIONS OR CONDITIONS. Except as provided in Section 17.4, the Parties intend that there will be no other modifications or conditions to this Agreement absent the agreement of the Parties. Notwithstanding anything to the contrary in this Agreement, in the event of any changes in ERO, Commission, Regional Entity, or Integrated Market requirements, which materially affect this Agreement, the Parties will negotiate in good faith appropriate changes to this Agreement and will make written modifications hereto. If the Parties do not mutually agree to such changes in writing, then they will refer the issues to dispute resolution under Section 14.

17.3 MOBILE-SIERRA STANDARD. Absent a filing with the Commission to reflect the agreement of the Parties as detailed in Section 17.4, the standard of review for changes or conditions to this Agreement, whether proposed by a Party, a non-Party or the Federal Energy Regulatory Commission acting sua sponte shall be the “public interest” standard of review set forth in United Gas Pipe Line Co. v. Mobile Gas Service Corp., 350 U.S. 332 (1956) and Federal Power Commission v. Sierra Pacific Power Co., 350 U.S. 348 (1956) (the “Mobile-Sierra” doctrine). Notwithstanding the foregoing in this Section 17.3, if the Commission changes its policy (in existence at the time of execution) with regard to non-signatories and imposes a standard different than the Mobile-Sierra standard set forth in this provision, then the Parties shall modify this Agreement to reflect the new standard. Any changes to this Agreement shall be prospective only. The Commission’s action on the initial filing of this Agreement shall be under the just and reasonable standard.

17.4 VOTING FOR ACCEPTANCE OF MODIFICATIONS OR CONDITIONS. This Agreement may be modified or conditioned only by at least a two-thirds affirmative vote of the Participants (each Participant receiving one vote regardless of size) with the assent of SPP; provided, however, no such modification or condition may be imposed on a Party that does not agree to the modification or condition to the extent that the modification or condition will cause the Party to no longer be in compliance with ERO or Regional Entity requirements. SPP shall file with the Commission any modifications to this Agreement resulting from this Section 17.4, which filing will be subject to the just and reasonable standard of


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review. Once the Commission accepts such modifications, then such modifications shall be considered as being part of this Agreement and all applicable terms of the Agreement, including Section 17.3, shall apply to the modifications.

18. MISCELLANEOUS PROVISIONS

18.1 ASSIGNMENT. Each Participant may assign its rights and obligations under this Agreement to another entity subject to receiving the approval of SPP; such approval shall not be unreasonably withheld.

18.2 NO AGREEMENT TO JURISDICTION. By entering into this Agreement, which shall be filed with the Commission and notwithstanding any provision in this Agreement, the Participants are not in any way agreeing individually or collectively that their activities under this Agreement are subject to Commission jurisdiction. In addition, nothing in this Agreement shall be construed (a) to confer Commission jurisdiction over Participants that are not public utilities as defined by the Federal Power Act, or (b) as a consent or waiver with respect to such jurisdiction, or (c) to cause a non-public utility to take any action or participate in any filing or appeal that would confer Commission jurisdiction over a non-public utility or require a non-public utility to comply with any Order or Rule issued by the Commission. A Party’s actions, decisions, and performance under this Agreement, including without limitation the exercise of its rights to withdraw from or terminate this Agreement, shall not be subject to Commission approval.

18.3 RESERVATION OF RIGHTS. Nothing in this Agreement shall affect a Party’s rights to argue issues that are not resolved pursuant to this Agreement in proceedings at the Commission and in the courts.

18.4 OPERATING COMMITTEE. As soon as practicable after the Effective Date, the Participants shall form an Operating Committee. The function of the Operating Committee shall be: (a) to review performance under this Agreement, (b) to discuss issues that may arise related to such performance, (c) to review BA Operating Protocols, and, (d) if necessary or advisable, to propose amendments to this Agreement for the Parties’ consideration and/or vote pursuant to Section 17.4. The Operating Committee shall be comprised of a member and an alternate for each Participant, who has authority to bind the respective Participant. The Operating Committee shall meet at least once each year on dates to be determined by SPP after consultation with the committee members. SPP shall facilitate such meetings and shall give reasonable written notice thereof to all Parties. At its first meeting, the Operating Committee shall, with the approval of at least two thirds of the Parties, establish procedures to govern its actions consistent with the terms of this Agreement.


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18.5 CONSOLIDATION OF PARTICIPANTS. The Parties agree that any consolidations of Participants shall be accommodated under this Agreement. This Agreement shall not be construed as inhibiting the consolidation of Participant Areas.

18.6 ADDITIONAL BALANCING AUTHORITIES. The Parties agree that any ERO certified BA or other entity that is not a signatory to this Agreement may become a signatory to this Agreement, subject to SPP approval, so long as the BA or other entity agrees to be bound by the provisions of this Agreement as an Participant within the CBAA and ceases to be a BA.

18.7 GOVERNING LAW. This Agreement shall be governed by and construed in accordance with the laws of Arkansas.

18.7.1 Compliance with State Law.

Notwithstanding any other provision of this Agreement, a non-jurisdictional Participant shall not be required to take any action or do any other thing with respect to rates, charges, terms or conditions of service, the resolution of disputes under this Agreement or any other matter regarding its obligations and performance under this Agreement, that (i) the non-jurisdictional Participant is not permitted by state law to undertake or that is prohibited in whole or in part by any state law or regulation applicable to the non-jurisdictional Participant; or (ii) would require the non-jurisdictional Participant to violate a provision of such state law or regulation in order to comply with this Agreement. Determination of compliance with and permissible action, conduct or obligations by a non-jurisdictional Participant shall be within the sole jurisdiction of the non-jurisdictional Participant’s governing board, subject to applicable state court review. A non-jurisdictional Participant shall not object to SPP’s participation in any state proceedings that impact the non-jurisdictional Participant’s ability to perform under this Agreement or determinations regarding such impact. To the extent possible without violating state law, a non-jurisdictional Participant shall notify SPP in advance of any action that the non-jurisdictional Participant is required to take that the non-jurisdictional Participant believes would constitute a violation of state law, and the non-jurisdictional Participant and SPP promptly shall meet and confer regarding the matter. As necessary, the non-jurisdictional Participant and SPP agree to negotiate in good faith to modify the Agreement as consistent as possible with the original intent to allow SPP to exercise operational authority over the non-jurisdictional Participant’s Tariff Facilities as otherwise provided in the Agreement. If the non-jurisdictional Participant and SPP are unable to resolve the matter, the


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non-jurisdictional Participant may terminate this Agreement pursuant to the withdrawal provisions of the Agreement.

18.7.2 Termination on Less Than Required Notice.

Participant may terminate this Agreement with less than the required notice, in the event that the state law governing Participant changes, or any provisions of this Agreement are changed or modified in a manner that causes a conflict with the Participant’s state law, regulations, or rate schedules, and the internal dispute resolution process described in Section 12 of the OATT is unable to resolve such conflict. In such event, Participant and SPP shall meet and confer to facilitate the withdrawal as soon as practicable as necessary to ensure compliance with state law.

18.7.3 Operational Authority.

A non-jurisdictional Participant reserves the right to exercise operational authority over a non-jurisdictional Participant’s tariff facilities (1) to protect public safety and the safety of its workers, to prevent damage to equipment, and to preserve reliability in compliance with NERC standards, and (2) as necessary to preserve a non-jurisdictional Participant’s rights, duties and obligations regarding electric service to its retail and wholesale native load customers pursuant to its state law and consistent with NERC standards, if SPP's exercise of operational authority over the tariff facilities would endanger said electric service or is contrary to or would curtail, surrender or delegate such state law rights, duties and obligations. A non-jurisdictional Participant will, as soon as reasonably practicable thereafter, notify SPP of such actions taken by a non-jurisdictional Participant. A non-jurisdictional Participant and SPP will meet and confer regarding the matter and, as necessary, negotiate in good faith to modify the Agreement to address the matter.

18.8 COMPLETE AGREEMENT. This Agreement shall constitute the complete agreement of the Parties on the subject matters covered herein.

18.9 FORCE MAJEURE. No Party shall be considered to be in breach of this Agreement to the extent that a failure to perform its obligations, other than a payment obligation, is due to an “Uncontrollable Force.” The term “Uncontrollable Force” means an event or circumstance which prevents one Party from performing its obligations, which event or circumstance is not within the reasonable control of, or the result of the negligence or intentional wrongdoing of, the claiming Party, and which by the exercise of due diligence, or Good Utility Practice, the claiming Party is unable to avoid, cause to be avoided, or overcome. Any Party rendered unable to fulfill any of its obligations by reason of an Uncontrollable Force shall give immediate notice of such fact to the other Parties


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and shall exercise due diligence to remove such inability within a reasonable time period. If a Party is unable to perform actions under this Agreement due to the actions of an independent third party (e.g. not a consultant or affiliate of the Party), that shall be considered an Uncontrollable Force. However, a Party whose performance under this Agreement is hindered by an event of Force Majeure shall make all reasonable efforts to perform its obligations under this Agreement.

18.10 NO AGENCY RELATIONSHIP. This Agreement shall not be interpreted or construed to create an association, joint venture, agency relationship, or partnership between or among the Parties, or any of the Parties, or to impose any partnership obligation or partnership liability upon any of the Parties. No Party shall have any right, power, or authority to enter into any agreement or undertaking for, or act on behalf of, or act as, or be, an agent or representative of, or otherwise bind, any other Party. Responsibilities undertaken or transferred to a Party shall be independently performed by that Party.

18.11 REPRESENTATIONS AND WARRANTIES. Each Party warrants that it possesses the necessary authority to enter into and agree to this Agreement.

18.12 EXECUTION BY COUNTERPARTS. This Agreement may be executed in any number of counterparts, and upon execution by all Parties, each executed counterpart shall have the same force and effect as an original instrument as if all Parties had signed the same instrument.

18.13 NO THIRD PARTY BENEFICIARIES. Except as otherwise provided herein, this Agreement is not intended to, and does not create, any rights, remedies, or benefits of any character whatsoever in favor of any persons, corporations, associations, or entities other than the Parties, and the obligations herein assumed are solely for the use and benefit of the Parties, their successors in interest and, where permitted, their assigns.

18.14 NO MARKET PARTICIPANT. The performance of functions described in this Agreement shall not cause a Party to become a Market Participant.

18.15 NOTICE. Each Party shall designate an individual to receive notice under this Agreement by providing the individual’s name, address, phone number, and email address to the Operating Committee. The Operating Committee shall maintain the list of individuals to receive notice. It shall be the responsibility of each individual Party to update its notice information when necessary.

18.16. ACCESS TO BOOKS AND RECORDS.

18.16.1 Upon request, SPP shall provide Participant with access to the CBA’s books, records, facilities, and procedures required of the BA under the ERO Reliability Standards which are reasonably necessary to determine SPP’s compliance with this Agreement


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and/or to support the Participant’s compliance with applicable ERO Reliability Standards in the Participant’s registered roles as TO, TOP, GO, GOP, LSE, and/or PSE. Such access shall be upon reasonable notice, at reasonable times, and under reasonable conditions.

18.16.2 Upon request, each Participant shall provide SPP with access to Participant’s books, records, facilities, and procedures as necessary to allow SPP to determine Participant’s adherence to this Agreement and/or to support SPP’s compliance as a BA. Such access shall be upon reasonable notice, at reasonable times, and under reasonable conditions. Each Party shall be responsible for its own expenses related to any such request for information.

IN WITNESS WHEREOF, the signatories have caused this Agreement Between Southwest Power Pool, Inc. and Participant Relating to Implementation of the Integrated Marketplace to be executed by their duly authorized representatives as of the dates set forth under their respective signatures. _________________________ Name: Company: Date:


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APPENDIX A

List of Participants


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Southwest Power Pool, Inc. ECONOMIC STUDIES WORKING GROUP

Recommendation to the Markets and Operations Policy Committee October 16-17, 2012

Benefit Metrics

Organizational Roster The following members represent the Economic Studies Working Group (ESWG):

Alan Myers (Chairman), ITC Great Plains Kip Fox (Vice-Chairman), AEP Paul Dietz, Westar Leon Howell, OG&E Randy Collier, CUS Greg Sweet, EDE Al Tamimi, Sunflower

Bruce Walkup, AECC Bennie Weeks, SPS Michael Watt, OMPA Mike Swearingen, Tri-County David Ried, OPPD Kurt Stradely, LES

Jim Sanderson, Kansas Commission Mike Proctor, Consultant

Background On February 9, 2012, the ESWG, under the direction of the Markets and Operations Policy Committee (MOPC), initiated the Metrics Task Force with the specific purpose of developing tangible dollar-oriented measures and metrics for use in the economic evaluations identified by the RARTF Report. In its report, the RARTF recommended the following eight (8) benefits be used in the Regional Cost Allocation Review:

• APC Benefits • Positive Impact on Capacity Required for Losses • Improvements in Reliability • Remedy Benefits • Reduction of Emission Rates and Values • Reduced Operating Reserves Benefits • Improvements to Import/Export Limits • Public Policy Benefits

The RARTF Report further recommended the development of specific metrics that quantify the benefits in dollars by the ESWG. Additionally, the RARTF Report gave freedom to the ESWG to identify other metrics to be used in the Regional Cost Allocation Review. Each of the benefits listed above is addressed by this report.

The ESWG (through the work of the Metrics Task Force) considered methods to monetize a number of benefit metrics, but focused on the benefit metrics listed below. Each of these metrics are facets of the benefit types identified by the RARTF and multiple metrics may be categorized under the same type of benefit. This report contains recommendations regarding each of the following metrics:

• Marginal energy losses benefits

• Mitigation of transmission outage impacts

• Capital savings due to reduction of members’ Minimum Required Capacity Margin

• Reduced Loss of Load Probability

• Reducing the cost of extreme events

• Assumed benefit of mandated reliability projects

• Savings due to lower ancillary service needs and production costs

• Increased wheeling through and out revenues

• Benefit of meeting public policy goals

SPP membership was represented at the MTF by the following individuals appointed by Alan Myers, Chair of the ESWG:

• Kip Fox, Chair American Electric Power

• Roy Boyer Xcel Energy – Southwestern Public Service Company

• Mike Collins Oklahoma Gas and Electric Company

• Paul Dietz Westar Energy, Inc.

• Tom Hestermann Sunflower Electric Power Corporation

• Greg Sweet The Empire District Electric Company

• Mitch Williams Western Farmers Electric Cooperative

In addition, Johannes Pfeifenberger and Kamen Madjarov of the Brattle Group were involved to give insight, suggest additional metrics and hypothetical examples, and finalize the MTF report.

The MTF also recommended that experiences in the application of these metrics, developments in market design, improvements in modeling tools, and increases in data availability be evaluated to ensure that these benefits are appropriately measured and quantified with a sufficient level of precision in the future.

The ESWG approved the Metrics Task Force report as amended by the ESWG in response to the request from the RARTF and further offers the developed metrics for use in whole or in part in the Regional Cost Allocation Review to the MOPC.

Recommendation MOPC approves the Metrics Task Force report and instructs SPP staff to use all of the metrics listed on slide 18 in the Regional Cost Allocation Review..

MTF Report Approved: ESWG 9/13/2012

Passed 13-0

MTF 9/13/2012

Passed 6-0, 1 Abstention

Action Requested: Select metrics for use in the Regional Cost Allocation Review

Southwest Power Pool, Inc. Markets and Operations Policy Committee Recommendation to the Board of Directors

October 29-30, 2012 Neligh 345/115 kV Waiver Request

Organizational Roster Lanny Nickell – Vice President, Engineering Katherine Prewitt – Director, Planning Jody Holland – Manager, Steady State Planning

Background As part of the 2012 ITP 10-Year Assessment (ITP10), the SPP Board of Directors approved for construction the Neligh 345/115 kV transformer In accordance with the Tariff, Nebraska Public Power District (NPPD) applied for a waiver for the Neligh 345/115 kV transformer. Below are details of this transformer:

The Neligh 345/115 kV transformer was identified in conjunction with the Neligh to Hoskins 345 kV line to enable Nebraska to meet its renewable goal in the 2012 ITP10. NPPD plans to put this 474 MVA transformer in-service in March 2019 with the Neligh-Hoskins 345 kV upgrade, and the transformer’s current Engineering and Construction cost is $5,244,000.

Analysis To address the considerations in the Tariff, SPP staff performed analysis to identify the expected usage of the transformer in four parts: need(s) of the transformer to support the underlying system; predominate directional power flows on the transformer in current SPP studies; impacts of generation interconnection queue in the Neligh area; and dependency of long-term transmission service requests on the transformer. NPPD also supplied analysis to support the cost allocation waiver.

Both SPP staff and NPPD find the Neligh transformer’s anticipated flows are predominately from the low (115 kV) to high (345 kV) system. This transformer and new Neligh to Hoskins 345 kV line are expected to provide an outlet for trapped generation based on the waiver evaluation. The Neligh transformer and the Neligh to Hoskins 345 kV line are expected to facilitate future wind interconnections in the surrounding area.

For more details on the analysis, see the Neligh Transformer Waiver Request Analysis report.

Stakeholder Review

SPP staff brought the report and recommendation to CAWG for review. After discussion CAWG endorsed the recommendation unanimously.

Recommendation MOPC recommends the BOD endorse the staff recommendation to approve NPPD’s classification waiver request to use the 345 kV higher voltage level of the Neligh 345/115 kV transformer for cost allocation purposes.

APPROVED:

Approved:

MOPC

Passed with one abstention-Xcel Energy

Cost Allocation Working Group

October 16-17, 2012

10-3-2012

Passed Unopposed


July 2012

Neligh Transformer Waiver Request

Analysis October 8, 2012

Engineering


July 2012 Neligh Transformer Waiver Request Analysis

Table of Contents Background ..................................................................................................................................................2

Staff’s Analysis .............................................................................................................................................3

Objectives ........................................................................................................................................3

Study Methodologies .......................................................................................................................3

Results ..............................................................................................................................................5

NPPD Supporting Information ...................................................................................................................7

Analysis............................................................................................................................................7

Conclusions ...................................................................................................................................................8

Staff’s Recommendation .............................................................................................................................8

Attachment 1 – NPPD waiver request letter

Attachment 2 – NTC 200186 to NPPD for 2012 ITP10 projects


July 2012 Neligh Transformer Waiver Request Analysis 2

Background

As part of the 2012 ITP 10-Year Assessment (ITP10), the SPP Board of Directors approved for construction the Neligh 345/115 kV transformer. The SPP OATT (“Tariff”) Attachment J, Section III specifies the methods under which entities may request a waiver to change the cost allocation of a transformer:

A waiver may be requested to use a transformer’s higher voltage level instead of the lower voltage level for the purposes of cost allocation under this Attachment J based on the anticipated utilization of the transformer. Such request must be made in writing with supporting analysis and submitted to the Transmission Provider not later than one hundred eighty (180) days following the inclusion of the transformer in an approved SPP Transmission Expansion Plan. Any waiver request submitted shall be evaluated based upon the following general factors, including but not limited to:

(i) whether the power flows through the transformer predominately are from the lower voltage to the higher voltage;

(ii) whether the transformer is not necessary for the support of, or does not substantially benefit, the lower voltage system in the host zone to which it is connected.

The Transmission Provider shall make a recommendation to accept or deny the waiver, on a non-discriminatory basis, to the Markets and Operations Policy Committee. Barring unusual circumstances, the recommendation to approve or reject such waiver request will be submitted to the SPP Board of Directors within one hundred twenty (120) days following the receipt of the waiver request.

In accordance with the Tariff, Nebraska Public Power District (NPPD) applied for a waiver for its Neligh 345/115 kV transformer. Below are details of this transformer:

The Neligh 345/115 kV transformer was identified in concert with the Neligh to Hoskins 345 kV line to enable Nebraska to meet its renewable goal in the 2012 ITP10. NPPD plans to put this 474 MVA transformer in-service in March 2019 with the Neligh-Hoskins 345 kV upgrade, and the transformer’s current Engineering and Construction cost estimate is $5,244,000.

Using the requesting party’s analysis and staff performing analysis outlined in this report, SPP staff proposes to the Markets and Operations Policy Committee (MOPC) and SPP Board of Directors a recommendation for the treatment of the waiver request. MOPC will also make a recommendation to the SPP Board of Directors.



Staff ’s Analysis

Objectives To address the considerations in the Tariff, SPP staff performed analysis to identify the expected usage of the transformer in four parts: need(s) of the transformer to support the underlying system; predominate directional power flows on the transformer in current SPP studies; impacts of generation interconnection queue in the Neligh area; and dependency of long-term transmission service requests on the transformer. Based on these analyses and the requesting party’s analyses, staff then proposes a recommendation to the Markets and Operations Policy Committee and SPP Board of Directors.

Map of Neligh Area

Study Methodologies SPP staff performed multiple analyses for the waiver request including determining if the transformer is needed to support the underlying system, determining flows on the transformer for every hour in a year (i.e. 8760 hours), impacts of future wind placement based on the generation interconnection queue, and transmission service dependencies impact. The details of each analysis are outlined below.



Underlying System Support

To determine if the Neligh transformer is needed to support the underlying system, SPP staff reviewed the 2012 ITP10 and 2013 ITPNT analyses to identify any potential regional or local concerns associated with installation of this transformer. The 2012 ITP10 2022 off-peak and peak models contained economic dispatch based on PROMOD tool and included all approved SPP projects. These models were chosen since they captured the timeframe after the Neligh transformer and Neligh-Hoskins 345 kV upgrade would be completed in 2019 and the seasons in which any issues may arise. SPP staff also utilized the 2013 ITPNT analysis to determine if the transformer was needed for support in models containing a block dispatch protecting long-term firm transmission service and projected load growth and including all approved SPP projects. The study horizon was from 2013 through 2018.

Directional flows on transformer

This analysis was performed using the 2012 ITP 10-Year Assessment (ITP10) models1. Future 1: Business As Usual included a wind level of 10 GW in the SPP footprint and Future 2: Federal RES and EPA Regulations incorporated 14 GW of wind in SPP. SPP staff selected the Future 1 model as a conservative approach for this analysis2. This Future 1 model was vetted by stakeholders, and the assumptions were approved by the ESWG for the 2012 ITP10 analysis. The 2012 ITP10 Future 1 model incorporated a total of 10 GW of wind capacity in the SPP footprint with 176 MW directly interconnected on the 115 kV system near Neligh. This is 6 GW more than was in-service in mid-2011. The additional wind was determined through the Cost Allocation Working Group (CAWG) 2011 Renewables Survey. For this analysis, the transformer was placed in the 2012 ITP10 Future 1 model. SPP staff then determined whether the flows on the transformer were predominately from the lower voltage to the higher voltage by running a security-constrained economic dispatch tool. The flows were calculated for every hour of the modeled year (2022).

1 Updated in August 2011 2 Future 1 contained 176 MW of wind near Neligh, and Future 2 contained 220 MW of wind at Neligh 115 kV.



Generation Interconnection Queue Impacts

SPP staff also considered other things in its analyses, including the generation interconnection (GI) queue. Below is a table of the current SPP GI queue statistics showing the Neligh area wind interconnection amounts in MW by status.

Transmission Service Requests Impacts

SPP staff evaluated dependency of this project on transmission service requests to guarantee long-term firm service execution.

Results

Underlying System Support

Using the 2012 ITP10 analysis, Staff determined that without the Neligh transformer the underlying system would be overloaded based on the placement of wind generation. The Neligh transformer and 345 kV line to Hoskins were approved because they relieve overloads on the underlying system and move trapped generation to the EHV system. In the 2013 ITPNT analysis, staff determined the transformer is not needed to support transmission service and projected load growth.

Directional flows on transformer

The flow on the Neligh transformer from the lower voltage to the higher voltage occurs 59% of year 2022. The flows on the transformer vary from nearly 100 MW going from the high to the low side of the transformer in a single hour to almost 175 MW flowing in the other direction in other hours. Figure 1 shows the flows for all 8760 hours of 2022 from the 2012 ITP10 Future 1 scenario. Of total MWh usage on the transformer, 70.6% (359,789 MWh flowing up and 150,102 MWh flowing down) of the flows are from the lower voltage to the higher voltage. The flow direction is impacted by the location of the wind along with the voltage level at which the wind is connected.

Figure 1



Generation Interconnection Queue Impacts

The SPP GI queue shows up to 460 MW of potential wind generation being installed near Neligh on the lower voltage 115 kV system, and nearly 385 MW of that total is currently in-service. The installed wind has been studied in ITP Near-Term Assessments and results showed no necessary transmission upgrades are needed for the facilitation of this wind generation. Staff observed the GI queue currently has fewer wind requests due to regulatory uncertainty on renewable incentives. With no wind under study in the queue, staff noted one goal of the 2012 ITP10 study was to respond to national energy priorities; in its assumptions, 2012 ITP10 integrated 10 GW and 14 GW of wind in SPP respectively based on Future 1 and Future 2, with large amounts of that wind connected near Neligh. Based on those assumptions, SPP projected the Neligh transformer could be used to integrate the wind with the EHV backbone system.

*As of August 31, 2012

Transmission Service Requests Impacts

As of August 2012, there are currently no transmission service requests dependent on this project for execution of long-term firm service. There are requests in later-queued studies, 2012-AG1 and 2012-AG2, showing a possible need for this transformer. These studies are still underway.

SPP Table – Current GI Queue Wind Statistics*

GI Queue Status

In-Service (MW)

IA Executed (MW) Under Study (MW)

Totals(MW)

Construction authorized

by customer

Construction not authorized

On Suspension

Neligh Area > 300 kV - - - - - 0

Neligh Area < 300 kV 384 - - 75 - 459

Totals (MW) 384 0 0 75 0 459



NPPD Supporting Information

SPP issued an NTC to NPPD to install a new 345/115 kV transformer at Neligh in conjunction with the Neligh-Hoskins 345 kV line. In accordance with Tariff provisions, on July 26, 2012, NPPD submitted a waiver request for this transformer’s cost allocation. Below is a summary of NPPD’s analysis for why this waiver should be granted.

Analysis NPPD provided a two-part assessment addressing the Tariff requirements for waiver requests. One analysis indicates the anticipated flows on the transformer are predominately from the low to high voltage system. The second portion states “but for” the 2012 ITP10 study, which needs the Neligh to Hoskins 345 kV project, the transformer is not needed for the support of the lower voltage system. To determine the anticipated flows on the transformer, NPPD performed analysis using the 2012 ITP10 models under system intact and worst-case contingency conditions3. In the off-peak season the flows on the transformer travel from the 115 kV to 345 kV, while under summer peak conditions the flows generally move from the 345 kV to 115 kV system. NPPD believes the off-peak period represents the majority of the year. Therefore NPPD reasons the flows are predominately from the low to high voltage system. To address the underlying system needs or benefits of the transformer, NPPD reasons the large wind injections in the 2012 ITP10 in the Neligh area require the Neligh to Hoskins 345 kV line and Neligh 345/115 kV transformer to provide generation outlet. It states the ITP Near-Term Assessments do not require this project for nearer term reliability needs. “But for” the Neligh to Hoskins 345 kV project needed in the 2012 ITP10, the Neligh transformer would be unnecessary. Therefore, NPPD concludes this waiver request should be granted.

3 See NPPD’s waiver request in Attachment 1 for more details.



Conclusions

Both SPP staff and NPPD find the Neligh transformer’s anticipated flows are predominately from the low (115 kV) to high (345 kV) system. Staff agrees this transformer and new Neligh to Hoskins 345 kV line are needed to provide an outlet for trapped generation based on the 2012 ITP10 study. The Neligh transformer in concert with the Neligh to Hoskins 345 kV line will help realize future wind interconnections in the surrounding area.

Staff ’s Recommendation

Staff recommends the SPP Board approve NPPD’s classification waiver request to use the 345 kV higher voltage level of the Neligh 345/115 kV transformer for cost allocation purposes.


Recommendation to the Board of Directors On NTC Re-evaluation for Altoona East Capacitor

October 16-17, 2012

Organizational Roster The following members represent the Southwest Power Pool:

Carl Monroe, Executive Vice President and Chief Operating Officer Lanny Nickell, Vice President, Engineering Katherine Prewitt, Director, Planning Steve Purdy, Manager, Transmission Service Studies

Background SPP issued a Notification to Construct (NTC) to Westar in September 2009 for a 6 MVAR 69 kV capacitor bank to be constructed at Altoona East substation. The upgrade was needed to support transmission service requested in aggregate study 2007-AG1. The cost estimate increased from $607,500 in the second-quarter project tracking update to $1,045,000 in the third-quarter 2012 update. Because the cost estimate increased by more than 20% from one quarter to the next, SPP Staff recommended that the need for the upgrade be re-evaluated pursuant to SPP Business Practice 7050. The SPP Board agreed and directed re-evaluation at its July 2012 meeting. Westar states that the construction lead time is 18 months and that it has spent approximately $4,000 to date for engineering and design work.

Analysis SPP Staff reviewed the power flow results from the 2007-AG1 study. The results showed that the requested transfers caused low voltages along the Altoona-Cherryvale 69 kV line for the loss of Altoona 138/69 kV transformer. In consultation with Westar, SPP Staff chose the 6 MVAR capacitor bank as the best solution. An NTC was issued with a June 2014 need date.

SPP Staff then examined the current 2012-series power flow models which includes all confirmed transmission service. This examination showed that low voltages would occur for the same contingency in the 2013 summer peak case without the capacitor bank in service.

SPP Staff considered alternative solutions, such as line re-conductors and transformer additions. Such alternatives could be reasonably expected to exceed the current cost estimate for the capacitor bank. SPP Staff’s analysis shows that the upgrade is still needed and is the most cost-effective solution.

Recommendation

MOPC recommends the BOD unsuspend the NTC.

APPROVED: MOPC October 16-17, 2012 Passed unanimously


Markets and Operations Policy Committee


October 29-30, 2012

Quarter 4 2012 Project Tracking NTC Re-evaluation

Organizational Roster MOPC Background As part of the quarterly project tracking effort as specified in Attachment O of the SPP Open Access Transmission Tariff (OATT) and Business Practice 7050, SPP staff reviews the cost estimates provided by Transmission Owners for all SPP Transmission Expansion Plan Network Upgrades approved by the SPP Board of Directors (BOD) and identifies each upgrade with a cost estimate increase of more than 20% from the previous quarter. SPP staff then requests the cause(s) of the cost increase for each upgrade for the Designated Transmission Owner. Using this information along with other factors, such as percentage of construction complete, SPP staff makes a recommendation as to whether the upgrade should be re-evaluated. As a result of the 4th quarter project tracking cycle of 2012, SPP staff made the recommendation to re-evaluate the upgrade with Network Upgrade ID 10511 titled “Afton Transformer 161/69 kV”. SPP staff identified this upgrade as a regional reliability solution in the 2007 SPP Transmission Expansion Plan, which was subsequently approved by the BOD in January 2008. SPP staff included the upgrade in NTC 20001 issued to Grand River Dam Authority (GRDA) on February 13, 2008. SPP staff issued GRDA a NTC with modifications to the project (NTC 20076) on February 8, 2010 moving the need date for the project from 6/1/2012 to 6/1/2010. The following project scope description and specification was listed on NTC 20076: Add second 161/69 kV transformer at Afton. Install the transformer for emergency rating 50 MVA. GRDA accepted NTC 20076 on March 10, 2010. On August 6, 2012, GRDA submitted to SPP staff an updated cost estimate of $8,020,000 for the Afton Transformer project. This indicated a 167.33% increase from the previously submitted cost estimate of $3,000,000. GRDA noted the reason for the cost variance is the substantial amount of work required to convert the substation to a “breaker-and-a-half” scheme that was not considered in previous estimates. GRDA informed SPP staff that approximately $720,000 had been spent on the upgrade to date. GRDA estimated the date of completion for the upgrade as August 1, 2013, and indicated a 24-month lead time was required for completion of the upgrade. A mitigation plan for the upgrade was previously provided by GRDA and approved by SPP staff. Recommendation MOPC recommends the BOD suspend the NTC for the Afton Transformer.

Action Requested: Suspend NTC

Approved:

MOPC

10/16-17/2012

Passed unanimously

Southwest Power Pool, Inc. FOURTH QUARTERLY

PROJECT TRACKING REPORT OCTOBER 2012

2

Southwest Power Pool, Inc. FOURTH QUARTERLY PROJECT TRACKING REPORT

October 2012

I. Project Tracking, Current SPP Process: SPP actively monitors and supports the progress of transmission expansion projects, emphasizing the importance of maintaining accountability for areas such as grid regional reliability standards, firm transmission commitments and tariff cost recovery. Each quarter SPP staff solicits feedback from the project owners to determine the progress of each approved transmission project. This quarterly report charts the progress of all SPP Transmission Expansion Plan (STEP) projects approved either directly by the Board of Directors or through a FERC filed service agreement under the SPP Open Access Transmission Tariff (OATT). In this Fourth Quarterly Report of 2012, the reporting period is June 1, 2012 through August 31, 2012.

II. Project Summary:

Figure 1 represents the summary of active projects for this quarter. Figure 1 reflects all upgrades, including transmission lines, transformers, substations, and devices. There were no Notifications to Construct issued this quarter, which is common following the large number of new upgrades issued in the 2nd Quarter.

Figure 2 shows the total miles of transmission lines currently planned within the portfolio, as well as miles by project voltage. Figure 3 reflects the percentage cost of each project type in the total active portfolio.

3

3rd Quarter 2012 Project Tracking Summary Upgrade Type Number of Upgrades Cost Estimate

Regional Reliability 240 $1,454,423,766 Regional Reliability - Non

OATT 14 $46,612,000

Zonal Reliability 10 $30,210,472

Transmission Service 55 $428,654,249

Generation Interconnect 22 $148,089,541

Balanced Portfolio 18 $856,231,896

High Priority 22 $1,446,090,589

ITP10 27 $1,141,793,310

Other Sponsored Upgrades 47 $292,622,341

TOTALS 455 $5,844,728,164

Figure 1: 2012 3rd Quarter Project Summary

3rd Quarter Total Active Portfolio Transmission Miles

Voltage Number of Upgrades New Miles Reconductor

Miles Total Miles 69 60 17.8 195.1 212.9

115 87 272.5 143.0 415.5

138 68 58.2 83.5 141.7

161 24 27.1 15.2 42.3

230 15 164.4 0.0 164.4

345 58 2,638.3 0.0 2,638.3

Totals 312 3,178.3 436.8 3,615.1

Figure 2: Project Mileage within the Portfolio

Figure 3: Breakdown of Project Categories on Cost Basis

III. Regional Reliability Project Summary:

Regional reliability projects include all tariff signatory projects identified in an SPP study to meet regional reliability criteria for which NTC letters have been issued. Figure 4 shows the breakdown of the regional reliability projects.

There were 16 upgrades, with latest Engineering and Construction (E&C) cost estimates of $106 million completed in the timeframe of the 3rd Quarter of 2012. The largest project completed was the 46.5 miles of new 345kV line in Oklahoma Gas and Electric Company’s portion of the Rose Hill to Sooner project, estimated at $44.7 million. Also completed this quarter were 62 miles of 230kV line built from Hitchland-Moore County by Southwestern Public Service Company. The cost for the project was almost $37 million. Eleven projects that were on track to be completed this quarter have been delayed until later in the reporting period.

There are 54 upgrades, with latest E&C cost estimates of $386.4 million, on schedule to be completed within the next four years. 139 upgrades, with latest E&C cost estimates of $761 million, are in a delayed status with mitigation.

4

IV. Transmission Service/Generation Interconnection (TSR/GI) Project Summary:

This category contains upgrades identified as needed to support new Transmission Service (TSR) and Generation Interconnection (GI) service agreements. Figure 4 shows the details of the Transmission Service and Generation Interconnect projects.

Ten Transmission Service upgrades, with latest E&C cost estimates at $98 million were completed in the 3rd Quarter of 2012. American Electric Power’s Turk to Northwest Texarkana project completed this quarter with an estimated cost of $44 million, adding 33 miles of 345kV line into the footprint. Also completed was ITC Great Plains Valliant to Hugo project, delivering 19 miles of 345kV line and equipment at an estimated cost of $35 million. There are nine Transmission Service upgrades, with estimated E&C costs of $179.6 million, on schedule to be completed within the next four years. There are 12 Generation Interconnect upgrades, at an estimated E&C cost of $69.3 million, scheduled to be completed in the next four years.

Figure 4: Project Status

5

V. Completed Projects Summary:

Figure 5 shows the number and costs for the projects completed over the last 12 month period. The 3rd Quarter of 2012 produced 26 projects that were completed with a total estimated cost of $204.4 million. Although 28 projects were completed for this same period in 2011, the total cost in the 3rd Quarter of 2011 was $84.1 million, which reflects a significantly larger investment in the footprint in the same period of 2012.

Previous quarter’s updated results are listed as the Transmission Owners may make adjustments to final costs and status of projects completed during the year. Corrections are listed for those projects reported complete after the 3rd Quarter reporting period had ended.

Projects Completed By Quarter

Figure 5: Completed Project Summary through 3rd Quarter 2012

6

7

3rd Quarter Total Transmission Miles and Devices Completed

Voltage Number of Upgrades

New Miles

Reconductor Miles

Total Miles Estimated Cost

69 5 0.0 8.6 8.6 $6,254,814

115 10 8.0 27.4 35.4 $19,063,989

138 4 0.0 0.0 0.0 $1,016,000

161 3 0.0 0.0 0.0 $12,832,934

230 1 62.0 0.0 62.0 $36,692,293

345 6 98.5 0.0 98.5 $117,750,096

Totals 29 168.5 36.0 204.5 $193,610,126

Figure 6: Completed Transmission for 3rd Quarter 2012

VI. Future Projections:

4th Quarter 2012:

The 4th Quarter of 2012, ending November 30, 2012 is scheduled to have 16 projects completed across all project types at an estimated cost of $44 million. The largest project is Midwest Energy-Westar Energy’s Rice-Circle 230kV conversion project at an estimated cost of $18.7 million. Figure 7 shows the 4th Quarter estimated completed projects broken out by Project Type.

There are 10 miles of new transmission scheduled to be completed in the next quarter, along with 25 miles of reconductored transmission added to the footprint. Figure 8 shows the details of the estimated transmission miles to be completed in the 4th Quarter.

September 2012 through August 2013:

The next 12 months are scheduled to have a total of 127 upgrades completed at an estimated cost of $752 million. This is higher than last quarter’s projections, as several projects were delayed into this 12 month period, along with the large amount of completed projects scheduled for June of 2013 (56). Figure 7 shows the next 12 months estimated completed projects broken out by Project Type.

There are scheduled to be 294 miles of new transmission added to the system during the next 12 month period. 161 miles of 345 kV transmission lines are still scheduled to be completed. There will also be 251 miles of reconductored transmission placed into the system. Figure 9 shows the details of the estimated transmission miles to be completed over the next 12 months.

Figure 7: Upgrades Scheduled to Complete Next Quarter/Next 12 Months

8

9

4th Quarter Projected Transmission Miles Complete

Voltage Number of Upgrades New Miles

Reconductor Miles

Total Miles

69 3 0.0 21.6 21.6

115 3 0.0 3.4 3.4

138 3 7.0 0.0 7.0

161 3 2.0 0.0 2.0

230 2 1.0 0.0 1.0

345 0 0.0 0.0 0.0

Totals 14 10.0 25.0 35.0

Figure 8: Transmission Miles Scheduled to Complete 4th Quarter

Projected Transmission Miles Complete Next 12 Months

Voltage Number of Upgrades New Miles

Reconductor Miles

Total Miles

69 22 3 95.76 98.76

115 32 22.02 93.22 115.24

138 25 34.2 47.13 81.33

161 12 18.1 15.2 33.3

230 5 56 0 56

345 8 161 0 161

Totals 104 294.32 251.31 545.63

Figure 9: Transmission Miles Scheduled to Complete Next 12 Months

e

20103 11497 WR Line - Thistle - Wichita 345 kV dbl Ckt High Priority 12/31/14 06/30/10 $5 ON SCHEDULE < 4 equipment at Wichita Sustation and uid 11497 was added to include

SPP 4th Quarter 2012 Project Tracking ListCOMPLETE Complete.

ON SCHEDULE <4 On Schedule 4 Year Horizon.ON SCHEDULE >4 On Schedule beyond 4 Year Horizon.

DELAY - MITIGATION Behind schedule, interim mitigation provided or project may change but time permits the implementation of project. RE-EVALUATION Behind schedule, require re-evaluation due to anticipated load forecast changes.

NTC-COMMITMENT WINDOW NTC issued, still within the 90 day written commitment to construct window and no commitment receiv

Project types "zonal - sponsored" and "regional reliability - non OATT" do not receive NTCs and are not filed at FERC but are being tracked because they are expected to be built in the near term

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20096 11236 AEP Line - Valliant - NW Texarkana 345 kV High Priority 05/01/15 06/30/10 $131,451,250 $127,995,000 ON SCHEDULE < 4 Delayed20096 11237 AEP Tulsa Power Station 138 kV reactor High Priority 06/10/11 06/30/10 $842,847 $960,895 COMPLETE Complete 6/10/201120097 11238 GMO Multi - Nebraska City - Maryville - Sibley 345 kV (GMO) High Priority 06/01/17 07/23/10 $174,500,000 $231,600,000 ON SCHEDULE > 4 currently in contract negotiations for line routing and siting.20097 11239 GMO Multi - Nebraska City - Maryville - Sibley 345 kV (GMO) High Priority 06/01/17 07/23/10 $114,500,000 $152,640,000 ON SCHEDULE > 4 currently in contract negotiations for line routing and siting.20098 11240 OPPD Line - Nebraska City - Maryville 345 kV (OPPD) high priority 06/01/17 06/30/10 $12,029,091 $19,796,666 ON SCHEDULE > 420099 11241 SPS Multi - Hitchland - Woodward 345 kV (SPS) High Priority 06/30/14 06/30/10 $8,883,760 $8,883,760 ON SCHEDULE < 420099 11242 SPS Multi - Hitchland - Woodward 345 kV (SPS) High Priority 06/30/14

0/140/140/14

06/306/3

0/10 ON SCHEDULE < 4$38,790,72720099 11243 SPS Multi - Hitchland - Woodward 345 kV (SPS) high priority 06/3 0/10 ON SCHEDULE < 4$238,122,03320100 11244 OGE Line - Hitchland - Woodward 345 kV dbl Ckt (OGE) High Priority 06/3 06/3

06/30/10 $187,250,000 ON SCHEDULE < 4 Project milage increased

20100 11245 OGE Line - Hitchland - Woodward 345 kV dbl Ckt (OGE) High Priority 06/3 0/10 ON SCHEDULE < 4 Project milage increased20121 11246 OGE Line - Thistle - Woodward 345 kV dbl Ckt (OGE) High Priority 12/31/14

1/1411/211/2

2/10 ON SCHEDULE < 4$149,600,000$97,427,50020121 11247 OGE Line - Thistle - Woodward 345 kV dbl Ckt (OGE) High Priority 12/3 2/10 ON SCHEDULE < 4

200163 11248 PW Line - Thistle - Woodward 345 kV dbl Ckt (PW) High Priority 12/31/141/14

07/29/11 $31,371,000 ON SCHEDULE < 4$10,800,000200163 11249 PW Line - Thistle - Woodward 345 kV dbl Ckt (PW) High Priority 12/3 07/29/11 $31,371,000 ON SCHEDULE < 4200162 11252 ITCGP Line - Spearville - Clark Co - Thistle 345 kV dbl Ckt High Priority 12/31/14

1/141/141/14

07/29/11 $46,486,418 ON SCHEDULE < 4200162 11253 ITCGP Line - Spearville - Clark Co - Thistle 345 kV dbl Ckt High Priority 12/3 07/29/11 $46,486,418 ON SCHEDULE < 4$201,221,000200162 11254 ITCGP Line - Spearville - Clark Co - Thistle 345 kV dbl Ckt High Priority 12/3 07/29/11 $99,057,647 ON SCHEDULE < 4200162 11255 ITCGP Line - Spearville - Clark Co - Thistle 345 kV dbl Ckt High Priority 12/3 07/29/11 $99,057,647 ON SCHEDULE < 4200162 11260 ITCGP Line - Spearville - Clark Co - Thistle 345 kV dbl Ckt High Priority 12/31/14 07/29/11 $4,379,000 $4,379,000 ON SCHEDULE < 4200162 50384 ITCGP Line - Spearville - Clark Co - Thistle 345 kV dbl Ckt High Priority 12/31/14 07/29/11 $4,727,306 $4,727,306 ON SCHEDULE < 4200163 11258 PW Line - Thistle - Wichita 345 kV dbl Ckt High Priority 12/31/14

1/1407/29/11 $80,668,000 ON SCHEDULE < 4

200163 11259 PW Line - Thistle - Wichita 345 kV dbl Ckt High Priority 12/3 07/29/11 $80,668,000 ON SCHEDULE < 4

20103 11497 WR Line - Thistle - Wichita 345 kV dbl Ckt High Priority 12/31/14 06/30/10 $5,262,000$150,700,000

,262,000 ON SCHEDULE < 4UID 11258 and 11259 were revised to separate out terminal equipment at Wichita Sustation and uid 11497 was added to include this equipment

20040 10927 GRDA Line - Sooner – Cleveland 345 kV (GRDA) Balanced Portfolio 12/31/12 06/19/09 $17,000,000 $2,780,000 ON SCHEDULE < 4 Original Estimate Revised 8/16/2012

20041 10929 OGE Line - Sooner - Cleveland 345 kV (OGE) Balanced Portfolio 12/31/12 06/19/09 $17,000,000 $55,912,524 ON SCHEDULE < 4 Cost reduced to account for lower construction costs than expected.20041 10930 OGE Line - Seminole - Muskogee 345 kV Balanced Portfolio 12/31/13 06/19/09 $131,000,000 $176,100,000 ON SCHEDULE < 420041 10932 OGE Multi - Tuco - Woodward 345 kV (OGE) Balanced Portfolio 05/19/14 06/1

06/1

06/1

9/09 $64,000,000 ON SCHEDULE < 420041 10933 OGE Multi - Tuco - Woodward 345 kV (OGE) Balanced Portfolio 05/19/14 9/09 $15,000,000 ON SCHEDULE < 4

20043 10937 OGE Multi - Tuco - Woodward 345 kV (OGE) Balanced Portfolio 05/19/14 9/09 $14,880,000$147,000,000

ON SCHEDULE < 4Build midpoint reactor station at interception point of Woodward to Tuco line. Cost already included in above two projects. Original SPS project.

20042 10934 KCPL Tap - Swissvale - Stilwell Balanced Portfolio 12/31/12 06/19/09 $2,000,000 $1,922,840 ON SCHEDULE < 4 project delayed due to delay in obtaining substation steel

20042 10945 KCPL Multi - Iatan - Nashua 345 kV Balanced Portfolio 06/01/15 06/19/09 $4,620,000 $4,230,820 ON SCHEDULE < 4 KCPL will construct 345/161kV, 650Mva transformer addition at Nashua

200189 50499 GMO Multi - Iatan - Nashua 345 kV Balanced Portfolio 06/01/151/15

04/17/12 $48,438,919$49,824,000 ON SCHEDULE < 4 GMO will construct Iatan-Nashua transmission line ~31 miles 345kV; 200188 10935 KCPL Multi - Iatan - Nashua 345 kV Balanced Portfolio 06/0 04/17/12 $12,130,261 ON SCHEDULE < 4 KCPL will construct line terminals and substation additions at Iatan & 20043 10936 SPS Multi - Tuco - Woodward 345 kV (SPS) Balanced Portfolio 05/19/14 06/19/09 $122,597,500 $170,247,072 ON SCHEDULE < 4 This is the SPS current cost estimate for the transmission line from 20084 11085 SPS Multi - Tuco - Woodward 345 kV (SPS) Balanced Portfolio 03/31/13 06/01/12 02/08/10 $11,250,000 $15,498,390 DELAY - MITIGATION This cost is included in the total cost of project UID 10936 according 20044 10938 WFEC Tap Anadarko - Washita 138 kV line into Gracemont 345 kV Balanced Portfolio 10/12/12 06/19/09 $2,000,000 $966,210 ON SCHEDULE < 420046 10940 ITCGP Multi - Axtell - Post Rock - Spearville 345 kV Balanced Portfolio 06/18/12 06/19/09 $96,000,000 $79,136,700 ON SCHEDULE < 420065 10941 ITCGP Multi - Axtell - Post Rock - Spearville 345 kV Balanced Portfolio 06/18/12 11/06/09 $3,000,000 $4,348,600 ON SCHEDULE < 420046 10943 ITCGP Multi - Axtell - Post Rock - Spearville 345 kV Balanced Portfolio 06/01/13 06/19/09 $66,000,000 $64,514,700 ON SCHEDULE < 4 Updated mileage for filed route; reactor added at Post Rock (55 Mvar)20047 10942 NPPD Line - Axtell - Kansas Border 345 kV (NPPD) Balanced Portfolio 12/31/12 06/19/09 $71,377,000 $59,050,000 ON SCHEDULE < 4

20041 10946 OGE Sub - Gracemont Balanced Portfolio 12/31/11 06/19/09 $8,000,000 $13,954,860 COMPLETE Final cost Still being compiled

20015 10460 AECC Line - Hope - Fulton 115 kV Recond Transmission Service 06/08/11 04/01/12 01/16/09 $440,000 $1,512,000 $640,645 COMPLETEFull BPF-In service-Waiting on final paper work

20015 10461 AECC Line - Hope - Fulton 115 kV Recond Transmission Service 06/08/11 04/01/12 01/16/09 $1,512,000 $440,000 $18,899 COMPLETE Full BPF-In service-Waiting on final paper work

20015 50151 AECC Line - McNab - Turk 115 kV Transmission Service 11/07/11 04/01/12 01/16/09 $165,000 $165,000 $417,349 COMPLETE Full BPF - In service - cost not final - NTC not closed out

10367 AECI Multi - Blackberry - Chouteau - GRDA 1 Inter-regional 12/31/13

1/11

1/11

ON SCHEDULE < 4 As of 05/11/12 Clearing approximately 100% complete. Construction: sec1 laid out 100%; framed 100%; set 80%, anchors 100%, stringing

10368 AECI Multi - Blackberry - Chouteau - GRDA 1 Inter-regional 02/0 COMPLETE


10781 AECI Multi - Blackberry - Chouteau - GRDA 1 Inter-regional 02/01/11

1/11

COMPLETE

$57,000,000 $100,000,000


20000 10140 AEP Multi - Wallace Lake - Port Robson - RedPoint 138 kV Regional Reliability 04/16/12 06/01/12 02/13/08 $24,000,000 $9,480,000 COMPLETE

20000 10141 AEP Multi - Wallace Lake - Port Robson - RedPoint 138 kV Regional Reliability 03/01/12 06/01/12 02/13/08 $0 $19,482,000 COMPLETE

10296 AEP Line - Turk - SE Texarkana - 138 kV Generation Interconnection 03/12/12 $26,850,000 $25,590,000 COMPLETE

20016 10374 AEP Line - Valliant Substation - Install 345 kV terminal equipment Transmission Service 04/17/12 04/01/12 01/16/09 $3,840,000 $3,840,000 COMPLETE Notification received from the SPP concurring with the new in-service date due to the delay of the Turk plant. 73% BPF. Completed 4/17/12

10446 AEP Multi - McNab REC - Turk 115 kV Generation Interconnection 12/01/11 $8,100,000 $7,810,000 COMPLETE



10451 AEP Multi - McNab REC - Turk 115 kV Generation Interconnection 12/01/11 $3,400,000 $3,266,000 COMPLETE Replacement not needed in 2009 due to re-rating, but replacement needed in 2011 due to voltage conversion associated with Turk.

10452 AEP Multi - McNab REC - Turk 115 kV Generation Interconnection 12/01/11 $9,190,000 $8,170,000 COMPLETE10455 AEP Multi - McNab REC - Turk 115 kV Generation Interconnection 12/01/11 $0 $11,250,000 COMPLETE

200161 10456 AEP Multi - McNab REC - Turk 115 kV Transmission Service 06/30/12 04/01/12 09/18/09 $7,310,000 $7,310,000 COMPLETE Turk commercial operation date delayed until late 2012; Complete 06/30/2012

10457 AEP Multi - McNab REC - Turk 115 kV Generation Interconnection 12/01/11 $9,110,000 $7,806,000 COMPLETE20000 10505 AEP Line - Riverside - Okmulgee 138 kV Regional Reliability 03/01/12 06/01/12 02/13/08 $125,000 $125,000 COMPLETE

20122 10509 AEP Line - Lone Star South - Pittsburg 138kV Ckt 1 Regional Reliability 05/11/12 06/01/12 02/14/11 $300,000 $300,000 COMPLETE

20027 10510 AEP Line - Howell - Kilgore 69 kV Regional Reliability 05/07/12 06/01/09 01/27/09 $2,000,000 $3,986,000 COMPLETE20027 10575 AEP Line - Osborne - Osborne Tap Regional Reliability 06/01/13 06/01/13 01/27/09 $6,000,000 $2,000,000 ON SCHEDULE < 420048 10578 AEP Line - Coffeyville Tap - North Bartleville 138 kV Transmission Service 05/11/11 06/01/11 09/18/09 $13,100,000 $13,100,000 COMPLETE Complete 5/11/1120000 10582 AEP Multi - Flint Creek – Centerton 345 kV and Centerton- East Centerton Regional Reliability 06/01/14 06/0

1/14 06/01/14 06/0

1/14 02/13/08 $11,962,000 ON SCHEDULE < 420000 10584 AEP Multi - Flint Creek – Centerton 345 kV and Centerton- East Centerton Regional Reliability 06/0 1/14 02/13/08 $13,104,000 ON SCHEDULE < 4$35,185,00020000 10585 AEP Multi - Flint Creek – Centerton 345 kV and Centerton- East Centerton Regional Reliability 06/0 1/14 02/13/08 $34,085,000 ON SCHEDULE < 4

20027 10586 AEP XFR - Whitney 138/69 kV Regional Reliability 06/01/11 06/01/11 01/27/09 $350,000 $350,000 COMPLETE Complete 6/1/2011

20048 10588 AEP Line - Bartlesville Southeast - North Bartlesville 138 kV Transmission Service 05/11/11 06/01/11 09/18/09 $8,400,000 $8,400,000 COMPLETE Complete 5/11/11

200167 10647 AEP Line - Northwest Henderson - Poynter 69 kV Regional Reliability 06/01/14 06/01/14 04/09/12 $7,214,837 $7,815,833 ON SCHEDULE < 4

200167 10648 AEP Line - Diana - Perdue 138 kV Regional Reliability 06/01/14 06/01/13 04/09/12 $926,970 $1,004,187 DELAY - MITIGATION

20000 10656 AEP Multi - Centerton - Osage Creek 345 kV Regional Reliability 06/01/16 06/0

1/16 06/0

1/16 06/0

1/16 02/13/08 $11,000,000 ON SCHEDULE < 4

20000 10659 AEP Multi - Centerton - Osage Creek 345 kV Regional Reliability 06/0 1/16 02/13/08 $24,500,000 ON SCHEDULE < 4$57,500,000

20000 10660 AEP Multi - Centerton - Osage Creek 345 kV Regional Reliability 06/0 1/16 02/13/08 $65,500,000 ON SCHEDULE < 4

20000 10786 AEP Multi - Wallace Lake - Port Robson - RedPoint 138 kV Regional Reliability 06/01/11 06/01/12 02/13/08 $11,988,400 COMPLETE

Complete 6/1/201120027 10853 AEP Line - Lone Star-Locust Grove 115 kV regional reliability 06/01/14 06/01/14 01/27/09 $2,150,000 $2,150,000 ON SCHEDULE < 420073 11011 AEP Multi - Canadian River - McAlester City - Dustin 138 kV regional reliability 06/01/13 06/01/10 02/08/10 $17,000,000 $24,965,000 DELAY - MITIGATION20073 11012 AEP Multi - Canadian River - McAlester City - Dustin 138 kV regional reliability 06/01/13 06/01/10 02/08/10 $8,500,000 $9,513,000 DELAY - MITIGATION

20064 11015 AEP Line - Ashdown - Craig Junction 138 kV Rebuild regional reliability 06/01/13 06/01/13 11/02/09 $2,500,000 $2,500,000 ON SCHEDULE < 4

200167 11171 AEP Line - Carthage - Rock Hill 69 kV Ckt 1 rebuild Regional Reliability 06/01/14 06/01/14 04/09/12 $13,500,000 $11,830,128 ON SCHEDULE < 4

20073 11183 AEP Multi - Canadian River - McAlester City - Dustin 138 kV Regional Reliability 05/16/12 06/01/10 02/08/10 $2,900,000 $4,096,000 COMPLETE

20073 11184 AEP Multi - Canadian River - McAlester City - Dustin 138 kV regional reliability 06/01/13 06/01/10 02/08/10 $2,900,000 $4,096,000 DELAY - MITIGATION

11185 AEP Line - Lone Oak - EnoGex Wilberton 138 kV Zonal - Sponsored 03/11/11 $0 $1,456,000 COMPLETEComplete 3/11/2011

20066 11199 AEP Line - Coffeyville Tap - South Coffeyville City 138 kV Transmission Service 06/28/11 06/01/11 01/13/10 $6,000,000 $6,000,000 COMPLETE

20066 11208 AEP Line - Coffeyville Farmland - South Coffeyville City 138 kV Transmission Service 05/22/11 06/01/11 01/13/10 $2,200,000 $2,200,000 COMPLETE Complete 5/22/2011

20104 11261 AEP Line - Broken Arrow North South Tap - Oneta 138 kV Ckt 1 Transmission Service 06/01/15 06/01/15 08/25/10 $4,400,000 $4,400,000 ON SCHEDULE < 4

200167 11331 AEP Line - Diana - Perdue 138 kV Reconductor Regional Reliability 06/01/14 06/01/14 04/09/12 $17,359,447 $18,805,489 ON SCHEDULE < 4 In mid 2011, this project was replaced with Springhill - Perdue 138 kV

20112 11347 AEP Line - Southwest Shreveport - Springridge REC 138 kV Transmission Service 06/01/13 06/01/12 12/09/10 $7,200,000 $7,200,000 DELAY - MITIGATION Interim redispatch required20112 11348 AEP Line - Eastex - Whitney 138 kV Accelerated Transmission Service 06/01/13 06/01/12 12/09/10 $2,800,000 $2,800,000 DELAY - MITIGATION Interim redispatch required20122 11421 AEP Line - Hooks - Lone Star Ordinance 69 kV Ckt 1 Regional Reliability 06/01/13 06/01/13 02/14/11 $2,100,000 $2,100,000 ON SCHEDULE < 4

20016 50148 AEP Line - Turk - NW Texarkana 345 kV Transmission Service 08/28/12 04/08/12 04/08/12 04/0

1/12 01/11/12 01/11/12 01/1

6/09 COMPLETE Change PID and UID (old PID 349 and old UID 10453)Turk 20016 50149 AEP Line - Turk - NW Texarkana 345 kV Transmission Service 08/2 6/09 $57,530,000 $44,200,000 COMPLETE Change PID and UID (old PID 349 and old UID 10453)Turk 20016 50150 AEP Line - Turk - NW Texarkana 345 kV Transmission Service 08/2 6/09 COMPLETE Change PID and UID (old PID 349 and old UID 10453)Turk 20122 50156 AEP Line - Bann - Lone Star Ordinance 69 kV Ckt 1 Regional Reliability 06/01/13 06/01/13 02/14/11 $4,225,000 $6,600,000 ON SCHEDULE < 4 Full BPF. SPP to provided revised NTC20016 50160 AEP Line - Linwood - Powell Street 138 kV Transmission Service 06/01/12 06/01/12 01/16/09 $456,000 $456,000 COMPLETE Full BPF20016 50163 AEP Line - Okay - Tollette 69 kV Transmission Service 12/01/11 04/01/12 01/16/09 $80,000 $80,000 COMPLETE Full BPF20016 50164 AEP Line - SE Texarkana - Texarkana Plant 69 kV Transmission Service 03/01/12 04/01/12 01/16/09 $35,000 $128,000 COMPLETE Full BPF Turk commercial operation date delayed to 7/01/201220016 50165 AEP Line - South Texarkana REC - Texarkana Plant 69 kV Transmission Service 05/30/12 04/01/12 01/16/09 $4,750,000 $8,193,000 COMPLETE Full BPF Turk commercial operation date delayed to 7/01/201220122 50334 AEP Device - Winnsboro 138 kV Regional Reliability 06/01/16 06/01/16 02/14/11 $0 $1,166,400 ON SCHEDULE < 420122 50336 AEP Device - Logansport 138 kV Regional Reliability 06/01/16 06/01/16 02/14/11 $0 $1,166,400 ON SCHEDULE < 420135 50363 AEP Line - Easton Rec - Knox Lee 138 kV ckt 1 Regional Reliability 12/31/12 06/01/12 05/27/11 $150,000 $150,000 DELAY - MITIGATION Mitigation is redispatch20135 50364 AEP Line - Easton Rec - Pirkey 138 kV ckt 1 Regional Reliability 12/31/12 06/01/12 05/27/11 $500,000 $500,000 DELAY - MITIGATION Mitigation is redispatch20135 50365 AEP Line - Pirkey - Whitney 115 kV ckt 1 Regional Reliability 06/01/13 06/01/13 05/27/11 $900,000 $900,000 ON SCHEDULE < 420135 50375 AEP XFR - Diana 345/138 kV ckt 3 Transmission Service 06/01/13 06/01/13 05/27/11 $5,500,000 $5,500,000 ON SCHEDULE < 4

200165 50387 AEP Line - Clinton Junction 138 kV relay (AEP) Generation Interconnection 06/30/12 08/02/11 $150,000 $150,000 DELAY - MITIGATION This project is on hold by Windfarm 66 LLC50392 AEP Sub - Cornville 138 kV Zonal - Sponsored 12/31/14 $0 $9,585,000 ON SCHEDULE < 4 Delayed50393 AEP Sub - Cornville 138 kV Zonal - Sponsored 12/31/14 $0 $4,770,000 ON SCHEDULE < 4 Delayed50394 AEP Sub - Cornville 138 kV Zonal - Sponsored 12/31/14 $0 $911,250 ON SCHEDULE < 4 Delayed

50395 AEP Sub - Cornville 138 kV Zonal - Sponsored 12/31/14 $0 $3,155,625 ON SCHEDULE < 4 Delayed

200167 50405 AEP Device - Coweta 69 kV Capacitor Regional Reliability 06/01/14 06/01/14 04/09/12 $1,428,440 $1,428,440 ON SCHEDULE < 4

200183 50413 AEP Multi - Elk City - Gracemont 345 kV ITP10 03/01/18 04/09/12 $81,514,845 $81,514,845 ON SCHEDULE > 4

200183 50414 AEP Multi - Elk City - Gracemont 345 kV ITP10 03/01/18 04/09/12 $18,060,547 $18,060,547 ON SCHEDULE > 4 Build new 345kV/230kV station with 3 breaker ring on 230 kV, 1 200167 50438 AEP Sub - Cornville 138 kV Regional Reliability 06/01/12 04/09/12 $19,998,928 $19,998,928 DELAY - MITIGATION The scope of this work involves building a new breaker and a half

10272 CLEC XFR - Cocodrie 230/138 kV Regional Reliability - Non OATT 06/01/12 06/01/09 $0 $5,000,000 ON SCHEDULE < 4

50136 CUS Device - Twin Oaks 69 kV Zonal - Sponsored 06/01/17 06/01/18 $0 $875,000 ON SCHEDULE > 410373 DETEC Line - Etoile - Chireno Zonal - Sponsored 06/01/12 $0 $8,864,000 ON SCHEDULE < 410834 DETEC Line - Chireno-Martinsville 138 kV Zonal - Sponsored 06/01/15 $0 $8,894,000 ON SCHEDULE < 4

10849 DETEC Line - Martinsville - Timpson 138 kV conversion Zonal - Sponsored 06/01/14 $0 ON SCHEDULE < 4 Cost estimate is for entire project.10850 DETEC Line - Martinsville - Timpson 138 kV conversion Zonal - Sponsored 06/01/14 $0 $11,454,960 ON SCHEDULE < 4 Cost estimate is for entire project.10851 DETEC Line - Martinsville - Timpson 138 kV conversion Zonal - Sponsored 06/01/14 $0 ON SCHEDULE < 4 Cost estimate is for entire project.10852 DETEC Line - Martinsville - Timpson 138 kV conversion Zonal - Sponsored 06/01/14 $0 ON SCHEDULE < 4 Cost estimate is for entire project.

20123 10548 EDE Multi - Nichols 170 - Republic 345 - Republic 451 - Republic 359 69 kV Regional Reliability 06/01/15 06/01/15 02/14/11 $2,973,000 $2,973,000 ON SCHEDULE < 4 EDE would like to request that this project need be re-evaluated.20123 10608 EDE Line - Explorer Spring City Tap - Joplin Southwest 69 kV Ckt 1 Regional Reliability 06/01/14 06/01/14 02/14/11 $1,550,000 $1,550,000 ON SCHEDULE < 419970 10644 EDE XFR - Oronogo 161/69 kV Transmission Service 06/01/11 06/01/11 01/10/08 $4,000,000 $4,000,000 $4,286,188 COMPLETE

19970 10730 EDE Line - Oronogo Junction - Riverton 161 kV Recond Transmission Service 06/01/11 06/01/11 01/10/08 $5,750,000 $5,750,000 $3,324,960 COMPLETE 95.1% of costs BPF20075 10839 EDE Line - Sub 170 Nichols - Sub 80 Sedalia 69 kV Regional Reliability 05/01/12 06/01/10 02/08/10 $3,520,000 $4,500,000 COMPLETE20123 10891 EDE Multi - Stateline - Joplin - Reinmiller conversion Regional Reliability 06/01/18 06/01/18 02/1 $ $4/11 $3,591,000 $3,591,000 ON SCHEDULE > 4

20123 10894 EDE Multi - Stateline - Joplin - Reinmiller conversion Regional Reliability 06/01/18 06/01/18 02/14/11 $2,011,500 $2,011,500 ON SCHEDULE > 4

20036 50073 EDE Device - Quapaw Cap 69 kV Regional Reliability 06/01/18 06/01/18 01/27/09 $0 $1,500,000 ON SCHEDULE > 4Project under study. Distribution transformer taps to be adjusted accordingly to serve load adequately until the project can be

20123 50316 EDE Multi - Monett South Regional Reliability 06/01/17 06/01/17 02/14/11 $468,000 $468,000 ON SCHEDULE > 4 Part of Multi Line upgrade @ Monett.



20123 50324 EDE Multi - Stateline - Joplin - Reinmiller conversion Regional Reliability 06/01/18 06/01/18 02/14/11 $749,250 $749,250 ON SCHEDULE > 420123 50325 EDE Multi - Stateline - Joplin - Reinmiller conversion Regional Reliability 06/01/18 06/01/18 02/14/11 $4,968,000 $4,968,000 ON SCHEDULE > 420123 50326 EDE Multi - Monett South Regional Reliability 06/01/17 06/01/17 02/14/11 $2,250,000 $2,250,000 ON SCHEDULE > 4 Part of Multi Line upgrade @ Monett. This 547510-547511 xfmr 20123 50348 EDE Multi - Nichols 170 - Republic 345 - Republic 451 - Republic 359 69 kV Regional Reliability 06/01/15 06/01/15 02/14/11 $1,100,500 $1,100,500 ON SCHEDULE < 4 EDE would like to request that this project need be re-evaluated.20123 50350 EDE Multi - Monett South Regional Reliability 06/01/17 06/01/17 02/14/11 $324,000 $324,000 ON SCHEDULE > 4 Part of Multi Line upgrade @ Monett.20123 50352 EDE Multi - Nichols 170 - Republic 345 - Republic 451 - Republic 359 69 kV Regional Reliability 06/01/15 06/01/15 02/14/11 $476,500 $476,500 ON SCHEDULE < 4 EDE would like to request that this project need be re-evaluated.20123 50353 EDE Multi - Monett South Regional Reliability 06/01/17 06/01/17 02/14/11 $4,149,000 $4,149,000 ON SCHEDULE > 4 Part of Multi Line upgrade @ Monett.

10370 EES Line - Grandview - Osage Inter-regional 12/31/11 06/01/09 $0 $6,000,000 COMPLETE Preliminary design has begun.20008 10243 GMO Line - Grandview - Martin City 161 kV Regional Reliability 06/01/09 02/13/08 $150,000 $50,000 $5,709 COMPLETE Project completed and in service; costs finalized

10431 GMO Line - Lone Jack - Greenwood 161 kV Zonal - Sponsored 06/01/15 $0 $7,096,402 ON SCHEDULE < 4

20034 10830 GMO Multi - Loma Vista - Montrose 161 kV - Tap into K.C. South Regional Reliability 12/31/12 06/01/09 01/27/09 $2,369,625 $2,369,625 DELAY - MITIGATION project is an alternative to replace the reconductor projects of the Duncan Rd - Blue Spring East and Martin City-Grandview East 161 kV

20034 10847 GMO XFR - Clinton 161/69 kV Regional Reliability 11/01/13 06/01/13 01/27/09 $2,000,000 $2,000,000 DELAY - MITIGATION

20034 10854 GMO Multi - South Harper 161 kV cut-in to Stilwell-Archie Junction 161 kV lin Regional Reliability 12/28/12 06/01/09 01/27/09 $2,259,673 $2,559,673 DELAY - MITIGATION

20087 10952 GMO Line - Glenare - Liberty 69 kV Ckt 1 regional reliability 06/01/13 06/01/13 02/08/10 $200,000 $800,000 ON SCHEDULE < 4 cost estimate increase due to poor condition of structures20124 11263 GMO Line - Nashua - Smithville 161 kV Ckt 1 Regional Reliability 06/01/11 02/14/11 $150,000 $150,000 $24,897 COMPLETE Project completed and in service; costs not finalized

50424 GMO XFR - Eastowne 345/161 kV Zonal - Sponsored 01/01/13 $0 $12,809,443 ON SCHEDULE < 4 Construction started

50501 GMO Device - Clinton Plant 69 kV Cap Zonal - Sponsored 06/01/13 $0 $1,100,000 ON SCHEDULE < 4 project to replace UID 331 PID 1042850502 GMO Device - Alabama 161 kV Cap Zonal - Sponsored 04/01/12 $0 $1,500,000 $866,122 COMPLETE capacitor bank is in service; costs not finalized

20021 10385 GRDA Multi - Kansas Tap - Siloam City 161KV Regional Reliability 08/01/13 06/01/12 01/16/09 $4,212,500 $4,372,000 DELAY - MITIGATION GRDA would could reduce generation at Kerr Hydro to relieve loading. 20021 10386 GRDA Multi - Kansas Tap - Siloam City 161KV Regional Reliability 08/01/13 06/01/12 01/16/09 $1,700,000 $1,831,000 DELAY - MITIGATION GRDA would could reduce generation at Kerr Hydro to relieve loading.

20001 10388 GRDA XFR - Sallisaw 161/69 kV Auto #2 Regional Reliability 07/15/12 06/0

1/13

1/08 02/13/08 $3,000,000 DELAY - MITIGATION Utilizing LTCs on GRDA transformers in this area increases voltages within criteria limits.

10389 GRDA Multi - Toneece - Siloam City 161 kV Zonal - Sponsored 01/0 $3,210,200$2,000,000 ON SCHEDULE < 4This project didn't come from any RTO reliability studies.

10390 GRDA Multi - Toneece - Siloam City 161 kV Zonal - Sponsored 01/01/13 $8,019,000 ON SCHEDULE < 4 This project didn't come from any RTO reliability studies.

20076 10511 GRDA XFR - Afton 161/69 kV Ckt 2 Regional Reliability 08/01/13 06/01/10 02/08/10 $750,000 $8,020,000 DELAY - MITIGATION GRDA and NEO will perform switching at the 13kV level to avoid dropping any load

20050 10512 GRDA Line - Pensacola - Kerr 161 kV Transmission Service 06/01/11 06/01/11 09/18/09 $10,450,000 $10,450,000 $9,509,623 COMPLETE

200168 10698 GRDA Line - Maid - Pryor Foundry South 69 kV Regional Reliability 06/01/13 06/01/12 04/09/12 $1,064,300 $1,374,534 DELAY - MITIGATION 1590 ACSR: Normal Rating=152 MVA, 1275 Amps @ 85C, Emergency Rating=185 MVA, 1550 Amps @100C, NTC Upgrade

200168 10699 GRDA Line - Maid - Redden 69 kV Regional Reliability 06/01/13 06/01/12 04/09/12 $1,092,500 $1,419,469 DELAY - MITIGATION 1590 ACSR: Normal Rating=152 MVA, 1275 Amps @85C, Emergency Rating=185 MVA, 1550 Amps @ 100C, NTC Upgrade

20028 50080 GRDA Device - Tahlequah West 69 Cap kV Regional Reliability 07/01/12 06/01/09 01/27/09 $0 $779,000 DELAY - MITIGATION Replaces Tahlequah City #1 and City #2 Cap 69. In the event of a

20001 50092 GRDA Device - Jay Cap 69 kV Regional Reliability 06/25/12 06/01/11 02/13/08 $0 $800,000 $1,013,318 COMPLETE

50459 GRDA SUB - PAWNEE 138 KV Generation Interconnection 12/31/13 $0 $2,500,000 ON SCHEDULE < 450460 GRDA LINE - FAIRFAX - PAWNEE 138 KV Generation Interconnection 06/30/14 $0 $1,700,000 ON SCHEDULE < 4 Original In-Service Date was 12/31/2013. Per Construction Update 10955 GRIS Line - Sub F - St. Libory 115 kV Regional Reliability - Non OATT 12/01/12 $0 $3,937,500 ON SCHEDULE < 410956 GRIS Line - Sub H - Sub E upgrade Regional Reliability - Non OATT 04/01/12 $0 $200,000 ON SCHEDULE < 410840 INDN Line - Blue Valley Plant - Sub M 161 kV Regional Reliability - Non OATT 06/01/12 10/01/09 $0 $2,625,000 COMPLETE

20018 10405 ITCGP Line - Valliant - Hugo 345 kV Transmission Service 06/08/12 04/01/12 01/16/09 $11,000,000 $22,230,000 COMPLETE Energized 6/8/12

20018 10406 ITCGP XFR - Hugo 345/138 kV Transmission Service 06/30/12 04/01/12 01/16/09 $5,000,000 $6,328,605 COMPLETEDirect assigned to Network Customer; Transformer installation scheduled to be complete by 4/1/12 - Tie into 138 kV bus to be constructed by WFEC delayed due to Hugo Plant outage schedule

20018 50173 ITCGP Line - Hugo - Sunnyside 345 kV Transmission Service 06/08/12 04/01/12 01/16/09 $45,000,000 $6,620,096 COMPLETE Energized 6/8/12200187 50425 ITCGP Multi - Elm Creek - Summit 345 kV ITP10 03/01/18 03/01/18 04/09/12 $28,580,803 $28,580,803 ON SCHEDULE > 4200187 50426 ITCGP Multi - Elm Creek - Summit 345 kV ITP10 03/01/18 03/01/18 04/09/12 $5,403,707 $5,403,707 ON SCHEDULE > 4

200187 50427 ITCGP Multi - Elm Creek - Summit 345 kV ITP10 03/01/18 03/01/18 04/09/12 $8,015,964 $8,015,964 ON SCHEDULE > 4Bus cost includes $3,052,177 for 30 Mvar switched reactor to be located on bus or line terminal

200187 50428 ITCGP Multi - Elm Creek - Summit 345 kV ITP10 03/01/18 03/01/18 04/09/12 $697,163 $697,163 ON SCHEDULE > 4

10363 KCPL Line - Craig - Lenexa 161 kV Zonal - Sponsored 06/01/12 $0 $112,184 COMPLETE project complete and in service; costs not finalized.

11376 KCPL Line - Olathe - Switzer 161 kV Zonal - Sponsored 06/01/13 $0 $2,963,000 ON SCHEDULE < 4 construction started200169 11498 KCPL Line - Loma Vista East - Winchester Junction North 161kV Ckt 1 Regional Reliability 12/31/12 06/01/12 04/09/12 $190,860 $190,860 DELAY - MITIGATION project is tied to NTC 20034 which has an in-service date 12/31/12. 20009 50083 KCPL Device - Craig Cap 161 kV Zonal Reliability 05/18/11 06/01/08 02/13/08 $0 $1,316,500 $1,469,151 COMPLETE Project placed in service 5/18/11. Costs finalized.

20116 50329 KCPL Line - Stillwell - West Gardner 345 kV Ckt 1 Transmission Service 12/31/12 09/03/10 $150,000 $150,000 ON SCHEDULE < 4 project delayed due to delay in obtaining substation steel

50468 KCPL Line - Merriam - Overland Park 161 kV Zonal - Sponsored 12/31/14 $0 $1,518,750 ON SCHEDULE < 4

50500 KCPL Device - West Gardner 12 kV Reactor Zonal - Sponsored 12/31/12 $0 $900,000 ON SCHEDULE < 4

11086 LEA Multi - ERF-Gaines 115 kV Ckt 1 Regional Reliability - Non OATT 06/01/12 06/01/12 $0 $1,000,000 ON SCHEDULE < 4



11215 LES Line - Sheldon - Folsom 115 KV Ckt 1 Zonal - Sponsored 05/31/11 $0 $380,000 COMPLETE Complete

11216 LES Line - Sheldon - Folsom 115 KV Ckt 2 Zonal - Sponsored 05/31/11 $0 $380,000 COMPLETE Complete

11217 LES Line - 2nd & N - 20th & PIO 115 KV Ckt 1 Zonal - Sponsored 05/31/11 $0 $100,000 COMPLETE Complete

11218 LES Line - Folsom - 20th & PIO 115 KV Ckt 1 Zonal - Sponsored 05/31/11 $0 $100,000 COMPLETE Complete11230 LES XFR - Folsom 115/12.5 KV Ckt 1 Zonal - Sponsored 05/31/11 $0 COMPLETE Complete11447 LES Line - Folsom - Rokeby 115 KV Ckt 1 Zonal - Sponsored 05/31/11 $0 $150,000 COMPLETE Complete50388 LES Line - 17th & Holdrege - 30th & A 115 kV Ckt 1 Zonal - Sponsored 09/13/13 $0 $17,318,000 ON SCHEDULE < 450389 LES Line - 30th & A - 56th & Everett 115 kV Ckt 1 Zonal - Sponsored 09/13/13 $0 $9,980,000 ON SCHEDULE < 4

50390 LES Line - 57 & Garland - 84 & Leighton 115 kV Ckt 1 Zonal - Sponsored 05/31/12 $0 $2,372,000 COMPLETE

50391 LES Line - SW 7 & Bennet - 40th & Rokeby 115 kV Ckt 1 Zonal - Sponsored 05/31/15 $0 $7,675,000 ON SCHEDULE < 4

200171 50403 LES Line - Folsom & Pleasant Hill - Sheldon 115 kV Ckt 2 Regional Reliability 05/15/13 01/01/12 04/09/12 $6,480,000 $6,382,777 DELAY - MITIGATION No additional substation equipment is expected.

20139 10410 MIDW Line - Hays Plant - South Hayes 115 kV Ckt 1 Transmission Service 06/01/12 06/01/12 05/27/11 $35,000 $35,000 COMPLETE Uprate complete. New ratings Rate A = 83 MVA, Rate B = 99 MVA20089 11209 MIDW Multi - North Ellinwood - City of Ellinwood 69 kV transmission service 01/01/11 06/01/09 03/31/10 $825,000 $825,000 COMPLETE20089 11210 MIDW Multi - North Ellinwood - City of Ellinwood 69 kV transmission service 01/01/11 06/01/09 03/31/10 $530,000 $530,000 COMPLETE

20089 11211 MIDW Multi - North Ellinwood - City of Ellinwood 69 kV transmission service 01/01/11 06/01/09 03/31/10 $325,000 $325,000 COMPLETE

20126 11311 MIDW XFR - Colby 69/34.5 kV TrXFR - Colby 115/34.5 kV Transformer Ckt 4 Regional Reliability 12/31/12 06/01/11 02/14/11 $2,000,000 $2,000,000 DELAY - MITIGATION Installation will occur after summer peak loads.

20106 11312 MIDW Line - MIDW Heizer - Mullergren 115kV Regional Reliability 12/31/12 06/01/11 08/25/10 $400,000 $507,000 DELAY - MITIGATION Construction underway.

20078 50184 MIDW Device - Kinsley Capacitor 115 kV Regional Reliability 06/27/12 06/01/11 02/08/10 #N/A $899,000 COMPLETEIn service as of 6/27/12. Final cost TBD. Original project scope expanded to include modifications to 115 kV bus (steel, foundations, 115 kV switch, etc.) to facilitate connection of 115 kV capacitors and

20078 50197 MIDW Device-Pawnee 115 kV Regional Reliability 12/07/12 06/01/11 02/08/10 #N/A $570,000 DELAY - MITIGATION Original project scope did not contemplate addition of interconnection 200172 50411 MIDW Multi - Ellsworth - Bushton - Rice 115 kV Regional Reliability 09/28/12 06/01/12 04/09/12 $3,351,728 $938,708 COMPLETE

200172 50448 MIDW Multi - Ellsworth - Bushton - Rice 115 kV Regional Reliability 07/10/12 06/01/12 04/09/12 $16,107,869 $3,351,728 COMPLETE This estimate includes the segment from the existing Rice Co. substation up to the new Rice Co. substation, and on to the new

50464 MIDW MULTI - RICE - CIRCLE 230KV CONVERSION Generation Interconnection 11/07/12 $0 $11,156,686 ON SCHEDULE < 4 Date Updated as of 9/14/12. Estimate includes 230/115 sub (minus xfmr costs) - $10,900,000-2,473,404, Circle 230 line conversion

50466 MIDW LINE - RICE COUNTY - LYONS 115KV Generation Interconnection 04/01/13 $0 $6,390,000 ON SCHEDULE < 4 Updated as of September 2012 prior to construction bid.50467 MIDW MULTI - RICE - CIRCLE 230KV CONVERSION Generation Interconnection 10/01/12 $0 $2,473,404 ON SCHEDULE < 4 Date per executed GIA. Installed cost of 230/115 transformer only.50549 MIDW Multi - Ellsworth - Bushton - Rice 115 kV Regional Reliability 06/01/15 06/01/12 $0 $1,459,629 DELAY - MITIGATION Project timing anticipated to coordinate with MKEC construction of

20079 10858 MKEC Line - Pratt - St. John 115 kV rebuild Regional Reliability 12/31/12 06/01/13 02/08/10 $9,239,000 $15,582,071 ON SCHEDULE < 4

20067 10994 MKEC XFR - Medicine Lodge 138/115 kV Transmission Service 02/01/13 01/01/10 01/13/10 $5,625,000 $8,627,726 DELAY - MITIGATION

20067 11200 MKEC Line - Clifton - Greenleaf 115 kV Transmission Service 01/31/13 06/01/11 01/13/10 $3,600,000 $6,063,189 DELAY - MITIGATION

20067 11201 MKEC Line - Flatridge - Medicine Lodge 138 kV Transmission Service 06/01/14 01/01/10 01/13/10 $2,012,500 $4,004,423 DELAY - MITIGATION Interim redispatch under service agreement

20067 11202 MKEC Line - Flatridge - Harper 138 kV Transmission Service 06/15/13 01/01/10 01/13/10 $6,037,500 $11,048,967 DELAY - MITIGATION Interim redispatch under service agreement20067 11203 MKEC Line - Medicine Lodge - Pratt 115 kV Transmission Service 12/31/13 01/01/10 01/13/10 $6,500,000 $11,277,390 DELAY - MITIGATION20107 11323 MKEC Line - Heizer - Mullergren 115kV Regional Reliability 12/31/12 06/01/11 08/25/10 $750,000 $771,129 DELAY - MITIGATION SEPC Portion ONLY.20107 11342 MKEC Line - Greenleaf - Knob Hill 115kV Ckt 1 Transmission Service 01/31/13 06/01/13 08/25/10 $5,887,242 $5,354,646 ON SCHEDULE < 420119 11440 MKEC PRATT - ST JOHN 115 KV CKT 1 Regional Reliability 12/31/13 06/01/11 12/09/10 $100,000 $100,000 DELAY - MITIGATION Going to be done as part of project 653.20007 50104 MKEC Device - Plainville Cap 115 kV Regional Reliability 12/31/12 06/01/12 02/13/08 $0 $1,500,000 DELAY - MITIGATION20107 50337 MKEC Line - Jewell - Smith Center 115kV Ckt 1 Transmission Service 06/01/18 06/01/18 08/25/10 $60,000 $150,000 ON SCHEDULE > 4

200173 50396 MKEC Line - Haggard - Ingalls 115 kV Ckt 1 Regional Reliability 06/01/15 06/01/12 04/09/12 $12,530,103 $23,377,556 DELAY - MITIGATION200173 50409 MKEC Multi - Ellsworth - Bushton - Rice 115 kV Regional Reliability 06/01/15 06/01/12 04/09/12 $13,151,512 $13,151,512 DELAY - MITIGATION200173 50410 MKEC Multi - Ellsworth - Bushton - Rice 115 kV Regional Reliability 06/01/15 06/01/12 04/09/12 $5,914,221 $5,914,221 DELAY - MITIGATION200173 50449 MKEC Multi - Ellsworth - Bushton - Rice 115 kV Regional Reliability 06/01/15 06/01/12 04/09/12 $2,669,385 $2,669,385 DELAY - MITIGATION Analysis for this estimate was provided by HDR.

50508 MKEC GEN-2008-079 POI Generation Interconnection 05/21/12 $0 $665,522 ON SCHEDULE < 4 This is an Option to Build LGIA. This cost is only for MKEC's part.50509 MKEC Line - Ft Dodge - N Ft. Dodge - Spearville CKT 2 Generation Interconnection 11/08/14 $0 $15,773,000 ON SCHEDULE < 4

50510 MKEC XFR - Spearville 345/115kV CKT 1 Generation Interconnection 11/08/14 $0 $16,711,000 ON SCHEDULE < 4

20080 10986 NPPD Line - Maloney - North Platte 115 kV Regional Reliability 06/01/12 06/01/12 02/08/10 $2,000,000 $1,749,395 COMPLETE Network upgrade complete. Awaiting project close-out to determine final cost.

200170 11078 NPPD Line - Albion - Genoa 115 kV Regional Reliability 06/01/14 06/01/14 04/09/12 $1,240,000 $1,240,000 ON SCHEDULE < 4 Substation terminal work will be completed by 6/1/2013, and is being coordinated/completed with the Albion-Spalding work required by

20080 11079 NPPD Line - Albion - Spalding 115 kV regional reliability 06/01/13 06/01/13 02/08/10 $1,000,000 $1,977,010 ON SCHEDULE < 420080 11080 NPPD Line - Loup City - North Loup 115 kV Regional Reliability 06/01/12 06/01/12 02/0 $ $8/10 $1,000,000 $1,828,267 COMPLETE Network upgrade complete. Awaiting project close-out to determine

20080 11151 NPPD Line - Twin Church - S. Sioux City 115 kV Regional Reliability 12/01/12 06/01/12 02/08/10 $33,000,000 $34,874,505 DELAY - MITIGATION Project delayed to Fall 2012 due to load forecast changes. Project need mitigated by delay in load increase at this location.

20117 11438 NPPD Line - Canaday - Lexington 115Kv Ckt 1 Regional Reliability 06/01/13 12/01/10 12/09/10 $3,500,000 $3,500,000 DELAY - MITIGATION

Post-contingency loading issues on this line would be managed through utilization of the short-term 30-minute emergency rating and generation re-dispatch. An interim facility rating upgrade on this line from 80 MVA to 113 MVA was completed by 6/11/12 as terminal equipment upgrades were completed. The conductor upgrade to 100 Degrees C is planned by 6/1/13 to complete the full scope of the project.

50206 NPPD Device - Oneill 69 kV Zonal - Sponsored 06/01/12 11/01/12 $0 $364,500 COMPLETE20080 50207 NPPD Device - Petersburg North 115 kV Regional Reliability 06/01/11 11/01/12 02/08/10 $0 $429,332 $364,898 COMPLETE Project Complete.

20080 50208 NPPD Device - Clarks 115 kV Regional Reliability 11/01/12 02/08/10 $0 $700,000 DELAY - MITIGATION NPPD has suspended the project. Mitigation plan not required due to load delay.

20080 50209 NPPD Device - Ainsworth 115 kV Regional Reliability 11/01/12 02/08/10 $0 $50,000 DELAY - MITIGATION NPPD has suspended the project. Mitigation plan not required due to load delay.

20080 50210 NPPD Device - Oneill 115 kV Regional Reliability 11/01/12 02/08/10 $0 $700,000 DELAY - MITIGATION NPPD has suspended the project. Mitigation plan not required due to

20080 50211 NPPD Device - Valentine 115 kV Regional Reliability 06/01/11 06/01/11 02/08/10 $0 $630,255 COMPLETE Project Complete. Awaiting project close out to determine final cost.20080 50213 NPPD Device - Gordon 115 kV Regional Reliability 06/01/12 06/01/13 02/08/10 $0 $673,574 COMPLETE Project Complete. Awaiting project close out to determine final cost.20080 50248 NPPD Device - Kearney 115 kV Regional Reliability 06/01/12 06/01/12 02/08/10 $0 $786,495 COMPLETE Project Complete. Awaiting project close out to determine final cost.

200170 50249 NPPD Device - Holdrege 115 kV Regional Reliability 06/01/14 06/01/14 04/09/12 $1,193,000 $1,193,000 ON SCHEDULE < 4 Project requires the re-termination of Transmission Line 1242 to allow 20117 50319 NPPD XFR - Ogallala 230/115kV Replacement Regional Reliability 06/01/14 06/01/10 12/09/10 $5,000,000 $5,645,881 DELAY - MITIGATION Project is on schedule according to the in-service date listed on the 20127 50320 NPPD Multi - Stegall 345/230 kV Transformer Ckt 2 Regional Reliability 06/01/15 06/01/15 02/14/11 $8,000,000 $8,000,000 ON SCHEDULE < 4

200170 50400 NPPD Multi - Stegall 345/230 kV Transformer Ckt 2 Regional Reliability 06/01/15 06/01/15 04/09/12 $5,239,000 $5,239,000 ON SCHEDULE < 4 This estimate will include 8 crossings of other lines. This estimate includes the 230 kV breaker bay in the existing Stegall 230 kV

200186 50440 NPPD Multi - Hoskins - Neligh 345 kV ITP10 03/01/19 03/01/19 04/09/12 $61,205,000 $61,205,000 ON SCHEDULE > 4Estimate includes expansion of Hoskins Substation to accommodate new Neligh 345 kV Terminal. Also includes cost to swap the line bay

200186 50441 NPPD Multi - Hoskins - Neligh 345 kV ITP10 03/01/19 03/01/19 04/09/12 $35,497,400 $35,497,400 ON SCHEDULE > 4 This option creates a new 345/115 kV Substation east of Neligh, as 200186 50442 NPPD Multi - Gentleman - Cherry - Holt 345 kV ITP10 01/01/18 01/01/18 04/09/12 $92,660,000 $92,660,000 ON SCHEDULE > 4 This is one of multiple components of the "rPLAN" project cost;

200186 50443 NPPD Multi - Gentleman - Cherry - Holt 345 kV ITP10 01/01/18 01/01/18 04/09/12 $1,380,000 $1,380,000 ON SCHEDULE > 4This is one of the multiple components of the "rPLAN" project cost; Component 1 of 8. (Line Reactor is include in the GGS-Cherry County 345 kV Line Segment estimate).

200186 50444 NPPD Multi - Gentleman - Cherry - Holt 345 kV ITP10 01/01/18 01/01/18 04/09/12 $6,000,000 $6,000,000 ON SCHEDULE > 4This is one of multiple components of the "rPLAN" project cost; Component 3 of 8. (Line reactor costs are include in the respective line segment estimates. 1 each in GGS-Cherry County Line and

200186 50445 NPPD Multi - Gentleman - Cherry - Holt 345 kV ITP10 01/01/18 01/01/18 04/09/12 $172,360,000 $172,360,000 ON SCHEDULE > 4This is one of multiple components of the "rPLAN" project cost; Component 4 of 8. This cost estimate includes 2 line reactors, 1 for

200186 50446 NPPD Multi - Gentleman - Cherry - Holt 345 kV ITP10 01/01/18 01/01/18 04/09/12 $16,880,000 $16,880,000 ON SCHEDULE > 4 This is one of multiple components of the "rPLAN" project cost;

50469 NPPD XFR - Cooper 345/161 kV Ckt 2 Zonal - Sponsored 04/01/12 $0 $9,000,000 ON SCHEDULE < 4

20081 10300 OGE Line - Fort Smith - Colony 161 kV 2 regional reliability 06/01/13 06/01/13 02/08/10 $2,500,000 $2,100,000 ON SCHEDULE < 4

10391 OGE Line - Razorback - Short Mountain 161 kV Zonal - Sponsored 01/19/11 $0 COMPLETE NOTE: Initial costs include distribution10392 OGE Line - Razorback - Short Mountain 161 kV Zonal - Sponsored 12/19/11 $0 COMPLETE10393 OGE Line - Razorback - Short Mountain 161 kV Zonal - Sponsored 02/28/11 $0 COMPLETE10394 OGE Line - Razorback - Short Mountain 161 kV Zonal - Sponsored 12/19/11 $0 COMPLETE10395 OGE Line - Razorback - Short Mountain 161 kV Zonal - Sponsored 02/10/11 $0 COMPLETE10396 OGE Line - Razorback - Short Mountain 161 kV Zonal - Sponsored 12/19/11 $0 COMPLETE10398 OGE Line - Razorback - Short Mountain 161 kV Zonal - Sponsored 03/31/11 $0 COMPLETE

$32,975,000

10400 OGE Line - Razorback - Short Mountain 161 kV Zonal - Sponsored 08/18/11 $0 COMPLETE11334 OGE Line - Razorback - Short Mountain 161 kV Zonal - Sponsored 04/01/11 $0 COMPLETE

11335 OGE Line - Razorback - Short Mountain 161 kV Zonal - Sponsored 04/01/11 $0 COMPLETE

11336 OGE Line - Razorback - Short Mountain 161 kV Zonal - Sponsored 04/01/11 $0 COMPLETE

20002 10514 OGE Breaker - Bodle 138 kV Regional Reliability 01/15/11 06/01/12 02/13/08 $1,000,000 $850,000 $695,395 COMPLETE

20002 10663 OGE Line - HSL East - HSL West 69 kV Regional Reliability 06/01/16 06/01/16 02/13/08 $250,000 $250,000 ON SCHEDULE < 4

20055 10668 OGE Line - Rose Hill - Sooner 345 kV (OGE) Regional Reliability 06/01/12 06/01/12 09/18/09 $45,000,000 $44,700,000 COMPLETE

10731 OGE Multi - Johnston County Project Zonal - Sponsored 06/01/11 $0 $27,069,913 COMPLETE Multi-upgrade project for new arc furnance near Arbuckle (on upgrade 10732 OGE Multi - Johnston County Project Zonal - Sponsored 06/01/11 $0 COMPLETE NOTE: Initial costs include distribution

10733 OGE Multi - Johnston County Project Zonal - Sponsored 06/01/11 $0 COMPLETE

10734 OGE Multi - Johnston County Project Zonal - Sponsored 06/01/11 $0 COMPLETE$31,683,453

10735 OGE Multi - Johnston County Project Zonal - Sponsored 06/01/11 $0 COMPLETE10820 OGE Multi - Johnston County Project Zonal - Sponsored 06/01/11 $0 COMPLETE10821 OGE Multi - Johnston County Project Zonal - Sponsored 06/01/11 $0 COMPLETE10747 OGE Multi - Arcadia Tap - Round Barn Sub Zonal - Sponsored 07/01/12 $0 $6,330,000 ON SCHEDULE < 4 Original Costs included distribution

10748 OGE Multi - Arcadia Tap - Round Barn Sub Zonal - Sponsored 07/01/12 $0 ON SCHEDULE < 4$1,900,000

20029 10792 OGE Multi: Dover-Twin Lake-Crescent-Cottonwood conversion 138 kV Regional Reliability 06/01/14 06/01/10 01/27/09 $5,404,250 $8,100,000 DELAY - MITIGATION Updated costs needed due to project delay Total cost of project

20081 10701 OGE Multi - Johnson - Massard 161 kV Regional Reliability 09/01/12 06/0

1/12 06/0

1/12 02/0

1/12 02/0

8/10$6,200,000$8,700,000

DELAY - MITIGATIONOriginal Costs included distribution

20081 10837 OGE Multi - Johnson - Massard 161 kV Regional Reliability 09/0 8/10 DELAY - MITIGATION

20029 10843 OGE Line - Kilgore - VBI 69 kV Regional Reliability 06/01/13 06/01/13 01/27/09 $10,000 $10,000 ON SCHEDULE < 4 Majority of project is removal only

20110 10876 OGE XFR - 3rd Arcadia 345/138 kV Transmission Service 06/01/12 06/01/15 08/25/10 $13,500,000 $10,900,000 COMPLETE Cost estimated reduced due to lower material costs and no scheduling issues occurred with project

20081 11182 OGE Sub - Canadian River Substation Regional Reliability 02/15/13 06/01/10 02/08/10 $5,500,000 $7,100,000 DELAY - MITIGATION Cost increase is partially due to location of site of new substation

11188 OGE Multi - Keystone West - Bell Cow - Warwick 138 kV Ckt 1 Zonal - Sponsored 05/30/11 $0 $14,665,000 $12,494,000 COMPLETE

11189 OGE Multi - Keystone West - Bell Cow - Warwick 138 kV Ckt 1 Zonal - Sponsored 05/30/11 $0 COMPLETE

11190 OGE Line - Stonewall - Remington Park 138 kV Zonal - Sponsored 04/01/11 $0 $1,300,000 $1,539,871 COMPLETE

11191 OGE Multi - 36 & Meridian - WRAirport - Pennsylvania 138 kV Ckt 1 Zonal - Sponsored 06/01/12 $0 $510,000 COMPLETE Transmission assets associated with project - Costs are still being compiled

11192 OGE Multi - 36 & Meridian - WRAirport - Pennsylvania 138 kV Ckt 1 Zonal - Sponsored 06/01/12 $0 COMPLETE Transmission assets associated with project - Costs are still being compiled

20110 11207 OGE Line - Bryant - Memorial 138 kV Transmission Service 06/01/19 06/01/19 08/25/10 $250,000 $225,000 ON SCHEDULE > 4

11228 OGE Line - Cushing - Pumping Station 32 138 kV Zonal - Sponsored 03/01/13 $0 $6,700,000 ON SCHEDULE < 4Customer driven in-service date delayed - New in-service date - Costs do not include distribution assets - Portion of cost to be reimbursed to OG&E

20110 11343 OGE Line - Arcadia - Redbud 345 kV Ckt 3 Transmission Service 06/01/19 06/01/19 08/25/10 $19,000,000 $18,000,000 ON SCHEDULE > 4

20128 11439 OGE Line - OGE Alva - WFEC Alva 69 kV Ckt 1 Regional Reliability 07/15/12 06/01/11 02/14/11 $112,500 $392,000 DELAY - MITIGATION In-service delay due to material delivery20137 11496 OGE XFR - Northwest 345/138 kV Ckt 3 Transmission Service 06/01/17 06/01/17 05/27/11 $15,000,000 $15,000,000 ON SCHEDULE > 4

200174 50098 OGE Device - Kolache 69 kV Capacitor Regional Reliability 07/15/13 06/01/12 04/09/12 $523,888 $523,888 DELAY - MITIGATION

20017 50166 OGE Line - Ardmore - Rocky Point 69 kV Transmission Service 06/01/11 06/01/11 01/16/09 $1,627,500 $1,400,000 $983,224 COMPLETE Full BPF - Scope of project was reduced - Rebuilt fewer miles - Portion of reported cost is distribution.

20017 50167 OGE Line - Dillard - Healdton Tap 138 kV Transmission Service 06/01/11 06/01/11 01/16/09 $300,000 $300,000 COMPLETEFull BPF Handled on O&M

20083 50247 SEPC 115 kV d ona li y 05/23/12 06/01/11 02/08/10 $0 $370 000 COMPLETE

20017 50168 OGE XFR - Ft Smith 500/161 kV Ckt 3 Transmission Service 06/01/17 06/01/17 01/16/09 $11,000,000 $14,000,000 ON SCHEDULE > 4Full BPF

20017 50169 OGE Multi - Hugo - Sunnyside 345 kV (OGE) Transmission Service 04/01/12 04/01/12 01/1

1/12 01/1

6/09 $75,000,000 $157,000,000 ON SCHEDULE < 4$3,000,000 reduction due to better cost information

20017 50171 OGE Multi - Hugo - Sunnyside 345 kV (OGE) Transmission Service 04/01/12 04/0 6/09 $6,750,000 ON SCHEDULE < 4 Full BPF

20017 50170 OGE Line - Sunnyside - Uniroyal 138 kV Transmission Service 06/01/11 06/01/11 01/16/09 $50,000 $50,000 $74,982 COMPLETE Project was performed on holiday at customer's request

20017 50172 OGE Line - VBI - VBI North 69 kV Transmission Service 06/01/17 06/01/17 01/16/09 $100,000 $100,000 ON SCHEDULE > 4Full BPF - Reviewing metering CT - May be able to increase rating to 600 amps

200174 50346 OGE XFR - Paoli 138/69 kV Regional Reliability 05/10/13 06/01/12 04/09/12 $2,020,094 $2,090,660 DELAY - MITIGATION20128 50347 OGE Device - Little River Lake 69 kV Regional Reliability 07/01/12 12/01/11 02/14/11 $0 $352,350 DELAY - MITIGATION Expect to meet schedule

200164 50385 OGE Line - Gracemont 138kV line terminal addition Generation Interconnection 10/15/11 08/02/11 $871,896 $871,896 COMPLETEFinal Cost Still being compiled

200174 50408 OGE Device - Lula 69 kV Regional Reliability 06/01/13 06/01/12 04/09/12 $377,797 $377,797 DELAY - MITIGATION

200185 50419 OGE Multi - Elk City - Gracemont 345 kV ITP10 03/01/18 03/01/18 04/09/12 $75,486,000 $75,486,000 ON SCHEDULE > 4OG&E will construct the east half of the ~93 miles of 345kv line and complete the substation work at Gracemont Substation which will include a reactor.

200185 50420 OGE Multi - Woodward EHV - Tatonga - Matthewson - Cimarron 345 kV ITP10 03/01/21 03/01/21 04/09/12 $71,876,622 $71,876,622 ON SCHEDULE > 4It is assumed that the Woodward District EHV upgrade will be completed prior to this project. Transmission line to utilize previously obtained Right of Way along Windspeed line.

200185 50421 OGE Multi - Woodward EHV - Tatonga - Matthewson - Cimarron 345 kV ITP10 03/01/21 03/01/21 04/09/12 $82,139,900 $82,139,900 ON SCHEDULE > 4 It is assumed that a terminal space is available at Tatonga. This 200185 50456 OGE Multi - Woodward EHV - Tatonga - Matthewson - Cimarron 345 kV ITP10 03/01/21 03/01/21 04/09/12 $32,780,617 $32,780,617 ON SCHEDULE > 4 It is assumed that Cimarron will be converted to a breaker and one 200185 50458 OGE Multi - Woodward EHV - Tatonga - Matthewson - Cimarron 345 kV ITP10 03/01/21 03/01/21 04/09/12 $20,169,602 $20,169,602 ON SCHEDULE > 4 It is assumed that Cimarron will be converted to a breaker and one

50461 OGE SUB - SHIDLER 138KV OG&E Osage Sub work Generation Interconnection 02/14/13 $0 $399,000 ON SCHEDULE < 4 Cost of OG&E portion of project in Osage Sub

20105 11262 OMPA Line - Arcadia - OMPA Edmond Garber 138 kV Ckt 1 Transmission Service 06/01/12 06/01/10 08/25/10 $30,000 $30,000 DELAY - MITIGATION

20082 10924 OPPD Multi - S1341 161 kV Regional Reliability 09/13/11 12/3

3/11 12/3

3/11 12/3

1/11 02/0

1/11 02/0

1/11 02/0

8/10 $7,617,744 COMPLETE

20082 10925 OPPD Multi - S1341 161 kV Regional Reliability 09/1 8/10 COMPLETE$16,300,000 $16,987,625

20082 10926 OPPD Multi - S1341 161 kV Regional Reliability 09/1 8/10 COMPLETE

11001 OPPD Line - Rebuild 902-983 Zonal - Sponsored 01/28/11 $0 $2,900,000 COMPLETE The purpose of this project is to address maintenance-related issues, 11002 OPPD Line - Sub 1221 - Sub 1255 161 kV Zonal - Sponsored 11/10/12 11/10/12 $0 $675,523 ON SCHEDULE < 410275 Rayburn Line - Ben Wheeler - Barton's Chapel (Rayburn) 138 kV Ckt 1 Regional Reliability - Non OATT 04/30/12 $0 $4,218,750 ON SCHEDULE < 4 Rayburn Country Project. Rayburn confirm project In Service Date is 10214 SEPC Line - Phillipsburg - Rhoades 115 kV Ckt 1 Zonal - Sponsored 07/01/11 $0 $9,846,782 COMPLETE COMPLETE - Project in Service, final financials are in progress.

20007 10215 SEPC Line - Holcomb - Plymell 115 kV Regional Reliability 06/01/12 06/01/08 02/13/08 $1,980,000 $3,986,076 COMPLETE Currently in engineering design and cost review. Mitigation is to 20014 10480 SEPC Line - Plymell - Pioneer Tap 115 kV Regional Reliability 06/01/12 06/01/09 09/18/08 $2,380,000 $5,534,364 COMPLETE Currently in engineering design and cost review. Mitigation is to 20138 11195 SEPC Line - Holcomb - Fletcher 115 kV Ckt 1 Regional Reliability 12/31/13 06/01/13 05/27/11 $4,000,000 $6,025,790 DELAY - MITIGATION20083 50246 SEPC Device - Johnson Corner 115 kV Capacitor Regional Reliability 05/23/12 06/01/10 02/08/10 $0 $740,000 COMPLETE

20083 50247 SEPC Device Johnson Corner 115 kV 2nd CapacitorDevice - Johnson Corner 2n Capacitor RegionalRegi Reliabilityl Re abilit 05/23/12 06/01/11 02/08/10 $0 $370 000 COMPLETE,

200166 10195 SPS XFR - Tuco 115/69 kV Transformer Ckt 3 Regional Reliability 06/01/14 06/01/12 04/09/12 $2,917,852 $2,633,003 DELAY - MITIGATION Estimate does not include breaker and a half expansion of the 115kV 20004 10200 SPS Multi - Hitchland - Texas Co. 230 kV and 115 kV Regional Reliability 05/20/11 06/01/08 02/13/08 $3,450,000 $5,132,829 $973,612 COMPLETE This line was formally circuit T-88 and now re configured in & out of 20004 10201 SPS Multi - Hitchland - Texas Co. 230 kV and 115 kV Regional Reliability 05/20/11 06/01/09 02/13/08 $3,780,000 $31,915,701 $9,329,355 COMPLETE This is the final cost of the 230/115 kV portion of the Hitchland 20031 10326 SPS Multi - Hitchland - Texas Co. 230 kV and 115 kV Regional Reliability 06/08/12 06/01/10 01/27/09 $16,094,371 $36,692,293 COMPLETE This project will be placed in-service the week of June 4, 2012. Q4-20004 10327 SPS Multi - Hitchland - Texas Co. 230 kV and 115 kV Regional Reliability 05/20/11 04/01/09 02/13/08 $8,400,000 $12,577,500 $6,219,570 COMPLETE This is the final cost of the 345 kV portion of the Hitchland substation.

20004 10328 SPS Multi - Hitchland - Texas Co. 230 kV and 115 kV Regional Reliability 05/20/11 06/01/09 02/13/08 $3,450,000 $15,848,000 $7,606,406 COMPLETEThis line was formally V-30 and now re configured in & out of Hitchland and resulted in the construction of 10 miles of new double circuit 115 kV line on steel structures

20084 10329 SPS Multi - Hitchland - Texas Co. 230 kV and 115 kV Regional Reliability 05/20/11 06/01/09 02/08/10 $10,771,825 $13,693,819 $13,118,448 COMPLETE The line from Dallam to Sherman is currently in-service. The current cost estimate amount was changed to the original NTC cost amount

20111 10330 SPS Multi - Hitchland - Texas Co. 230 kV and 115 kV Regional Reliability 02/01/13 06/01/09 08/09/10 $19,687,500 $16,999,620 DELAY - MITIGATION The estimated ISD is 02/01/2013. Q4-2012 Cost Estimate updated. 20111 10331 SPS Multi - Hitchland - Texas Co. 230 kV and 115 kV Regional Reliability 02/01/13 06/01/09 08/09/10 $1,500,000 $7,480,685 DELAY - MITIGATION This large project is underway and portions of this project will be

10407 SPS Line - Roosevelt County Interchange 115 kV - Curry County Interchang Regional reliability 10/01/10 06/01/15 $0 $200,000 ON SCHEDULE < 4 Will need additional study200166 10597 SPS Line - Curry - Bailey 115kV Regional Reliability 06/01/15 06/01/12 04/09/12 $9,132,270 $35,099,588 DELAY - MITIGATION Assumes relay replacements are required at remote ends of Bailey 20031 10704 SPS Multi: Dallam - Channing - Tascosa -Potter Regional Reliability 08/10/11 06/01/09 01/27/09 $27,452,677 $16,665,675 COMPLETE Project is in-service but all associated costs are not yet final. Should 20031 10705 SPS Multi: Dallam - Channing - Tascosa -Potter Regional Reliability 06/01/12 06/01/09 01/27/09 $0 $9,005,940 DELAY - MITIGATION This line goes from Channing to Potter and does not go in and out of 20031 10757 SPS Line - Ocotillo sub conversion 115 kV Regional Reliability 02/28/12 06/01/09 01/27/09 $3,375,000 $3,175,596 $3,102,202 DELAY - MITIGATION20004 10800 SPS Multi - Wheeler County Project - Tap 230 kV line - Two new XFs - new Regional Reliability 06/01/10 06/01/08 02/13/08 $0 $2,000,000 DELAY - MITIGATION The earliest that any portion of the Wheeler County Interchange

20031 10822 SPS Multi: Legacy Interchange 69 kV Tap - 115/69 transformer -2 new lines Regional Reliability 08/18/11 06/01/09 01/27/09 $10,406,250 $4,646,250 $4,676,493 COMPLETE This project is the fix for the Gaines Co. Auto STEP project. Q4-2012 final costs updated. MN-9/19/12

20031 10823 SPS Multi: Legacy Interchange 69 kV Tap - 115/69 transformer -2 new lines Regional Reliability 07/29/11 06/01/09 01/27/09 $0 $2,514,338 $2,790,800 COMPLETE This project is the fix for the Gaines Co. Auto STEP project. Q4-2012

20031 10824 SPS Multi: Legacy Interchange 69 kV Tap - 115/69 transformer -2 new lines Regional Reliability 07/29/11 06/01/09 01/27/09 $0 $2,875,000 $3,348,949 COMPLETE This project is the fix for the Gaines Co. Auto STEP project. Q4-2012 Cost Estimate and final costs updated. MN-9/19/12

20031 10825 SPS Multi: Eagle Creek 115 and 69 kV Taps - 116/69 XF - 3 new lines Regional Reliability 06/22/11 06/01/09 01/27/09 $5,197,500 $4,285,000 $4,727,194 COMPLETE Q4-2012 Cost Estimate updated. MN-9/19/1220031 10826 SPS Multi: Eagle Creek 115 and 69 kV Taps - 116/69 XF - 3 new lines Regional Reliability 06/16/11 06/01/09 01/27/09 $0 $281,250 $450,538 COMPLETE20031 10827 SPS Multi: Eagle Creek 115 and 69 kV Taps - 116/69 XF - 3 new lines Regional Reliability 06/16/11 06/01/09 01/27/09 $0 $320,000 $335,413 COMPLETE

20031 10828 SPS Multi: Eagle Creek 115 and 69 kV Taps - 116/69 XF - 3 new lines Regional Reliability 12/31/12 06/01/09 01/27/09 $0 $1,800,000 DELAY - MITIGATION

Mitigation will not be needed. The 115 kV potion of this project is 100 % complete. The new 115/69 kV transformer at Eagle Creek is carrying load. The new 69 kV lines out of Eagle Creek are not complete. However the existing 69 kV lines are terminated on the Eagle Creek Substation 69 kV bus. To address the overload of one Artesia Interchange 115/69 kV transformer during the outage of the other Artesia Interchange 115/69 Kv transformer, the above latest model was used. The results of that contingency revealed a 49% load on the in service transformer in Artesia. Q4-2012 updated ISD: current cost estimate remains valid. MN-9/19/12

20031 10829 SPS Line - Chaves Co - Roswell Int 69/115 kV Voltage Conversion Regional Reliability 06/01/13 06/01/09 01/27/09 $4,716,000 $6,000,000 DELAY - MITIGATION This project is the replacement for adding a 3rd XF at the Roswell Interchange. Q4-2012 Cost Estimate updated. MN-9/19/12

20130 11007 SPS XFR - Happy County 115/69 kV Transformers Regional Reliability 06/01/14 06/01/12 02/14/11 $1,890,000 $2,230,200 DELAY - MITIGATION Alternative 1: Swap Swisher Co-op load onto Kress Interchange, bus 525192, CLOSE N.O. REC (22) Claytonville and OPEN REC (16)

20130 11009 SPS XFR - Happy County 115/69 kV Transformers Regional Reliability 06/01/14 06/01/12 02/14/11 $1,890,000 $2,230,200 DELAY - MITIGATION Alternative 1: Swap Swisher Co-op load onto Kress Interchange, bus 525192, CLOSE N.O. REC (22) Claytonville and OPEN REC (16)

20084 11019 SPS Multi - Cherry Sub add 230kV source and 115 kV Hastings Conversion Regional Reliability 12/30/13 06/01/10 02/08/10 $112,500 $679,000 DELAY - MITIGATION Mitigation plan has been provided to and accepted by SPP for this project.Q4-2012 updated ISD: current cost estimate remains valid.

20084 11020 SPS Multi - Cherry Sub add 230kV source and 115 kV Hastings Conversion Regional Reliability 06/30/13 06/01/10 02/08/10 $4,905,000 $8,515,623 DELAY - MITIGATION Mitigation plan has been provided to and accepted by SPP for this project.

20084 11021 SPS Multi - Cherry Sub add 230kV source and 115 kV Hastings Conversion Regional Reliability 06/30/13 06/01/10 02/08/10 $5,062,500 $5,062,500 DELAY - MITIGATION Mitigation plan has been provided to and accepted by SPP for this 20084 11023 SPS Multi - Cherry Sub add 230kV source and 115 kV Hastings Conversion Regional Reliability 12/31/13 06/01/10 02/08/10 $1,700,000 $1,700,000 DELAY - MITIGATION Mitigation plan has been provided to and accepted by SPP for this 20084 11029 SPS Line - Maddox - Sanger SW 115 kV Regional Reliability 05/31/12 06/01/10 02/08/10 $3,000,000 $330,957 DELAY - MITIGATION Project has scope change from reconductor to a wreckout/rebuild due 20084 11033 SPS XFR - Install 2nd Randall 230/115 kV transformer Regional Reliability 04/30/13 06/01/10 02/08/10 $11,250,000 $7,357,000 DELAY - MITIGATION Mitigation plan has been provided to and accepted by SPP for this 20084 11036 SPS Line - Maddox Station - Monument 115 kV Ckt 1 regional reliability 11/30/12 06/01/11 02/08/10 $1,417,500 $1,425,915 DELAY - MITIGATION Mitigation plan has been provided to and accepted by SPP for this 20084 11038 SPS Line - Brasher Tap - Roswell Interchange 115 kV Regional Reliability 12/31/13 06/01/12 02/08/10 $114,000 $190,000 DELAY - MITIGATION Mitigation will not be needed for this line. Using the newest model, 20084 11040 SPS Multi - New Hart Interchange 230/115 kV Regional Reliability 04/30/15 06/01/10 02/08/10 $11,250,000 $11,980,445 DELAY - MITIGATION Mitigation plan has been provided to and accepted by SPP for this 20084 11041 SPS Multi - New Hart Interchange 230/115 kV Regional Reliability 04/30/15 06/01/10 02/08/10 $16,031,250 $11,850,018 DELAY - MITIGATION Mitigation plan has been provided to and accepted by SPP for this 20084 11042 SPS Multi - New Hart Interchange 230/115 kV Regional Reliability 04/30/15 06/01/10 02/08/10 $10,125,000 $15,086,485 DELAY - MITIGATION Mitigation plan has been provided to and accepted by SPP for this 20084 11043 SPS Multi - New Hart Interchange 230/115 kV Regional Reliability 04/30/15 06/01/10 02/08/10 $13,500,000 $15,632,544 DELAY - MITIGATION Looks to be an entry error???? NTC is $13.5m20084 11044 SPS Multi - New Hart Interchange 230/115 kV Regional Reliability 04/30/15 06/01/10 02/08/10 $2,250,000 $2,010,780 DELAY - MITIGATION Mitigation plan has been provided to and accepted by SPP for this 20084 11045 SPS Multi - New Hart Interchange 230/115 kV Regional Reliability 04/30/15 06/01/10 02/08/10 $8,438,000 $13,266,452 DELAY - MITIGATION This line will go from Newhart to Lampton. There will be a tap from

20130 11046 SPS Line - Cunningham - Buckey Tap 115 kV reconductor Regional Reliability 06/01/13 06/01/13 02/14/11 $3,607,000 $3,607,000 ON SCHEDULE < 4

20084 11052 SPS Multi - Pleasant Hill- Potter 345 kV Ckt 1 Regional Reliability 12/30/14 06/01/11 02/08/10 $11,250,000 $19,349,122 DELAY - MITIGATION NO MITIGATION must shed load for Summer Peaks 2013-2014

20084 11053 SPS Multi - Pleasant Hill- Potter 345 kV Ckt 1 Regional Reliability 12/30/14 06/01/11 02/08/10 $13,500,000 $14,805,472 DELAY - MITIGATION NO MITIGATION must shed load for Summer Peaks 2013-201420084 11054 SPS Multi - Pleasant Hill- Potter 345 kV Ckt 1 Regional Reliability 12/30/14 06/01/11 02/08/10 $21,937,500 $20,612,670 DELAY - MITIGATION NO MITIGATION must shed load for Summer Peaks 2013-2014

200166 11067 SPS Multi - Bowers - Howard 115 kV Ckt 1 Regional Reliability 06/01/16 06/01/16 04/09/12 $4,120,585 $2,980,329 ON SCHEDULE > 4 Estimate includes re-routing of the Kingsmill 69kV line to the south side of the subustation. Assumes Bowers was converted to three-

20084 11096 SPS XFR - Kingsmill 115/69 kV Ckt 2 Regional Reliability 05/31/13 06/01/11 02/08/10 $1,935,000 $4,500,000 DELAY - MITIGATION Mitigation plan has been provided to and accepted by SPP for this project.Q4-2012 ISD and Cost Estimate updated. MN-9/19/12

20130 11100 SPS XFR - Northeast Hereford 115/69 kV Transformer Ckt 2 Regional Reliability 06/01/14 06/01/11 02/14/11 $1,890,000 $2,000,000 DELAY - MITIGATION OPEN 69 kV tie NE-Hereford – Hereford by OPEN Breaker 5704 Hereford Int. South 524605-524573. Q4-2012 Cost Estimate updated.

20084 11101 SPS Line - Portales - Zodiac 69 kV to 115 kV Conversion Regional Reliability 06/01/14 06/01/13 02/08/10 $3,487,500 $4,500,000 DELAY - MITIGATION Q4-2012 updated ISD; Cost Estimate remains valid. MN-9/19/12

20088 11102 SPS Multi - Move Load from East Clovis 69 kV to East Clovis 115 kV Regional Reliability 06/01/14 06/01/14 05/07/10 $2,500,000 $2,500,000 ON SCHEDULE < 4

200166 11104 SPS Sub - Convert Muleshoe East 69 kV to 115 kV Regional Reliability 11/28/15 06/01/12 04/09/12 $1,634,119 $4,673,759 DELAY - MITIGATION

The Valley Substation will be replaced with a 115/13.2kV transformer which will feed a 13.2/2.4kV transformer at East Muleshoe. Escalation included in Contingency cost. Contingency - $532,180; Escalation - $273,122

200166 11107 SPS Multi - Kress Interchange - Kiser - Cox 115 kV Regional Reliability 11/30/14 06/01/14 04/09/12 $14,737,500 $16,923,371C f #DELAY - MITIGATION Cost for Kiser substation included on Network Upgrade ID #50450. Escalation included in Contingency costs. Contingency - $1,524,589;

200166 11109 SPS Multi - Kress Interchange - Kiser - Cox 115 kV Regional Reliability 02/28/14 06/01/14 04/09/12 $7,762,500 $5,848,405 ON SCHEDULE < 4 Cost for Kiser substation included on Network Upgrade ID #50450.

20084 11121 SPS Line - Harrington - Randall County 230 kV Regional Reliability 04/30/13 06/01/10 02/08/10 $225,000 $271,440 DELAY - MITIGATION Mitigation plan has been provided to and accepted by SPP for this project.

11128 SPS Multi - ERF-Gaines 115 kV Ckt 1 Regional Reliability - Non OATT 06/01/12 $0 $4,500,000 ON SCHEDULE < 4

200166 11173 SPS XFR - Eddy County 230/115 kV Transformer Ckt 2 Regional Reliability 06/01/14 06/01/14 04/09/12 $6,761,086 $4,863,725 ON SCHEDULE < 4 Escalation included in contingency costs. Contingency - $329,131; Escalation - $105,493

20084 11177 SPS Line - Randall - Amarillo S 230 kV Ckt 1 Regional Reliability 04/30/13 06/01/10 02/08/10 $27,450,000 $15,220,511 DELAY - MITIGATION Mitigation plan has been provided to and accepted by SPP for this project.

20130 11315 SPS Line - Osage Station and Line Re-termination Regional Reliability 06/01/15 06/01/16 02/14/11 $1,680,000 $1,999,200 ON SCHEDULE < 4

20130 11316 SPS Line - OXY Permian Sub - Sanger SW Station 115 kV Ckt 1 Reconduc Regional Reliability 06/01/12 06/01/16 02/14/11 $295,313 $295,313 $220,090 COMPLETE Q4-2012 Final Costs updated. MN-9/19/12

200166 11317 SPS XFR - Grassland 230/115 kV Transformer Ckt 1 Regional Reliability 06/01/15 06/01/15 04/09/12 $3,961,322 $3,914,401 ON SCHEDULE < 4 The existing transformer foundation will be replaced. The existing equipment ratings are sufficient for this upgrade. Escalation included

20130 11318 SPS XFR - Swisher 230/115 kV Transformer Ckt 1 Upgrade Regional Reliability 06/30/17 06/01/16 02/14/11 $5,953,500 $4,762,800 DELAY - MITIGATION

20130 11319 SPS Line - Wolford-Yuma 115 kV Ckt 1 Wave Trap Regional Reliability 10/31/12 06/01/12 02/14/11 $945,000 $945,000 DELAY - MITIGATION Q4-2012 updated ISD; Current cost estimate remains valid. MN-9/19/12

20118 11321 SPS Multi: Dallam - Channing - Tascosa -Potter Regional Reliability 06/01/12 06/01/09 11/15/10 $26,043,761 $18,284,786 DELAY - MITIGATION This line goes from Channing to Potter and does not go in and out of 20118 11322 SPS Multi: Dallam - Channing - Tascosa -Potter Regional Reliability 06/01/12 06/01/09 11/15/10 $0 $3,216,816 DELAY - MITIGATION

20113 11349 SPS CHERRY - HARRINGTON STATION EAST BUS 230KV CKT 1 Transmission Service 12/30/13 06/01/13 12/09/10 $500,000 $500,000 DELAY - MITIGATION

Q4-2012 Updated ISD; Cost Estimate remains valid. MN-9/19/12

20130 11353 SPS Convert Lynn load to 115 kV Regional Reliability 12/31/13 06/01/12 02/14/11 $100,000 $4,489,314 DELAY - MITIGATIONAlternative 1: CLOSE N.O. tie 6846 Garza, bus 526622. OPEN switch 6736 LG-Central, bus 526666. Alternative 2: CLOSE switch 6745 LS, bus 526979 LG-JS_Smith. OPEN SW 7797 bus 526777 Goodpasture;

200166 11358 SPS Line - Randall - South Georgia 115 kV reconductor Regional Reliability 07/31/15 06/01/17 04/09/12 $6,921,313 $3,618,651 ON SCHEDULE < 4 The 115kV yard at Randall County Interchange will need to be converted to a breaker-and-half, which was not included in this

200166 11359 SPS Line - Hereford - Northeast Hereford 115 kV Ckt 1 Regional Reliability 06/01/13 06/01/12 04/09/12 $2,362,500 $4,139,406 DELAY - MITIGATION NE Hereford substation 115 kV yard will be converted to ring bus.

20130 11372 SPS Line - Soncy convert load to 115 kV Regional Reliability 06/01/15 06/01/15 02/14/11 $500,000 $590,000 ON SCHEDULE < 4 Q4-2012 Cost Estimate updated. MN-9/19/1211374 SPS Line - Eagle Creek - Seven Rivers Interchange 115 kV Ckt 1 Zonal - Sponsored 07/31/11 $0 $12,462,188 $10,594,373 COMPLETE

20130 11378 SPS Multi - Cherry Sub add 230kV source and 115 kV Hastings Conversion Regional Reliability 06/30/13 06/01/13 02/14/11 $1,771,875 $1,771,875 DELAY - MITIGATION

11379 SPS Multi - Randall County Interchange - Palo Duro Sub 115 kV Ckt 1 Reco Zonal - Sponsored 12/31/11 $0 $5,094,140 $5,094,140 ON SCHEDULE < 4

200184 50457 SPS Multi Tuco Amoco Hobbs 345 kV 01/01/20 04/09/12 ON SCHEDULE > 4




20130 11383 SPS Line - North Plainview line tap 115 kV Regional Reliability 12/31/14 06/01/15 02/14/11 $150,000 $200,000 ON SCHEDULE < 4 Q4-2012 updated ISD: Current Cost Estimate remains valid. MN-

20130 11384 SPS Line - Kress Rural line tap 115 kV Regional Reliability 12/31/14 06/01/15 02/14/11 $150,000 $175,000 ON SCHEDULE < 4 Q4-2012 updated ISD; Current Cost Estimate remains valid. MN-9/19/12

20130 11388 SPS Line - Lighthouse - North Plainview 69 kV Ckt 1 Regional Reliability 12/31/11 06/01/11 02/14/11 $50,000 $56,275 $62,154 DELAY - MITIGATION Mitigation not required for 2011. Future TEMPORARY MITIGATION: OPEN 8758 near Kress Rural; CLOSE 3811 Plainview; Shed load as

20130 11389 SPS Multi - Hitchland - Texas Co. 230 kV and 115 kV Regional Reliability 12/31/12 06/01/11 02/14/11 $1,181,400 $1,622,862 DELAY - MITIGATION Revised load forecast in the most recent 2011 MDWG Build 2 models do not show any violations.

11390 SPS XFR - Deaf Smith 230/115/13.2 kV Auto Ckt 1 Zonal - Sponsored 06/01/13 $0 $4,632,000 ON SCHEDULE < 4

200184 11502 SPS Multi - Tuco - Stanton 345 kV ITP10 06/006/006/0

1/18 04/01/18 04/01/18 04/0

9/12 ON SCHEDULE > 4200184 11503 SPS Multi - Tuco - Stanton 345 kV ITP10 9/12 ON SCHEDULE > 4$37,490,796 $37,490,796200184 11504 SPS Multi - Tuco - Stanton 345 kV ITP10 9/12 ON SCHEDULE > 4

200166 11505 SPS XFR - Spearman 115/69/13.2 Ckt 1 Upgrade Regional Reliability 06/30/14 06/01/13 04/09/12 $2,394,495 $2,351,378 DELAY - MITIGATION Escalation included in Contingency costs. Contingency - $235,733; Escalation - $121,849

200166 50093 SPS Device - Bushland Interchange 230 kV Capacitor Regional Reliability 12/30/13 06/01/12 04/09/12 $1,714,505 $1,714,505 DELAY - MITIGATION Estimate assumes capacitor banks will be installed off of existing

50354 SPS Device - Norton Reactor 115 kV Zonal - Sponsored 06/01/13 $0 $1,475,255 ON SCHEDULE < 4

200166 50379 SPS Device - Drinkard 115 kV Capacitor Regional Reliability 06/01/15 06/01/15 04/09/12 $2,225,089 $2,225,089 ON SCHEDULE < 4 Estimate includes the substation scope and the transmission line 200166 50401 SPS Device - Crosby 115 kV Capacitor Regional Reliability 03/30/14 06/01/12 04/09/12 $985,519 $985,519 DELAY - MITIGATION Bus will be expanded. Will require additional land to the north of the 200166 50402 SPS Sub - Move lines from Lea Co 230/115 kV sub to Hobbs Interchange 2 Regional Reliability 11/27/13 01/01/14 04/09/12 $8,270,297 $10,608,509 ON SCHEDULE < 4 Escalation included in Contingency costs. Contingency - $805,431; 200184 50404 SPS Line - Grassland - Wolfforth 230 kV ITP10 03/01/18 03/01/18 04/09/12 $50,068,309 $50,068,309 ON SCHEDULE > 4

200166 50406 SPS Multi - Cedar Lake Interchange 115 kV Regional Reliability 06/30/15 06/01/12 04/09/12 $3,914,970 $5,524,876 DELAY - MITIGATION Escalation included in Contingency costs. Contingency - $572,460; Escalation - $430,918

200166 50407 SPS Multi - Cedar Lake Interchange 115 kV Regional Reliability 06/30/15 06/01/12 04/09/12 $6,112,772 $7,699,644 DELAY - MITIGATION

The new Sulphur-KC 115kV transmission line has one mile of new double circuit with the existing single circuit 115kV transmission line T20. Escalation included in Contingency costs. Contingency - $894,191; Escalation - $596,679

200166 50450 SPS Multi - Kress Interchange - Kiser - Cox 115 kV Regional Reliability 02/28/14 06/01/14 04/09/12 $4,500,000 $6,500,705 ON SCHEDULE < 4The four transmission line estimates are reterminations of existing circuits into Kiser substation. Escalation included in Contingency costs. Contingency - $540,175; Escalation - $105,750

200184 50447 SPS Multi - Tuco - Amoco - Hobbs 345 kV ITP10 01/0

01/0

01/0

01/01/20

1/20 04/0

1/20 04/0

1/20 04/0

04/09/12

9/12 ON SCHEDULE > 4

200184 50451 SPS Multi - Tuco - Amoco - Hobbs 345 kV ITP10 9/12 ON SCHEDULE > 4$181,415,883 $181,415,883

200184 50452 SPS Multi - Tuco - Amoco - Hobbs 345 kV ITP10 9/12 ON SCHEDULE > 4

200184 50457 SPS Multi - Tuco - Amoco - Hobbs 345 kV - - - ITP10ITP10 ON SCHEDULE > 4

200166 50453 SPS Multi - Bowers - Howard 115 kV Ckt 1 Regional Reliability 05/31/14 06/01/16 04/09/12 $13,286,935 $22,577,591 ON SCHEDULE < 4Transmission line estimate assumes the existing single circuit Y62 (Bowers to Howard) 69kV circuit will be wrecked out and rebuilt on the new 115kV as double circuit. This will minimize the impact to

50562 SPS Line(s) - Harrington - Nichols 230kV DBL CKT Generation Interconnection 12/31/12 $0 $1,738,502 ON SCHEDULE < 4

10125 SWPA XFR - Eufaula 161/138 kV Regional Reliability - Non OATT 03/30/11 04/01/09 $0 $3,000,000 COMPLETE10576 SWPA Line - Nixa - Nixa DT Rebuild Regional Reliability - Non OATT 06/01/15 $0 $660,000 ON SCHEDULE < 4

10645 SWPA XFR - Springfield 161/69kV #3 Regional Reliability - Non OATT 12/01/13 06/01/17 $0 $2,250,000 ON SCHEDULE < 4

10741 SWPA XFR - Paragould 161/69 kV Auto 1 & 2 Regional Reliability - Non OATT 11/30/11 12/01/11 $0 $3,150,000 COMPLETE Project complete. Xfmr 1 was replaced and put in service 3/26/2011. 10819 SWPA Line - Asherville - Idalia 161 kV Reconductor Regional Reliability - Non OATT 06/26/12 06/01/14 $0 $10,095,750 COMPLETE

10836 SWPA Line - Asherville - Poplar Bluff 161 kV Regional Reliability - Non OATT 06/01/14 06/01/15 $0 $4,500,000 ON SCHEDULE < 4

10856 SWPA XFR - Carthage 161/69 kV Transformers 1 & 2 Regional Reliability - Non OATT 06/01/14 $0 $5,625,000 ON SCHEDULE < 4

10944 SWPA Line - Dardanelle - Russellville South 161 kV Regional Reliability - Non OATT 05/25/11 06/01/10 $0 $165,000 COMPLETE Project is complete20030 10173 WFEC Multi - Lindsay - Lindsay SW and Bradley-Rush Springs Regional Reliability 09/01/12 06/01/10 01/27/09 $3,577,500 $2,328,750 DELAY - MITIGATION20003 10174 WFEC Line - Meeker - Hammett 138 kV Regional Reliability 12/01/13 06/01/08 02/13/08 $5,250,000 $6,674,000 DELAY - MITIGATION Temporary op guide provided.20003 10175 WFEC Line - Wakita - Hazelton 69 kV Regional Reliability 12/01/12 04/01/09 02/13/08 $5,670,000 $8,000,000 DELAY - MITIGATION

20003 10176 WFEC Line - OGE Woodward - WFEC Woodward 69 kV regional reliability 12/01/13 04/01/09 02/13/08 $0 $1,050,000 DELAY - MITIGATION

19985 10179 WFEC Line - ACME - W Norman 69 kV regional reliability 12/01/13 06/01/08 02/02/07 $0 $912,000 DELAY - MITIGATION Mitigation Plan under review by SPP. Defered in latest SPP Transmission Expansion Plan.

20003 10303 WFEC Line - Atoka - WFEC Tupelo - Lane 138 kV Regional Reliability 06/01/13 06/0

1/11 06/0

1/12

1/12 02/1

02/13/08 $8,265,000 $8,265,000 COMPLETE AEP's station cost is $1.665M. WFEC's construction cost is $6.6M. An interconnection agreement has been executed between WFEC

20003 10304 WFEC Line - Atoka - WFEC Tupelo - Lane 138 kV Regional Reliability 06/0 3/08 COMPLETE

20030 10305 WFEC Line - WFEC Snyder - AEP Snyder Regional Reliability 03/01/12 06/01/09 01/27/09 $3,373,000 $839,770 COMPLETE

20003 10307 WFEC Line - Anadarko - Georgia Tap 138 kV regional reliability 12/01/14 06/01/09 02/13/08 $750,000 $2,000,000 DELAY - MITIGATION20003 10308 WFEC Line - Elmore - Paoli 69 kV regional reliability 12/02/14 06/01/09 02/13/08 $3,240,000 $3,240,000 DELAY - MITIGATION20003 10309 WFEC Multi - OU SW - Goldsby - Canadian SW 138 kV Regional Reliability 12/31/12 06/01/09 02/13/08 $9,087,500 $2,753,800 DELAY - MITIGATION line converted but energized @ 69kV

20114 11351 WFEC G03-05T PARADISE 138KV CKT 1 Transmission Service 06/01/15 06/01/15 12/09/10 $150 000 $150 000 ON SCHEDULE < 4

20003 10310 WFEC Multi - OU SW - Goldsby - Canadian SW 138 kV Regional Reliability 12/31/12 06/01/09 02/13/08 $0 $2,250,000 DELAY - MITIGATION line converted but energized @ 69kV

20003 10311 WFEC Multi - OU SW - Goldsby - Canadian SW 138 kV Regional Reliability 12/31/12 06/01/09 02/13/08 $0 $5,000,000 DELAY - MITIGATION in construction20003 10401 WFEC Multi - Franklin SW - Acme - Norman - OU SW Conversion 138 kV Regional Reliability 12/31/14 06/01/10 02/13/08 $3,646,594 $2,065,000 DELAY - MITIGATION built at 138kV but energized @ 69kV20003 10402 WFEC Multi - Franklin SW - Acme - Norman - OU SW Conversion 138 kV regional reliability 12/31/13 06/01/10 02/13/08 $0 $1,601,000 DELAY - MITIGATION20003 10403 WFEC Multi - Franklin SW - Acme - Norman - OU SW Conversion 138 kV Regional Reliability 12/31/15 06/01/10 02/13/08 $1,577,000 $1,577,000 DELAY - MITIGATION built at 138kV but energized @ 69kV19951 10467 WFEC XFR - Anadarko 138/69 kV Transmission Service 09/30/12 06/01/11 01/02/07 $2,000,000 $2,000,000 DELAY - MITIGATION20003 10471 WFEC Line - Fletcher - Marlow Jct 69 kV regional reliability 06/01/14 06/01/11 02/13/08 $2,000,000 $2,000,000 DELAY - MITIGATION

20003 10519 WFEC Line - Lindsay - Wallville 69 kV Regional Reliability 06/01/15 06/01/12 02/13/08 $1,347,000 $1,347,000 DELAY - MITIGATION Loading of facility shows mitigation not needed before summer 2015.20003 10520 WFEC Line - Pharoah - Weleetka 138 kV Regional Reliability 09/28/12 06/01/12 02/13/08 $100,000 $225,000 COMPLETE Field Verified that Pharoah – Weleetka CT is 800:5 and has thermal 20003 10521 WFEC Line - WFEC Russell - AEP Altus Jct Tap 138 kV Regional Reliability 06/01/12 06/01/12 02/13/08 $50,000 $50,000 COMPLETE

20003 10522 WFEC Multi - Granfield - Cache SW 138 kV Regional Reliability 06/01/13 06/0

1/13 06/0

1/13 06/0

1/12 02/13/08 $1,125,000 DELAY - MITIGATION

20003 10523 WFEC Multi - Granfield - Cache SW 138 kV Regional Reliability 06/0 1/12 02/13/08 $7,306,000 DELAY - MITIGATION$18,182,800

20003 10524 WFEC Multi - Granfield - Cache SW 138 kV Regional Reliability 06/0 1/12 02/13/08 $5,000,000 DELAY - MITIGATION

20030 10794 WFEC Multi: WFEC-Dover-Twin Lake_Cresent-Cottonwood conversion 138 k Regional Reliability 12/31/12 06/01/10 01/27/09 $0 $5,765,600 DELAY - MITIGATION Use Dover-Twin Lakes op guide for temporary mitigation20030 10795 WFEC Multi: WFEC-Dover-Twin Lake_Cresent-Cottonwood conversion 138 k Regional Reliability 12/31/13 06/01/10 01/27/09 $0 $5,315,700 DELAY - MITIGATION built at 138kV but energized @ 69kV; Use Dover-Twin Lakes op guide 20030 10796 WFEC Multi: WFEC-Dover-Twin Lake_Cresent-Cottonwood conversion 138 k Regional Reliability 12/31/13 06/01/10 01/27/09 $0 $3,164,000 DELAY - MITIGATION built at 138kV but energized @ 69kV; Use Dover-Twin Lakes op guide 20030 10797 WFEC Multi: WFEC-Dover-Twin Lake_Cresent-Cottonwood conversion 138 k Regional Reliability 12/31/12 06/01/10 01/27/09 $0 $3,937,500 DELAY - MITIGATION Use Dover-Twin Lakes op guide for temporary mitigation; under 20030 10798 WFEC Line - Carter Jct-Lake Creek 69 kV Regional Reliability 09/15/11 06/01/10 01/27/09 $150,000 $150,000 COMPLETE CT's upgraded to 600 amp effective 9/15/11. NO cost for this 20030 10799 WFEC Multi - Lindsay - Lindsay SW and Bradley-Rush Springs Regional Reliability 09/01/12 06/01/10 01/27/09 $0 $1,248,750 DELAY - MITIGATION in construction20132 10865 WFEC Line - Reeding - Twin Lakes Switchyard conversion to 138 kV Regional Reliability 04/01/13 06/01/12 02/14/11 $1,971,000 $1,971,000 DELAY - MITIGATION Temporary op guide provided.20085 10878 WFEC Line - El Reno - El Reno SW 69 kV Regional Reliability 06/01/12 06/01/12 02/08/10 $1,950,000 $1,950,000 COMPLETE20132 10879 WFEC Line - Bradley - Lindsay 69 kV Ckt 1 reconductor Regional Reliability 09/01/12 06/01/15 02/14/11 $3,712,500 $3,712,500 ON SCHEDULE < 4 in construction

20085 11114 WFEC Line - Snyder - Tipton 69 kV CT Regional Reliability 06/01/11 06/01/11 02/08/10 $225,000 $225,000 COMPLETE

20132 11115 WFEC Multi - Anadarko - Blanchard - OU SW 138 kV Ckt 1 Regional Reliability 12/01/14 06/01/12 02/14/11 $14,737,500 $14,737,500 DELAY - MITIGATION Temporary operating guide provided.

20132 11116 WFEC Multi - Anadarko - Blanchard - OU SW 138 kV Ckt 1 Regional Reliability 12/01/15 06/01/12 02/14/11 $1,125,000 $1,125,000 DELAY - MITIGATION Temporary operating guide provided.

20132 11117 WFEC Line - Wakita - Nash 69 kV Ckt 1 Regional Reliability 06/01/14 06/01/11 02/14/11 $6,705,000 $6,705,000 DELAY - MITIGATION Temporary op guide provided.20114 11350 WFEC ALTUS SW - NAVAJO 69KV CKT 1 Transmission Service 06/01/13 06/01/10 12/09/10 $150,000 $150,000 COMPLETE

20114 11351 WFEC G03-05T - PARADISE 138KV CKT 1 - Transmission Service 06/01/15 06/01/15 12/09/10 $150 000 $150 000 ON SCHEDULE < 4, ,

20132 11424 WFEC Line - Alva - Freedom 69 kV Ckt 1 Regional Reliability 06/01/13 06/01/11 02/14/11 $6,243,750 $6,243,750 DELAY - MITIGATION Temporary operating guide provided.20132 11429 WFEC Line - Criner - Lindsay 69 kV Ckt 1 Regional Reliability 06/01/13 06/01/11 02/14/11 $50,000 $50,000 DELAY - MITIGATION20030 50045 WFEC Device - Esquandale Cap 69 kV regional reliability 06/01/14 06/01/14 01/27/09 $0 $243,000 ON SCHEDULE < 4 WFEC will move ahead line project: Cache to Grandfield to mitigate

19985 50047 WFEC Device - Comanche regional reliability 06/01/12 06/01/12 02/02/07 $0 $350,000 ON SCHEDULE < 4 Shed load at Loco Substation (up to 3.5MW in 2007 Summer Peak) Shed load at Empire Substation (up to 5MW in 2007 Summer Peak).

20003 50050 WFEC Device - Gypsum Cap 69 kV regional reliability 06/01/11 04/01/08 02/13/08 $0 $150,000 DELAY - MITIGATION

20003 50085 WFEC Device - Carter Cap 69 kV regional reliability 06/01/12 06/01/10 02/13/08 $0 $324,000 DELAY - MITIGATION20003 50099 WFEC Device - Latta Cap 138 kV Regional Reliability 06/01/12 06/01/12 02/13/08 $0 $324,000 DELAY - MITIGATION20030 50180 WFEC Device Eagle Chief 69 kV Capacitor Regional reliability 06/01/10 06/01/09 01/27/09 $0 $300,000 DELAY - MITIGATION20085 50186 WFEC Device - Electra 69 kV Capacitor Regional Reliability 08/31/12 06/01/11 02/08/10 $0 $240,000 COMPLETE20136 50366 WFEC Line - Canton - Taloga 69 kV ckt 1 Transmission Service 06/01/13 06/01/11 05/27/11 $4,800,000 $4,800,000 DELAY - MITIGATION Interim redispatch under service agreement

20136 50367 WFEC XFR - Taloga 138/69 kV ckt 1 Transmission Service 06/01/13 06/01/11 05/27/11 $1,000,000 $1,000,000 DELAY - MITIGATIONInterim redispatch under service agreement

50462 WFEC Line - Washita - Gracemont 138 kv ckt 2 Generation Interconnection 10/12/12 $0 $4,740,546 ON SCHEDULE < 4 In service date expected around October 12, 2012. Percent 50463 WFEC SUB - SLICK HILLS 138KV Generation Interconnection 02/01/12 $0 $1,500,000 COMPLETE

20006 10220 WR Line - Weaver - Rose Hill 69 kV Regional Reliability 01/27/11 06/01/08 02/13/08 $1,350,000 $2,676,185 $2,627,677 COMPLETE

20006 10221 WR Line - Tecumseh Energy Center - Midland 115 kV Regional Reliability 06/01/13 06/01/12 02/13/08 $2,000,000 $5,423,701 DELAY - MITIGATION Redispatch TEC generation.

19986 10229 WR Line - Stranger Creek - Thornton Street 115 kV Addition Regional Reliability 02/24/11 06/01/07 02/02/07 $2,500,000 $9,206,570 $9,231,495 COMPLETE In-Service - Cost Not Final

20059 10231 WR Line - Chase - White Junction 69 kV Regional Reliability 06/01/13 06/01/10 09/18/09 $5,184,701 $6,066,000 DELAY - MITIGATION Interim mitigation is application of existing Transmission Operating Directive 634

20033 10349 WR Line - Circle - HEC GT 115 kV Rebuild regional reliability 03/17/11 06/01/11 01/27/09 $300,000 $1,256,055 $1,242,102 COMPLETEIn-Service - Cost Not Final

20086 10350 WR Line - Halstead - Mud Creek Jct. - 69 kV Regional Reliability 12/30/11 06/01/11 02/08/10 $2,500,000 $5,718,375 COMPLETE UVLS operational in Newton Division. Adjustment of CTs at Halstead and Newton to increase line rating is interim mitigation.

20086 10351 WR Line - Halstead - Mud Creek Jct. - 69 kV Regional Reliability 02/24/12 06/01/11 02/08/10 $360,000 $764,190 COMPLETE The mitigation is to open the Halstead-Burrton 69 kV line and close 20086 10352 WR Line - Halstead - Mud Creek Jct. - 69 kV Regional Reliability 05/23/12 06/01/11 02/08/10 $1,300,000 $3,011,613 COMPLETE20006 10417 WR Line - Oaklawn - Oliver 69 kV Regional Reliability 07/25/12 06/01/10 02/13/08 $483,000 $2,686,996 COMPLETE

200181 10425 WR XFR - Moundridge 138/115 kV Regional Reliability 12/01/14 12/01/14 04/09/12 $12,197,900 $12,197,900 ON SCHEDULE < 4 This will be designed as an installation of a single/larger (200MVA) 20140 10487 WR Line - Creswell - Oak 69 kV Ckt 1 Transmission Service 12/31/13 06/01/11 05/27/11 $1,500,000 $1,500,000 DELAY - MITIGATION Interim redispatch under service agreement. The mitigation is to run

19964 10488 WR XFR - Rose Hill 345/138 kV Ckt 3 transmission service 06/01/13 06/01/11 06/27/07 $5,000,000 $10,387,399 DELAY - MITIGATIONDisplacement need to make filing for displacement $

20086 10603 WR Line - Gill - Interstate 138 kV Regional Reliability 12/01/13 06/01/13 02/08/10 $50,000 $118,341 DELAY - MITIGATION Mitigation is to re-dispatch Gill and Evans in the Wichita area.20033 10638 WR Line - Jarbalo - Stranger Creek Regional Reliability 08/11/11 06/01/10 01/27/09 $8,050,000 $5,228,040 $3,755,915 COMPLETE In-Service - Cost not final20033 10639 WR Line - Jarbalo - Stranger Creek Regional Reliability 04/26/11 06/01/10 01/27/09 $0 $4,536,005 $4,141,799 COMPLETE In-Service - Cost Not final20059 10674 WR Line - Rose Hill - Sooner 345 kV Ckt 1 (WR) Regional Reliability 04/27/12 01/01/13 09/18/09 $84,669,696 $84,379,298 COMPLETE Project costs are for Westar Energy portion only; Public hearing held; 20086 10679 WR XFR - Halstead South 138/69 kV Ckt 1 regional reliability 06/01/14 06/01/11 02/08/10 $1,700,000 $3,205,323 DELAY - MITIGATION20063 10713 WR Multi - Litchfield - Aquarius - Hudson Jct. 69 kV Uprate regional reliability 06/01/13 06/01/13 11/02/09 $75,000 $140,500 ON SCHEDULE < 420033 10767 WR Line - 27th & Croco - 41st & California 115 kV regional reliability 03/21/11 06/01/09 01/27/09 $2,752,000 $3,654,556 COMPLETE In-Service - Cost Not Final

20033 10806 WR Multi - NW Manhattan Regional Reliability 05/11/12 06/0

9/12 06/0

1/10 01/27/09 $3,650,576 COMPLETE Currently 230/115kV dollars are combined. Will break apart for Q3 report.

20033 10808 WR Multi - NW Manhattan Regional Reliability 03/1 1/10 01/27/09 $23,493,424$17,437,500

COMPLETE Current cost estimate for UID 10806 is sufficient for both 230/115kV work. Additional dollars not required. The mitigation is to run Abilene

20059 10810 WR Line - Richland - Rose Hill Junction 69 kV Zonal Reliability 11/03/11 06/01/11 09/18/09 $2,815,000 $3,782,279 COMPLETE

200175 10812 WR Line - Fort Junction - West Junction City 115 kV Regional Reliability 06/01/13 06/01/15 04/09/12 $6,969,136 $6,969,136 ON SCHEDULE < 4

20033 10813 WR Line - Rebuild Chisolm - Ripley 69 kV Regional Reliability 06/01/11 06/01/10 01/27/09 $2,255,250 $3,962,701 COMPLETEIn-Service - Cost Not final

20086 10866 WR Line - Gill - Clearwater 138 kV Regional Reliability 04/27/11 06/01/11 02/08/10 $3,324,375 $8,466,466 COMPLETE Line energized 4/27/11, however breaker change out at Gill will not be completed until 11/15/11.

20063 10870 WR Line - GEC West - Waco 138 kV Regional Reliability 12/01/12 06/01/10 11/02/09 $1,000,000 $4,747,641 DELAY - MITIGATION

20086 11082 WR Line - Gill Energy Center East - MacArthur 69 kV Regional Reliability 06/01/14 06/01/13 02/08/10 $2,200,000 $4,001,482 DELAY - MITIGATION Mitigation is to re-dispatch Gill and Evans in the Wichita area.

20068 11204 WR Line - Macarthur - Oatville 69 kV Ckt 1 Transmission Service 03/12/12 06/01/12 01/13/10 $40,000 $50,200 $20,679 COMPLETE All terminal equipment meets minimum NTC requirement20131 11344 WR Multi - Craig - 87th - Stranger 345 kV Ckt 1 Regional Reliability 12/31/12 06/0

1/12 06/0

1/12 06/0

1/11 02/14/11 $9,866,277 DELAY - MITIGATION Mitigiation is to re-dispatch LEC generation and/or open Wakarusa Jct-20131 11345 WR Multi - Craig - 87th - Stranger 345 kV Ckt 1 Regional Reliability 12/3 1/11 02/14/11 $15,119,789$26,825,000 DELAY - MITIGATION Mitigiation is to re-dispatch LEC generation and/or open Wakarusa Jct-

20131 11346 WR Multi - Craig - 87th - Stranger 345 kV Ckt 1 Regional Reliability 12/3 1/11 02/14/11 $12,047,385 DELAY - MITIGATION Mitigiation is to re-dispatch LEC generation and/or open Wakarusa Jct-Eudora 115 kV

20131 11411 WR Multi - Mulberry - Franklin - Sheffield 161 kV Regional Reliability 06/01/14 06/01/14 06/0

1/13 02/14/11 $4,981,988$7,347,754 DELAY - MITIGATION Distribution Capacitor banks are in-service to improve the PF on 20131 11412 WR Multi - Mulberry - Franklin - Sheffield 161 kV Regional Reliability 06/0 1/13 02/14/11 $4,981,988 DELAY - MITIGATION Distribution Capacitor banks are in-service to improve the PF on 20131 11413 WR Multi - Mulberry - Franklin - Sheffield 161 kV Regional Reliability 06/01/14 06/01/13 02/14/11 $8,750,767 $11,471,091 DELAY - MITIGATION

11441 WR Caney River Wind Project Generation Interconnection 09/13/11 $0 $6,867,000 $278,558 COMPLETE Costs to be incurred by wind farm owner.20131 11444 WR Multi - Mulberry - Franklin - Sheffield 161 kV Regional Reliability 06/01/14 06/01/13 02/14/11 $0 $3,297,121 DELAY - MITIGATION

11445 WR Caney River Wind Project Generation Interconnection 09/13/11 $0 $625,000 $847,064 COMPLETE Costs to be incurred by wind farm owner.20091 50228 WR Multi - Green - Coffey County No. 3 - Burlington Junction - Wolf Creek Transmission Service 12/31/12 06/01/12 03/31/10 $3,921,591 $4,380,845 DELAY - MITIGATION Mitigation is to re-dispatch generation in the (Chanute, Erie, and Iola).20059 50229 WR Device - Allen 69 kV Capacitor Transmission Service 05/31/12 06/01/12 09/1 $ $8/09 $0 $954,830 COMPLETE

20059 50230 WR Device - Altoona East 69 kV Capacitor transmission service 06/01/14 06/01/14 09/18/09 $0 $1,045,000 ON SCHEDULE < 4

20059 50231 WR Device - Athens 69 kV Capacitor Transmission Service 12/01/13 06/01/13 09/18/09 $0 $1,026,734 DELAY - MITIGATION Bring on cap banks at Allen and Tioga. Dispatch Chanute/Erie/Iola 20091 50232 WR Multi - Green - Coffey County No. 3 - Burlington Junction - Wolf Creek Transmission Service 05/25/11 04/01/11 03/31/10 $1,960,795 $3,993,819 $2,855,297 COMPLETE In-Service - Cost Not final

20091 50233 WR Multi - Green - Coffey County No. 3 - Burlington Junction - Wolf Creek Transmission Service 06/01/14 07/01/13 03/31/10 $4,575,190 $2,718,863 DELAY - MITIGATION

20091 50234 WR Multi - Green - Coffey County No. 3 - Burlington Junction - Wolf Creek Transmission Service 06/01/13 01/01/13 03/31/10 $2,614,395 $3,438,116 DELAY - MITIGATION

20091 50236 WR Multi - Green - Coffey County No. 3 - Burlington Junction - Wolf Creek Transmission Service 12/15/13 04/01/14 03/31/10 $5,882,387 $6,024,876 ON SCHEDULE < 4

20091 50239 WR Multi - Green - Coffey County No. 3 - Burlington Junction - Wolf Creek Transmission Service 12/14/11 12/01/11 03/31/10 $5,555,588 $2,996,364 COMPLETE

20091 50240 WR Multi - Green - Coffey County No. 3 - Burlington Junction - Wolf Creek Transmission Service 03/29/12 11/01/13 03/31/10 $653,598 $1,693,501 COMPLETE

20059 50241 WR Line - Neosho - Northeast Parsons 138 kV Transmission Service 06/01/11 06/01/11 09/18/09 $250,000 $114,269 $114,269 COMPLETE Jumper was replaced with bundled 266 ACSR wire rated at 192MVA.20059 50243 WR Device - Timber Jct 138 kV Capacitor Transmission Service 08/16/11 06/01/11 09/18/09 $0 $1,637,096 COMPLETE

20059 50244 WR Device - Tioga 69 kV Capacitor Transmission Service 07/05/11 06/01/11 09/18/09 $0 $732,398 $584,242 COMPLETE

20091 50245 WR Multi - Green - Coffey County No. 3 - Burlington Junction - Wolf Creek transmission service 03/03/11 01/01/11 03/31/10 $3,267,992 $2,777,239 $1,976,966 COMPLETEIn-Service - Cost Not Final

20068 50284 WR Device - Dearing 138 kV Capacitor Transmission Service 06/01/13 06/01/12 01/13/10 $0 $1,215,000 DELAY - MITIGATION50290 WR Device - Benton Cap #2 Zonal - Sponsored 06/01/14 $0 $3,072,000 ON SCHEDULE < 4

20108 50327 WR Line - East Manhattan - NW Manhattan 230 kV Ckt 1 Transmission Service 03/19/12 06/01/19 08/25/10 $700,000 $700,000 COMPLETE20108 50328 WR Line - Halstead South - Sedgwick 138 kV transmission service 06/01/16 06/01/19 08/25/10 $700,000 $700,000 ON SCHEDULE > 4

20140 50368 WR Sub - Chapman Junction 115 kV Zonal Reliability 12/31/12 10/01/12 05/27/11 $4,877,550 $4,877,550 DELAY - MITIGATION

20140 50369 WR Sub - Clay Center Junction 115 kV Zonal Reliability 12/31/12 10/01/12 05/27/11 $2,849,367 $2,849,367 DELAY - MITIGATION

20140 50370 WR Device - Chapman Junction 115 kV Capacitor Zonal Reliability 10/01/13 10/01/12 05/27/11 $0 $873,461 DELAY - MITIGATION

20140 50371 WR Line - Clay Center Junction - Clay Center Switching Station 115 kV Zonal Reliability 12/31/12 10/01/13 05/27/11 $6,790,959 $7,476,811 DELAY - MITIGATION Clay Center did not provide Westar with construction easement. This 20140 50372 WR Line - Clay Center Switching Station - TC Riley 115 kV ckt 1 Zonal Reliability 06/01/14 10/01/12 05/27/11 $4,549,942 $7,472,511 DELAY - MITIGATION Due to uncertainty of Presidential Permit, TransCanada has extended

20140 50373 WR Sub - Clay Center Switching Station 115 kV Zonal Reliability 12/31/12 10/01/12 05/27/11 $4,877,550 $2,774,851 DELAY - MITIGATIONClay Center did not provide Westar with construction easement. This required redesign and will extend construction by one month. Mitigation is to serve the load at existing Delivery Point for an extra

20140 50374 WR Sub - TC Riley 115 kV Zonal Reliability 06/01/14 10/01/12 05/27/11 $850,000 $963,441 DELAY - MITIGATIONDue to uncertainty of Presidential Permit, TransCanada has extended their in-service date to June 2014. Load will not be in-service until June, 2014. No mitigation is needed. The RTO date needs to be changed according to an email that was sent to Steve Purdy.

200175 50382 WR Device - Wheatland 115 kV Capacitor Zonal Reliability 06/01/13 06/01/12 04/09/12 $957,660 $957,660 DELAY - MITIGATION200175 50383 WR Device - Northwest Manhattan 115 kV Capacitor Zonal Reliability 12/31/12 06/01/14 04/09/12 $957,660 $957,660 ON SCHEDULE < 4

200175 50386 WR Mund - Pentagon 115 kV Regional Reliability 12/01/12 04/09/12 $278,300 $278,300 ON SCHEDULE < 4 After substation review, equipment in the sub already meets NTC requirements.

200175 50397 WR Line - Cowskin - Centennial 138 kV rebuild Regional Reliability 06/01/13 06/01/12 04/09/12 $3,676,071 $3,676,071 DELAY - MITIGATION200179 50398 WR XFR - Auburn Road 230/115 kV Transformer Ckt 1 Regional Reliability 06/01/14 06/01/14 04/09/12 $25,845,600 $32,211,913 ON SCHEDULE < 4 Substation Scope: This will be a "greenfield" substation requiring land

200175 50399 WR Device - Elk River 69 kV Capacitor Zonal Reliability 12/01/13 06/01/12 04/09/12 $1,007,160 $1,007,160 DELAY - MITIGATIONThere is an existing capacitor bank at Elk River substation. Installation of a second cap bank will require control & switching upgrades on the existing bank.

200182 50429 WR Multi - Elm Creek - Summit 345 kV ITP10 03/01/18 04/09/12 $62,110,152 $62,110,152 ON SCHEDULE > 4200176 50465 WR MULTI - RICE - CIRCLE 230KV CONVERSION Generation Interconnection 11/15/12 01/16/12 $5,095,881 $5,095,881 ON SCHEDULE < 4

50470 WR Multi - Creswell - BellePlain 138 kV Zonal - Sponsored 06/01/12 $0 $6,581,250 ON SCHEDULE < 450471 WR Multi - Creswell - BellePlain 138 kV Zonal - Sponsored 06/01/12 $0 $885,938 ON SCHEDULE < 450472 WR Multi - Creswell - BellePlain 138 kV Zonal - Sponsored 06/01/12 $0 $3,075,469 ON SCHEDULE < 4

Integrated MarketplaceUpdate

Board of Directors

October 30, 2012

Bruce Rew, P.E.

Vice President, Operations

Agenda

• Budget update

• Development

– Internal Readiness

– Market Participant Readiness

– Systems Development

2

Integrated Marketplace – Budget Overview

3

INTEGRATED MARKETPLACE INTERNAL READINESS UPDATE

4

October Internal Readiness Status

5

SPP’s Internal Readiness Status for Integrated Marketplace is currently green.

Department Internal Readiness Status

6

The Internal Readiness Status is currently green for each department at SPP.

NS indicates the related Readiness activities have not started.N/A indicates the readiness area is not applicable .

Internal Readiness Liaisons and Scorecard

• Initial scorecard was distributed October 1.

• Scorecards will be posted bi‐monthly until start of Market Trials Structured Testing.

• Scorecards will be posted monthly from start of Market Trials Structured Testing until month preceding Go‐Live.

7

INTEGRATED MARKETPLACE MARKET PARTICIPANT UPDATE

8

Participant Readiness: Accomplishments

• Three months of Engagement Reporting (July–September)

– Summary‐level, MP‐level reports on iDashboard

• Reviewing updated 2013 Engagement Activities with Readiness liaisons

• Updated Readiness Metrics based on Market Trials Connectivity and TCR approaches

• Upcoming activities

– October 17: Liaison review of Readiness Metrics

– Add Readiness Metrics to iDashboard

9

2012 Participant Engagement Activity Status

10

Date Participant Activity Status

May 31, 2012 • ENG.002 ‐ Technical Specifications Reviewed (Markets,Settlements, TCR)

Red

June 1, 2012 • ENG.001 ‐ Participant System Design Underway Yellow

June 1, 2012 • ENG.003 ‐ Registration Packet Returned Green

June 29, 2012 • ENG.004 ‐ Participant Interface Design Complete Red

Aug 1, 2012 • ENG.005 ‐ Participant Interface Build Underway Yellow

Aug 31, 2012 • ENG.006 ‐ Complete Participation in TCR Mock Phase 2 Green

Sept 28, 2012 • ENG.007 ‐ Participant System Design Complete Yellow

Sept 30, 2012 • ENG.008 ‐MP Approach Completed for TCR Market Trials Red

Data as of September 28, 2012

2012 Participant Engagement Activity Status

11

Date Participant Activity Status

Oct 7, 2012 • ENG.009 ‐MP Approach Completed for Market Trials Connectivity Testing

Red

Nov 1, 2012 • ENG.011 ‐ Participant System Build Underway Green

Nov 9, 2012 • ENG.022 ‐ Participant TCR Interfaces Ready for Connectivity Green

Nov 9, 2012 • ENG.026 ‐ TCR Accelerated Connectivity Test Scheduled TBD

Nov 30, 2012 • ENG.010 ‐MP/TO Testing with the MCST tool TBD

Dec 21, 2012 • ENG.015 ‐Market Trials Connectivity Test Scheduled TBD

Dec 28, 2012 • ENG.012 ‐ Participant Interfaces Ready for Connectivity (excluding TCR)

Yellow

Data as of September 28, 2012

Outreach Program: Accomplishments

• Identified Outreach project manager, team members, and responsibilities with internal framework

• Finalized Outreach project plan with schedule, resources, deliverables

• Request Management System online (October 16)

• Built consolidated issues report for internal tracking

• Developed Outreach communications plan

12

Outreach Program: What’s Next?

• Implement, communicate detailed Outreach plan

• Continue needs analyses

• Identify readiness gaps, recommendations for closing gaps

• Implement program’s measurement, evaluation

• Report outcomes of Outreach efforts

13

Issues Update

• Issues being addressed through workstream process, RMS

• Escalated issues:

– Automatic escalation based on Service Level Agreements

– Responses stored in RMS

– Members and SPP can monitor status through RMS

• July issues list posted with October MOPC materials

– All items closed or currently being worked

– Follow‐up continues

14

INTEGRATED MARKETPLACE SYSTEM UPDATE

15

Market Trials Readiness System Heat Map

16

17

18

19

20

Systems Delivered

21

Completed Acceptance Testing

Portal

iHedge (TCR)

TCRXFER

Credit Management System

OASIS Transfer Tool

Select SPP Legacy Applications

OATI (eTag, ROT_SS, Ramp Reservation System, Reserve Sharing

Energy Management System

PRT Load Forecast

Select Settlements (non_vendor)

RTGEN

Integration Services Interfaces

System Areas of Concern

• Markets

• Settlements

• Registration

• Integration Services (Interface Delivery)

22

MarketsCurrent State:

• Market system development delays with core Markets functionality. Working with Alstom to address delays

• Identified 1062 Markets development/testing items pending100 development gaps, 600+ (criticals, highs, medium, lows) system defects, 300 known development items pending

• Factory Acceptance Testing is 66% through scheduled time with 46% of test procedures verified (total of 1245 out of 2692). Additional test procedures are being finalized and will be added

• With 220 development and defects items identified as required for Factory Acceptance Testing exit criteria; an estimated Vendor resolution rate of 20‐30 items per week does not meet the exit criteria by mid‐November

23

Markets – Cont’d

Action Plan:• Working with vendor to prioritize pending functionality and system

defects with Market Trials critical path driving higher priority to minimize downstream impacts

• Vendor to provide updated delivery dates based on prioritization

• Program mitigation planning to be initiated as a result of prioritization and updated delivery dates

24

Settlements

Current State:

• Settlements system development approximately 4 weeks behind schedule, plan to make up 2 weeks prior to end of FAT, but expecting an over 2‐week delay to FAT end

• Factory Acceptance Testing (FAT) is 33% through the schedule and has validated 38% of test procedures for functionality validated during pre‐FAT (663 out of 1734)

• Most of the remaining 70% planned test execution has been verified in pre‐FAT, with 30% of the remaining being new functionality.

Action Plan:

• Resources working overtime to maintain testing schedule to offset late system delivery

25

Registration

Current State:

• Testing plan accounts for Centralized Modeling system delivery one month behind schedule mitigating schedule impacts

• SAT has (7) high participant‐facing defects that must be fixed by Alstom with a scheduled completion of November 2

Action Plan:

• Vendor resources on‐site at SPP during three weeks of Site Acceptance Testing

• Assigned SPP resources at higher capacity than originally planned

• Mitigation plan to manually publish models until CMT is in Production

26

Integration ServicesCurrent State:

• Scope increased from 75 to 135 interfaces while average complexity decreased; divided build effort into 2 delivery waves (Sep 2012, Dec 2012)

• Adjusted Wave 1 build schedule to accommodate late delivery of Registration system

• Wave 1 interfaces (53) build complete; migration to Integrated Test Environment (ITE) 50% complete

• SIT testing underway

Action Plan:

• Wave 2 Technical Design in progress

• Wave 2 on schedule for Dec 31, 2012 delivery to ITE27

Connectivity Test Preparation Tasks• SPP has expedited many of the following Connectivity Testing activities

to mitigate schedule impacts for Participants:

– Marketplace Portal availability for Participant LSA access as of 9/17/12 to configure Participant Users

– Participant Sandbox availability access as of 9/20/12

– Participant Connectivity Testing for MCST scheduled for 10/29/12

– Participant Connectivity Testing for TCR scheduled for 11/12/12

• Working with the MTRG, SPP published the Connectivity Test Approach and TCR Market Trials Approach on 8/7/12

• All other SPP tasks and dependencies to conduct Market Trials Connectivity Testing are on schedule

28

Market Trials Structured Test Preparation

• Market Trials Structured Test Approach, scheduled for Participant review in December, will account for system delivery delays and SPP internal testing time

• Some Structured Testing scenarios may not be fully tested by the start of the test (6/3/13). We will closely monitor these and communicate status that would impact Participant Market Trials testing efforts

• January report to include system update and impacts to Market Trials Structured Testing Approach

29

Market Participant Milestones

30

Southwest Power Pool Regional State Committee, Board of Directors/Members Committee &

Regional Entity Trustees Future Meeting Dates & Locations

** BOD December 11 Dallas

2013 RET/RSC/BOD January 28-29 New Orleans RET/RSC/BOD April 29-30 Kansas City *BOD June 10-11 Little Rock RET/RSC/BOD July 29-30 Denver RET/RSC/BOD October 28-29 Little Rock (Annual Meeting of Members) ** BOD December 10 Dallas

2014

RET/RSC/BOD January 27-28 Austin RET/RSC/BOD April 28-29 Oklahoma City *BOD June _____ Little Rock RET/RSC/BOD July 28-29 Omaha RET/RSC/BOD October 27-28 Little Rock (Annual Meeting of Members) ** BOD December 9 Dallas

The RET/RSC/BOD meetings are Mon/Tues with the RET meeting on Monday morning, the RSC meeting on Monday afternoon, the BOD/Members Committee meeting on Tuesday. * The June BOD meeting is for educational purposes. There will be no RSC of RET meetings in conjunction with this meeting. ** The December BOD meeting is intended to be a one day in and out meeting for administrative purposes. There will be no RSC or RET meetings in conjunction with this meeting.

MINUTES NO. 55

Southwest Power Pool ANNUAL MEETING OF MEMBERS

Southwest Power Pool Corporate Campus, Little Rock, AR

October 30, 2012

Agenda Item 1 – Administrative Items SPP Board of Directors Chair, Mr. Jim Eckelberger, called the meeting to order at 8:00 a.m. There were 114 people in attendance either in person or via phone representing 32 members (Attendance List – Attachment 1). Mr. Nick Brown reported proxies (Proxies – Attachment 2). Mr. Eckelberger referred to the Annual Meeting of Members minutes from October 25, 2011 (Minutes 10/25/11 – Attachment 3). The minutes were approved by acclamation. Agenda Item 2 – Corporate Governance Committee Report Mr. Nick Brown presented the Corporate Governance Committee report (CGC Report – Attachment 4). Mr. Brown stated that the Committee is responsible for nominating candidates to the Membership for 3-year terms for the Board of Directors, Members Committee, and the Regional Entity Trustees. Nominations for the Members Committee were also entertained from the floor. Hearing none, the Membership was asked to vote for the following nominees to fill the positions with terms commencing January 1, 2013:

Board of Directors: Jim Eckelberger Harry Skilton Members Committee (sector): Mike Deggendorf (IOU)

Gary Roulet (Cooperatives) Mike Wise (Cooperatives) Kevin Smith (IPPs/Marketers) Tom Kent (State/Federal) Regional Entity Trustees: Dave Christiano

All nominees were elected. In addition, Kevin Smith (Tenaska) was nominated and elected to fill a current vacancy for the IPP/Marketers sector representative. His term will start immediately and expire at the end of 2012. Mr. Brown noted that the CGC is responsible for reviewing Board compensation. The Corporate Governance Committee at Its October 25, 2011 meeting approved that Directors should be compensated when they are not able to attend a live meeting, but otherwise prepared to participate. A fee of $1,500 in this instance was determined as reasonable. Mr. Brown requested approval of the compensation revision. Mr. Rob Janssen moved to approve as presented; Mr. Dave Osborne (proxy for Ms. Cindy Holman, OMPA) seconded the motion. The motion was unanimously approved. Agenda Item 3 – President’s Report Mr. Nick Brown provided the President’s Report (President’s Report – Attachment 5). Mr. Brown welcomed everyone to the new SPP Corporate Campus. SPP moved into the new facility in mid-July with a very smooth migration over one weekend. Mr. Brown said that he was proud to announce that the facility was completed on schedule and at 5% under budget. Mr. Brown provided information regarding the Integrated Marketplace initiative, which is currently on schedule and on budget. The program is being monitored utilizing an outside consultant and SPP’s Internal Audit staff, all reporting directly to Mr. Brown. The program is comprised of three legs: Market

Participant Readiness, SPP Staff Readiness, and Systems. The Systems leg is currently in orange status, but SPP is working with the vendor at issue (Alstom) to address delays. Mr. Brown reported that SPP is currently 4.3% below the 2012 Budget expects to end the year much the same. He also reported that there will be a budget increase in 2013 with a 31.5¢ Administration Fee. This is due in part to the loss of the revenues from the ICT and ITO contract services. Even with the fee increase, the cost to benefit ratio for SPP is still 10 to 1. Mr. Brown voiced concern regarding the focus on compliance with standards rather than the rewriting of standards. He asked that the members provide more rigor in the effort to provide clarity to help improve reliability standards. He pointed out that it is taking an inordinate amount of time to rewrite standards. He asked to please not let perfection stand in the way of getting standards passed. Mr. Brown announced that the SPP Stakeholder Survey was about to be distributed and will be a focus at the December meeting. SPP needs member participation. Historically the Staff Performance Compensation was attached to the Stakeholder Survey. This year SPP is using a new approach for this component by surveying the Members Committee since this group is more engaged in the big picture. Mr. Brown called attention to the fact that Mr. Mel Perkins will retire from the Members Committee at the end of the year after many years of service. A resolution was read and presented thanking Mr. Perkins for his many efforts on behalf of SPP (Perkins Resolution – Attachment 6). Mr. Brown then called on Mr. Carl Monroe to review the SPP Metrics report. Adjournment With no further business, Mr. Eckelberger adjourned the Annual Meeting of Members at 8:30 a.m.

Stacy Duckett, Corporate Secretary

1

Subject: FW: SPP/Notice of Elections - October 30, 2012

From: Deggendorf Michael [mailto:[email protected]] Sent: Thursday, October 25, 2012 5:41 PM To: Stacy Duckett Subject: Re: SPP/Notice of Elections ‐ October 30, 2012 I am giving my proxy for the upcoming meeting to Scott Heidtbrink. Thanks Stacy Thanks, Mike

1

Subject: FW: Members Meeting October 30

From: Cindy Holman [mailto:[email protected]] Sent: Tuesday, September 18, 2012 11:30 AM To: Stacy Duckett Cc: Osburn, David; Cheryl Robertson Subject: RE: Members Meeting October 30 Yes, he does have my proxy for the Annual Meeting of Members and Members Committee. Thanks. Cindy

From: Stacy Duckett [mailto:[email protected]] Sent: Tuesday, September 18, 2012 11:26 AM To: Cindy Holman Cc: Dave Osburn; Cheryl Robertson Subject: RE: Members Meeting October 30 Cindy – This is sufficient with one clarification – does he have your proxy for the Annual Meeting of Members (thus, elections) and the Members Committee? Thanks and have a great trip – Stacy From: Cindy Holman [mailto:[email protected]] Sent: Tuesday, September 18, 2012 8:56 AM To: Stacy Duckett Cc: Osburn, David Subject: Members Meeting October 30 Stacy, as I mentioned earlier, I will be out of the country for this meeting and Dave Osburn will be attending the Members meeting on my behalf. Will you need anything else from me in order for Dave to have my proxy? Thanks. Cindy Holman General Manager, OMPA P O Box 1960 Edmond, OK 73083-1960 2701 W I-35 Frontage Road Edmond, OK 73013 405-359-2533 Direct Dial 405-471-2734 Cell Phone

1

Subject: SPP October 29 & 30

From: LABS, CHRISTI A [mailto:[email protected]] Sent: Tuesday, October 16, 2012 10:57 AM To: Cheryl Robertson Cc: Doghman, Mohammad Subject: SPP October 29 & 30 Cheryl – Jennifer St. Clair asked that Mo send you an email confirming that Jim Foley will be attending the SPP meeting on October 29th & 30th for Mo. Mo is traveling out of the country at this time so I hope an email from me will be sufficient I have also copied Mo so he is aware that I have sent the email. Mo is unable to attend the SPP meeting on October 29th & 30th, Jim Foley will be attending in Mo’s place. If you need anything further please let me know. Thanks,

Christi Labs Executive Administrative Assistant Omaha Public Power District 444 South 16th Street Mall, Omaha, NE 68102 402-636-3212 [email protected]

1

Subject: FW: SPP Annual Meeting

From: Lowry, Stuart [mailto:[email protected]] Sent: Tuesday, October 23, 2012 11:20 AM To: Stacy Duckett Cc: Cheryl Robertson; Williams, Noman; Hestermann, Thomas (Tom) Subject: SPP Annual Meeting Stacy, I would like to give my proxy for the SPP Annual Meeting next week to Noman Williams. If Noman is for any reason unable to serve, I would like to designate Tom Hesterman as the Sunflower voting delegate. Please let me know if you have questions or if further action is required. Thanks. Stuart S. Lowry President and CEO Sunflower Electric Power Corporation

MINUTES NO. 54

Southwest Power Pool ANNUAL MEETING OF MEMBERS

Eldorado Hotel & Spa, Santa Fe, NM

October 25, 2011

Agenda Item 1 – Administrative Items SPP Board of Directors Chair, Mr. Jim Eckelberger, called the meeting to order at 8:00 a.m. There were 106 people in attendance representing 31 members (Attendance List – Attachment 1). Mr. Nick Brown reported proxies (Proxies – Attachment 2). Mr. Eckelberger asked for a motion to approve the Annual Meeting of Members minutes from October 26, 2010 and the Special Meeting of Members on January 25, 2011 (Minutes 10/26/10 and 1/25/11 – Attachment 3). Mr. Ricky Bittle moved to approve the minutes as submitted; Ms. Cindy Holman seconded the motion. The minutes were unanimously approved. Agenda Item 2 – Corporate Governance Committee Report Mr. Nick Brown presented the Corporate Governance Committee report (CGC Report – Attachment 4). Mr. Brown stated that the Committee is responsible for nominating candidates for the Board of Directors, Members Committee, and the Regional Entity Trustees to the Membership for 3-year terms. Nominations for the Members Committee were also entertained from the floor. Hearing none, the Membership was asked to vote for the following nominees to fill the positions with terms commencing January 1, 2012:

Board of Directors: Larry Altenbaumer Josh Martin Members Committee (sector): Mel Perkins (IOU)

Steve Parr (Cooperatives) Cindy Holman (Municipals) Brett Kruse (IPPs/Marketers)

Mo Doghman (State/Federal) Regional Entity Trustees: Gerry Burrows

All nominees were elected. One expiring position on the Members Committee will remain vacant as there are no members in the sector at this time: Public Interest/Alternative Power. In addition, Tom Kent (NPPD) was elected to fill a current vacancy for a State/Federal Power Agencies sector representative. Mr. Kent’s term will start immediately and expires at the end of 2012. Agenda Item 3 – 2011 Overview/2012 Outlook Mr. Nick Brown provided the 2011 Overview/2012 Outlook for SPP (President’s Report – Attachment 5). Mr. Brown stated that 2011 had been a most unusual year listing the following events:

February – Extreme cold affected nine plants totaling 3200 MW and taxed operating reserve March – Wild fires resulting in multiple systems out for days April – Storms in Arkansas with multiple system outages, 500 kV out for 58 days May 22 – Tornado in Joplin, 250 MW load lost June – River flooding, resulting in plants and system outages causing much daily coordination June 19 and 20 – Storms with significant damage to 115, 230, and 345 kV lines

August 2 – Peak demand, 54,949 MW, 13 of 16 Balancing Authorities over 100 degrees and several near 110 degrees

In all this, Mr. Brown stated that the SPP footprint was able to manage well. Other events included:

• FERC Order 1000 – Issues causing concern are the removal of the right of first refusal and interregional cost allocation.

• Entergy/MISO Proposal – SPP continues to feel that it is the better choice. • EPA Rules – SPP has written two letters copying the US Congressional delegations and the

ISO/RTO continue to propose rules. The ISO/RTO document is posted on SPP’s website for review. All are encouraged to continue expressing concern and to provide feedback.

• OPPD possible withdrawal resulted in a new process, which was successful. Administrative issues include the new campus, which is on schedule and on budget. Regarding the Integrated Marketplace, all critical path milestones through go live are currently green. Mr. Brown expressed thanks to PJM and ERCOT for providing help, having both implemented Day-2 Markets. Mr. Trip Doggett’s help with interdependencies was much appreciated. Tariff language for the Integrated Marketplace is expected to be presented at the January Board meeting. Stressing the fact that SPP is relationship based/member driven, Mr. Brown recognized Mr. Darrell Dorsey and Mr. Gary Voigt for their work with SPP. Mr. Dorsey serves on the Human Resources Committee and will be retiring next April; Mr. Voigt served in the past as Chairman of the Board of Directors, on the Members Committee and until his recent retirement on the Finance Committee. Mr. Brown stated that the Customer Satisfaction Surveys will be distributed soon and stressed that SPP values everyone’s input. Historically the level of participation has been very high. Ms. Stacy Duckett provided an update on withdrawal obligations associated with regional transmission cost allocation (Withdrawal Obligations – Attachment 6). The Strategic Planning Committee directed Staff to research the issue. The Corporate Governance Committee has considered various drafts and proposals, held workshops and will provide modifications to the Board in January 2012. Mr. Eckelberger announced that the Corporate Metrics would be reviewed at the December 13 Board of Directors meeting. Adjournment With no further business, Mr. Eckelberger adjourned the Annual Meeting of Members at 8:30 a.m.

Stacy Duckett, Corporate Secretary

Southwest Power Pool, Inc. CORPORATE GOVERNANCE COMMITTEE

Recommendation to SPP Membership October 30, 2012

NOMINATIONS TO FILL EXPIRING TERMS AND ONE VACANCY

Background Representatives on the Board of Directors, Members Committee and Regional Entity Trustees are elected by the Membership to serve three-year terms. Analysis The Corporate Governance Committee is responsible for nominating candidates for the Board of Directors, Members Committee, and Regional Entity Trustees to the Membership for consideration and election at the Annual Meeting of Members. The following are nominated for three-year terms to commence January 1, 2013: Board of Directors: Jim Eckelberger Harry Skilton Members Committee (sector): Mike Deggendorf (IOU) Gary Roulet (Cooperatives)

Mike Wise (Cooperatives) Kevin Smith (IPPs/Marketers)

Tom Kent (State/Federal) Regional Entity Trustees: Dave Christiano Other nominations for the Members Committee may be made from the floor. In addition to the nominations noted above, Kevin Smith (Tenaska) is nominated to fill a current vacancy for the IPP/Marketers sector representative. If elected, his term will start immediately and expire at the end of 2012. Action Requested Conduct of the elections.

Approved Corporate Governance Committee August 30, 2012

October 2012

SPP BOARD OF DIRECTORS

TERM EXPIRES Larry Altenbaumer 2014

Phyllis Bernard 2013

Julian Brix 2013

Nick Brown N/A

Jim Eckelberger 2012

Josh Martin 2014

Harry Skilton 2012

Class of 2012 Jim Eckelberger Harry Skilton

Class of 2013 Phyllis Bernard Julian Brix

Class of 2014 Josh Martin Larry Altenbaumer

October 2012

REGIONAL ENTITY TRUSTEES

TERM EXPIRES Gerry Burrows 2014

Dave Christiano 2012

John Meyer 2013

Class of 2012 Dave Christiano

Class of 2013 John Meyer

Class of 2014 Gerry Burrows

October 2012

SPP MEMBERS COMMITTEE

SECTOR COMPANY TERM EXPIRESInvestor Owned Utilities Kelly Harrison Westar 2013

Mel Perkins OG+E 2014

Mike Deggendorf KCPL 2012

Stuart Solomon AEP 2013

Cooperatives Steve Parr KEPCo 2014

Gary Roulet WFEC 2012

Noman Williams Sunflower 2013

Mike Wise GSEC 2012

Municipals Jeff Knottek City Utilities of

Springfield 2013

Cindy Holman OMPA 2014

IPPs/Marketers Kevin Smith Tenaska 2012

Rob Janssen Dogwood 2013

Brett Kruse Calpine 2014

State/Federal Agencies Tom Kent NPPD 2012

Mo Doghman OPPD 2014

Large Retail Customer vacant 2014

Small Retail Customer vacant 2013

Public Interest/ Alternative Power

vacant 2014

vacant 2012

Class of 2012 Mike Deggendorf Gary Roulet Mike Wise Kevin Smith Tom Kent Publ Int/Alt Pwr (vacant)

Class of 2013 Kelly Harrison Stuart Solomon Noman Williams Jeff Knottek Rob Janssen Sm. Retail (vacant)

Class of 2014 Mel Perkins Steve Parr Cindy Holman Mo Doghman Brett Kruse Lg. Retail (vacant) Publ Int/Alt Pwr (vacant)

September 2009


ANNUAL MEETING OF MEMBERS October 30, 2012

Ballot for

SPP Annual Elections SPP BOARD OF DIRECTORS:

(All members should vote for 2 nominees)

Recommended by Corporate Governance Committee: For Against

Jim Eckelberger

Harry Skilton

SPP MEMBERS COMMITTEE:

Each Member should vote for the number of nominees allocated for each sector.

Investor Owned Utilities: (All members should vote for 1 nominee)

Recommended by Corporate Governance Committee:

For Against Mike Deggendorf (KCPL)

Additional Nominees: ____________________________________ ____________________________________

Cooperatives: (All members should vote for 2 nominees) Recommended by Corporate Governance Committee:

For Against Gary Roulet (WFEC)

Mike Wise (GSEC)

Additional Nominees: ____________________________________ ____________________________________

Ballot for SPP Membership October 30, 2012

IPPs/Marketers: (All members should vote for 1 nominee)


Kevin Smith (Tenaska) to fill expiring term

Kevin Smith (Tenaska) new 3-year term

Additional Nominees:

____________________________________ ____________________________________

State/Federal Agencies: (All members should vote for 1 nominee)


Tom Kent (NPPD)

Additional Nominees:

____________________________________ ____________________________________

Public Interest/Alternative Power: There are currently no members in this sector.

SPP REGIONAL ENTITY TRUSTEES:

(All members should vote for 1 nominee)

Recommended by Corporate Governance Committee:

For Against Dave Christiano

MEMBER: _________________________________ REPRESENTATIVE’S SIGNATURE: ________________________________

Southwest Power Pool, Inc. CORPORATE GOVERNANCE COMMITTEE

Recommendation to the Membership October 30, 2012

Board of Directors Compensation

Organizational Roster The following persons are members of the Corporate Governance Committee:

Nick Brown, Chair Jim Eckelberger Cindy Holman Robert Janssen John McClure Stephen Parr Mel Perkins Stacy Duckett

SPP Director OMPA Dogwood Energy NPPD KEPCo OG+E Staff Secretary

Background The Corporate Governance Committee is responsible for reviewing Director compensation and recommending any changes to the Membership for consideration and vote. The current Fee schedule is as follows:

Board of Directors Compensation Annual Retainer, Chair $20,000Annual Retainer 15,000Meeting, Chair 3,500Meeting 3000Teleconference 500Committee Meeting, Chair 2500Committee Meeting 2000MOPC Liaison 2000Committee Teleconference 500Meeting Observer 1,500Teleconference Observer 250Other 1,500Other Teleconference 250

Analysis At the October 25, 2011 meeting, the staff suggested and the Committee approved an additional fee that would compensate Directors when they are not able to attend a live meeting, but otherwise prepared to participate. A fee of $1,500 in this instance was determined as reasonable.

Recommendation The Corporate Governance Committee recommends that the Board of Directors are compensated in the amount of $1,500 versus the current $500 teleconference fee for attendance when they have prepared for a live meeting but must attend via teleconference.

Approved: Corporate Governance Committee October 25, 2011


To: SPP Officers / Directors / ManagersFrom: Sheri Parish / Cindy GoodwinDate: October 22, 2012RE: September 2012 Financials

Page1). Financial Commentary: Full Year Actual to Budget Variances 1

2). 3

3). Income Statement Actual Results Overview: Current Month Actual vs. Forecast, YTD Actual vs Budget, YTD Actual vs. Prior 4

4). Balance Sheet: Current Month vs. Ending Prior Year 5

5). 6

Memorandum

Financial Forecast Overview: Full Year Actuals by Month vs. Budget vs. Prior Year

Facility and Integrated Marketplace Projects: Overview of

Attached are the September 2012 monthly financial reports.

) 6

6). 9

7). Headcount Analysis: Current Month - Actual vs. Budget and Full 11

8). Job Tracker: List of Current Open Positions as Tracked by Human Resources

12

current status of projects

Capital Projects Summary: Project to Date and Current Year/Future Projections Compared to Budget

2012 FY 2012 FY Fav/(Unfav)Forecast Budget Variance

Revenues $148,437 $146,415 $2,022 1.4%Expenses 145,418 151,953 6,536 4.3%

Net Income/(Loss) $3,019 ($5,539) $8,558 154.5%


Tariff Administration Service $92,030 $90,131 $1,899 2.1%Fees & Assessments 27,085 26,909 176 0.7%Contract Services & Misc Income 29,322 29,375 (53) (0.2%)

Total Revenue $148,437 $146,415 $2,022 1.4%

9

10

2012 Financial CommentaryAs of September 2012

(in thousands)

Summary

Revenue

Revenue exceeds budget for Tariff Administration Services due to 2011 NITS load exceeding 2012 budget ($1.9M), which is basedon prior year.

FERC assessments currently exceed budget due to adjustments for recovery of prior year under collections ($2.2M). The favorable variance is partially offset by Regional Entity revenues which trail budget due to lower audit and project consulting expenditures to date ($2.1M). Reductions in RE expenditures are mainly associated with the violation caseload project and the BES definition and expenditures are mainly associated with the violation caseload project, and the BES definition and exception process.

Generally, Miscellaneous Income consists primarily of accrued revenue associated with billable resource time related to various studies. Billing associated with studies has been lower than anticipated year to date, contributing to the overall unfavorable variance ($1.7M). SPP received a $1.0M settlement for a FERC penalty charged against Constellation Energy Group which partially offsets the unfavorable variance to budget for Miscellaneous Income. Other miscellaneous revenues for ARS reimbursements are not budgeted and therefore also contribute to the favorable offset ($500K).

Page 1 of 12

2012 Financial CommentaryAs of September 2012

(in thousands)


Salary & Benefits $71,913 $72,222 $309 0.4%Assessments & Fees 14,977 15,410 433 (2.8%)Communications & Maintenance 12,421 13,904 1,483 10.7%Outside Services 14,465 18,700 4,236 22.7%Depreciation & Amortization 16,323 17,317 994 5.7%Other Expenses 15,319 14,401 (919) (6.4%)

Total Expense $145,418 $151,953 $6,536 4.3%

Expense

Although Salaries & Benefits are forecasted to be $309K favorable to budget, significant variances exist for both salary expenses(favorable $1.1M) and benefits (unfavorable $975K). The favorable variance in Salary expense ($1.1M) is a result of the actual vacancy rate exceeding the rate assumed in the budget. Continuing Education expenses continue to be favorable to budget ($217K).

Primary contributors to the unfavorable benefits variance are as follows:

● $613K - Increases in SPP self-funded health care plan expenses● $294K - Increases to the pension funding accrual● $ 68K - Miscellaneous benefit account fluctuations

The accrual for FERC Assessments & Fees was adjusted in June after receiving the 2011 FERC invoice, which was lower than what had been expensed (accrued) in the previous year. This causes a p ( ) p yfavorable variance in 2012 since the over accrual results in a reduction to current year expense.

Communications and Maintenance are favorable to budget due to the following:

● Manufacturer supply shortages of computer equipment earlier in the year have resulted in lower than expected new equipment maintenance contracts

● Favorable pricing negotiations of software maintenance and conferencing rates has resulted in lower than expected expense

● Lower than expected YTD charges for member circuits

Outside Services are favorable to budget due to the following:

● Lower than expected usage of contractors for Regional Entity audit work, legal and regulatory engagements, and RTO Engineering studies

● Reduction in consulting expenses for lower prioritized projects due to increased prioritization of all Marketplace activities for current staff

● Delay in implementation of after-hours monitoring of IT Command Center

The favorable variances mentioned above are partially offset by unbudgeted expenditures associated with the Entergy/MISO cost analysis study.

The budget assumed depreciation on the new Ops Center would begin in April. Actual depreciation did not commence until July, resulting in a favorable variance to budget in Depreciation expense.

Other Expenses, which is composed of interest income & expense, miscellaneous income & expense, and various valuation adjustments, are unfavorable to budget largely due to our budget assumptions for capitalized interest being higher than what has occurred to date. Capitalized Interest is impacted by the timing and amount of capital expenditures on significant projects.

Page 2 of 12

Actual Actual Actual Actual Actual Actual Actual Actual Actual FCST FCST FCST FY 2012 FY 2012 Variance VarianceJan-12 Feb-12 Mar-12 Apr-12 May-12 Jun-12 Jul-12 Aug-12 Sep-12 Oct-12 Nov-12 Dec-12 Forecast Budget Fav/(Unfav) Fav/(Unfav)

IncomeTariff Administration Service $7,844 $7,340 $7,716 $7,616 $7,763 $7,543 $7,808 $7,768 $7,535 $7,779 $7,540 $7,778 $92,030 $90,131 $1,899 $71,702 $20,327Fees & Assessments 2,519 2,122 1,964 1,903 1,960 2,240 2,507 2,834 2,316 2,240 2,240 2,240 27,085 26,909 176 24,123 2,962Contract Services Revenue 2,244 2,427 2,169 2,188 2,151 2,315 2,265 2,199 1,558 1,515 1,515 1,515 24,061 23,759 302 26,549 (2,488)Miscellaneous Income 506 530 1,350 519 280 528 243 (498) 554 392 392 467 5,261 5,616 (355) 6,566 (1,305)

Total Income 13,113 12,419 13,199 12,226 12,153 12,626 12,823 12,303 11,964 11,926 11,687 12,000 148,437 146,415 2,022 128,940 19,497

ExpenseSalary 3,872 3,933 3,947 3,984 3,877 4,097 4,112 4,158 4,245 4,272 4,344 4,378 49,222 50,289 1,068 44,471 (4,750)Benefits & Taxes 1,654 2,015 1,747 1,784 1,730 1,920 1,932 1,779 1,919 1,893 1,885 1,932 22,190 21,215 (975) 19,528 (2,663)Continuing Education 34 15 36 68 33 27 37 75 42 50 35 49 500 717 217 515 15

Salary & Benefits 5,560 5,963 5,730 5,836 5,640 6,044 6,081 6,012 6,206 6,215 6,265 6,360 71,913 72,222 309 64,514 (7,398)Employee Travel 105 154 173 193 236 222 216 241 198 319 209 162 2,428 3,002 574 1,655 (773)Administrative 303 270 347 374 324 300 363 257 552 324 263 265 3,941 4,212 271 3,003 (938)Assessments & Fees 1,284 1,284 1,284 1,284 1,284 697 1,310 1,310 1,310 1,310 1,310 1,310 14,977 15,410 433 16,639 1,662Meetings 53 70 93 119 80 53 64 99 62 202 89 112 1,095 1,445 350 838 (258)Communications 294 379 404 374 351 380 377 354 264 347 347 347 4,219 4,592 373 3,204 (1,015)Leases 158 151 158 153 155 151 381 62 86 68 68 68 1,660 1,631 (28) 1,624 (36)Maintenance 600 629 633 667 532 673 713 767 730 750 727 780 8,202 9,312 1,110 7,308 (894)Services 935 1,404 929 1,110 1,141 1,156 1,399 895 1,415 1,289 1,477 1,315 14,465 18,700 4,236 15,813 1,348Regional State Committee 41 77 53 38 21 72 51 21 14 23 23 83 516 394 (122) 311 (205)Depreciation & Amortizatio 1,173 1,162 1,117 1,008 1,289 1,058 1,561 1,674 1,565 1,617 1,613 1,487 16,323 17,317 994 13,107 (3,216)

FY 2011 Actuals

Southwest Power PoolForecast Overview

As of September 2012CONSOLIDATED TOTAL

(in thousands)(Unaudited)

ep ec a o & o a o , 73 , 6 , 7 ,008 , 89 ,058 ,56 ,67 ,565 ,6 7 ,6 3 , 87 6,3 3 7,3 7 99 3, 07 (3, 6)Total Expense 10,505 11,543 10,922 11,158 11,052 10,807 12,516 11,692 12,402 12,463 12,390 12,288 139,738 148,237 8,499 128,015 (11,723)

Other Income/(Expense)Other Income / Expense 14 43 3 (2) (83) 46 1 14 27 - - - 63 - 63 (3,998) 4,060Interest Income 29 25 19 5 (24) 27 17 18 19 - - - 133 - 133 157 (24)Interest Expense (664) (685) (702) (678) (677) (815) (791) (845) (749) (904) (904) (903) (9,317) (7,945) (1,372) (8,250) 1,067Capitalized Interest - - 995 - - 780 - - 539 - - 680 2,994 4,229 (1,235) 1,943 (1,051)Swap Valuation - - 292 - - 3 - - 153 - - - 448 - 448 183 (265)

Net Other Income (Expense) (621) (617) 607 (675) (784) 40 (773) (813) (11) (904) (904) (223) (5,680) (3,716) (1,964) (9,965) 3,788

Net Income (Loss) $1,987 $260 $2,884 $392 $317 $1,859 ($466) ($203) ($449) ($1,442) ($1,608) ($512) $3,019 ($5,539) $8,558 ($9,040) $12,0595,379,040

2012 Headcount Actual/Fcst 518 524 526 531 528 537 546 554 555 568 579 581 581 2012 Headcount Budget 548 561 575 579 581 585 588 588 590 590 590 590 590

Over / (Under) Budget (30) (37) (49) (48) (53) (48) (42) (34) (35) (22) (11) (9) (9)

Page 3 of 12

YTD YTD YTD YTDSep-12 Sep-12 Variance Sep-12 Sep-12 Variance Sep-12 Sep-2011 VarianceActual Forecast Fav/(Unfav) Actual Budget Fav/(Unfav) Current Year Prior Year Fav/(Unfav)

IncomeTariff Administration Service $7,535 $7,535 $0 $68,933 $67,598 $1,335 $68,933 $53,575 $15,358Fees & Assessments 2,316 2,390 (74) 20,365 20,276 89 20,365 18,725 1,640Contract Services Revenue 1,558 1,515 43 19,516 19,214 303 19,516 19,726 (210)Miscellaneous Income 554 550 5 4,012 4,291 (280) 4,012 4,842 (830)

Total Income 11,964 11,990 (26) 112,826 111,379 1,446 112,826 96,868 15,958

ExpenseSalary 4,245 4,263 17 36,227 37,461 1,234 36,227 32,716 (3,512)Benefits & Taxes 1,919 1,853 (66) 16,480 15,865 (615) 16,480 14,347 (2,133)Continuing Education 42 144 102 366 581 216 366 419 53

Salary & Benefits 6,206 6,260 54 53,073 53,907 834 53,073 47,482 (5,592)Employee Travel 198 364 165 1,738 2,318 580 1,738 1,245 (493)Administrative 552 568 17 3,089 3,074 (14) 3,089 2,317 (772)Assessments & Fees 1,310 1,310 - 11,048 11,558 510 11,048 12,464 1,416Meetings 62 143 81 693 1,057 363 693 599 (94)

Southwest Power PoolActual Results Overview

For the Month Ending September 30, 2012(in thousands)

Current Month Compared to Forecast

Communications 264 352 89 3,177 3,544 368 3,177 2,366 (810)Leases 86 78 (8) 1,455 1,416 (39) 1,455 1,386 (69)Maintenance 730 710 (20) 5,945 6,822 876 5,945 5,273 (673)Services 1,415 1,576 160 10,384 14,382 3,998 10,384 10,460 76Regional State Committee 14 23 9 388 266 (122) 388 122 (266)Depreciation & Amortization 1,565 1,635 70 11,606 12,600 994 11,606 9,866 (1,740)

Total Expense 12,402 13,018 616 102,596 110,945 8,349 102,596 93,580 (9,016)

Other Income/(Expense)Other Income / Expense 27 - 27 63 - 63 63 (110) 172Interest Income 19 - 19 133 - 133 133 85 48Interest Expense (749) (781) 32 (6,606) (2,539) (4,067) (6,606) (6,091) (515)Capitalized Interest 539 1,035 496 2,314 - 2,314 2,314 1,871 (443)Swap Valuation 153 - 153 448 - 448 448 (37) 485

Net Other Income (Expense) (11) 254 726 (3,649) (2,539) (1,110) (3,649) (4,282) (253)

Net Income (Loss) ($449) ($774) $325 $6,580 ($2,105) $8,685 $6,580 ($994) $7,575

Page 4 of 12

9/30/2012 12/31/2011 VarianceASSETS Current Assets Cash & Equivalents $55,291 $73,763 ($18,472) Restricted Cash Deposits 42,080 34,904 7,176 Accounts Receivable (net) 18,335 15,901 2,434 Other Current Assets 9,147 6,636 2,511 Total Current Assets 124,852 131,204 (6,351)

Total Fixed Assets 160,781 112,188 48,593 Total Other Assets 1,853 2,141 (288) Investments 897 775 122TOTAL ASSETS $288,383 $246,307 $42,076

LIABILITIES & EQUITY Liabilities Current Liabilities Accounts Payable (net) $8,070 $17,816 ($9,746) Customer Deposits 43,467 34,903 8,564 Current Maturities of LT Debt 12,322 11,206 1,116 Other Current Liabilities 19 790 25 741 (5 951)

Southwest Power PoolBalance Sheet

As of September 30, 2012(in thousands)

Other Current Liabilities 19,790 25,741 (5,951) Deferred Revenue 7,096 7,450 (354) Total Current Liabilites 90,745 97,117 (6,372) Long Term Liabilities US Bank Floating Senior Note - 2014 6,875 11,000 (4,125) US Bank 5.45% Senior Notes - 2016 18,000 21,000 (3,000) US Bank Maumelle Mortgage - 2027 3,804 3,958 (154) Campus 4.82% Senior Notes - 2042 64,259 65,000 (740) Integrated Marketplace 3.55% Senior Note - 2024 70,000 70,000 0 Senior Notes - 2024 50,000 0 50,000 Other Long Term Liabilities 7,542 7,655 (113) Total Long Term Liabilities 220,480 178,612 41,867 Net Income 6,580 (9,040) 15,620 Members' Equity (29,422) (20,382) (9,040) Total Members' Equity (22,842) (29,422) 6,580

TOTAL LIABILITIES & EQUITY $288,383 $246,307 $42,075

Page 5 of 12

CapitalizedExpense *

Current Projections $104,476Approved Target $105,640

Over/(Under) ($1,164)

2012 Project CommentaryAs of September 2012

(in thousands)


The IM project is currently forecasted at $1.2M less than the board approved target of $105.6M.This is a favorable movement of approximately $571K from the August 31st report. Significantchanges from the prior month include the following:

● Recognized savings for IT contracts negotiated lower than expected - $850K

● Removed training costs provided by Structure - $84K

● Removed PCI costs inappropriately included in CBA - $38K

● Addition to Accenture contract for additional resources needed - $136K

● Addition of PRT contract to complete Neural Electric Load Forecaster - $205K

● Addition of CMS unbudgeted development costs - $60K

Page 6 of 12


(in thousands)

CapitalizedExpense

Current Projections $83,983Approved Target $88,553

Over/(Under) ($4,570)

Corporate Campus Construction and Migration

The facility project remains on target and under budget. Costs for data center hardware were significantly lower than original projections. The overall project is projected to be $4.6 MM under budget.

● The contractor has maintanied a presence onsite through October 5th. Beyond this date, waranty and post-occupancy enhancements will be coordinated with Nabholz Client Services.

● Items below are the only outstanding issues to be completed outside of the project closure:

1) Owner training for building management systems (currently 95% complete)2) Resealing of parking deck joints to eliminate leaks

● Future work associated with the migration project will be performed by the contractor and SPP facilities team. The activities below are now considered out-of-scope, although funding will be covered under the migration budget contingency.

1) Enhancements to audio solutions in the auditorium and conference rooms A, B and C2) Remaining punch list items for furniture installations3) Installation of case goods for third and forth floor copy centers4) Additional seating and tables for conference rooms5) Mirrors and countertops in restrooms6) Enhancements to Central Energy Plant

● SPP Project Management Office (PMO) will schedule a series of "lessons learned" exercises during October, with the results fully documented by month-end. External contractors will participate.

● The Project Manager will work with corporate management to archive the extensive set of records associated with the project, also to be completed by month-end.

Page 7 of 12


(in thousands)

Actual Estimate toBudget Item SPP Approved Projection Expenditures CompletionConstruction Project

Land 4,574$ 4,566$ 4,566$ -$ Ops/Data Center 24,896$ 22,477$ 22,477$ -$

Construction 23,184$ 20,736$ 20,736$ -$ Professional 1,712$ 1,741$ 1,741$ -$

Office Building 32,464$ 34,852$ 30,118$ 4,734$ Construction 29,687$ 31,549$ 27,081$ 4,468$ Professional 2,777$ 3,303$ 3,037$ 266$

Totals - Construction 61,933$ 61,895$ 57,161$ 4,734$

Migration ProjectFurnishings & Decommission 11,550$ 9,253$ 8,933$ 320$ Data Center Hardware 4,969$ 3,802$ 3,784$ 18$ Ops Center HW, AV & Desktop 1,491$ 1,183$ 1,022$ 161$ Network, Telecom & Security 7,500$ 7,850$ 7,795$ 55$ Contingency (5%) 1,110$ -$ -$ -$ Totals - Migration 26,620$ 22,088$ 21,534$ 554$

Total Project (Capitalized) 88,553$ 83,983$ 78,695$ 5,288$

Budget Analysis of the Facilities ProgramAs of October 8, 2012

Budgets

Decommission Plaza West Exp 2 -$ -$ 631$ -$

1 Estimates of projected work activity for Construction provided by Nabholz Construction Services.2 This expense was originally included in the capital project budget for 2012, but was actually expensed (accrued) in 2011.

Page 8 of 12

SOUTHWEST POWER POOL2012 FORECAST

PROJECT OVERVIEW, DESCRIPTIONS ANALYSIS

Prior Year(s) Q1 Q2 Q3 Q4 Total Future Total Budget Over/(Under)

Expense Actual Actual Actual Forecast 2012 Expense Project Thru 2014 Budget

PRPC Projects (in thousands)

Integrated Marketplace (Future Markets) thru 2014 $29,440 $9,161 $9,718 $10,947 $17,392 $47,219 $25,371 $102,029 $101,001 $1,028Consolidated Balancing Authority $1,263 $105 (138) $312 $148 $428 $756 $2,447 $4,639 (2,192)

Future Markets Initiatives Total $30,704 $9,267 $9,580 $11,260 $17,540 $47,646 $26,127 $104,476 $105,640 (1,164)

High Availability $2,367 - $47 $11 $580 $638 - $3,005 $5,120 (2,115)

New Facilities Construction $47,604 $3,217 $4,748 $1,598 $4,728 $14,291 - $61,895 $61,933 (38)Facility Migration $10,777 $2,768 $6,028 $1,962 $554 $11,311 - $22,088 $26,620 (4,532)

New Facility Initiatives Total $58,381 $5,984 $10,776 $3,560 $5,282 $25,602 - $83,983 $88,553 (4,570)EMS Upgrade $608 $185 $126 $75 $172 $558 - $1,166 $1,265 (100)Centralized Modeling Tool $337 $318 $546 $522 $274 $1,660 $355 $2,352 $1,863 $489EMS Enhancements-Foundation $67 $10 $15 $22 - $48 $250 $365 $469 (104)PRR Implementation Foundation $100 - - - $50 $50 $300 $450 $649 (199)Add - Remove SPP Market Entities (BAs, MPs, etc.) $31 $4 $4 $5 - $12 $125 $168 $215 (47)E-terra Vision Implementation - - - - $25 $25 $100 $125 $193 (68)Model Change Submission Tool - - - - - - - - - - Ops Automation #1 OATI - - - - $10 $10 $150 $160 $210 (50)Ops Automation #1 RTOSS-Settlements - - - - - - - - $113 (113)Ops Automation #1 DC Ties - - - - - - $200 $200 $364 (164)C bi d C l $ 800 $ 800 $ 800 Combined Cycle - - - - - - $11,800 $11,800 $11,800 - Replace OPS1 Outage Coordination Scheduler $300 $33 $33 - - $65 - $365 $133 $232

Operations Initiatives Total $1,444 $550 $724 $623 $531 $2,428 $13,280 $17,151 $17,275 (123)ITP Data Repository ** $30 - - - - - - $30 $184 (154)Project Tracking Database (TAGIT) - - - - - - - - $150 (150)Credit Process Stack List Analysis - - - $126 - $126 - $126 $295 (169)Electromagnetic Transient Program (EMTP) - - - - - - - - $80 (80)Redundant EnFuzion Node and PSSE/MUST Lock - - - - - - - - $23 (23)

Engineering Initiatives Total $30 - - $126 - $126 - $156 $732 (576)e-Tariff Phase II $383 - - - - - - $383 $950 (567)

Regulatory Initiatives Total $383 - - - - - - $383 $950 (567)SPP Budgeting & Forecasting System - - - - $40 $40 - $40 $40 -

Administration Initiatives Total - - - - $40 $40 - $40 $40 - Request Management System - - - - - - $182 $182 $273

Process Integrity Initiatives Total - - - - - - $182 $182 $273 -

Total PRPC Managed Projects $93,308 $15,801 $21,127 $15,580 $23,972 $76,480 $39,589 $209,377 $218,582 (9,115)

Page 9 of 12

SOUTHWEST POWER POOL2012 FORECAST

PROJECT OVERVIEW, DESCRIPTIONS ANALYSIS

Prior Year(s) Q1 Q2 Q3 Q4 Total Future Total Budget Over/(Under)

Expense Actual Actual Actual Forecast 2012 Expense Project Thru 2014 Budget

Non-PRPC Projects (in thousands)MOS Enhancements Foundation $120 $2 $1 - $20 $23 $800 $943 $969 (26)OATI Enhancements $196 $24 $89 $8 $78 $200 $200 $596 $537 $59

Operations Initiatives Total $316 $26 $90 $8 $98 $223 $1,000 $1,539 $1,506 $33Stochastic Modeling Tool** - - - - $100 $100 - $100 $170 (70)

Engineering Initiatives Total - - - - $100 $100 - $100 $170 (70)2012 IT Apps Foundation $73 $91 $23 $176 $193 $483 $59 $615 $421 $1942012 IT Data Management Foundation $19 $9 - - - $9 - $28 $91 (63)2012 IT Server Admin Foundation $3,200 $881 $174 $412 $71 $1,539 $3,424 $8,163 $9,493 (1,330)2012 IT Service Management Foundation $263 $92 $226 $613 $562 $1,493 $950 $2,706 $3,191 (485)2012 IT Environment Ops Foundation $13 $16 - - $15 $31 $120 $165 $336 (171)2012 IT Tele/Network/Security Foundation $326 $183 $78 $62 $118 $441 $3,001 $3,768 $4,523 (755)CIP (Ver 4) Project $35 $16 - - - $16 - $51 - $51

IT Initiatives Total $3,929 $1,287 $502 $1,263 $960 $4,012 $7,553 $15,494 $18,055 (2,561)AREVA ETS Foundation $250 - - - - - $150 $400 $475 (75)

Administration Initiatives Total $250 - - - - - $150 $400 $475 (75)

Total Non-PRPC Managed Projects $4,495 $1,313 $592 $1,271 $1,158 $4,334 $8,703 $17,533 $20,206 (2,673)

TOTAL PROJECTS $97,803 $17,114 $21,719 $16,851 $25,130 $80,815 $48,292 $226,910 $238,788 (11,788)

2012 UnbudgetedEDNA Software Replacement - $1,000 - - - $1,000 - $1,000 - $1,000Standardized Cost Estimate Reporting Template (SCERT) - - $128 $12 - $140 - $140 - $140Netezza Upgrade - - - $519 - $519 $2,400 $2,918 $2,918 - EMS Marketplace Readiness - - $154 $110 $53 $317 $361 $678 $714 (37)ICCP Architecture - - $64 $120 $108 $291 $311 $602 $665 (63)

$0 - - - - - - $0 $0 -

2012 Unbudgeted Items $0 $1,000 $346 $760 $161 $2,267 $3,071 $5,338 $4,298 $1,040

TOTAL PROJECTS INCLUDING UNBUDGETED $97,803 $18,114 $22,065 $17,611 $25,291 $83,081 $51,364 $232,248 $243,086 (10,748)

* New Facility costs include IT refresh expense which will coincide with the building move ($1.5M data center hardware/$1.9M Telecom/Network/Security - total $3.4M).** Highlighted projects are new to 2012. All other projects are carryover projects.

Page 10 of 12

Current Month Actual vs. Budget Forecast vs. BudgetActual Budget Over/(Under) FY 2012 FY 2012 Over/(Under)Sep-12 Sep-12 Budget Forecast Budget Budget

Total Administration 73 75 (2) 77 75 2

Total Process Integrity 44 46 (2) 46 46 0

Total Compliance & Corporate Affairs 34 36 (2) 36 36 0

Total SPP Regional Entity 28 32 (4) 32 32 0

Total Information Technology 135 140 (5) 138 140 (2)

Total Markets 6 6 0 6 6 0

Total Operations 151 156 (5) 155 156 (1)

Total Engineering 46 55 (9) 51 42 9

Total Contract Services 18 21 (3) 17 34 (17)

Total Regluatory Policy & General Counsel 20 23 (3) 23 23 0

TOTAL HEADCOUNT 555 590 (35) 581 590 (9)

Forecast vs. Budget

Original Budget 590

Southwest Power PoolHeadcount Analysis

As of September 30, 2012

Original Budget 590IT DBA position approved out of budget 1IT eliminated 5 Part-time Svc Desk positions, replaced with 2 full-time (3)No backfill for Ops position promotions (2)Net 7 ICT positions eliminated in Engineering (7)Out of budget overlap of Eng Budget Analyst position 1Temporary overlap of IT Budget Analyst position until mid-2013 1

Current Forecast 581

Page 11 of 12

2012 Job Tracker

Req. # Position Dept # Dept Name Status11-148 Outreach Coordinator 230 Compliance12-002 HR Generalist I 150 Human Resources12-024 Sr. Compliance Specialist 130 RE - Compliance12-025 Sr. Compliance Specialist 130 RE - Compliance12-041 Sr. Market Analyst, RT Market Policy 840 Market Operations12-047 Settlement Analyst II 160 Settlements12-048 Facilities Coordinator 150 Corporate Services12-070 Sr. Engineer 440 GI Studies12-071 Engineer II 8110 ICT Planning12-073 Part-Time Law Clerk 180 RE Enforcement12-076 IT Specialist II 510 IT Apps-Mkt & Settlements12-080 IT Specialist II 510 IT Apps-Reliability12-088 Engineer II 440 GI Studies12-090 Settlement Analyst II 160 Settlements12-094 Engineer II 420 Transmission Service Studies12-100 Engineer II 850 Modeling & Data Integrity12-103 Customer Trainer 340 Training12-104 Manager 900 Regulatory12-105 Regulatory Analyst III 900 Regulatory12-106 Sr. Engineer 900 Regulatory12-108 Supervisor, Modeling & Data Integrity 850 Modeling & Data Integrity12-109 Project Analyst II 560 Project Management12-112 Sr. Engineer 870 Operational Planning12-113 Engineer II 880 Real Time & Current Day Eng.12-114 Complance Analyst II 230 Compliance12-116 Executive Director 130 Regional Entity12-117 Engineer II 460 Economic Planning12-119 Manager, Project Management 560 Project Management

Remaining 2011 Positions in Blue: 11-xxx 2012 YTD Budgeted Positions Filled 442012 Budgeted Positions Highlighted in Grey: 12-001 thru 12-050 2012 YTD Replacement Positions Filled 44Replacement Positions Highlighted in Yellow: 12-051 thru 12-xxx 2012 YTD Total Hires 68

2011 Positions Filled in 2012 23Status Legend 2012 2011

Inactive 1 0Active, Not Posted 9 0

Active, Posted 17 1Filled 88 23

Hire LegendInternal 41 11External 43 13

08/31 Ending Active Headcount 554 Number of Internal Hires 52Resignations during August -1 Number of External Hires 56September External Hires 2

09/30 Ending Active Headcount 5552011 Open 12012 Open 25

2012 Year End Target 581

Page 12 of 12

Corporate Metrics3rd Quarter 2012

October 30, 2012

1 Congestion2 Regional Control Performance3 Transmission Utilization Proxy4 EIS Prices and Price Range5 Revenue Neutrality Uplift6 Market Liquidity

Financial Metrics

7 SPP Admin Fee performance8 Budget Performance Monitor9 Financial Settlement Index

10 Financial Disputes Index

11 Employee Turnover12 Recruiting

13 SPP Regional Entity Compliance14 IT System Performance15 Strategic Plan Progress16 Studies

Metrics Definitions

Supplement - Regulatory Activity Update & Outlook

DISCLAIMER

The data and analysis in this report are provided for informational purposes only and shall not be considered or relied upon as market advice or market settlement data. Southwest Power Pool (SPP) makes no representation or warranties of any kind, express or implied, with respect to the accuracy or adequacy of the information contained herein.

SPP shall have no liability to recipients of this information or third parties for the consequences arising from errors or discrepancies in this information, or for any claim, loss or damage of any kind or nature whatsoever arising out of or in connection with (i) the deficiency or inadequacy of this information for any purpose, whether or not known or disclosed to the authors, (ii) any error or discrepancy in this information, (iii) the use of this information, or (iv) a loss of business or other consequential loss or damage whether or not resulting from any of the foregoing.

Learning & Growth

Performance


Corporate Metrics

Table of Contents

Transmission & Market Indicators

1a. Congestion

Time in hours Jul 11 Aug 11 Sep 11 Oct 11 Nov 11 Dec 11 Jan 12 Feb 12 Mar 12 Apr 12 May 12 Jun 12 Jul 12 Aug 12 Sep 12 2009 2010 2011Prev

12 mo

Binding & Breached Time 609 650 552 627 459 613 639 666 653 631 478 585 650 720 636 519 505 555 613

Over Limit Time 160 171 178 182 87 228 146 187 288 123 215 301 493 367 344 41 82 156 247

% Tags/ Schedules Curtailed (GWh) 0.30% 0.38% 0.56% 0.46% 0.25% 0.31% 0.23% 0.26% 0.47% 0.22% 0.09% 0.13% 0.31% 0.47% 0.51% 0.41% 0.51% 0.44% 0.31%

Tra

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Monthly Average

0.00%

0.20%

0.40%

0.60%

0.80%

1.00%

1.20%

1.40%

1.60%

-

100

200

300

400

500

600

700

800

% T

ag

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Binding & Breached Time Over Limit Time % Tags/ Schedules Curtailed (GWh)

-

200

400

600

800

2009 2010 2011 Prev 12 mo

Average Monthly Binding & Breached Time (hrs)

-

50

100

150

200

250

2009 2010 2011 Prev 12 mo

Average Monthly Over Limit Time (hrs)

1b. Congestion - Curtailments

in GWh Jul 11 Aug 11 Sep 11 Oct 11 Nov 11 Dec 11 Jan 12 Feb 12 Mar 12 Apr 12 May 12 Jun 12 Jul 12 Aug 12 Sep 12 2009 2010 2011Prev

12 mo

Tag Curtailments 68.1 75.1 110.5 75.7 36.9 47.1 39.4 14.5 68.5 17.3 7.6 13.0 34.0 51.9 83.1 50 85 87 41

Market (Schedules) Curtailments 28.7 42.3 19.1 25.8 16.4 28.5 14.5 42.7 30.0 29.6 15.4 23.8 67.5 87.5 40.6 42 43 22 35

TOTAL Curtailments 96.8 117.4 129.6 101.4 53.4 75.6 53.9 57.2 98.5 46.8 23.0 36.8 101.5 139.4 123.7 92 128 109 76

Total Tags/ Schedules 32,308 30,915 23,269 22,004 21,755 24,237 23,553 21,607 21,142 21,016 24,343 27,262 32,404 29,460 24,023 22,311 24,599 24,689 24,401

% Tags/ Schedules Curtailed 0.30% 0.38% 0.56% 0.46% 0.25% 0.31% 0.23% 0.26% 0.47% 0.22% 0.09% 0.13% 0.31% 0.47% 0.51% 0.41% 0.51% 0.44% 0.31%

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0.00%

0.20%

0.40%

0.60%

0.80%

1.00%

1.20%

-

50

100

150

200

250

300

% T

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GW

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Market (Schedules) Curtailments Tag Curtailments % Tags/Schedules Curtailed

-

20

40

60

80

100

2009 2010 2011 Prev 12 mo

Tag Curtailments (GWh)

-

20

40

60

2009 2010 2011 Prev 12 mo

MarketCurtailments (GWh)

1c. Congestion - TLR / CME Time

in hours Jul 11 Aug 11 Sep 11 Oct 11 Nov 11 Dec 11 Jan 12 Feb 12 Mar 12 Apr 12 May 12 Jun 12 Jul 12 Aug 12 Sep 12 2009 2010 2011Prev

12 mo

Level 3A 519 325 425 534 439 537 629 493 621 213 199 266 251 364 443 1,293 949 517 416

Level 3B 49 44 35 27 37 34 37 29 19 8 17 19 21 27 33 179 166 46 26

Level 4 8 11 43 3 17 0 5 2 2 25 31 34 1 0 0 322 41 77 10

Level 5A 28 32 53 17 45 7 63 52 36 36 128 126 430 171 117 70 83 52 102

Level 5B 4 3 4 2 7 2 3 3 1 3 5 5 21 4 7 3 6 6 5

Total TLR Time 608 415 560 583 545 580 737 579 679 285 380 450 723 566 600 1,868 1,246 697 559

CME Time (loading >90%) 1,374 2,210 1,387 1,994 1,274 1,739 2,126 2,354 1,874 2,076 1,566 2,276 2,665 2,192 2,207 847 1,315 2,029

Tra

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Monthly Average in Hours

0

1,000

2,000

3,000

Ho

urs

in

TL

R /

CM

E

Level 5B Level 5A Level 4 Level 3B Level 3A CME Time (loading >90%)

-

400

800

1,200

1,600

2009 2010 2011 Prev 12 mo

Monthly Average Level 3 TLR (hrs)

-

20

40

60

80

100

120

2009 2010 2011 Prev 12 mo


-

100

200

300

400

2009 2010 2011 Prev 12 mo


-

500

1,000

1,500

2,000

2,500

2009 2010 2011 Prev 12 mo

CME Time (loading > 90%)(hrs)

1d. Congestion - Congested Intervals

Jul 11 Aug 11 Sep 11 Oct 11 Nov 11 Dec 11 Jan 12 Feb 12 Mar 12 Apr 12 May 12 Jun 12 Jul 12 Aug 12 Sep 12 2009 2010 2011Prev

12 mo

Breached Dispatch Intervals 5% 5% 5% 7% 3% 4% 4% 3% 5% 9% 6% 6% 8% 5% 6% 5.5% 5.4% 4.4% 5.6%

Binding Dispatch Intervals 80% 85% 75% 83% 62% 81% 85% 95% 86% 85% 62% 64% 86% 96% 86% 68.8% 66.7% 74.4% 82.3%

Congested Dispatch Intervals 82% 87% 77% 84% 64% 82% 86% 96% 88% 88% 64% 81% 87% 97% 88% 71.1% 69.2% 76.0% 84.0%

Interval = 5 minutes

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Average

0%

20%

40%

60%

80%

100%

Breached Dispatch Intervals Binding Dispatch Intervals Congested Dispatch Intervals

0%

20%

40%

60%

80%

Breached Dispatch Intervals Binding Dispatch Intervals Congested Dispatch Intervals

2009 2010 2011 Prev 12 mo

1e. Price Contour Map (July - September 2012)T

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500 kV

345 kV

230 kV

161 kV

138 kV

115 kV

69 kV

Oklahoma City

Tulsa

1f. Price Contour Map - last 12 months (October 2011 - September 2012)T

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500 kV

345 kV

230 kV

161 kV

138 kV

115 kV

69 kV

Oklahoma City

Tulsa

PENMUNSTRCRALAKALASTJHAWIASCLKNASJHA

MEDXFRREDMIN

MINXFRMINSET

SSHWALDOLXFR

SUBTEKFTCRAU

OSGCANBUSDEA

GRAXFRSWEELK

1g. Congestion - Flowgates - last 12 months (October 2011 - September 2012)

RegionFlowgate

NameFlowgate Location (kV)

Avg Hourly

Shadow

Price

($/MWh)

Total %

Intervals

Congested

Projects Expected to Provide Some Positive Mitigation

(Estimated In Service Date – Upgrade Type)

OSGCANBUSDEAOsage Switch - Canyon East [SPS] [(115) ftlo

Bushland - Deaf Smith [SPS] (230) $11.92 15.7%

1. Tuco Int. – Woodward 345 kV line (May 2014 - Balanced Portfolio)

2. Castro County Int. – Newhart 115 kV line (April 2015 - Regional Reliability)

3. Tuco Int. – Amoco – Hobbs 345 lines (January 2020 – ITP10)

GRAXFRSWEELKGrapevine Xfmr (230/115) [SPS] ftlo

Sweetwater – Elk City (230) [CSWS]$2.09 1.0%

1.Bowers – Howard 115 kV line (June 2016 – ITPNT)

2. Altus Jct Tap – Russell 138 kV

PENMUNSTRCRAPentagon – Mund (115) [WR] ftlo Stranger

Creek – Craig (345) [WR-KCPL]$5.13 4.8%

1. Tap existing Swissvale – Stilwell 345 kV line at West Gardner (June 2012 - Balanced

Portfolio)

2. Terminal upgrade for Pentagon – Mund 115 kV line (TBD – ITPNT)

3. Iatan – Nashua 345 kV line (June 2015 - Balanced Portfolio

LAKALASTJHAWLake Road – Alabama [GMOC] (161) ftlo St.

Joe – Hawthorn [GMOC] (345)$5.02 1.6%

1. Axtell – Post Rock – Spearville 345 kV line, two Spearville – Comanche – Flat Ridge

–Woodward 345 kV lines, and two Flat Ridge – Wichita 345 kV lines (Dec 2014 - Balanced

Portfolio/Priority Projects)

2. Iatan – Nashua 345 kV line (June 2015 - Balanced Portfolio)

3. Nebraska City – Maryville – Sibley 345 kV line (June 2017 - Priority Projects)

4. Eastowne Transformer (345/161) and decommission of Lake Road – Alabama 161 kV line

(January 2020 - ITP10)

CIRKNGIATSTJCircleville - King Hill [WR] (115) ftlo Iatan -

St. Joe [KCPL] (345)$4.05 1.0% 1. Iatan – Nashua 345 kV line (June 2015 - Balanced Portfolio)

IASCLKNASJHA

Iatan – Stranger Creek (345) [KCPL/WR] ftlo

Lake Road – Alabama (161) [KCPL/GMOC];

St. Joe – Hawthorn (345) [GMOC/KCPL]

RCF - MISO

$2.49 10.4%

1. Axtell – Post Rock – Spearville 345 kV line, two Spearville – Comanche – Flat Ridge

–Woodward 345 kV lines, and two Flat Ridge – Wichita 345 kV lines (Dec 2014 - Balanced

Portfolio/Priority Projects)

2. Iatan – Nashua 345 kV line (June 2015 - Balanced Portfolio)

3. Nebraska City – Maryville – Sibley 345 kV line (June 2017 - Priority Projects)

SUBTEKFTCRAUSub 1226 - Tekamah (161) ftlo Fort Calhoun -

Raun (345) [OPPD/MEC]

RCF-MISO

$2.46 0.5% 1. Nebraska City – Maryville – Sibley 345 kV line (June 2017 - Priority Projects)

South Central

KansasMEDXFRREDMIN

Medicine Lodge Xfmr [138/115] (SECI) ftlo

Red Willow - Mingo (345) [NPPD-SECI]$2.48 2.4%

1. Rebuild Holcomb – Plymell Switch 115 kV line (Jun 2012 - Regional Reliability completed)

2. Axtell – Post Rock – Spearville 345 kV lines (June 2013 - Balanced Portfolio)

Western Kansas MINXFRMINSETMingo Xfmr (345/115) ftlo Mingo - Setab

(345) [SECI]$2.11 3.3%

1. Axtell-Post Rock-Spearville 345 kV (June 2013 – Balanced Portfolio

2. Hitchland – Woodward 345 kV (July 2014 – High Priority)

Shreveport Area SSHWALDOLXFRS. Shreveport – Wallace (138) [CSWS] ftlo

Dolet Xfmr (345/230) [CLEC]$2.01 1.0%

1. McDade – Haughton - Redpoint 138 kV Voltage Conversion (Completed – Regional

Reliability)

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Texas Panhandle

Kansas City -

Omaha Corridor

0%

10%

20%

$0

$10

$20

Avg Hourly Shadow Price ($/MWh) Total % Intervals Congested

2a. Regional Control Performance - CPS1 Compliance

CPS1 Jul 11 Aug 11 Sep 11 Oct 11 Nov 11 Dec 11 Jan 12 Feb 12 Mar 12 Apr 12 May 12 Jun 12 Jul 12 Aug 12 Sep 12 2009 2010 2011 2012

>150% 5 5 4 3 3 6 7 7 5 6 7 8 5 7 5 7 6 4 4

100%-150% 15 15 16 17 17 14 13 13 15 14 13 12 15 13 15 12 13 16 16

<100% 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 - - - -

* City of Springfield, MO added as BA in April 2011.

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Average

Violation if any 1 Balancing Authority has an average over the 12 month

period of less than 100%.

0

2

4

6

8

10

12

14

16

18

20# B

ala

nc

ing

Au

tho

riti

es

<100% 100%-150% >150%BA's with a CPS1 value of <100% are non-compliant

-

4

8

12

16

20

2009 2010 2011 2012

# B

ala

nc

ing

Au

tho

riti

es

<100% 100%-150% >150%

2b. Regional Control Performance - CPS2 Compliance

CPS2 Jul 11 Aug 11 Sep 11 Oct 11 Nov 11 Dec 11 Jan 12 Feb 12 Mar 12 Apr 12 May 12 Jun 12 Jul 12 Aug 12 Sep 12 2009 2010 2011 2012

>95% 15 14 17 18 19 20 19 19 18 17 14 15 13 16 16 14 17 17 16

90-95% 5 6 3 2 1 0 1 1 2 3 6 5 7 4 4 4 2 3 4

<90% 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 - 0 - -

Violation if any 1 Balancing Authority has a violation in a 12 month period.

* City of Springfield, MO added as BA in April 2011.

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Average

0

2

4

6

8

10

12

14

16

18

20# B

ala

nc

ing

Au

tho

riti

es

<90% 90-95% >95%BA's with a CPS2 value of <90% are non-compliant

0

4

8

12

16

20

2009 2010 2011 2012

# B

ala

nc

ing

Au

tho

riti

es

<90% 90-95% >95%

3a. Transmission Utilization - $

Service (in MM $) Jul 11 Aug 11 Sep 11 Oct 11 Nov 11 Dec 11 Jan 12 Feb 12 Mar 12 Apr 12 May 12 Jun 12 Jul 12 Aug 12 Sep 12 2009 2010 2011Prev

12 mo

Network 68.71 71.52 78.46 63.87 62.09 63.46 66.61 74.32 73.36 72.76 78.13 80.27 80.62 84.20 83.98 33.56 46.88 66.16 73.64

Firm PTP 4.42 4.55 4.19 4.89 5.42 6.89 5.73 5.91 6.61 7.45 7.63 7.73 6.30 6.20 6.12 5.20 4.80 4.65 6.41

Non-Firm PTP 0.75 0.85 0.50 0.48 0.56 0.59 0.54 0.41 0.46 0.85 0.70 0.64 0.73 0.61 0.49 1.74 0.95 0.65 0.59

Total 73.87 76.93 83.14 69.23 68.07 70.94 72.88 80.64 80.42 81.06 86.46 88.64 87.65 91.01 90.60 40.50 52.63 71.46 80.63

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Monthly Average

0

20

40

60

80

100in

mil

lio

ns

$

Non-Firm PTP Firm PTP Network

$0

$20

$40

$60

$80

2009 2010 2011 Prev 12 mo

in m

illi

on

s

Non-Firm PTP Firm PTP Network

4a. EIS Price and Price Range - for three months ending

AECC AEPM BEPM EDEP GMOC GRDX GSEC INDN KBPU KCPS KPP LESM MEAN MIDW OGE OMPA OPPM SECI SPSM TEAC TEAN WFES WRGS

MP Max 189 128 200 210 203 207 212 203 204 204 210 199 199 246 234 242 359 209 212 210 199 214 209

MP Avg 24.59 24.10 22.35 24.95 23.97 24.69 27.52 24.43 24.48 24.59 24.78 22.94 22.92 27.18 25.11 25.28 23.39 27.02 27.23 25.00 23.03 25.14 24.41

MP Min -7 -7 -143 -7 -48 -7 -1 -8 -8 -8 -8 -134 -137 -90 -7 -7 -130 -52 1 -7 -134 -7 -8

Volatility 37% 30% 55% 42% 40% 40% 41% 38% 38% 39% 37% 52% 53% 77% 40% 41% 66% 61% 40% 46% 54% 38% 34%

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rsSeptember 2012

$24.87 37%

0%

20%

40%

60%

80%

100%

$20

$22

$24

$26

$28

$30

Vo

lati

lity

(S

tan

da

rd D

evia

tio

n /

Ave

rag

e)

LIP

($

/MW

h)

MP Volatility SPP Avg LIP = MP Avg LIP SPP Volatility

4b. EIS Price and Price Range - for 12 months ending

AECC AEPM BEPM EDEP GMOC GRDX GSEC INDN KBPU KCPS KPP LESM MEAN MIDW OGE OMPA OPPM SECI SPSM TEAC TEAN WFES WRGS

MP Max 470 308 307 309 309 309 308 309 309 309 309 308 308 312 309 308 359 311 307 396 308 321 309

MP Avg 22.93 22.38 19.83 23.09 21.88 22.30 24.24 22.70 23.19 22.91 22.35 20.53 20.35 23.99 22.68 22.78 20.74 23.35 24.15 23.20 20.51 22.73 22.31

MP Min -139 -138 -185 -140 -142 -138 -69 -142 -141 -141 -142 -225 -204 -148 -137 -138 -228 -179 -70 -140 -204 -140 -142

Volatility 56% 38% 55% 49% 42% 40% 44% 44% 49% 46% 41% 54% 53% 64% 41% 42% 61% 70% 44% 54% 54% 41% 38%

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rsSeptember 2012

$22.56 39%

0%

20%

40%

60%

80%

100%

$18

$20

$22

$24

$26

$28

Vo

lati

lity

(S

tan

da

rd D

evia

tio

n /

Ave

rag

e)

LIP

($

/MW

h)

MP Volatility SPP Avg LIP = MP Avg LIP SPP Volatility

4c. EIS Prices

in $ Jul 11 Aug 11 Sep 11 Oct 11 Nov 11 Dec 11 Jan 12 Feb 12 Mar 12 Apr 12 May 12 Jun 12 Jul 12 Aug 12 Sep 12 2009 2010 2011Prev

12 mo

Monthly AvgLIP ($/MWh) 39.24 35.80 27.97 25.30 24.43 23.32 20.90 21.16 18.80 18.42 22.25 21.33 27.33 25.00 22.19 27.89 31.33 29.28 22.56

PEPL GasCost ($/MMBtu) 4.27 3.94 3.80 3.38 3.17 3.15 2.66 2.43 2.02 1.85 2.29 2.33 2.80 2.72 2.70 3.31 4.17 3.89 2.63

Average

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$0

$10

$20

$30

$40

$50

$0

$2

$4

$6

$8

$10

Sep 10

Oct 10

Nov 10

Dec 10

Jan 11

Feb 11

Mar 11

Apr 11

May 11

Jun 11

Jul 11 Aug 11

Sep 11

Oct 11

Nov 11

Dec 11

Jan 12

Feb 12

Mar 12

Apr 12

May 12

Jun 12

Jul 12 Aug 12

Sep 12

Ele

ctr

icit

y P

rice (

LIP

)

Gas C

ost

(Pan

han

dle

Easte

rn P

ipelin

e)

$/M

MB

tu

Gas (PEPL) 12 month avg Gas Electricity (LIP) 12 month avg LIP

5. Revenue Neutrality Uplift

in thousands $ Jul 11 Aug 11 Sep 11 Oct 11 Nov 11 Dec 11 Jan 12 Feb 12 Mar 12 Apr 12 May 12 Jun 12 Jul 12 Aug 12 Sep 12 2009 2010 2011Prev

12 mo

Total Uplift -2,568 -2,243 -661 -306 886 -677 -1,203 -764 -896 -1,269 233 -399 -815 -580 -938 7,754 -2,398 -13,769 -6,727

Revenue Neutrality Uplift (RNU) ensures settlement payments/receipts for each

hourly settlement interval equal zero.

• Positive RNU - SPP receives insufficient revenue and collects from market participants.

• Negative RNU - SPP receives excess revenue, which must be credited back to

market participants.

-3000 -3000 -3000 -3000 -3000 -3000 -3000 -3000 -3000 -3000 -3000 -3000 -3000

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Total

-$3,000

-$2,000

-$1,000

$0

$1,000

$2,000

in t

ho

usa

nd

s $

-$16,000

-$12,000

-$8,000

-$4,000

$0

$4,000

$8,000

2009 2010 2011 Prev 12 mo

in t

ho

usa

nd

s $

6a. Market Liquidity - Offered and Dispatchable

Daily Average Jul 11 Aug 11 Sep 11 Oct 11 Nov 11 Dec 11 Jan 12 Feb 12 Mar 12 Apr 12 May 12 Jun 12 Jul 12 Aug 12 Sep 12 2009 2010 2011Prev

12 mo

Dispatchable MW 17,140 16,394 13,184 11,413 10,657 12,346 12,518 12,598 11,711 11,304 13,244 16,564 17,693 16,938 14,833 10,522 11,221 12,738 13,485

Total Offered MW 42,389 40,994 31,715 27,280 26,747 30,107 29,582 28,608 26,639 27,255 31,560 38,155 42,357 39,584 33,311 29,193 33,917 32,079 31,765

% of Total Offered 40% 40% 42% 42% 40% 41% 42% 44% 44% 41% 42% 43% 42% 43% 45% 36.0% 33.1% 39.7% 42.5%

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Monthly Average

0%

20%

40%

60%

80%

0

10,000

20,000

30,000

40,000

Sep 10 Oct 10 Nov 10 Dec 10 Jan 11 Feb 11 Mar 11 Apr 11 May 11 Jun 11 Jul 11 Aug 11 Sep 11 Oct 11 Nov 11 Dec 11 Jan 12 Feb 12 Mar 12 Apr 12 May 12 Jun 12 Jul 12 Aug 12 Sep 12

% o

f T

ota

l O

ffere

d

MW

(d

ail

y a

vera

ge

)

Dispatchable MW Total Offered MW % of Total Offered

0

10,000

20,000

30,000

40,000

Dispatchable MW Total Offered MW

MW

(d

ail

y a

vera

ge

)

2009 2010 2011 Prev 12 mo0%

10%

20%

30%

40%

2009 2010 2011 Prev 12 mo

% of Total Offered

6b. Market Liquidity - Volume

Average Daily Jul 11 Aug 11 Sep 11 Oct 11 Nov 11 Dec 11 Jan 12 Feb 12 Mar 12 Apr 12 May 12 Jun 12 Jul 12 Aug 12 Sep 12 2009 2010 2011Prev

12 mo

Sales (MWh) 65,986 67,166 58,590 60,420 62,394 65,745 71,574 68,901 77,065 70,807 67,753 78,720 83,253 83,685 71,518 56,969 55,116 60,380 71,820

Sales ($000's) 2,513 2,319 1,541 1,452 1,461 1,478 1,427 1,404 1,362 1,227 1,461 1,658 2,194 2,051 1,480 1,518 1,651 1,695 1,554

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Monthly Average

$0

$1,000

$2,000

$3,000

$4,000

$5,000

0

20,000

40,000

60,000

80,000

100,000


Sale

s (

$000s)

Sale

s M

Wh

EIS Market Sales Volumes (average daily volume by month)

Sales (MWh) Sales ($000's)

0

20,000

40,000

60,000

2009 2010 2011 Prev 12 mo

Avera

ge

Dail

y S

ale

s (

MW

h)

0

1,000

2,000

3,000

2009 2010 2011 Prev 12 mo

Avera

ge

Dail

y S

ale

s (

$000's

)

7. SPP Admin Fee Performance

2004 2005 2006 2007 2008 2009 2010 2011 2012

Budgeted Net Revenue Required ($000s) 38,322$ 44,391$ 45,688$ 52,819$ 61,462$ 56,478$ 68,358$ 78,368$ 89,560$ Budgeted Load (000's) 245,776 253,489 258,556 288,649 312,496 331,324 333,458 343,000 353,453 Budgeted NRR / Budget Load 0.156$ 0.175$ 0.177$ 0.183$ 0.197$ 0.170$ 0.205$ 0.228$ 0.253$

Approved Admin Fee 0.150 0.160 0.160 0.190 0.190 0.170 0.195 0.210 0.255

Actual Net Revenue Required ($000's) 33,443$ 38,714$ 48,613$ 47,998$ 58,081$ 59,837$ 63,497$ 80,841$ 83,894$ Actual Load (000's) 245,571 267,239 286,446 301,098 296,135 328,175 331,610 341,438 360,902 Actual NRR / Actual Load 0.136$ 0.145$ 0.170$ 0.159$ 0.196$ 0.182$ 0.191$ 0.237$ 0.232$

EIA-411 Load Growth Forecast -0.37% 3.05% -0.60% 1.80% 2.10% 2.40% -1.00% 2.21%

Actual Load Growth -1.60% 8.82% 7.19% 5.12% -1.65% 10.82% 1.05% 2.96%

Fin

an

cia

l M

etr

ics

Note: Budgeted 2012 figures cover the entire 2012 calendar year, while actual 2012 figures cover the

period through the date of this report.

$0.12

$0.14

$0.16

$0.18

$0.20

$0.22

$0.24

$0.26

2004 2005 2006 2007 2008 2009 2010 2011 2012

$ p

er

MW

h

Approved Admin Fee Budgeted NRR / Budget Load Actual NRR / Actual Load

8. Budget Performance Monitor

in thousands $ Oct 11 Nov 11 Dec 11 Jan 12 Feb 12 Mar 12 Apr 12 May 12 Jun 12 Jul 12 Aug 12 Sep 12

Budgeted Operating Expense 11,736 11,197 11,296 11,723 11,695 11,917 12,419 12,265 12,757 12,907 12,570 12,692

Actual Operating Expense 11,147 10,608 11,790 10,505 11,543 10,922 11,158 11,052 10,807 12,516 11,692 12,402

Monthly Variance:Over Budget / (Under Budget) (589) (589) 494 (1,218) (152) (995) (1,261) (1,213) (1,950) (391) (878) (290)

12 month Cumulative Variance:Over Budget / (Under Budget) (589) (1,178) (684) (1,902) (2,054) (3,049) (4,311) (5,524) (7,474) (7,865) (8,743) (9,032)

Fin

an

cia

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etr

ics

-$10,000

-$8,000

-$6,000

-$4,000

-$2,000

$0

$2,000

Oct 11 Nov 11 Dec 11 Jan 12 Feb 12 Mar 12 Apr 12 May 12 Jun 12 Jul 12 Aug 12 Sep 12

in t

ho

us

an

ds

$

Operating Expense Variance

Monthly Variance Cumulative Variance

9. Financial Settlement Index


12 mo

% of Transmission Payment $ Received After the Due Date

0.2% 2.1% 2.2% 0.0% 1.4% 0.0% 0.0% 10.9% 2.6% 3.1% 1.8% 1.3% 0.0% 0.3% 0.0% 3.4% 6.2% 2.8% 1.8%

% of Market Payment $ Received After the Due Date

0.2% 0.0% 0.4% 0.2% 0.5% 0.3% 0.3% 0.0% 1.2% 0.0% 0.1% 0.2% 0.0% 0.0% 0.0% 3.8% 1.8% 1.7% 0.2%

% of Market Payment $ short paid 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0%

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ics

Monthly Average

Note 1: Figures represent

billings with a due date in

month shown. For

example, the September

figures are related to the

August 31 transmission

billing, which has payments

due on September 20.

0%

5%

10%

15%

20%

25%

30%%

of

$ r

ec

eiv

ed

aft

er

du

e d

ate

Late Payments

Transmission Billing Payments EIS Market Billing Payments

0%

2%

4%

6%

8%

Transmission Billing EIS Market Billing

La

te P

aym

en

ts

2009 2010 2011 Prev 12 mo

10a. Financial Disputes Index - $

(Figures in $000's)


12 mo

Total Disputes $9.1 $0.4 $222.5 $3.3 $6.5 $26.2 $0.4 $76.1 $2.5 $245.6 $60.4 $142.0 $13.1 $116.8 $30.9 210.3$ 234.2$ 45.2$ 60.3$

Avg. Dispute Size $0.1 $0.1 $2.6 $0.2 $0.2 $0.7 $0.0 $5.1 $0.1 $12.3 $2.5 $5.5 $1.0 $3.4 $1.0 16.9$ 15.2$ 1.3$ 2.7$

Largest single dispute $3.2 $0.3 $212.4 $2.3 $2.1 $18.5 $0.1 $75.6 $1.3 $231.8 $28.7 $41.5 $6.8 $68.2 $8.9 1567.2$ 1611.3$ 212.4$ 231.8$ *

* Annual maximum

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Monthly Average

$0

$50

$100

$150

$200

$250

$300$000's

Settlement Dispute Statistics ($)

Total Disputes Largest single dispute Average Dispute Size

$0

$100

$200

$300

2009 2010 2011 Prev 12 mo

Monthly Average Amount in Dispute ($000's)

$0

$5

$10

$15

$20

2009 2010 2011 Prev 12 mo

Average Dispute Size ($000's)

$0

$500

$1,000

$1,500

$2,000

2009 2010 2011 Prev 12 mo

Largest Single Dispute ($000's)

10b. Financial Disputes Index

(Figures in $000's) Sep 11 Oct 11 Nov 11 Dec 11 Jan 12 Feb 12 Mar 12 Apr 12 May 12 Jun 12 Jul 12 Aug 12 Sep 12 2009 2010 2011Prev 12

mo

# Disputes 49 30 38 20 23 13 21 36 23 41 25 24 23 40.1 17.8 38.1 26.4

# Resettlements 27 34 14 4 1 11 33 14 35 30 10 19 31 22.5 11.7 8.6 19.7

Avg Days Outstanding 24 32 35 35 29 33 41 42 65 44 39 35 33 33.2 27.4 27.3 38.6

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an

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ics

Monthly Average

0

25

50

75

0

25

50

75

100

125

150

Avg

. D

ays O

uts

tan

din

g

# o

f D

isp

ute

s a

nd

Resett

lem

en

ts

Settlement Dispute Statistics

Avg Days Outstanding # Disputes # Resettlements

-

20

40

60

80

100

2009 2010 2011 Prev 12 mo

Monthly Average of Active Disputes

-

10

20

30

2009 2010 2011 Prev 12 mo

Average Monthly Resettlements

-

10

20

30

40

2009 2010 2011 Prev 12 mo

Average Days Outstanding

11a. Employee Turnover - monthly

Jul 11 Aug 11 Sep 11 Oct 11 Nov 11 Dec 11 Jan 12 Feb 12 Mar 12 Apr 12 May 12 Jun 12 Jul 12 Aug 12 Sep 12

Voluntary TO Rate 0.8% 0.4% 0.4% 0.2% 0.2% 0.2% 0.0% 0.2% 0.2% 0.9% 0.2% 0.6% 0.4% 1.1% 0.2%

Involuntary TO Rate 0.0% 0.0% 0.0% 0.2% 0.2% 0.0% 0.0% 0.4% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0%

Total Turnover (# of employees) 4 2 2 2 2 1 - 3 1 5 1 3 2 6 1

Permanent Employees 499 500 510 512 512 514 514 524 527 530 528 541 549 553 554


Rolling 12-monthTurnover Rate 4.5% 4.0% 4.2% 4.4% 4.1% 4.1% 4.0% 4.4% 4.4% 4.7% 4.7% 5.0% 4.6% 5.3% 5.1%

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300

350

400

450

500

550

600

0.0%

0.5%

1.0%

1.5%

2.0%

2.5%

3.0%

Sep 10

Oct 10

Nov 10

Dec 10

Jan 11

Feb 11

Mar 11

Apr 11

May 11

Jun 11

Jul 11 Aug 11

Sep 11

Oct 11

Nov 11

Dec 11

Jan 12

Feb 12

Mar 12

Apr 12

May 12

Jun 12

Jul 12 Aug 12

Sep 12

Tu

rno

ver

Rate

Employee Turnover (monthly)

Involuntary TO Rate Voluntary TO Rate # of Employees

0%

2%

4%

6%

8%

10%


Tu

rno

ver

Rate

Rolling 12-month Turnover Rate

11b. Employee Turnover - annual

1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012

Total Turnover 3 1 7 7 10 8 8 8 14 21 30 13 21 20 22

Total Employees 39 45 73 110 110 116 131 169 245 295 345 423 449 514 554

Turnover Ratio 7.7% 2.2% 9.6% 6.4% 9.1% 6.9% 6.1% 4.7% 5.7% 7.1% 8.7% 3.1% 4.7% 3.9% 5.3%

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Note 1: Total Turnover only includes voluntary and involuntary separations; retirements and interns are not used in the calculation.

Note 2: Turnover Ratio is annualized for the current year.

-

100

200

300

400

500

600

0%

2%

4%

6%

8%

10%

12%

1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012

Tota

l Em

plo

yee

s

Turn

ove

r R

ate

(an

nu

aliz

ed

)

Annual Turnover Ratio and Employee Count

Total Employees Turnover Ratio

12. Staffing Summary


Filled w/ Internal Hire 8 6 5 5 5 5 6 5 3 6 9 5 4 5 2

Filled w/ External Hire 8 4 11 2 3 3 1 - 2 6 2 12 9 10 2

Hired YTD 107 117 133 140 148 156 7 12 17 29 40 57 70 85 89

* June 2012 external hires does not include 5 summer interns, only permanent employees are included.

2011 2012

Filled w/ Internal Hire 78 45 Filled w/ External Hire 78 44 Hired YTD 156 89

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0

20

40

60

80

100

120

140

160


Emp

loye

es

Filled w/ External Hire Filled w/ Internal Hire Hired YTD

13. SPP Regional Entity Compliance

2009 2010 2011 1Q 2012 2Q 2012 3Q 2012

Starting Caseload 57 154 268 245 275 286New Violations 129 254 239 57 44 34Processed by SPP RE 27 117 187 15 22 84Dismissed by SPP RE 5 23 75 12 11 16Ending Caseload 154 268 245 275 286 220

Cumulative Violations 194 448 687 744 788 822

Perf

orm

an

ce

0

100

200

300

2008 2009 2010 2011 1Q12 2Q12 3Q12

Period End Open Caseload

2009 2010 2011 1Q12 2Q12 3Q12

0

100

200

300Violations

New Processed Dismissed

14a. IT System Performance - Monthly Service Availability

Market System

(MOS)

Reliability

(EMS)

Reliability

(ICCP)

Tariff Admin

(OASIS)

Scheduling

(RTO_SS)COS Portal MUI Portal

Target Uptime % 99.87 99.93 99.93 99.87 99.87 99.46 99.87

Target Threshold (min) 60 30 30 60 60 240 60

Jul Uptime % 100.00 100.00 100.00 100.00 100.00 100.00 100.00

Aug Uptime % 100.00 100.00 100.00 100.00 100.00 100.00 100.00

Sep Uptime % 100.00 100.00 100.00 100.00 100.00 100.00 100.00

Jul Outage Minutes 0 0 0 0 0 0 0

Aug Outage Minutes 0 0 0 0 0 0 0

Sep Outage Minutes 0 0 0 0 0 0 0

GREEN

Meets or Exceeds Targeted Uptime

YELLOW

Unplanned outage below Target Uptime

RED

Unplanned outage below Target Uptime

Perf

orm

an

ce

Apr Apr Apr Apr Apr Apr AprMay May May May May May MayJun Jun Jun Jun Jun Jun Jun

98.00

98.50

99.00

99.50

100.00

Market System(MOS)

Reliability(EMS)

Reliability(ICCP)

Tariff Admin(OASIS)

Scheduling(RTO_SS)

COS Portal MUI Portal

% S

erv

ice

Ava

ilab

ility

14b. IT System Performance - 12 Month Service Availability

%Market

System

(MOS)

Reliability

(EMS)

Reliability

(ICCP)

Tariff Admin

(OASIS)

Scheduling

(RTO_SS)COS Portal MUI Portal

12 Month

Service

Availability

99.93 100.00 100.00 100.00 99.95 100.00 100.00

Perf

orm

an

ce

98.00

98.50

99.00

99.50

100.00

Market System (MOS)

Reliability (EMS)

Reliability (ICCP)

Tariff Admin (OASIS)

Scheduling (RTO_SS)

COS Portal MUI Portal

% S

erv

ice

Ava

ilab

ility

16a. Studies - Aggregate - MW

Completed 3Q 11 4Q 11 1Q 12 2Q 12 3Q 12 In Progress 3Q 11 4Q 11 1Q 12 2Q 12 3Q 12

2008-AGP1 2010-AGP1 3,503 3,212

2009-AGP1 2011-AGP1 6,948 6,143 5,680 4,587 4,554

2009-AGP2 2011-AG2 5,941 3,866 3,074 2,474 2,174

2010-AGP1 2,624 2011-AG3 7,505 6,125 4,592 3,573

2012-AG1 3,019 2,870

2012-AG2 5,733

TOTAL - - 2,624 - - TOTAL 16,392 20,726 17,898 14,523 16,034

MW

Perf

orm

an

ce

MW

2010-AGP1 2010-AGP1

2011-AGP12011-AGP1

2011-AGP12011-AGP1 2011-AGP1

2011-AG2

2011-AG2

2011-AG2

2011-AG2 2011-AG2

2011-AG3

2011-AG3

2011-AG3

2011-AG3

2012-AG1

2012-AG1 2012-AG2

Completed2010-AGP1

(4,000)

-

4,000

8,000

12,000

16,000

20,000

3Q 11 4Q 11 1Q 12 2Q 12 3Q 12

MW

16b. Studies - Aggregate - Upgrade $

Completed 3Q 11 4Q 11 1Q 12 2Q 12 3Q 12 In Progress 3Q 11 4Q 11 1Q 12 2Q 12 3Q 12

2008-AGP1 2010-AGP1 22.1$ 23.7$

2009-AGP1 2011-AGP1 255.0$ 275.9$ 281.3$ 114.7$ 79.0$

2009-AGP2 2011-AG2 1,281.2$ 364.9$ 495.7$ 206.6$ 21.4$

2010-AGP1 13.0$ 2011-AG3 1,778.9$ 1,307.8$ 1,158.9$ 627.4$

2012-AG1 98.1$ 72.8$

2012-AG2 526.4$

TOTAL -$ -$ 13.0$ -$ -$ TOTAL 1,558.3$ 2,443.4$ 2,183.0$ 1,553.0$ 1,254.3$

Perf

orm

an

ce

$ (in millions) $ (in millions)

2010-AGP1 2010-AGP1

2011-AGP1 2011-AGP1 2011-AGP12011-AGP1 2011-AGP1

2011-AG2

2011-AG22011-AG2

2011-AG2

2011-AG2

2011-AG3

2011-AG3

2011-AG3

2011-AG3

Completed2010-AGP1

Completed2010-AGP1

2012-AG1

2012-AG1

2012-AG2

-$1,000

$0

$1,000

$2,000

$3,000

3Q 11 4Q 11 1Q 12 2Q 12 3Q 12

$ (

in m

illio

ns)

16c. Studies - Generation Interconnection - MW

In Progress 3Q 11 4Q 11 1Q 12 2Q 12 3Q 12

Pre Queue Reform 48 48 48 48 18

Transition Cluster 454 454 454 454 544

DISIS-2009-001 201 201 201 201 201

DISIS-2010-001 1,821 1,821 1,087 1,013 911

DISIS-2010-002 2,075 2,075 534 478 278

DISIS-2011-001 4,824 4,722 4,420 4,420 4,092

DISIS-2011-002 2,893 3,096 2,073 2,073 1,972

DISIS-2012-001 333 1,250 816 794

DISIS-2012-002 99 3,542

PISIS-2011-001 200

PISIS-2012-001 150 150

PISIS-2012-002 605

FCS-2011-004 74 74

FCS-2012-002 80 80

FCS-2012-003 425

FCS-2012-004 680

Pending Withdrawal

TOTAL 12,588 12,823 10,297 10,257 13,637

Perf

orm

an

ce

MW

-

5,000

10,000

15,000

3Q 11 4Q 11 1Q 12 2Q 12 3Q 12

MW

Generation Interconnection MW - In Progress

Pre Queue Reform Transition Cluster 2009 Studies 2010 Studies 2011 Studies 2012 Studies

16d. Schedule of Commerical Operation Dates for Upcoming Generation Interconnection Agreements

as of September 30, 2012

MW Capacity

IA Fully Executed / On Schedule 2,614.7 IA Fully Executed / On Suspension 8,459.8

Total Scheduled or Suspended Generation 11,074.5

Perf

orm

an

ce

Charts above reflect Executed Generation Interconnection Agreements (GIA’s) with upcoming Commercial Operation Date (COD) milestones by year and month.

Data based on Queue Status of “IA Fully Executed / On Schedule”,

0

200

400

600

800

1,000

1,200

Jan

Fe

b

Mar

Ap

r

May

Ju

n

Ju

l

Au

g

Sep

Oct

No

v

Dec

Jan

Fe

b

Mar

Ap

r

May

Ju

n

Ju

l

Au

g

Sep

Oct

No

v

Dec

2012 2013

MW

Cap

acit

y

Commercial Operation Month

0

1,000

2,000

3,000

4,000

2012 2013 2014 2015 2016

MW

Cap

acit

y

Commercial Operation Year

Metrics Definitions

Transmission and Market Indicators

Two groups of metrics will be monitored to provide an overall health indication of the regional transmission system and market.

• Reliability Performance Indicators, which focus on the actual operations of the transmission system and whether or not it was operated within expected limits and standards.

• Market Performance Indicators, which focus on the performance of the market in terms of overall volume, prices and level of participation.

The intent is to monitor the trends in these areas over time to identify any unexpected performance in an area. Specific performance targets may be established in the future as experience is gained with the information.

Reliability Performance Indicators

This sub-group of metrics is designed to measure the operations of the transmission system from a reliability perspective. • How much time was congested during the period. (see Congestion) • How much energy was curtailed due to congestion? (see Congestion) • Was the system operated in compliance with the relevant control performance standards? (see Regional Control Performance)

1. Congestion

1a. Congestion

• Time (in hours) during the month that flowgates were in Congested (Breached or Binding) and Over the Limit

• % of Schedules/Tags Curtailed

1b. Curtailments

• Tag Curtailments and Market (Schedules) Curtailments along with Total Tags and Schedules.

1c. TLR / CME Time

•

TLR Events by level (in hours) Level 3 - curtailment of non-firm schedules and non-firm market flow Level 4 – curtailment of all non-firm schedules and non-firm market flow (additional reconfiguration

of transmission allowed) Level 5 - curtailment of all non-firm and some firm schedules and market flow "A" Levels begin curtailing at the beginning of the next hour "B" Levels begin curtailing immediately and lasts through the end of the next hour

• CME (Congestion Management Events) where loading is greater than 90% (in hours) 1d. Congested Intervals

• Percent of intervals binding (flow = System Operating Limit [SOL]), breached (flow > SOL) and congested (either binding or breached) during the month.

1e. & 1f. Price Contour Map

• Graphic representation of average monthly prices by load area for the last quarter and last 12 months. Flowgates appearing in the top ten by average shadow price impact in 1g. are identified on 1f.

1f. Congestion

• Congestion by flowgate by average hourly shadow price.

2. Regional Control Performance

Measures the aggregate performance to the NERC CPS (Control Performance Standards) of the Balancing Authorities in the region. This indicator is set based on the number of BAs within region that are in compliance with the NERC real time control performance standards (known as BAL-001 – Real Power Balancing Control Performance and BAL-002 – Disturbance Control Performance).

• CPS1 requires BAs to be in compliance for 100% of the periods measured within the month; and CPS2 requires BAs to be in compliance for 90% of the periods measured within the month.

• For the CPS1 standard, each BA’s rolling 12 month performance is grouped into one of three performance bands (<100% [red], 100-150% [yellow], >150% [green]).

• The number of BA’s whose CPS1 score falls into these bands is shown; with below 100% meaning non-compliant with the standard.

• CPS2 performance is depicted in the appropriate bands (<90% [red], 90-95% [yellow], >95% [green]) based on the monthly CPS2 score rather than a rolling 12 month average.

Market Performance Indicators This sub-group of indicators provides a view of the effectiveness of the EIS market in the context of answering the following questions:

• What was the value of transmission services used in the month? (see Transmission Utilization) • What was the average wholesale price paid in the region and what was its volatility? (see EIS Price and Price Range)

• How much Revenue Neutrality Uplift was generated during the month? (see Congestion Uplift)

• What was the level of available generation offered to the market and EIS related energy sales in the month? (see Market Liquidity)

3. Transmission Utilization

Measures the volume of transmission service scheduled in the month in terms of the transmission service revenues paid by both Network Customers and Point-to-Point customers.

• The revenues paid by transmission customers are directly related to the amount of transactions scheduled on the transmission system and therefore provide a proxy as to the utilization of the transmission system in the period.

• Transmission service revenues will be reported as a simple sum of revenues paid for Network Service, Firm Point-to-Point, and Non-Firm Point-to-Point transmission service.

• Transmission service MWh will be reported as a simple sum of Network Service, Firm Point-to-Point, and Non-Firm Point-to-Point transmission service.

4. Price and Price Ranges •

Shows the EIS market prices (high, average and low) for each market participant within the footprint on during the previous 12-month period as well as for the previous month. Also provides an SPP-wide average price for the period reported. Volatility (measured as the coefficient of correlation, which is average divided by the standard deviation) is shown for each market participant as well as SPP as a whole. A higher volatility indicates more variability in prices.

• Shows the SPP-wide monthly average EIS price and the Gas Cost at the Panhandle Eastern Pipeline hub along with12-month rolling averages.

5. Revenue Neutrality Uplift

Tracks amount of RNU (Revenue Neutrality Uplift) charged or credited to market participants during the month. RNU ensures settlement payments/receipts for each hourly settlement interval equal zero.

• Positive RNU - SPP receives insufficent revenue and collects from market participants.

• Negative RNU - SPP receives excess revenue, which must be credited back to market participants.

6. Market Liquidity

Measures the average daily MW offered and dispatchable to the EIS market (dispatchable generation); as well as the average daily sales volume during the month in MWh and dollars.

• Data is taken from the Resource Plans.

• A “percent of total offered” is calculated using the dispatchable MW divided by the total offered MW. Although no specific performance targets have been set, the intent is to monitor the trend of this index to identify significant deviations from average.

Financial Metrics

This group of metrics provides a view of the organization’s overall financial situation in terms of both the operating costs and settlement functions carried out.

7. SPP Admin Fee Performance Measures actual costs incurred by SPP on an annual basis and compares this to the approved Admin Fee and Budgeted Net Revenue Requirement (NRR).

8. Budget Performance Monitor Measures the total actual operating expenses against the total budgeted operating expenses across the organization.

9. Financial Settlement Index Metric measures the timeliness of the financial settlements for both transmission billing and EIS market billing and provides a proxy for the strength of the organization’s cash flow.

10. Financial Disputes Index

Measures the number and value of disputes made with regard to the financial settlements of the markets. The objective in this area is twofold: (1) minimize the time to clear disputes; and (2) minimize the total value of dollars in dispute.

• The dollar amount for total disputes, the average dispute size and the largest single dispute is tracked.

• The number of disputes active during the month, as well as the average days outstanding for those disputes is calculated. In addition, the number of resettlements during the month is tracked.

Learning & Growth Metrics

These indicators provide insights into the organization’s success in maintaining and supporting its desired staffing levels and employee growth plans.

11. Employee Turnover

Measures both involuntary and voluntary turnover rates, along with number of employees in the organization. Monthly turnover is charted on a rolling 12 month basis, while annual turnover ratio and number of employees is provided for historical purposes.

•

A turnover rate is calculated each month by dividing the total turnover for the month by the total employee count at month-end. This monthly rate is then aggregated for the previous 12 months giving a 12-month turnover rate. In order to observe the trend, this 12-month turnover rate is calculated on a rolling basis for the last 25 months.

• An annual turnover rate and the number of employees at year-end are both tracked for historical purposes.

12. Staffing Measures the number of new hires during a month (positions filled) from internal transfers and external hires. Also shows year-to-date new hire total.

Performance Metrics

The metrics in this group focus on NERC Compliance and IT System Availability.

13. SPP RE Compliance Measures SPP Regional Entity compliance of all NERC standards. Metrics track the active caseload, as well as new possible violations and the disposition of reported violations.

14. IT System Availability Measures availability of SPP IT Systems.

15. Strategic Plan Progress Tracks status of elements of the SPP Strategic Plan.

16. Studies Tracks status of Aggregate Studies and Generation Interconnection Studies by MW and upgrade costs (Aggregate Studies only).

Regulatory Update - Activity in Significant Dockets

Third Quarter 2012

Page 1 of 11

SPP Tariff/Governing Document Revisions

Docket Number Short Description Summary

ER12-1179 SPP Submission of Tariff

Revisions to Implement SPP


On July 9, 2012, the Omaha Public Power District (“OPPD”) filed an answer in response to SPP's June 26,

2012 Answer.

OPPD requested that the Commission direct SPP to recognize the transmission border points referenced in

OPPD's May 25, 2012 Answer as settlement locations for transmission transactions under the SPP Tariff

so that OPPD may obtain and use Auction Revenue Rights and Transmission Congestion Rights

consistent with SPP's representations in its Integrated Marketplace filing and SPP's May 15, 2012 Answer.

On July 11, 2012, E.ON Climate & Renewables North America LLC (“E.ON”) filed an answer in

response to SPP's June 26, 2012 Answer.

E.ON stated:

1) the compensation and charge issues E.ON raised in its May 30 Answer bear directly on whether SPP's

proposed Integrated Marketplace design is just and reasonable and thus are appropriately resolved in this

docket;

2) if SPP's use of persistence forecasting is accepted by the Commission, then SPP's Tariff should reflect

the limited application SPP proposes; and

3) SPP's latest clarification still does not make its proposed Dispatchable Variable Energy Resources

(DVER) Ramp Rate limitations just and reasonable and not unduly discriminatory.

On July 11, 2012, Missouri River Energy Services (“MRES”) and Heartland Consumers Power District

(“Heartland”) filed a Conditional Withdrawal of Protest. MRES and Heartland stated if they correctly

understand SPP's June 26, 2012 filing to recognize that service to MRES and Heartland under the 1977

Transmission Service Agreement will not be affected by or subject to SPP's proposed Integrated

Marketplace, then MRES and Heartland withdraw the MRES Protest and Answer.

On October 11, 2012, the Midwest Independent Transmission System Operator, Inc. filed amended

comments. MISO requested that the Commission expressly address market-to-market coordination in part

of its review of the Integrated Marketplace proposal.

EL12-2

Investigation Under Section 206

of the Federal Power Act

(“FPA”) to Determine the

Justness and Reasonableness of

Certain Language in Section

VII.8(b) of Attachment O of

SPP's Tariff

On July 31, 2012, in Docket No. ER12-2366, SPP submitted revisions to Attachment O, Section VII.8(b)

of its Tariff in compliance with the February 29, 2012 Order issued in Docket Nos. ER09-659 and EL12-

2. SPP modified the language to state that individuals not belonging to a confirmed pre-screened Member

or Market Participant shall make application for approval to obtain Critical Energy Infrastructure

Information (CEII) used in the transmission planning process in accordance with the procedures posted on

the SPP website.

An effective date of July 31, 2012 was requested.


Third Quarter 2012

Page 2 of 11



ER12-1402

ER12-2366

SPP Submission of Tariff

Revisions to Section VII.8(b) of

Attachment O

SPP Submission of Tariff

Revisions to Modify Section

VII.8(b) of Attachment O in

Compliance with Order issued in

ER09-659 and EL12-2


Revisions to Attachment AE to

Facilitate the Systematic Rather

than Manual Curtailment of

Non-Dispatchable Resources in

the Energy Imbalance Services

Market ("EIS Market") During

Period of Congestion

On July 23, 2012, SPP submitted revisions to Attachment AE of its Tariff in order to facilitate the

systematic rather than manual curtailment of Non-Dispatchable Resources in the SPP EIS Market during

period of congestion.

An effective date of October 15, 2012 was requested. SPP requested that the Commission rule on this

filing within 60 days so that SPP can complete the design, development, and testing of necessary software

to implement the changes on the effective date.

Several parties filed Motions to Intervene and/or Comments or Protests.

On September 20, 2012, FERC issued an Order Conditionally Accepting Tariff Revisions, effective

October 15, 2012 as requested.

FERC directed SPP to make a compliance filing that revises the Tariff provisions to specify that

automated curtailment applies only prospectively to Non-Dispatchable Resources that become

commercially operable on or after October 15, 2012.

Further, FERC conditionally accepted that part of SPP's proposal that applies to existing Non-

Dispatchable Resources (i.e. commercially operable prior to October 15, 2012), subject to a compliance

filing with tariff revisions reflecting the results of stakeholder process. This stakeholder process will

address the issues raised by the existing Non-Dispatchable Resources in a manner that is consistent with

ensuring reliability, with the results of the stakeholder process to become effective a year from the date of

this order.

FERC directed SPP to revise proposed Section 4.3(i) and Section 5.5(f) to delete the reference to "all of"

in the phrase "Qualifying Facility exercising its rights under PURPA to deliver all of its net output to its

host utility" to be consistent with the requirements of section 292.304(d)(1) of the Commission's

regulations which permits any Qualifying Facility ("QF") to decide how much energy is available for such


Third Quarter 2012

Page 3 of 11



purchases.

FERC conditionally accepted SPP's proposed curtailment of unscheduled output at TLR level 5 on an

equivalent basis with firm transmission service, for the output of QFs sold under PURPA. FERC stated

that to the extent that a Non-Dispatchable Resource is a designated network resource, it should be

assigned TLR level 5 curtailment priority, on an equivalent basis with other firm designated network

resources, up to the level of output designated for that resource (provided that the aggregate generation

from designated network resources for a particular network load does not exceed the associated network

load plus losses). FERC directed SPP to include this modification in the compliance filing or explain why

it cannot operationally satisfy this provision.

SPP's Compliance Filing is due December 19, 2012.


Revisions to Implement

Balanced Portfolio Transfers

On August 2, 2012, SPP submitted revisions to its Tariff to update revenue requirements and associated

rates in Attachments H and T in order to implement the initial reallocation of revenue requirements

pursuant to Attachments J and O of the Tariff (Balanced Portfolio Transfers). An effective date of

October 1, 2012 was requested.

Several parties filed Motions to Intervene and/or Comments.

On September 7, 2012, SPP filed an answer in response to Comments filed in this proceeding.

On September 26, 2012, SPP filed a Motion to Amend Filing and Amend Answer. SPP requested to

amend its August 2, 2012 Filing in response to recent Commission Orders. SPP also amended its

September 7, 2012 Answer. An effective date of October 1, 2012 was requested.


Third Quarter 2012

Page 4 of 11

Other Filings of Interest


EL11-34

and

12-1158

(U.S. Court of Appeals)

Midwest Independent

Transmission System Operator,

Inc. ("MISO”) Petition for

Declaratory Order Seeking

Commission Confirmation

Regarding Section 5.2 of the

Joint Operating Agreement

("JOA") between MISO and SPP

Southwest Power Pool, Inc. v.

Federal Energy Regulatory

Commission

On August 20, 2012, the United States Court of Appeals issued an Order establishing the briefing

schedule as follows in Case No. 12-1158:

October 2, 2012 - Petitioner's Brief;

October 17, 2012 - Intervenors for Petitioner's Brief;

December 17, 2012 - Respondent's Brief;

December 31, 2012 - Intervenors for Respondent's Brief;

January 14, 2013 - Intervenors for Petitioner's Reply Brief;

January 14, 2013 - Petitioner's Reply Brief;

January 22, 2013 - Deferred Appendix; and

February 5, 2013 - Final Briefs.

On October 2, 2012, SPP filed its Opening Brief Case No. 12-1158.

SPP stated:

1) having resorted to extrinsic evidence to ascertain the meaning of Section 5.2, FERC was compelled to

support its interpretation with substantial evidence and to consider all relevant evidence, not merely

evidence that FERC perceived to be consistent with its interpretation;

2) proper consideration of SPP's proffered evidence would have demonstrated the error in the

Commission's interpretation of Section 5.2;

3) FERC's "contextual" analysis of Section 5.2 does not support and, in fact, undercuts FERC's

conclusion; and

4) FERC's straw-man argument regarding inferred intentions is based on a fundamental misunderstanding

of the contract.

EL12-60 SPP, Western Area Power

Administration ("Western"),

Basin Electric Power

Cooperative ("Basin Electric")

and Heartland Consumers Power

District ("Heartland")

(collectively "Petitioners") Filing

of a Joint Petition for

Declaratory Order and Request

for Shortened Notice Period and

for Expedited Treatment Seeking

Confirmation that the Terms of

On September 18, 2012, FERC issued an Order Granting Petition for Declaratory Order and Conditionally

Accepting Joint Operating Agreement.

FERC found that the Congestion Management Process requires reciprocity with third parties that have

entered into reciprocal coordination agreements with one or more of the parties to a reciprocal agreement.

Because Western and MISO both have reciprocal coordination agreements with SPP, FERC found that

MISO must treat its flowgates with Western as reciprocal coordinated flowgates.


Third Quarter 2012

Page 5 of 11



the Congestion Management

Process ("CMP") in the Joint

Operating Agreement ("JOA")

between SPP and the Midwest

Independent Transmission

System Operator, Inc. ("MISO")

Apply to the Reciprocal

Coordinated Flowgates ("RCFs")

of a Third Party Who has

Entered into a Reciprocal

Coordination Agreement with

SPP

ER12-1586 SPP Submission of an Executed

Joint Operating Agreement

("JOA") Between SPP and

Western Area Power

Administration, Upper Great

Plains Region ("Western")

(SPP-WAPA JOA)

(FERC Rate Schedule No. 13)

On July 20, 2012, SPP submitted its responses to the June 19, 2012 deficiency letter.

On September 18, 2012, FERC issued an Order Granting Petition for Declaratory Order and Conditionally

Accepting Joint Operating Agreement.

FERC conditionally accepted the proposed Western-SPP JOA, subject to the revisions SPP proposed in

the July 20, 2012 response to deficiency letter. FERC also directed SPP to revise the JOA to clarify that

the term "energy exchange" as applied in sections 5.4 - 5.6 relates only to energy sourced in Western or

SPP.

SPP's Compliance Filing is due October 18, 2012.

ER12-2390 Entergy Services, Inc. ("ESI")

Request for an Interim Extension

of the Independent Coordinator

of Transmission ("ICT")

Arrangement and the Transfer

from SPP to Midwest

Independent Transmission

System Operator, Inc. ("MISO")

as the Provider of ICT Services

On August 2, 2012, ESI requested that the Commission approve 1) an interim extension of the ICT

arrangement through and until the earlier of December 31, 2014 or the date of the proposed transfer of

functional control of the Operating Companies' transmission assets to the MISO Regional Transmission

Organization is completed; and 2) the transfer from SPP to MISO as the provider of ICT services,

effective December 1, 2012. An effective date of December 1, 2012 was requested.

Several parties filed Motions to Intervene and/or Comments or Protests.

On August 23, 2012, SPP filed a Motion to Intervene and Comments.

On October 2, 2012, FERC issued an Order Accepting Amended Agreement and Proposed Tariff

Revisions.

FERC accepted ESI’s:


Third Quarter 2012

Page 6 of 11



1) proposed extension of Attachment W from November 17, 2012 to November 30, 2012;

2) proposed transfer of ICT functions from SPP to MISO effective December 1, 2012; and

3) proposal to allow Attachment W remain effective until May 31, 2013, or earlier as determined by the

parties, in order to allow for SPP to provide the needed transition assistance services.

FERC also accepted ESI's proposal to extend the ICT Agreement until the earlier of December 31, 2014

or the proposed date of transfer of ESI's transmission assets to MISO.

ER12-2681

EC12-145

EL12-107

Joint Application of ITC

Holdings Corp. ("ITC") and

Entergy Corporation ("Entergy")

for Authorization of Acquisition

and Disposition of Jurisdictional

Transmission Facilities,

Approval of Transmission

Service Formula Rate and

Certain Jurisdictional

Agreements, and Petition for

Declaratory Order on

Application of Section 305(a) of

the Federal Power Act

On September 24, 2012, ITC Holdings Corp. and Entergy Corporation filed a Joint Application for

Authorization of Acquisition and Disposition of Jurisdictional Transmission Facilities, Approval of

Transmission Service Formula Rate and Certain Jurisdictional Agreements, and Petition for Declaratory

Order on Application of Section 305(a) of the Federal Power Act.

The Applicants requested that the Commission provide an extended comment period of 45 days. The

Applicants also requested that FERC issue an order on the Application within 180 days.

The Applicants requested that the effective date of the tariff sheets be deferred until the closing date of the

transaction.

Several parties filed Motions to Intervene.

On October 4, 2012, the Entergy Retail Regulators filed a Motion for Extension of Comment Deadline.

The Parties requested the comment deadline be extended until December 7, 2012.

On October 9, 2012, ITC and Entergy filed an answer stating they do not oppose the Entergy Retail

Regulators' Motion for Extension of Comment Deadline


Third Quarter 2012

Page 7 of 11

State Cases


Arkansas

04-137-U

SPP Application before the

Arkansas Public Service

Commission ("APSC") for a

Certificate of Public

Convenience and Necessity

("CCN")

On September 21, 2012, Southwestern Electric Power Company (“SWEPCO”), Oklahoma Gas and

Electric Company (“OG&E”), and The Empire District Electric Company (“Empire”) filed a Joint Petition

for Approval to Participate in Southwest Power Pool's Integrated Marketplace and for Declaratory Relief.

On September 21, 2012, SWEPCO, OG&E, and Empire filed the Direct Testimony of Carl Monroe in

support of the Joint Petition.

On October 1, 2012, the APSC General Staff filed its Response to the Joint Motion for Approval to

Participate in Southwest Power Pool's Integrated Marketplace and for Declaratory Relief.

Staff requested that the Commission issue an order authorizing the utilities to participate in SPP's

Integrated Marketplace, and for a declaration that Condition Nos. 1, 2, 3(a), and 4 of Order No. 6 issued in

this proceeding are no longer applicable once SPP's Integrated Marketplace is fully implemented.

Arkansas

10-011-U

In the Matter of a Show Cause

Order Directed to Entergy

Arkansas, Inc. (“EAI”)

Regarding Its Continued

Membership in the Current

Entergy System Agreement, or

Any Successor Agreement

Thereto, and Regarding the

Future Operation and Control of

Its Transmission Assets

On August 3, 2012, the APSC issued Order No. 68. The APSC stated it was unable to reach a finding that

EAI's Application is in the public interest. However, if EAI and Midwest Independent Transmission

System Operator, Inc. ("MISO") meet the conditions specified in the Order, and upon proper motion and

proof of compliance in the form of sworn testimony by EAI and MISO officials who are expressly

authorized to commit their respective organizations, the Commission will make a determination whether

EAI and MISO have complied with the conditions. Upon finding by the Commission that the conditions

are met, the Commission will grant conditional approval of EAI's Application as being in the public

interest, and will authorize EAI to sign the MISO Transmission Owners Agreement and move forward

with the MISO integration process.

On August 24, 2012, EAI filed a Motion for Finding of Compliance with Conditions and for the Approval

of Application or, in the Alternative, Petition for Rehearing.

On August 31, 2012, MISO filed a Motion for Finding of Compliance with Conditions and Approval of

Application, Motion for Clarification, or in the Alternative Petition for Rehearing.

Several parties filed responses to EAI’s and MISO’s compliance filings.

On September 20, 2012, the APSC issued Order No. 71, granting rehearing solely for the purpose of

further consideration by the Commission.

Louisiana – City of New Initiating Investigation of the On August 3, 2012, the parties filed Cross-Answering Testimony. Carl Monroe filed Cross-Answering


Third Quarter 2012

Page 8 of 11

State Cases


Orleans

UD-11-01

Potential Costs and Benefits of

Entergy New Orleans, Inc.

(“ENO”) and Entergy Louisiana,

LLC (“ELL”) (collectively

“Entergy”) Joining a Regional

Transmission Organization

Versus the Continuation of the

Entergy Independent

Coordinator of Transmission

with Enhancements

Testimony on behalf of SPP.

On August 22, 2012, Entergy filed Rebuttal Testimony.

On September 6, 2012, the Council of the City of New Orleans adopted Resolution R-12-333, Resolution

and Order to Suspend the Evidentiary Hearings (in Docket No. UD-11-01) and Initiating Discovery on

International Transmission Company's Acquisition of Entergy New Orleans, Inc. and Entergy Louisiana,

LLC's Transmission Assets Prior to the Companies Becoming Market Participant in the Midwest

Independent System Operator (in Docket Nos. UD-11-01 and UD-12-01).

The evidentiary hearing was suspended until October 23, 2012.

Louisiana – City of New

Orleans

UD-12-01

Investigation of the Proposed

Divestiture of the Transmission

Assets of Entergy New Orleans,

Inc. ("ENO") and Entergy

Louisiana, LLC ("ELL")

(collectively “Entergy”) to ITC

Holdings Corp.

On September 6, 2012, the Council of the City of New Orleans adopted Resolution R-12-333, Resolution

and Order to Suspend the Evidentiary Hearings (in Docket No. UD-11-01) and Initiating Discovery on

International Transmission Company's Acquisition of Entergy New Orleans, Inc. and Entergy Louisiana,

LLC's Transmission Assets Prior to the Companies Becoming Market Participant in the Midwest

Independent System Operator (in Docket Nos. UD-11-01 and UD-12-01).

A period of discovery commences with the adoption of this Resolution and shall continue until the date of

any subsequent administrative hearing is established or by further action of the Council. Entergy and ITC

were ordered to respond to all discovery regarding the proposed ITC transaction, including any discovery

regarding the impact of the proposed ITC transaction on the costs and benefits of the Joint MISO

Application.

On September 12, 2012, ENO, et al. filed a Joint Application for Approval of Change of Ownership of

Electric Transmission Businesses, for Certain Cost-Recovery Adjustments, and for Related Relief.

Mississippi

2011-UA-376

Joint Application of Entergy

Mississippi, Inc. (“EMI”), and

the Midwest Independent


Inc. (“MISO”), for Transfer of

Functional Control of Entergy

Mississippi's Transmission

Facilities to MISO

On July 6, 2012, Bates White submitted its report entitled "Evaluation of the Entergy Mississippi Proposal

to Join MISO." Bates White filed a supplement to the report on July 11, 2012.

On July 16, 2012, the MPSC held a Technical Conference.

A pre-hearing conference was held on July 17, 2012.

On July 18, 2012, the MPSC issued an Order Cancelling Hearing, cancelling the evidentiary hearings set

for July 19 and 20, 2012.

On August 27, 2012, Bates White filed its Revised Report to the MPSC on the Evaluation of the Entergy


Third Quarter 2012

Page 9 of 11

State Cases


Mississippi Proposal to Join MISO.

On September 17, 2012, the Mississippi Public Utilities Staff and EMI filed a Joint Stipulation. MPSC

Staff and EMI stipulated and agreed that conditions specified in the Joint Stipulation are appropriate to

ensure that EMI's transfer of functional control of its transmission facilities to MISO is consistent with the

public interest.

On September 19, 2012, the Parties filed a Joint Stipulation of Parties Agreeing to an Abbreviated

Proceeding Pursuant to Rule 15.101.3 of the Rules of Practice and Procedure.

The remaining procedural schedule is as follows:

October 19, 2012 - Proposed orders and briefing due; and

November 6, 2012 - Date by which final order issued.

Missouri

EO-2012-0135

In the Matter of the Application

of Kansas City Power & Light

Company (“KCPL”) for

Authority to Extend the Transfer

of Functional Control of Certain

Transmission Assets to the


On October 5, 2012, Charles Locke and James Okenfuss filed Direct Testimony on behalf of KCPL.

Missouri

EO-2012-0136

In the Matter of the Application

of KCP&L Greater Missouri

Operations Company (“KCPL-

GMO”) for Authority to Extend

the Transfer of Functional

Control of Certain Transmission

Assets to the Southwest Power

Pool, Inc.

On October 5, 2012, Charles Locke and James Okenfuss filed Direct Testimony on behalf of KCPL-

GMO.

Missouri

EO-2012-0269

In the Matter of The Empire

District Electric Company's

(“Empire”) Submission of Its

Interim Report Regarding

Participation in the Southwest

Power Pool, Inc.

On July 9, 2012, the MoPSC issued an Order Granting Applications to Intervene of Dogwood Energy,

LLC, Kansas City Power & Light Company and KCP&L Greater Missouri Operations Company, and


Texas

40346

Application of Entergy Texas,

Inc. ("ETI") for Approval to

On July 6, 2012, Intervenors filed Direct Testimony. Carl Monroe and Ralph Luciani filed Direct

Testimony on behalf of SPP.


Third Quarter 2012

Page 10 of 11

State Cases


Transfer Operational Control of

its Transmission Assets to the

Midwest Independent


Inc. (“MISO”) Regional

Transmission Organization

(“RTO”)

On July 16, 2012, Commission Staff filed Direct Testimony.

On July 20, 2012, Carl Monroe filed Cross-Rebuttal Testimony on behalf of SPP.

On July 20, 2012, the parties filed Statements of Position.

A hearing was held on August 1, 2012.

On August 6, 2012, certain parties filed the Non-Unanimous Stipulation and Settlement Agreement.

On August 8, 2012, certain parties filed an Amended Non-Unanimous Stipulation and Settlement

Agreement.

On August 8, 2012, John Hurstell filed Supplemental Direct Testimony in Support of Non-Unanimous

Settlement on behalf of ETI.

On August 20, 2012, Carl Monroe filed Pre-Filed Testimony on Non-Unanimous Stipulation on behalf of

SPP.

A hearing on the Non-Unanimous Stipulation was held on August 24, 2012.

On August 31, 2012, the parties filed Initial Briefs.

On September 7, 2012, the parties filed Reply Briefs.

On September 7, 2012, parties filed Proposed Final Orders.

On October 1, 2012, the State Office of Administrative Hearings filed the Proposal for Decision.

The proposed ordering paragraphs are as follows:

1) ETI's Application to transfer operational control of ETI's transmission assets to the MISO RTO is

conditionally approved, as modified by and subject to the terms and conditions of the Non-Unanimous

Stipulation;

2) this proceeding did not address any cost recovery relating to ETI joining MISO;

3) the entry of this Order consistent with the Non-Unanimous Stipulation does not indicate the

Commission's endorsement of any principle or methodology that may underlie the Non-Unanimous


Third Quarter 2012

Page 11 of 11

State Cases


Stipulation. Neither should entry of this Order be regarded as precedent as to the appropriateness of any

principle or methodology underlying the Non-Unanimous Stipulation; and

4) all other motions, requests for entry of specific findings of fact, conclusions of law, and ordering

paragraphs, and any other requests for general or specific relief, if not expressly granted in this order, are

hereby denied.

On October 1, 2012, the PUCT issued notice that the Proposal for Decision issued by the State Office of

Administrative Hearings on October 1, 2012 will be considered at the open meeting scheduled for October

19, 2012.

On October 8, 2012, parties filed Exceptions to the Proposal for Decision.

On October 11, 2012, parties filed Responses to Exceptions to the Proposal for Decision.

Regulatory Outlook

RM12-20

10/1/2012FERC Effective date of Order No. 766, Final Rule regarding Delegation of Authority Regarding Electric ReliabilityOrganization's Budget, Delegation Agreement, and Policy and Procedure Filings (Order No. 766 issuedSeptember 20, 2012)

12-1158

10/2/2012United States Court of SPP's Brief due (U.S. Court of Appeals Order issued August 20, 2012)

RM11-17

10/4/2012FERC Phase 2 datasets to be delivered to FERC pursuant to Order No. 760 (to include virtual offers and bids,and demand bids for energy) (Final Rule issued April 19, 2012)

40346

10/8/2012State of Texas Deadline for Filing Exceptions to Proposal for Decision

40346

10/11/2012State of Texas Deadline for Filing Responses to Exceptions to Proposal for Decision

09-1029

10/15/2012FERC Offer Cap Filing due (annual filing) (Docket number TBD)

ER12-959

10/15/2012FERC SPP Answering Testimony is due (Order Establishing Procedural Schedule issued July 13, 2012)

EA-2013-0098

10/15/2012State of Missouri Joint Procedural Conference begins at 9 AM (Order Directing Notice, Setting Intervention Deadline,Directing Filing and Scheduling a Conference issued September 5, 2012)

EO-2012-0367

10/15/2012State of Missouri Joint Procedural Conference begins at 9 AM (Order Directing Notice, Setting Intervention Deadline,Directing Filing and Scheduling a Conference issued September 5, 2012)

ER05-652

10/15/2012FERC File Informational Report on SPP Aggregate Study (Safe Harbor Report) (April 22, 2005 Order)

10/12/2012 10:53:31 Page: 1

Regulatory Outlook

12-1158

10/17/2012United States Court of Intervenors for Petitioner's Brief due (U.S. Court of Appeals Order issued August 20, 2012)

ER12-2387

10/17/2012FERC Comments due in response to SPP's September 26, 2012 Amendatory Filing (Combined Notice ofFilings issued September 27, 2012)

ER12-1586

10/18/2012FERC SPP's Compliance Filing due to revise the Western-SPP Joint Operating Agreement to include therevisions SPP proposed in the July 20, 2012 response to deficiency letter and to clarify that the term"energy exchange" as applied in sections 5.4 - 5.6 relates only to energy sourced in Western or SPP(Order Granting Petition for Declaratory Order and Conditionally Accepting Joint Operating Agreementissued September 18, 2012)

2011-UA-376

10/19/2012State of Mississippi Proposed orders and briefing due (Second Revised Scheduling Order issued August 20, 2012)

40346

10/19/2012State of Texas Open Meeting begins at 9:30 AM to consider Proposal for Decision

UD-11-01

10/23/2012State of LA - New Orleans Hearing (Resolution R-12-333 adopted September 6, 2012; Resolution R-12-55 adopted February 16,2012)

12-060-R

10/31/2012State of Arkansas Public hearing begins at 9:30 AM (Order No. 1 issued August 8, 2012)

ER08-1338

11/1/2012FERC SPP to file its Annual Budget in FERC Docket Nos. ER04-48, ER08-1338, RT04-1

RM11-17

11/2/2012FERC Phase 3 dataset documentation due to FERC pursuant to Order No. 760 (must define each field indataset) (Final Rule issued April 19, 2012)

10/12/2012 10:53:32 Page: 2

Regulatory Outlook

EA-2013-0098

11/5/2012State of Missouri Staff Report and Recommendation to be filed (Order Directing Notice, Setting Intervention Deadline,Directing Filing and Scheduling a Conference issued September 5, 2012)

EO-2012-0367

11/5/2012State of Missouri Staff Report and Recommendation to be filed (Order Directing Notice, Setting Intervention Deadline,Directing Filing and Scheduling a Conference issued September 5, 2012)

RM10-23

11/12/2012FERC SPP's Compliance filing due to submit revised Attachment K of the pro forma OATT and otherCommission jurisdictional documents to include a cost allocation method or methods for regional costallocation consistent with principles of Final Rule (Notice of Extension of Time issued July 13, 2012;Section III.C. of Order No. 1000 issued July 21, 2011)

RM10-23

11/12/2012FERC SPP's Compliance filing due to submit revised Attachment K of the pro forma OATT and any otherCommission jurisdictional documents to include local and regional transmission planning processes thatare consistent with the requirements of Final Rule (Notice of Extension of Time issued July 13, 2012;Section III.A. of Order No. 1000 issued July 21, 2011)

RM12-12

11/26/2012FERC Comments due in response to NOPR proposing to approve regional reliability standard PRC-006-NPCC-1(Automatic Underfrequency Load Shedding) (Notice of Proposed Rulemaking issued September 20,2012)

RM11-17

12/3/2012FERC Phase 3 datasets to be delivered to FERC pursuant to Order No. 760 (to include marginal costestimates; energy and ancillary service awards; resource output; internal bilateral contracts; and upliftdata) (Final Rule issued April 19, 2012)

ER12-959

12/4/2012FERC Hearing begins at 10 AM EST (Order Establishing Procedural Schedule issued July 13, 2012)

12-1158

12/17/2012United States Court of Respondent's Brief due (U.S. Court of Appeals Order issued August 20, 2012)

10/12/2012 10:53:32 Page: 3

Regulatory Outlook

ER12-2292

12/19/2012FERC SPP's Compliance Filing due (Order Conditionally Accepting Tariff Revisions issued September 20, 2012)

RM10-13

12/31/2012FERC SPP to submit compliance filing to comply with the requirement that RTOs and ISOs enhance theirability to offset market obligations in bankruptcy, pursuant to the Final Rule (Notice of Extension of Timeissued May 14, 2012; Notice of Extension of Time issued January 24, 2012; Notice of Extension of Timeissued September 13, 2011; Order No. 741-A issued February 17, 2011; Order No. 741 issued October21, 2010)

12-1158

12/31/2012United States Court of Intervenors for Respondent's Brief due (U.S. Court of Appeals Order issued August 20, 2012)

RM11-17

1/2/2013FERC Phase 4 dataset documentation due to FERC pursuant to Order No. 760 (must define each field indataset) (Final Rule issued April 19, 2012)

ER12-959

1/7/2013FERC Initial Briefs due (Order Establishing Procedural Schedule issued July 13, 2012)

12-1158

1/14/2013United States Court of Intervenors for Petitioner's Reply Brief due (U.S. Court of Appeals Order issued August 20, 2012)

12-1158

1/14/2013United States Court of SPP's Reply Brief due (U.S. Court of Appeals Order issued August 20, 2012)

12-1158

1/22/2013United States Court of Deferred Appendix (U.S. Court of Appeals Order issued August 20, 2012)

ER12-959

1/28/2013FERC Reply Briefs due (Order Establishing Procedural Schedule issued July 13, 2012)

10/12/2012 10:53:32 Page: 4

Regulatory Outlook

RM11-17

2/1/2013FERC Phase 4 datasets to be delivered to FERC pursuant to Order No. 760 (to include day-ahead shift factors;supply offer and demand bids for ancillary services; capacity market offers, designation and prices;pricing data for interchange transactions; and FTR data) (Final Rule issued April 19, 2012)

07-00390-UT

2/2/2013State of New Mexico Southwestern Public Service Company to file Interim Report regarding SPS' continued participation in theSPP RTO (September 17, 2009 Uncontested Stipulation; February 2, 2010 Final Order ApprovingCertification of Stipulation)

12-1158

2/5/2013United States Court of Final Briefs due (U.S. Court of Appeals Order issued August 20, 2012)

ER06-451

3/1/2013FERC SPP Demand Response Informational Status Report Due

ES11-14

3/18/2013FERC Authorization to issue $20 million in promissory notes expires (March 18, 2011 Letter Order)

10/12/2012 10:53:32 Page: 5